COVER NG O&G_FINAL:oct08
WEATHERING THE STORM ExxonMobil’s hurricane response Page 50
VIRTUAL REALITIES Inside the digital oilfield Page 72
BIG IDEAS, SMALL SOLUTIONS Can nanotechnology work for oil and gas? Page 92
As energy demand heats up and dependence on foreign oil continues to rise, can natural gas help bridge the production gap?
VIEWPOINTS MATTHIAS BICHSEL Shell CECIL COLWELL Forest Oil GEORGE KIRKLAND Chevron FRANK RUDOLPH Devon Energy
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EDS NOTE quark7:OCT09
FROM THE EDITOR 7
Mixed messages One year on from his election victory, President Obama’s policies on offshore drilling remain unclear.
welve months is a long time in politics. Yet despite entering the White House on the back of a campaign based around energy last November, America’s new president has yet to solidify his thoughts on oil and gas and clearly communicate his intentions.
Riding into Washington in the wake of $4-agallon gas, the Obama campaign focused on the area of greatest concern to voters: their pocketbooks. With sky-high oil prices fresh in the mind, his vision was one of a greener and more efficient America; one that would create jobs and cut US reliance on rogue, oil-producing states in the Middle East and elsewhere. And the implication was that he would get there with or without the cooperation of the international oil majors. As a statement of intent, it certainly set industry pulses racing. Today, however, his policy direction is less clear-cut. For instance, we still don’t know exactly what his thoughts on offshore drilling are, and in trying to appease both environmentalists and energy
“I am conﬁdent that the importance of natural gas to the world’s energy portfolio will continue to grow, and that the business we are building will sustain its momentum” George Kirkland, EVP for Upstream and Gas, Chevron P38
conservatives he is merely muddying the waters. On the one hand he has declared his intentions to limit offshore drilling and further development of America’s natural resources; but on the other he has vowed to bring down prices and reduce US dependence on foreign oil. It is these mixed signals that are causing confusion and generating ill-feeling within government and the industry at large. Now is the time for clear leadership on this issue. America is the world’s third-biggest oil producer and largest petroleum consumer. But global oil discoveries have declined steadily since the early 1960s, despite periods of high prices and advances in exploration and production technology. The deficit has grown such that around the world we are now consuming roughly three times the amount of oil we are discovering each year. Many, including the OECD’s International Energy Agency (IEA), forecast another supply crunch between late 2010 and 2012, depending on how quickly global demand recovers. In fact, the discovery deficit is now so large that the IEA estimates an equivalent of six additional
Saudi Arabias need to be found and developed, requiring cumulative investments of $26 trillion, in order to meet expected 2030 global oil demand. Meanwhile the US has abundant resources on its doorstep, but is currently failing to utilize them. This is the dilemma the administration’s policymakers are facing. Mixed signals on offshore drilling will only serve to create contempt and disillusionment among fellow government officials and voters alike. The US must remain competitive in the energy production sector, especially against emerging powers like China. And greater transparency would go a long way to help open up the debate about which direction the US needs to take to help meet its future energy requirements.
Ben Thompson Senior Editor
“There’s loads of gas on the island, and we’ve invested in substantial infrastructure for its development”
“These challenges and ﬂawed policies have serious implications. They could lead to price spikes once the world economy recovers”
Ian Craig, CEO, Sakhalin Energy P124
Jim Mulva, CEO, ConocoPhillips P132
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Coming of age Chevron’s George Kirkland reveals the three vital drivers that are redeﬁning the world’s energy equation for the 21st century
30 Under pressure Higher, uncertain world oil prices, growing concern about greenhouse gas emissions, stalling R&D and import dependence: can natural gas provide the solution?
56 The energy challenge
When storms hit hard
Matthias Bichsel, discusses how Shell is looking to meet the world’s energy needs in economically, socially and environmentally responsible ways
The Gulf Coast region is home to the nation’s highest concentration of reﬁning and supply operations, a host of terminals, the origination points of the nation’s largest pipeline systems and extensive fuelsmarketing networks. ExxonMobile gives O&G an insight into its hurricane response systems
Improving oil and gas collaboration
82 44 Challenging times Bruce Vincent reveals why the current climate is creating tough challenges for independents
48 Why oil and gas is an economic engine
ASK THE EXPERT 76 Bart Stafford, SAIC 120 Mark Guest, Oilcareers.com
The fight against corrosion
Small soulutions for big returns
88 Getting smarter about the future of oil and gas How can we improve performance along with making cost reductions, asks Laura Mooney
90 Integrating IT Jens H. Schroeder explains the important role of IT in the oil and gas industry
How the oil and gas industry is supporting the US economy
78 Thinking business in the oil field 64 A new formula for success Daniel C. Hitzman explains why 3G has the potential to improve E&P results
66 License to drill Cecil Colwell gives an insight into the increasing importance of technology at Forest Oil
Bill Kuzmich offers his advice for dealing with digital oil ﬁeld data
80 Stepping stones for continuous optimization With IBM’s David Womack
92 Small solutions for big returns Diana Milne reports on why nanotechnology could be the small solution to a very big problem
102 The fight against corrosion Mark Byerley explains why inspecting pipelines is vital in the battle with corrosion
72 Field of dreams
82 Improving oil and gas collaboration
104 In great shape
IDC’s Catherine Madden on the three essentials for developing the next generation digital oil field
According to a new report, oil and gas pros view social media as important for productivity and collaboration
Richard Norsworthy argues that the pipeline industry is in good condition; it just needs to get smarter
106 Capturing and communicating knowledge
IN THE BACK Stepping on the gas
Paul Oleksa explains how well-written procedures can help document a company’s operations, improve efﬁciency and limit risk
108 Improving offshore operations John H. Edvardsen looks at offshore asset tracking and monitoring solutions
110 A sticky problem
The challenge of sediment in oil and gas pipelines
122 Safety success 114 A balancing act Will universities and corporations develop enough talent to address the looming retirement deadline?
Hans Jorn Johansen examines the safety improvements the industry has seen over the past two decades
124 Waking a sleeping giant 118 Critical tools for tough times Frank R. Lloyd explains why planning for growth is essential – even in a downturn
Thanks to its abundant reserves of oil and gas, Sakhalin Island could yet prove an unlikely source of hope for global energy markets
132 In my view: Jim Mulva 134 Energy innovation: OriginOil 136 Oil sands: Cracking the code 138 Security: Somali pirates 140 Vantage point: Qatargas 2 142 On the shelf: Book reviews 144 Final word: Carl Hughes
Waking a sleeping giant
A balancing act
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Chairman/Publisher SPENCER GREEN Director of Projects ADAM BURNS Editorial Director HARLAN DAVIS
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Russian President Medvedev (L) and Cuba's President Raul Castro (R), brother of ailing revolution leader Fidel Castro, stand together during Medvedev's visit to Cuba last November. Russia recently signed a major deal to drill for oil in the Cuban portion of the Gulf of Mexico – just 45 miles from US soil.
THE RUSSIANS ARE COMING… And so are the Chinese, the Venezuelans, the Brazilians and a host of others. Environmentalists may cringe, but given the recent news that Cuba has signed a major deal with Russia to jointly search for oil in the Gulf of Mexico, is it time for the US to revise its policy of drilling off the coast of Florida?
Cuba began opening up 59 blocks in the Gulf for exploration by foreign companies over a decade ago, and by March of this year had 21 of these under lease to seven companies, with 23 more in negotiation. Russia is not the only country to cut deals with Cuba for a stake in the potentially lucrative Gulf waters: Venezuela’s
state oil company PDVSA plans to begin drilling in 2010; Brazil’s PETROBRAS has also leased a block and plans to begin its initial seismic surveys this year; and in 2008, China National Petroleum Corp. – China’s premier oil explorer – also signed a deal with the island’s state-run oil company Cubapetroleo to jointly develop
oil and gas fields in the region. American fi rms are notable by their absence. But the prospect of Russian rigs drilling for oil and gas just 45 miles from the United States coastline has reawakened deep-rooted fears about the Russian threat first planted during the Cuban Missile Crisis of the 1960s – although this time the concerns are over energy and resources rather than nukes and ideology.
In 2004, the US Geological drastically reduce plans to open the Survey estimated that potential re- coast to offshore oil and gas drillsources in the North Cuban basin ing, citing threats to marine life could total 4.5 billion barrels of and potentially devastating effects oil and 9-10 trillion cubic feet of of oil spills in coastal waters. The natural gas. By way of comparison, recommendations by the National Prudhoe Bay on the north slope of Oceanic and Atmospheric AdAlaska – the largest US discovery ministration are informal and not to date – originally held about 25 binding, but if adopted, they would billion barrels of oil. restrict development in some of the Many believe the Cuban pro- nation’s most resource-rich unposal should send a message that tapped offshore areas – including if other nations are willing to open large tracts of the Alaska coast, the up their offshore waters, Atlantic seaboard and the so should the US. Gulf of Mexico – and Naturally, Amerimark a significant Increased access can oil and gas departure from to the GOM could provide up to firms are among the pro-drilling those clamorpolicies of the ing for the US Bush adminisgovernment to tration. in new revenue rethink its own Secretary of policy regarding the Interior Ken Saladrilling in the eastern zar, who has been accused Gulf of Mexico, an area the USGS of dragging his heels over an exestimates has three billion barrels panded drilling program, has said of oil and over 11 trillion cubic feet any future offshore leasing plan of natural gas. “must take into account several Proponents of drilling main- key considerations, including areas tain it would provide the Obama of the ocean that are critical to administration with a dramatic military training and the nation’s influx of $2.2 trillion in new rev- defenses; other economic benefits enue from royalties and taxes on of the oceans, including fisheries, profits, and estimate it would add tourism and subsistence uses; envione million new jobs to the Gulf ronmental considerations; existing of Mexico regional economy. “It’s oil and gas infrastructure; interest a no-cost stimulus to the economy from industry; and the availability that we’re leaving off the table,” of scientific and seismic data.” argues Thomas Pyle, President of Whether the US decides to the Institute for Energy Research, push ahead with an expanded a free-market energy think-tank drilling program or not, it seems based in Washington DC. certain that oil and gas activity in Not everyone agrees, of the Gulf of Mexico will increase course, with many environmen- regardless thanks to Cuba’s plans. tal groups thinking the potential “It does present a dilemma for the risk of damage to ecosystems and US,” admits Wayne Smith, a senior wildlife from an expanded drilling fellow at the Center for Internaprogram is too great. Indeed, such tional Policy in Washington. “But claims were given greater weight as long as it’s in Cuba’s economic last month as top ocean scientists zone, we may not like it but there is urged the Interior Department to little we can do about it.”
NEWS IN PICTURES
In 2004, the US Geological Survey estimated that potential resources in the North Cuban basin could total 4.5 billion barrels of oil and 9-10 trillion cubic feet of natural gas. Pressure is growing to reconsider drilling in the US-owned eastern Gulf of Mexico, an area the USGS estimates has similar amounts of oil and gas.
Cuban military salute Russia’s anti-submarine destroyer Admiral Chabanenko – the ﬁrst Russian warship to visit the communist-led island since the 1991 Soviet collapse – as it enters the harbour of Havana in December 2008. For some, Russia’s renewed military presence carries echoes of 1962’s Cuban Missile Crisis.
Environmentalists and the tourism industry are concerned that heightened drilling in the Gulf of Mexico will have a detrimental impact on US resorts such as this one at Ocean Pointe, Tavernier, Florida.They say drilling so close to Florida’s coastline will increase the risk of oil spills washing up on its shores.
ENERGY IMBALANCE The United States has become ever more dependent upon imported or foreign oil. A mere 30 years ago, 28 percent of the oil consumed in the United States was imported; today nearly 60 percent of the oil utilized and consumed in the United States is imported from other countries. Contrary to public opinion, however, a good share of imported oil does come from nations that have fairly stable political situations. Most people are surprised to learn that the country from which the United States imports the greatest amount of oil is Canada – in recent years, the United States has imported approximately 200 million barrels of crude oil annually from its northern neighbor. Nonetheless, the largest amount of oil reserves are located in the Middle East – one of the most volatile regions in the world. Addressing this energy imbalance is one of the toughest challenges facing the US.
WAS PEAK OIL DATA DISTORTED? The UK’s Guardian newspaper reported this month that a whistleblower from within the IEA claims the organization came under extreme pressure from the US to “distort” figures that pointed towards a looming oil shortage, for fear of triggering panic buying. “Many inside the organization believe that maintaining oil supplies at even 90-95 million barrels a day would be impossible, but there are fears that panic could spread on the fi nancial markets if the figures were brought down further,” the Guardian quoted the IEA source as saying. The concerns surround the IEA’s prediction in the 2008 World Energy Outlook that oil production can be raised from its current level of 83 million barrels a day to 105 million barrels. Critics claim the reality is far more alarming, arguing the figures cannot be substantiated by firm evidence and that the world has already passed its peak in oil production.
“The IEA in 2005 was predicting oil supplies could rise as high as 120 million barrels a day by 2030, although it was forced to reduce this gradually to 116 million and then 105 million last year,” said the IEA source, who was unwilling to be identified for fear of reprisals inside the industry. “The 120 million figure always was nonsense but even today’s number is much higher than can be justified and the IEA knows this.” As of yet, no senior officials at the IEA have come forward to comment on the issue, but in the past the organization repeatedly warned that a lack of investment would lead to serious strain on supply. However, it has also continuously argued there is enough oil in the ground and that we would not hit peak for another two decades. Some commentators are even raising the idea that a peak in demand could occur because of policies to curb fuel use as part of efforts to combat global warming.
REALITY CHECK FOR OIL In the first half of 2008, oil and gas companies were living large. The price of crude surpassed $100 per barrel; oil and gas companies everywhere were posting record profits; project expansions were on the rise. But then, in September 2008, after peaking in July at almost $150, the bottom fell out of the market. Suddenly, life in the oilpatch was very different. Much of the new project planning and preparation that had been undertaken at higher oil prices was no longer viable, and those same record-setting companies were now faced with a new set of challenges – no longer how best to put their unprecedented profit levels to work, but how to make a profit at all. With this in mind, Deloitte has put together a list of the top 10 challenges currently facing oil and gas companies as they look to rebound from the downturn. “The oil and gas business is anything but straightforward,” says Dick Cooper, leader of Deloitte’s national Energy & Resources practice. “It’s complex, costly and subject to intense public expectation and scrutiny.”
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Economic uncertainty may spark supply shortages Elevated expenses will squeeze margins Global operations demand robust processes Talent shortages loom The pace of mergers and acquisitions is accelerating Market access will be limited by resource nationalism Reserves are getting harder to reach and extract Health and safety remain critical concerns Carbon reduction targets are set to rise in prominence An alternative energy strategy is mandatory
AROUND THE WORLD IN 80 DAYS
Our guide to the last quarter’s global events – and their impact on your business. IRAQ OPENS UP
Following agreement on two new oil service contracts, Iraq’s oil minister has said he expects his country to increase its oil production to 10-12 million b/d over the next six years from the current 2.5 million b/d. The further development of Iraqi oil fields can only be good news for IOCs and international contractors alike.
Brazil’s state-owned oil and gas company Petrobras has signed a $10 billion loan agreement with China Development Bank Corp. Petrobras said it will give preference to Chinese companies for the purchase of goods and services and will pay back part of the loan from the sale of oil to China. The Dragon’s global influence is increasing.
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The International Energy Agency projects that global energy demand will climb 40 percent between 2007 and 2030, and that the world’s energy resources are adequate to meet this projected demand increase through that date and beyond. Oil will remain the single-largest fuel in the energy mix in 2030. That’s a relief.
Gabon will launch an oil licensing round for more than 40 blocks from two of its deepwater basins in May 2010. It is a deepwater round with attention on subsalt plays. Does Gabon’s deepwater offshore acreage hold similar potential to that of Brazil and Angola, both of which announced large discoveries recently?
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LNG PROJECT UNDERWAY
SINO-RUSSIAN PIPE COMPLETE
ExxonMobil Corp. and its joint venture partners completed the front-end engineering and design phase for their Papua New Guinea LNG project. The project will cost $15 billion and have the capacity to produce 6.6 million tonnes/year of LNG. Is this further indication of the global LNG market’s rise to prominence?
Russia’s state-owned pipeline monopoly OAO Transneft has completed construction of a spur from the Eastern Siberia-Pacific Ocean pipeline to the Chinese border. The line will be able to ship 15 million tons/year of oil, rising to 300 million tons/ year over the 20-year contract. Russia’s diversification plans continue.
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CONNECTING THE SUPPLY CHAIN Continually challenged to improve operational excellence and ensure employee safety, today’s petrochemical industry needs new ways to manage business safely and reliably. Process control and maintenance systems for improving operational efficiency and asset performance have been in place for many years. What’s been missing is the ability to extend and connect these wireline systems with your mobile workforce. It’s not about replacing these systems – it’s about extending systems to allow personnel to communicate whenever and wherever they are with the data they require in real-time. Mobile and wireless technology is rapidly reshaping the industrial world. Connecting the petrochemical supply chain starts with the development of an enterprise-wide strategy for the automation and mobilization of information access and data collection at the point of business activity, throughout all operations. Wireless connectivity across the petrochemical enterprise enables real-time information in the hands of the people who need it to make decisions or perform their jobs. When workers have seamless access to enterprise systems with the right information at the right time, they can make business-critical decisions that streamline business processes and improve results. For upstream, midstream or downstream operations, wireless connectivity delivers data that enable companies to manage assets, ensure employee safety, reduce the cost of compliance and optimize overall operational efficiency. The decision to deploy wireless technology can raise concerns about security and cost. Other challenges to wireless deployments include complex, multi-path environments, the need for ruggedization and expansive coverage areas. The technology barriers to deploying wireless technology in a difficult, industrial environment have been overcome and the cost of deployment has been significantly reduced. It is still not a simple undertaking. The keys to successful deployment include understanding your technology options, taking a systems approach and using the right planning tools.
DENBURY BUYS ENCORE
Texas-based oil and gas developer Denbury Resources Inc. is set to purchase Encore Acquisition Co. in cash and stock, as it seeks to become one of the largest independent oil exploration and production companies in North America. Denbury CEO Phil Rykhoek only had four months in the job before attempting the biggest US oil and natural gas acquisition of 2009, yet said the deal was his “defi ning transaction”. The $2.64 billion takeover of Fort Worth, Texas-based Encore accelerates a push Denbury started under Rykhoek’s predecessor, Gareth Roberts. Analysts say the deal will create one of the largest tertiary extraction specialists in the US and demonstrates the market’s confidence in the future of regional unconventional oil and gas production. “Encore has built an enviable asset portfolio in the Rockies, anchored by mature legacy crude oil assets, and our combined size and scale of operations will allow us to undertake significantly larger CO2 projects in the Gulf Coast and the Rockies,” said Rykhoek in a statement.
For more information visit www.motorola.com/petrochemical
The realistic scenario in the latest Canadian Energy Research Institute outlook expects Alberta oil sands production to increase to 1.7 million b/d by 2015, 2.5 million b/d by 2020, 4.5 million b/d by 2030 before reaching a peak of 5.3 million b/d in 2041
INVESTMENT NEEDED The global financial crisis has had a profound effect on the oil industry. Demand has dwindled, which has driven down prices, which in turn has led to fi rms making drastic cut backs to improve their bottom line; inevitably, exploration and production has suffered. But with the crisis easing, this means that huge investments are now needed to ensure the industry has enough production capacity to meet future demand, according to a new ARC Advisory Group study. Over the next five years, ARC predicts companies will put millions of dollars into automation of exploration, production and pipeline processes, and expects the automation business to grow at a compounded annual growth rate of nearly seven percent over the next five years. “With the global economic downturn as a backdrop, it would be understandable if oil companies were to dial back their capital investments as a response to reduced demand and falling oil prices,” says analyst Allen Avery, the principal author of ARC’s Automation Expenditures in Upstream Oil & Gas Worldwide Outlook. “However, many of the major oil companies are maintaining their capital spending plans into 2009 and beyond.” The production segment is being driven by challenging capital projects as oil companies aim to boost reserves by drilling in remote areas that are much less hospitable and more dangerous – both environmentally and politically. Therefore, companies are stepping up exploration efforts in tar sands, shale oil and coal-to-liquid gas that will require new midstream and production facilities to be developed, increasing demand for automation systems and field devices. According to estimates, global demand for petroleum products will soon increase significantly as the economies in developing regions improve and per capita energy consumption increases.
CANADIAN OIL SANDS BOOST US ECONOMY The economic impact of oil sands develIn the study commissioned by API, CERI opment in neighboring Canada is a boon based its assumptions on oil sands output for the US economy and is expected to lead rising from about 1.4 million barrels a day to the creation of more than 342,000 new to around four million barrels a day in 2025. American jobs between 2011 and 2015, a It estimated annual capital investment and study by the Canadian Energy Research operating costs needed to achieve this output Institute (CERI) has found. – about $25 billion in new investment and The study, entitled Canada’s Oil Sands $7 billion in operating costs in the peak year and Economic Impact on the USA, said of 2015 – and then estimated the economic greater production of Canadian oil sands impact to Canadian and US economies. would stimulate economic activity According to the study by CERI, a in both countries. As oil sands non-profit Canadian energy and production and investment environmental research instiin Canada rises, demand tute, the benefits of oil sands for US goods and services development are broadly Annual investment increases significantly, shared across many US inrequired to expand adding an estimated $34 dustry sectors and regions. output to 4 million billion to America’s gross Canada is by far the biggest bpd by 2025 domestic product in 2015 and supplier of imported oil and $42.2 billion in 2025. Canada natural gas to the United States, is the largest trading partner of the and companies are investing huge United States. sums to expand US refineries and build new “Oil sands reserves play an increasingly infrastructure to transport the Canadian oil important role in the economic evelopment into the United States. of Alberta, Canada and the United States,” “Clearly Canadian oil sands developCERI said in its study. “What is often not ment is a win-win for both Canada and clearly understood is that the large invest- the United States,” says API President Jack ment in the oil sands industry contributes Gerard. “Not only is greater oil sands proto increased economic activity in the rest of duction crucial for US energy security, it North America by stimulating demand for also supports thousands of American jobs goods and services across a wide range of and is a major contributor to our nation’s industries.” economic growth.”
PROVED RESERVES AT THE END OF 2008
TOP 10 OIL CONSUMERS
The world uses up almost 82 million barrels of oil every day, or 30 billion barrels per year, and consumption is constantly rising by the day with economies like India and China growing at breakneck speed.
NEW SOFTWARE FOR E&P MARKET Over the past year JewelSuite has been working with its partners leveraging Microsoft’s .NET application engineering environment. Thanks to the patented Jewel Grid (Faulted S-Grid) industry leading, cost effective geoscience and engineering tools such as SMT’s Kingdom Suite and CMG’s IMEX Simulation engine can be used in conjunction with JewelSuite to provide end-to-end workflows in both 32 and 64 bit Microsoft Windows workstation environments. Geoscientists and engineers can now defi ne, create and more easily maintain up-to-date static and dynamic reservoir simulation models. The approach is facilitated through hybrid gridding techniques that enable fast, accurate links to models and maps generated in purpose built applications while providing a framework to integrate the data into one consistent 3D
model. The grid and associated properties can then easily be scaled for use amongst the disciplines. The main driver for the development of this new soft ware and gridding technique is the shift ing E&P market – where production of complex fields and heavy hydrocarbons has become increasingly important – thus requiring up-to-date reservoir models with a fast turnaround time in weeks instead of months. The vision to build higher quality reservoir models is realized by no longer focusing on ‘best in class’ for individual parts of the static and dynamic workflow, but to generate better insight on the total integrated reservoir model, referred to as four models in one: the geophysical structural model, the geological model, the reservoir simulation model and the geo-mechanical model when required.
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USA 20,698 (23.90% of total) CHINA 7855 (9.30%) JAPAN 5051 (5.80%) INDIA 2748 (3.30%) RUSSIAN FEDERATION 2699 (3.20%) GERMANY 2393 (2.80%) SOUTH KOREA 2371 (2.70%) CANADA 2303 (2.60%) SAUDI ARABIA 2154 (2.50%) FRANCE 1919 (2.30%)
Ibraheem Assaadan, Vice President of Exploration for Middle East oil giant Saudi Aramco, explains how the company are growing hydrocarbon resources through a combination of human capital and IT. We manage our investment in a way that deals with the short-term while staying focused on long-term objectives and strategic comparatives – going radical when it comes to R&D and exploration is not the right approach all the time, however we realize there is a need to deal with short-term fluctuations in oil prices. We’re looking at growing the hydrocarbon resources from the 755 billion barrels that we have today to 900 billion, and this is primarily going to be coming through exploration for the most part. Optimization of existing assets and improved management of existing wells and infrastructures and facilities, de-bottlenecking, is ongoing at all times, whether you’re at peak prices or low. Saudi Aramco is looking to be a leader in ecology. We look around for solutions and if they are available, we’ll adopt them. If not, we’ll make them and we’ll create them, and that applies in every single aspect of our busi-
ness, whether it’s upstream or downstream. Lately, we have taken the more prudent approach of growing a long-term strategy and looking forward 20-30 years at what is required from the upstream side as well as the downstream side, and what needs to be done in terms of viable targets to deal with technological challenges, whether it is seismic imaging and exploration or reservoir collectivization or dealing with refi ning processes and oil field well-being requirements. Data is data and interpretation is the human capital. You can have all the data in the world but if you don’t have the right people, the data is useless. The investment is wasted. So Saudi Aramco strikes a balance between automation and human capital development. Automation has its own advantages in terms of reducing cycle time and reducing running requirements, but nothing will replace human judgment and this is where we are putting tremendous emphasis on human resource development. Our engineers and geoscientists
are receiving tremendous levels of training because we believe that human capital is the most valuable asset any company in any business may have. We’re capitalizing technology and pushing the envelope as much as we can in terms of what is needed to tackle the future challenges of the industry. We also have a parallel effort focusing on HR development to make sure that the workforce is world-class and one of the best in the world. The Upstream Professional Development Center is a mechanism to really accelerate the move from academic education into real life. It is designed – whether it’s the curriculum or the facilities – to shorten the time it takes for a new graduate to transform into a full-blown professional. The curriculum, the practicality and the facilities are all designed in a way to achieve exactly that and shorten the time it takes to move him from where he is into a fully contributing member in the shortest possible time.
UPFRONT 24 Itâ€™s been 150 years since a businessman struck oil in a small Pennsylvania town and changed the world forever.
Cold comfort T
he Arctic presents a ‘good news, bad news’ situation in terms of oil and natural gas development, according to the fi ndings of a study into the region’s potential for exploration and drilling released by the US Energy Information Administration last month. The good news is that the Arctic holds about 22 percent of the world’s undiscovered conventional oil and natural gas resources, based on recent US Geological Survey estimates. The bad news for the industry is that the Arctic resource base is largely composed of natural gas and natural gas liquids, which are significantly more expensive to transport over long distances than oil; that Arctic oil and natural gas resources will be considerably more expensive, risky and take longer to develop than comparable deposits found elsewhere in the world; that unresolved Arctic sovereignty claims could preclude or substantially delay development of those oil and natural gas resources where economic sovereignty claims overlap; and that protecting the Arctic environment will be costly. As a result, concludes the report, the high cost and long lead-times of Arctic oil and natural gas development undercut the immediate importance of these sovereignty claims, while at the same time diminishing the economic incentive to develop these resources. Another factor is the emergence of socalled unconventional resources elsewhere in the world – many of them in existing fields. Given that the Arctic resource base is predominantly composed of natural gas and natural gas liquids, the study suggests the importance of Arctic oil and natural gas resources is likely to be affected by the growing realization that shale beds in existing petroleum provinces around the world might be capable of producing be-
tween 5000 and 16,000 trillion cubic feet of natural gas. Th is potentially large shale gas resource could significantly defer the future development of Arctic natural gas resources. Of course, there could be exceptions. Hypothetically, growing European demand for natural gas, the depletion of existing North Sea and Russian natural gas fields, and disappointing European shale gas exploration and development results could act as a strong incentive to develop Russia’s Arctic natural gas resources in the West Siberian Basin and East Barents Basin. Other aspects of the estimated Arctic oil and natural gas resource base are more neutral in character. For example, the fact that the expected undiscovered Arctic resource base is largely confi ned to a few sedimentary provinces might be more reflective of the fact that little, if any, oil and natural gas exploration drilling has been conducted in those provinces with low resource estimates. On the other hand, if the estimates for these unexplored and underexplored provinces prove correct, and they have little or no oil and natural gas, then the drive by nations to claim economic sovereignty over these offshore provinces would diminish. The bottom line for Arctic oil and natural gas potential is that high costs, high risks and lengthy lead-times can all serve to deter their development in preference to the development of less challenging oil and natural gas resources elsewhere in the world. Also, the less abundant Arctic oil resources will be more readily developed than the Arctic’s natural gas resources. Thus, concludes the report, while the Arctic has the potential to be a more important source of global oil and natural gas production sometime in the future, the timing of a significant expansion in Arctic production is difficult to predict.
Explorers Robert Peary and Matthew Henson, plus four inuits, become the ﬁrst men to reach the North Pole
Discovery of oil on the Alaska North Slope
The SS Manhattan, a specially designed oil tanker with icebreaker, successfully sails through the Northwest Passage in the ﬁrst attempt to bring commercial shipping to the region
The Soviet nuclear icebreaker Arktika reaches the North Pole, the ﬁrst surface ship to do so
It is reported that the Arctic average ice thickness has declined by 40 percent since the 1960s
The Denmark Science Ministry claims the North Pole belongs to Denmark and sends an expedition to prove the seabed there is a natural continuation of Danish territory
Norway’s Statoil ASA announces oil exploration drilling from the offshore rig Eirik Raude has been shut down after its third spill into Arctic waters in two months
Russia plants a titanium ﬂag under the North Pole, staking a claim to the Arctic
Russia reveals plans to establish military bases along its northern coastline
100 YEARS IN THE ARCTIC
The Minerals Management Service, part of the federal Interior Department, gives Shell the green light to begin exploratory wells off the north coast of Alaska
US OIL FACTS
In the US alone, exploration is down 27.8 percent from a year ago, with 309 rigs actively drilling, compared with 428 at this time in 2008, according to the Baker Hughes Rig Count.
Today, the EIA estimates US proven oil reserves to be about 21 BILLION barrels. Oil meets 37 PERCENT of US energy demand, with 70 PERCENT directed to fuels used in transportation – gasoline, diesel and jet fuel. Another 24 PERCENT is used in industry and manufacturing, 5 PERCENT is used in the commercial and residential sectors and between 1-2 PERCENT is used to generate electricity.
PETROLEUM U.S IMPORTS BY COUNTRY
Other 19% Mexico 10%
DRESSER-RAND/SAUDI ARAMCO PARTNERSHIP
UK Russia 2% 4% Source: Energy Information Administration, MER May 2009
Source: Energy Information Administration, AER 2008
Dresser-Rand Group Inc., one of the largest suppliers of rotating equipment solutions to the worldwide oil, gas, petrochemical and process industries, has announced that its affi liate entered a long-term corporate procurement agreement with Saudi Aramco. Owned by the Saudi Arabian government, Saudi Aramco is a fully integrated, global petroleum enterprise. The company manages proven reserves of 260 billion barrels of oil and manages the fourth-largest gas reserves in the world. Saudi Aramco selected Dresser-Rand as the fi rst manufacturer to supply its full range of compressor and steam turbine products under the agreement. “Part of our strategic plan clearly identified the need for a strong unified approach to our Middle East markets, including the opportunity to better serve our clients with more local presence. The agreement with Saudi Aramco is a leap forward for us,” said Vince Volpe, DresserRand’s President and CEO. Dresser-Rand also announced it will open a facility to serve as a center of excel-
lence for manufacturing, repairs, service, technical expertise and training. The company expects the new operation will be a joint venture with long-time business associates, Al-Rushaid Petroleum Investment Company of Saudi Arabia, and will serve Saudi Aramco, other clients in the Kingdom of Saudi Arabia, and selected clients in the gulf region. “Dresser-Rand Arabia will serve as the hub of activity in the region,” said Volpe. “It will provide support for new project programs, provide after-sales service, offer training and repair support for the existing installed base of rotating equipment, create a competitive manufacturing environment for Dresser-Rand products for in-Kingdom projects and for export, engage with the King Fahd University of Petroleum and Minerals in joint research and development programs, and create employment in the Kingdom at all levels from management to the shop floor.” For more information about Saudi Aramco, visit www. saudiaramco.com. For information about DresserRand, visit www.dresser-rand.com.
IRAQ OPENS UP
In June this year, Iraq opened d its doors to the world’s largest energy commpanies only for many of them m to walk out on the bidding ng process due to the tough terms ms the Iraqis were proposing. ng. But now many of those same me companies are returning to the he Middle East in search of the he lucrative contracts they turned ed down just a few months ago. go. The Iraqi Oil Ministry recently announced that it is to award a consortium led by Exxon Mobil Corp. and Royal Dutch Shell PLC the right to develop the West Qurna-1 field in southern Iraq, while similar deals were also struck with British oil giant BP and China’s CNPC.
The structure stru of the deals – essentially sen service contracts – won’t allow foreign companies co to boost their own ow reported reserves and production pr numbers. But executives ex see them as providing vi access to Iraqi oil officials c and a chance to work in the country’s fields, both crucial cru if Iraq continues to open up to international companies. In December, Iraq will hold a second bid round for a further 10 unexplored oil and gas fields. Such high levels of foreign investment will be crucial as the government looks to boost production in order to help revive its economy.
134 POWER PLANTS Can a breakthrough in technology transform algae into a true competitor to petroleum?
COMPANY INDEX Q4 2009 Companies in this issue are indexed to the ﬁrst page of the article in which each is mentioned. Absolute Pipeline 113, OBC
Gubkin Russian State Oil and
PetroBeam Inc. 136
Advanced Energy Consortium 92
Gas University 124
Polyguard Products Inc. 104, 105
Potential Gas Committee 30
Baker Hughes 2, 69
IBM 13, 80, 81
BP America 30
IDC Energy Insights 72
Cambridge Energy Research
Independent Petroleum Association of
RWD Technologies 117
America (IPAA) 44
Institute of Nanotechnology 92
SAIC 8, 76, 77
International Association of Oil and Gas
Sakhalin Energy Investment
CGG Veritas 97, 99
Producers (OGP) 122
International Energy Agency 92, 124
SatPos 108, 109
JOA Oil & Gas 22, 43
SES New Skies 75
Colorado School of Mines 30
m:pro IT Consult 90, 91
Shell 56, 124
Southern Methodist University 118
Cox School of Business 118, 119
Metastrom IFC, 86, 88
CSC 78, 79
TRE Europe 47
Devon Energy 114
Motorola 20, 89
Dresser Rand 15, 28
NACE International 102
Forest Oil 66
Oilcareers.com 120, 121
Oleksa and Associates 106, 107
Geo-Microbial Technologies (GMT) 6, 64
136 CRACKING THE CODE The potential of cracking technology could save the industry hundreds of billions of dollars
138 OIL, TOIL AND TROUBLE Piracy is back. Can the industry ward off potential attacks or is it merely a sitting duck?
COVER STORY Uncertain oil prices, growing concern about greenhouse gas emissions, stalled R&D investment and foreign oil dependence are all heaping pressure on the government to decide on the longterm energy future for the US. Can natural gas fulﬁl its promise and bring long-desired stability and direction to a volatile industry?
By Rebecca Goozee
n the summer of 2008, the US – along with the rest of the world – was consumed by fears that soaring oil prices would plunge the country into an energy crisis. Then the credit crunch struck, sinking almost every major economy into a deep recession and sending oil and gas prices plummeting. With a new US government in place just a few months later, the industry was evaluated as part of the country’s new energy future. Focusing on the power of clean, renewable energy, Obama’s administration embraced alternative technologies, concentrated on a cap and trade system to control carbon emissions and worked to strike a concrete deal to limit global warming. However, the potential of natural gas to solve Obama’s energy woes by curbing emissions, reducing import dependence and improving the country’s energy prospects had, undoubtedly, been glossed over. Interior Secretary Ken Salazar has recently said that natural gas should play a more prominent role in America’s energy future and former Vice President Al Gore, Senate Majority Leader Harry Reid and Energy Secretary Steven Chu have all voiced similar thoughts. However, the Obama administration is remaining tight-lipped over the role of natural gas in the country’s future plans. Indeed, it seems that natural gas has run out of steam in Washington, where the industry is facing a brick wall in terms of getting written into President Obama’s energy bill. Influential lawmakers are backing carbon capture technologies, believing them to be a better long-term bet than gas for solutions to climate change. However, it is not just a battle over the environment: industry profits depend on the important policy outcomes. A climate change proposal approved in June by the House of Representatives, the Waxman-Markey Bill, focused on capping greenhouse gas emissions and as such renewable fuels like wind and solar won out, while the cost of emitting carbon dioxide emissions remained at levels that would continue to provide a price advantage for coal. While natural gas did see benefits including a cap-and-trade system that sets limits on emissions of greenhouse gases and pollution credits to be sold on the carbon-trading market, utilities that burn coal will receive tens of billion of dollars worth of free credits as opposed to the $30 billion over 10 years that natural gas has been allocated.
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WHAT THEY SAY
This amount of natural gas is equivalent to around 320 billion barrels of oil – more than Saudi Arabia’s 264 billion barrels by quite some margin. “Our knowledge of the geological endowment of technically recoverable gas continues to improve with each assessment,” explains Dr John B. Curtis, Professor of Geology and Geological Engineering at the Colorado School of Mines and Director of the Potential Gas Agency there, which provides guidance and technical assistance to the PGC. “Furthermore, new and advanced exploration, well drilling and completion technologies are allowing us increasingly better access to domestic gas resources – especially ‘unconventional’ gas – which, not all that long ago, were considered impractical or uneconomical to pursue.”
Gas rush While gas has up until now has played a supporting role to oil in terms of America’s energy policy, it may be the time for natural gas to step out of the shadows and emerge as the major player. Firstly, it is the cleanest burning fossil fuel, delivering 60 percent less CO2 than coal per kilowatt. It is also the most versa“Shell is increasingly focusing on natural gas, the cleanest-burning fossil tile of all fossil fuels and can be used for transportation, generatfuel. By 2012, natural gas will likely make up around half of our ing light and heat and combined with turbines to create a more production. This is not merely a shift in our portfolio. Increasing natural renewable source of energy. Finally, natural gas generators are gas production – and transportation by liquefying it and shipping the more easily switched on and off than coal-fired plants and can LNG to global markets – means that more natural gas will be available to also be expanded and permitted with far fewer NIMBY issues. displace coal as the fuel for power plants. A natural gas-ﬁred power Lamar McKay, Chairman and President of BP America plant emits on average half the CO2 of a coal-burning plant to produce Inc, believes that natural gas has huge potential as part of a more the same amount of electricity. It also generates signiﬁcantly less local diverse energy supply. “Natural gas has been described before as pollution. In fact, coal-ﬁred electricity is responsible for the fastest a ‘bridge fuel’ to a lower-carbon future. It is that, certainly. But growth in greenhouse gas emissions worldwide, so it’s urgent that we I believe it can be much more. Rather than merely a bridge fuel, address that. Supplying more natural gas is one way of doing that. In the it can be a destination fuel for a lower-carbon future. The poUnited States, new technology has opened up abundant gas resources tential of natural gas is not a vision founded on conjecture or contained in dense rock formations, increasing supplies dramatically. So hope. It is founded on existing reality. Increased use of natural you can see why I’m sometimes tempted to say: nothing beats natural gas provides us with the best, most realistic path for achieving gas.” Peter Voser, CEO, Royal Dutch Shell the greatest emission reductions, at the lowest cost, using technology that is available today.” So why has gas been largely ignored in Obama’s new energy bill? Phil Indeed estimates predict that almost all the newfound resources are in Flynn, Senior Energy Analyst at PFGBest believes that the administration shale deposits, which are now thought to contain 616 Tcf of recoverable gas. simply do not want to acknowledge the potential of natural gas. “Natural Supplies in the Appalachian basin alone are calculated at 227 Tcf, with the gas is going to play a major role in the future of the US,” he claims, “Even Marcellus accounting for the bulk of that. The Marcellus is the most recently though the Obama administration doesn’t want to admit it. From their idediscovered layer of shale in the Appalachian basin as well as the oldest, deepological viewpoint oil companies and anything to do with oil or gas is inest and most possibly largest shale gas deposit. There are also a number of herently bad whereas any alternative fuels are inherently good. They are other deposits scattered throughout the country including the ‘big four’, doing themselves a disservice by not making natural gas a much bigger part which are several potentially mammoth shale deposits. Alongside the of their energy platform.” Marcellus, these are the Barnett of north-central Texas, Haynesville of East He goes on to explain that he amazed that the administration are not Texas and northwestern Louisiana, and Fayetteville of central Arkansas. The jumping for joy after hearing about the Potential Gas Committee’s report first target for companies was the Barnett site in Texas, which was first exearlier this year. When the Colorado School of Mines PGC report, released plored in the 1990s. back in June 2009, announced the results of its latest biennial assessment of Shale gas has become increasingly more important as a source of natural gas the nation’s natural gas resources, it was the highest evaluation in the comover the past decade and the shale gas boom of recent years has been due to modmittee’s 44-year history. It indicated that the US possesses a total technicalern technology advancement in hydraulic fracturing to create extensive artificial ly recoverable resource base of 1836 trillion cubic feet (Tcf) of natural gas. fractures around well bores. The breakthrough has opened a new frontier for the
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WHERE THE SHALE GAS IS
energy industry, turned long-held assumptions on their head and revealed an America that is awash with gas. The Department of Energy now predicts that shale gas could meet half America’s demand within two decades and turn the country into a net exporter and the shale boom is only in its infancy. According to the Department of Energy’s Energy Information Agency (EIA) the US consumes about 23 Tcf of natural gas a year, which translates into a 90-year supply at current consumption rates and if natural gas totally replaced coal in generating electricity, domestic supplies would last for 50
years. Some geologists believe that gas supplies in the Marcellus and other shale deposits could potentially be even more plentiful that the PGC estimates.
Energy diversiﬁcation While natural gas is not interchangeable with oil and will therefore not single-handedly solve the country’s energy needs, it may reduce dependence on foreign oil and ultimately encourage energy diversification. Indeed, with vast supply estimates and a plunge in prices, leaders are quickly re-evaluating long-term en-
WHAT THEY SAY “There is a very real hope that natural gas plays a foundational role in the future of energy for this country, which it needs to. We’re ﬁnally reaching Congress and some of the decision-makers about how important this fuel is for all of us and for a greener environment and as a substitution for foreign oil to make us more domestically secure as a nation. It’s also the only thing that can back up oil and coal. “Natural gas is a wonderful and abundant resource that we discovered in this country and is a fairly new phenomenon over the past few years. It’s got the long-dated reserves domestically that coal has, but the difference is that we can actually grow the deliverability and serve an expanding market capability, which I think other fuel sources will have a tough time doing outside of nuclear.” Jim Hackett, Chairman and CEO, Anadarko Petroleum Corporation
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WHAT THEY SAY
NATURAL-GAS RESOURCES 2.5 quadrillion cubic feet
■ Coal-bed gas
■ Shale and other
■ EIA proved reserves 0
“Our energy future isn’t predetermined, we can and we need to shape it. What we badly need is a roadmap for this transition; we need to take carbon out of the energy mix today and be realistic about how we’re going to do that. Until renewables gain a sizeable share of the power sector and cleaner coal is available through carbon capture and storage, I can see only one way of doing it – by increasing the use of natural gas. Gas is the fuel that offers the greatest potential to provide the largest reductions at the lowest cost – and all that by using technology that’s available today. If we get it right, gas can transform the global energy outlook in the decades to come.” Tony Hayward, CEO, BP
US USE OF GAS (2008) 2
Industrial Electric power
Lease and plant fuel Pipeline fuel
Transportation 0.1% Sources: Potential Gas Committee (Natural Gas Resources); EIA
CARBON DIOXIDE EMISSIONS FROM ELECTRICITY GENERATION (2007)
ELECTRICITY GENERATION (2007)
21.7% Natural gas
15.6% Natural gas
19.5% Nuclear 48.7% Coal
6.0% Hydro 2.5% Other renewables 1.6% Petroleum
NATURAL-GAS PRODUCTION AND CONSUMPTION 25 trillion cubic feet
Consumption Net imports
15 10 5 0 ’06 ’10
ergy decisions. Tampa Electric for example has converted one of its power stations from coal to natural gas, representing a fundamental change in the company’s energy mix. Located near Tampa Bay, the H. L. Culbreath Bayside Power Station has been re-powered with natural gas to reduce nitrogen oxides and sulfur dioxide emissions by approximately 99 percent to date, plus particulate matter emissions by more than 93 percent from 1998 levels. The project integrates seven new combustion turbines and seven heat recovery steam generators and two of the plants’ steam turbines to effectively produce 1800 megawatts of power. Natural gas is even finding support among utilities that embrace renewable energy, with firms building facilities for both solar or wind power alongside natural gas as a way to transition away from fossil fuels entirely. That said, the majority of utilities remain unconvinced by the potential of natural gas, mainly because prices have been so volatile over the years. And while natural gas producers believe they are sitting on the greatest volumes to date, there are also a number of obstacles in getting the commodity to market. One such challenge revolves around infrastructure. “Right here in the Rockies we see this exact problem,” reveals Curtis. “We have a great deal of production and we have a very small population compared to the rest of the country so we have to export our gas by pipeline out of these Rocky Mountain basins – we need more
Polorcus AD.indd 1
GAS STORY_nov09 13/11/2009 16:59 Page 36
Gas concerns Dr Frank Clemente is a Professor at Penn State University where he specializes in research on the socioeconomic aspects of energy policy.
he price of natural gas over the next decade is one of the most important energy questions facing the United States. Our steadily increasing dependence on gas is worrisome – especially since gas supply is projected to decline through 2020. Despite this supply decrease we continue to build out an ever more extensive natural gas infrastructure – verifying Santayana’s warning that: “Those who cannot learn from history are doomed to repeat it.” Our ‘dash to gas’ over the past decade led to higher electricity rates and increased home heating prices and it raised the cost of manufacturing. Why should the next decade be any different? Is this prudent with decreasing gas supply? Almost 90 percent of power plants built since 2000 depend on gas. Eight million gas homes have been built since 2000. Almost 10,000MW of new wind power capacity was built in 2008, but gas is the primary backup when the wind is not producing electricity (75 percent of the time). And over 55,000MW of new gas power plants will be built between 2008-2012 alone. EIA’s analysis of the American Clean Energy and Security Act of 2009 – the Waxman-Markey climate bill – came to this conclusion: “Our results suggest that this legislation would likely increase the use of natural gas for generation over the next decade in all of the scenarios we analyzed.” You don’t have to be a PhD in economics to understand that when supply goes down and demand goes up (or even stays the same), prices are going to increase. And that is exactly what happened the ﬁrst half of this decade when a mere four percent decline in supply led to an almost doubling of wellhead natural gas prices. Imagine what a nine percent drop in supply will do. Of course, we had a hurricane in 2005. But that is exactly the point. Our supply/demand balance for gas is so fragile that a problem in the Gulf, a hot summer in the South or a cold winter in the Midwest will lead to price spikes with dire socioeconomic impacts. In 2005, for example, businesses in Illinois paid 101 percent more for gas than they paid in 2002 – leading Andrew Liveris, Chair of Dow Chemical, to state bluntly: “Some of the best manufacturing jobs in the world are right here in the American chemical industry – and they depend on globally competitive natural gas prices.”
pipelines to be able to do that and transport to the California markets, mid-continent and the Eastern coast.” While continuing pipeline capacities are being put into place it is not an overnight process. And it is not just pipelines that are needed; land access is a key challenge as much of the future supply is underneath federally owned land, which requires a drawn out permitting process. “We have to be stewards of this natural gas endowment,” advises Curtis, “We have to use it wisely. At one extreme, we don’t just want to open up the taps and drill everywhere, but on the other hand we don’t want to restrict drilling to nowhere.” Infrastructure and land access are not the only factors that are causing headaches for natural gas. The administration’s continued lack of recognition for the positive aspects of natural gas has led the industry leaders to fight back. In March, Chesapeake, Noble Energy and Apache Corp were among 28 companies that formed America’s Natural Gas Alliance, a Washington-based group aimed at increasing ‘appreciation’ for natural gas. Its aim is to try and generate more natural gas demand and it is currently looking to re-ed-
“They are doing themselves a disservice by not making natural gas a much bigger part of their energy platform” Phil Flynn, PFGBest ucate the Senate in relation to the Waxman-Markey plan and improve the sector’s outlook. While the legislation was approved by the House of Representatives in June the Senate has yet to vote on it, and the alliance are hoping for a positive result. Flynn also believes that it is of vital importance that the government continue to look to the future and understand the significant impact of the economic downturn on energy demand. “This country’s in a very delicate situation: we’re trying to have an economic comeback and bad energy legislation could prolong our economic slowdown for years to come and could put a lot of people out of work. For every green job created, five jobs in the private sector could be lost if they’re not very careful in how they write this legislation. So it’s a delicate balance and I think natural gas has to be a major part of any energy policy. If it isn’t, there’s not going to be a good policy in place,” says Flynn. There is no doubt that times are tough in the natural gas business. With technology costs rising in relation to reaching unconventional sources plus the long lasting effects of the recession it looks pretty bleak. Only one thing is for certain – natural gas faces a highly unpredictable future. If the challenges can be overcome there is a real chance that natural gas has the potential to change energy policy in the US. That said, a change in energy policy needs happen now and only more money, more drilling and more time will tell if natural gas will revolutionize the industry, provide a much needed boost to the industry and prove its potential. n
Centek AD.indd 1
George Kirkland ed:nov09
George Kirkland, Executive Vice President for Upstream and Gas at Chevron, reveals the three vital drivers that are redeďŹ ning the world's energy equation for the 21st century.
George Kirkland ed:nov09
et’s imagine a natural gas project that could, over its lifetime, produce enough energy to power a city of one million people for the next 800 years – a project of such scale, scope, ingenuity and commitment that it would expand the possibilities of what a natural gas project could be in the 21st century. Not so long ago, we could have only imagined a project of this breadth and promise. Today, because of growth in market demand, particularly in Asia, it is a reality. The fact is natural gas has come of age. What was once a second prize to oil is now a premium commodity. Today, natural gas is almost one-quarter of the world’s energy mix. And the importance of this abundant, clean-burning hydrocarbon to the world’s future energy needs will only continue to grow. Chevron believes in natural gas. We have 150 trillion cubic feet of un-risked gas resources located throughout the world. Our holdings in the Asia-Pacific region are the largest in our competitor group. Natural gas will clearly have a larger role in our future. And today, our industry is gripped by tough, complex challenges: sustaining long-term growth and the supply of new gas to market, while managing investments in the short-term. In recent years, the global gas business has achieved strong momentum. We've seen development of a global gas infrastructure through LNG, gas-toliquids and long-distance pipeline projects. Now we are confronted by a recession that has weakened many of the world's economies. This is particularly evident in the United States where gas prices are depressed. On an OEG basis, the Henry Hub gas index is trading at approximately 25 percent of West Texas Intermediate oil prices, a drop of almost one-half in one year. The recession has adversely impacted financing and cash flows and project development costs remain high. We’re not just dealing with the effects of a recession, however. We’re confronted by other, ongoing challenges, such as geopolitics and the reality of making final investment decisions while in a high-cost environment.
George Kirkland ed:nov09
At the same time, the world has a lot of natural gas. Market demand from questration and the energy efficiency of the project’s equipment, Gorgon will regions like the Asia-Pacific is strong. And this cleanest-burning of all hydrobe one of the most carbon-efficient LNG projects in the world. carbons is increasingly regarded as a bridge to a lower-carbon future. Our job is Gorgon is a massive investment – the largest development in Chevron’s to balance these challenges and opportunities to benefit our companies, our parthistory – but it is not all we are doing in LNG in Australia. Next in line is our ners, our customers and suppliers, and the countries that have the resources. Wheatstone LNG Project, which includes natural gas from the Wheatstone I am confident in Chevron’s ability to continue investing for the and Iago fields offshore northwest Australia. Wheatstone will include long-term. In September, Chevron and our partners, two LNG processing trains, each with a total capacity of 4.3 milExxonMobil and Shell, announced a final investment decilion tons per year, and a domestic gas plant supplied by our The Gorgon sion on the Gorgon Project in Australia. The first phase of equity gas from the Wheatstone and Iago fields. We reProject has enough Gorgon will be an investment of AUS$43 billion, makcently awarded a front-end engineering and design conenergy to power ing it one of the world's largest foundation LNG develtract for the first phase of this project. It will anchor and a city of opments with initially three trains totaling 15 million facilitate the development of not only the Wheatstone tons of LNG per annum. Gorgon is the project with field, but other nearby gas fields as well. people for 800 years enough energy to power a city of one million people for I mention both Gorgon and Wheatstone because the next 800 years. It’s a legacy project, a long-term growth they reaffirm a point that is important to all of us in the engine with prime access to the entire Asia-Pacific market. industry. And that point is this: going forward, natural gas Chevron has signed sales and purchase agreements with will become a larger part of the world’s energy equation. The Tokyo Gas, Osaka Gas and GS Caltex, and heads of agreements with International Energy Agency forecasts that global demand for natural Chubu Electric and Korea Gas Corporation. gas will increase roughly 50 percent by 2030. To satisfy that demand, the Gorgon also will include the largest, most advanced carbon injection and IEA estimates that a cumulative investment of $5.5 trillion dollars, or $227 sequestration project in the world. Approximately 120 million tons of CO2 billion dollars per year, will be required over the next 20 years to satisfy will be sequestered over the life of the asset. Through the injection and selong-term global demand for natural gas.
George Kirkland ed:nov09
I believe there are three fundamental things that must happen to meet this demand growth. First, development costs must continue to come down. Second, our industry must continue to invest for the long-term. And third, we must focus relentlessly on superior project execution. These three drivers are always important, but now they are critically important. All of us recognize that rising costs in recent years have put pressure on the economic returns of our investments. There are modest signs that cost pressures are beginning to ease. So far in 2009, the CERA upstream capital cost index has shown only a 12 percent reduction in costs. For projects to be developed economically, there needs to be further cost reductions. The second fundamental area we need to focus on is investing for the long-term, to ensure there’s sufficient energy available to grow the world's economies. Investing for the long-term is a requirement for our industry. Without continued investment, natural gas will simply not be available to meet demand and drive economic growth. Investing in long-term projects must always be guided by transparency, predictability and discipline. Stable, predictable and reasonable terms are needed to ensure that investment continues to flow. Taxes, fiscal regimes, sound regulatory structures and sanctity of contacts must be in place and fit together.
Gorgon Project The Gorgon Project, operated by the Australian subsidiary of Chevron (50 percent) in joint venture with Australian subsidiaries of ExxonMobil (25 percent) and Shell (25 percent), is currently estimated to cost AUS$43 billion (US$37 billion) for the first phase of development. First gas is planned for 2014. The Greater Gorgon Area’s projected natural gas resources are equivalent to 6.7 billion barrels of oil. The project’s scope includes a three-train, 15 million-metric-tonper-year liqueﬁed natural gas (LNG) facility and a domestic gas plant. The project underwent a rigorous and thorough environmental assessment that culminated with some of the most stringent conditions imposed on a major project anywhere in the world. The project is expected to have the world’s largest carbon dioxide injection system and be a global leader in underground carbon dioxide injection technology.
Left: Elevated natural gas pipelines Below: worker watches as a giant drill casement approaches at sunset. Despite millions of dollars in damage from Hurricane Katrina, Chevron is spending billions drilling new oil wells in the Gulf of Mexico. The drilling ship called the Deep Sea Discovery is Chevron’s newest project, 140 miles off the coast of Louisiana
George Kirkland ed:nov09
Angola LNG Angola’s ﬁrst liqueﬁed natural gas plant should be ready to start exporting gas in the ﬁrst quarter of 2012, despite higher-than-expected costs for the plant. “The project is on track,” Daniel Rocha, director of Angola LNG, told Reuters. Chevron, Total, BP and Eni have agreed to build the terminal in Angola with state oil company Sonangol. Rocha said the cost of building the plant – estimated at between $8 billion and $10 billion – was higher than initially expected because the facility was being built in a remote area of Angola and that construction began at a time of high oil prices. He declined to provide a ﬁnal ﬁgure for the plant but said the recent downturn in the oil and gas sector could help bring down the overall cost of the project. “We’re talking about the biggest project of this kind in Angola and maybe even in Africa,” he said. “We began building the plant when the industry was booming but now we are trying to take advantage of the downturn to bring down costs.” The LNG plant was initially expected to cost $4 billion. State-owned Jornal de Angola recently said the cost of the plant had doubled to $8 billion while Chevron put a preliminary $10 billion price tag on the project. Located near the coastal town of Soyo in northern Angola, the plant will produce around 5.2 million tonnes per year of LNG and related products to export to the US, Europe and Asia, said Rocha.
The Angola LNG project is a good example of this. Angola LNG, with Sonangol and Chevron as the largest shareholders, is currently under construction, and it is one of the biggest projects under way in Africa. It’s a multibillion dollar development with multiple joint ventures supplying gas to a liquefaction facility with five partners. Angola LNG will monetize associated gas from a series of both deepwater and shallow water blocks located offshore Angola. It will produce about 5.2 million metric tons per year of LNG, or approximately 750 million cubic feet of gas per day for export to the US, Europe and Asia. We anticipate it will start up in 2012. When it does, Angola LNG will facilitate offshore oil development, provide domestic supply, reduce flaring and create a new industry
for Angola. Angola LNG is an excellent project, an excellent investment, and an excellent example of why our industry needs to stay the course. The third fundamental area we need to focus on is superior project execution. We must efficiently and cost-effectively deliver on projects that fulfill our commitments to host governments and buyers. That means building projects in a safe, reliable, economic and environmentally responsible manner. To be successful, our industry must be proficient at managing large, complex projects with multiple partners in challenging environments. Last year, Chevron brought online nine major oil and gas projects around the world. Three of the largest that we operate – Agbami in Nigeria, the Tengiz Expansion in Kazakhstan and Blind Faith in the US Gulf of Mexico – are complex, multi-billion dollar projects. This year, we will follow up with another seven startups, including three multi-billion dollar Chevron-operated projects: Tahiti in the US Gulf of Mexico, Frade in Brazil, and Tombua-Landana in Angola. Our experience, expertise and track record gives us confidence in our ability to execute Gorgon with excellence.
“I am confident that the importance of natural gas to the world’s energy portfolio will continue to grow. I am confident that the global gas business that we are building will sustain its momentum” Managing costs, investing for the long-term and superior project execution are the three critical drivets and going forward, those who get these fundamentals right will be successful in the natural gas business. There is another important aspect in successful execution of natural gas projects. Our investments create opportunities for local communities. Chevron’s approach to community engagement is strategic. We target key areas such as job creation, healthcare, education and training. All of these contribute to building human capacity and a healthy, growing society. In countries where we have major investments, the first value that we provide, other than a revenue stream, is jobs. Our Angola LNG project, for example, will employ approximately 3500 to 4500 Angolans during the construction phase. And, we have targeted spending over $1 billion in local goods and services for the project. We also make a variety of investments into the social health of the communities where we operate – areas such as education, malaria prevention, HIV/AIDS training, and local economic development. My point is that the investments in the communities where we operate are an important part of the way we do business. The development of energy should benefit everybody who is involved: our shareholders, our employees, customers and suppliers, our partners, and the countries and communities where the resources are found. Finally, I want to state my confidence in the future of natural gas. I am confident that the importance of natural gas to the world’s energy portfolio will continue to grow. I am confident that the global gas business that we are building will sustain its momentum. And I am confident that natural gas will redefine the world’s energy equation in the 21st century.
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America’s independent oil and natural gas producers are responsible for more than 90 percent of US oil and 80 percent of the natural gas wells, and it has been argued that they are the true innovators of the industry. However, the current climate is creating tough challenges for smaller players, reveals Bruce Vincent.
ruce Vincent, Chairman of the Independent Petroleum Association of America (IPAA), believes that misguided energy policy is one of the biggest risks the independent oil and gas industry faces. He says that the US has yet to see a comprehensive energy strategy focused on trying to develop our own resources and become less dependent on foreign sources. And he doesn’t foresee this changing any time soon. “This is really nothing new, but what we see happening today in the current administration is a desire to take away incentives in place in the tax policy arena that both mitigate risk and provide economic return for producers to drill wells in America,” he explains. “They want to create further regulation, particularly in the form of an environmental legislation focused on hydraulic fracturing – used in probably 90 percent of the natural gas wells in America – that would at a minimum slow down, inhibit and push up costs, but could in many places shut production down.” Painting a gloomy forecast for the future of independent oil and gas producers, Vincent believes that the government appears to want to take away a producer’s ability to hedge its future products – the way producers mitigate risk, protect cash flows and help make investment decisions. “On top of that, they want to create climate change legislation that actually favors other types of energy, in particular coal. Natural gas is clearly a big part of the energy future in America. It’s certainly a big part of a clean, environmentally friendly energy future and to not recognize that in the policy doesn’t make any sense.”
In March, President Obama revealed his proposed 10-year budget and virtually every tax incentive and cost recovery mechanism in the tax code will potentially be taken away, explains Vincent, and examples of those include intangible drilling cost deductions. “This is something that has been in the tax code since 1913, when the tax code was first developed – it’s built into the fabric of industry economics. Another good example is percentage depletion and that was actually introduced just a few years later in 1926. If
these are taken away it would have a dramatic impact on both existing production in terms of economics and production, and in the industry’s cash flow and its future investment, all of which would lead to lower domestic supplies and greater dependence on foreign sources.” Vincent also believes that the volatility of price will be big a big threat to the industry, making investment decisions and predicting future cash flows difficult. Independents have always invested 100 percent of their cash flow into the busi-
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have access to America’s resources so that we can develop better supply domestically as opposed to importing it from foreign sources.” And Vincent does not see this changing any time soon. Towards the end of the prior administration, Congress let the restrictions on offshore drilling lapse, which allowed the Department of Interior to begin nominating leases for the industry to bid on, providing an injection of optimism into the industry. “The new Administration has basically shut that process down and delayed it further. I do think it will ultimately change, but it will take some time. If you look at the behavior of the previous administration, you see them delaying access to those previously restricted areas at the beginning of their time in office, too.
“It takes time to develop resources, particularly offshore resources, and if we don’t ever start we’ll never be able to create anything” “The industry of course will continue to pursue other opportunities, but the real impact will be seen on America. It takes time to develop resources, particularly offshore resources, and if we don’t ever start we’ll never be able to create anything. And there have been studies to prove that if you actually get in there and get access to resources, there’s a significant amount of oil that would power American homes for decades. And so if we don’t ever start, the long-term negative consequences will be felt by all Americans, not just the independents or the industry itself.”
Technology ness and have recently been investing 150 percent of their cash flow, but Vincent believes that by taking away the predictability of return on investment there will ultimately be less investment. And less investment means a reduction in supplies and therefore greater dependence on foreign sources, leading to higher prices. Access to resources is another area that Vincent voices his concern over. He says that 85 percent of the coastal areas in the US are off limits to developing America’s resources, and that it
is the only country in the world to limit such a significant portion of resource space to development. “Many countries are actually trying to encourage companies to come in and develop their resources instead of discourage, which seems to be the policy that we have in Washington,” says Vincent. “And there’s a significant amount of what we refer to as the ‘intermountain west of the US’ that’s also off limits. In order to become more energy secure and less dependent on foreign sources, clearly we need to
Despite a tussle over the future direction of the industry, it is certainly moving forward in one sector: technology. By reducing the per barrel cost of producing oil the industry has looked to lower the cost of finding, producing and accessing reserves. Vincent believes that contrary to popular opinion, a down cycle is often when the industry works with their service companies to develop these new technologies. “Better image and target potential reservoirs deep under the oceans or underground are being developed and continue to
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be refined that allow us to drill the wells better, smarter, more efficiently and at less cost. And it’s a combination of those many technologies that ultimately drive down the cost of finding and producing natural gas, delivering a better product at a better price to the marketplace.” Vincent believes that there are a couple of technologies with the potential to unlock natural gas in America. For decades much natural gas has been locked in shale formations, but because the nature of these formations didn’t allow for the gas to flow well out of them, they were not economic to produce. Today, the combination of horizontal drilling, hydraulic fracturing and the ability to conduct several or multistage fracture stimulations with a horizontal wellbore has given the ability to capture this natural gas locked in shale formations in a commercially viable way. Looking at revolutionary technologies, how does Vincent hope to encourage innovation and make changes to drilling? First, he believes that the government should let companies, particularly small independents, get on with their business. “Government interference slows the innovation process down, and I can appreciate people’s concern over regulation and the like, but the fact is that the oil and gas industry is an incredibly entrepreneurial group of people that has created many technological advances,” explains Vincent. “They’ve been able to access reserves and resources in America that no-one ever thought possible. It’s astonishing to me today – and I know we’ve been doing it for a while – that we can drill in 10,000 feet of water and then we can drill another 25,000 feet below the subsurface of the ocean and find large oil fields, develop and produce them. Technologically, if you just think about that, that’s pretty remarkable and we’ve done that because we’re a very innovative bunch
and the best way to continue that is to let government let business do what it’s good at.” And with anywhere from 30-70 percent of oil and 10-20 percent of natural gas not being recovered in field development, technology has a role to play in improving recovery rates, with shale gas a prime example. The industry has known about the resource for decades, but it is only now that shale gas is being developed. “Shale has always been thought of as a source rock, meaning that it provided hydrocarbons that actually migrated into reservoirs that you could produce out of, but it’s the technology of
‘Energy In Depth’ For months, IPAA's government relations and communications teams have been working around-the-clock on a new industry-wide campaign known as ‘Energy In Depth’ (www.energyindepth.org) to combat new environmental regulations, especially with regard to hydraulic fracturing. The ‘Energy In Depth’ project results from the realization that American production opponents are spending millions of dollars throughout the country. This project is a major initiative to respond to those attacks. It reaches into the new communications tools that are becoming the pathway of choice in national political campaigns. It connects IPAA at the federal level to state associations and member companies across the nation.
the hydraulic fracturing, horizontal drilling and multistage fracking coming together that have allowed the industry to tap this resource base. While it was previously an unusable resource base, it may now be the key ingredient to America’s energy future over the next 100 years.” Continuing to look to the future, Vincent sees energy as a key indicator of economic wellbeing: the better the economy’s doing, the more energy is used. “Having the global economic recovery continue and progress is important to the future of America’s oil and gas producers,” he says. “On a big picture basis, the other thing that I believe impacts the industry is living in as stable a world as we can live. We always worry about significant political events that create problems with economic activity and the way we run our lives and certainly energy is a big part of that because so much of the world’s oil supply is in the Middle East, which is where you find a lot of potential instability.” Obama’s energy policy is yet to be unveiled in full, but there is no doubt that Vincent believes it will have one of the biggest impacts yet on the future of the oil and natural gas industry, particularly in regard to the independent producers. n
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WHY OIL AND GAS IS AN ECONOMIC ENGINE The oil and natural gas industry supports more than nine million US jobs while contributing to the national economy as both an employer and purchaser of US goods and services, according to a new study by PricewaterhouseCoopers (PwC).
he report, commissioned by the American Petroleum Institute, said the oil and gas industry currently supplies more than 60 percent of the nation’s total energy demands and more than 99 percent of the fuel used by US motorists in their cars and trucks, while 900 of the next 1000 US electric power plants are projected to use natural gas. The industry is one of the largest employers in the country, with millions of people in exploring, producing, processing, transporting and marketing oil and natural gas. “Millions of jobs in other industries are supported by the oil and natural gas industry’s purchases of intermediate inputs and capital goods from other US producers,” the report said. “These businesses include equipment suppliers, construction services, management services, food services, and many other types of support services. These supporting businesses, in turn, purchase goods and services, spurring additional economic activities. Further, employees and business owners make personal purchases out of the additional income that is generated by this process, sending more new demands rippling through the economy.”
At the national level, the study found each job in the oil and gas industry supported more than three jobs elsewhere in the US economy in 2007, the most recent year for which data are available. In terms of operational impact, it directly and indirectly contributed over 7.8 million full-time and part-time jobs to the national economy. Further, the industry’s capital investment contributed an additional 1.4 million jobs to the national economy. Combining both operational and capital investment impacts, the oil and natural gas industry’s total employment contribution to the national economy amounted to 9.2 million full-time and part-time jobs in 2007, accounting for 5.2 percent of total US employment. Associated labor income, including proprietors’ income, was estimated at $558 billion, or 6.3 percent of total national labor income. The industry’s total value-added contribution to the national economy topped $1 trillion, accounting for 7.5 percent of US gross domestic product for 2007. “The economic impact of the oil and natural gas industry reaches all 50 states and the District of Columbia,” PwC reported. The total number of jobs
directly or indirectly attributable to the industry’s operations ranged from a low of 12,815 (in the District of Columbia) to more than 1.7 million (in Texas). The top 15 states, in terms of the total number of jobs directly or indirectly attributable to the oil and natural gas industry’s operations in 2007 were Texas, California, Oklahoma, Louisiana, New York, Pennsylvania, Florida, Illinois, Ohio, Colorado, Michigan, Georgia, North Carolina, Virginia and New Jersey.” PwC said the industry accounted for four percent or more of total employment in another group of 15 states, including Wyoming (18.8 percent), Oklahoma (16.3 percent), Louisiana (13.4 percent) and Texas (13.1 percent); Alaska, New Mexico, West Virginia, Kansas, Colorado, North Dakota, Mississippi, Montana, Utah, Arkansas and Nebraska are the others. As Congress debates greater domestic oil and gas access and higher energy taxes, legislators should keep in mind the oil and gas industry’s importance to the US economy and in states well beyond traditional oil and gas-producing regions, said API President Jack Gerard. “Congress should remember that some of the energy tax and climate change legislation it has proposed would have a devastating impact on the industry and many of the 9.2 million American jobs it supports, as well as on the American economy and energy security,” he said. “The people in the US oil and natural gas industry are the backbone of our economy,” Gerard said. “They provide most of the nation’s energy, spurring growth and job creation across America. At a time of economic recession, the oil and natural gas industry is actually responsible for creating more jobs and generating more revenue to the economy. Irresponsible proposals to pile new taxes on the industry threaten these jobs and the nation’s ability to produce more of its own energy. We should not put any jobs at risk, but especially not when millions of Americans already are unemployed and economic recovery remains uncertain.”
Deals in North America The fall in North America O&G deal volume from its 2006 $164.7 billion high accelerated sharply in 2008. Total deal value fell 43 percent, from $129.7 billion in 2007 to $73.6 billion in 2008. Deal numbers were down by eight percent but it was a halving of the number of big transactions that really hit total value. There were just 15 deals in 2008 worth $1 billion or above, for example, compared to 31 in 2007. This alone accounted for $49.4 billion of the total $56 billion year-on-year fall in total deal value. Upstream activity experienced the smallest fall of all the sectors but still saw total value down by 27 percent. Between them, two companies – Chesapeake and XTO – accounted for $22.4 billion of the total $59.6 billion upstream deal value. The difference was that, while XTO was on the acquisition trail with nine purchases in 2008 totaling $10.6 billion, Chesapeake was a seller as it responded to a closing of the debt markets with a series of eight cash-raising deals that yielded a total of $11.8 billion. As well as the sales to StatoilHydro and Plains Exploration, two further $1 billion plus deals saw BP acquire tight gas assets from Chesapeake totaling $3.65 billion. The contrasting deal context was matched by their timing. Six of the nine XTO purchases were made in the ﬁrst half of the year as the oil price remained buoyant while all but two of Chesapeake’s sales came in the second half of the year as the ﬁnancial market deterioration intensiﬁed and commodity prices collapsed. The largest XTO transaction was the $4.2 billion acquisition of Hunt Petroleum and associated entities. The deal gives XTO an estimated 1.05 trillion cubic feet of gas equivalent in East Texas, Louisiana, the Gulf Coast and non-operating assets in the North Sea. Hunt is an 80year private company founded by legendary wildcatter, the late Haroldson Lafayette Hunt. The Hunt sale was the second largest North
American deal after Royal Dutch Shell’s $5.8 billion Duvernay purchase. It was a sign of straitened debt market conditions that these were the only two corporate deals among the ﬁve largest North American O&G deals. The remaining three transactions were the Chesapeake asset sales and, indeed, 2008 was a year in which asset deals were much more common. Moves by foreign buyers for North American assets continued to catch the eye in 2008 with the Shell, BP and StatoilHydro purchases accounting for three of the ﬁve biggest North American deals. Deals outside of the upstream sector were down very sharply, with total value shrinking by more than a half of its 2007 level in the case of the downstream sector. The fall was even greater in the midstream and service sectors – total deal value in both sectors plummeted to around a quarter of 2007 totals. One of the most striking contrasts with the preceding years was the relative absence of service sector plays. The services sector had attracted investors as demand for services grew but anticipation of reduced demand has dampened sentiment. Oilﬁeld services deals had leapt from $5.9 billion in 2006 to $22.9 billion in 2007 with four such transactions among the 12 largest 2007 North American deals. Only one service sector deal – Precision Drilling Trust’s $1.6 billion acquisition of drilling rig assets from Grey Wolf – featured so high in 2008.
From Texas to Louisiana, the Gulf Coast region is home to the nation’s highest concentration of reﬁning and supply operations, a host of terminals, the origination points of the nation’s largest pipeline systems and extensive fuels-marketing networks. It has also been landfall for some of history’s most destructive hurricanes. By Shelley Moore Christiansen and Richard Cunningham 50 www.ngoilgas.com
oon after Hurricane Gustav made a surprise inland assault on Baton Rouge, Louisiana, last September, Tom Moeller, ExxonMobil Director of Refining for the Americas, arrived in the city to survey the storm damage that had shut down operations at the company’s second-largest US refinery. En route from the airport, he observed long lines of anxious motorists at the few service stations that had the fuel, electrical power and staffing to remain open for business. “Scenes like that illustrate the role our industry plays in supporting the everyday infrastructure of society,” says Moeller. “It’s why we needed to get back up and running quickly.” When hurricanes hit, restoring normal operations is a guiding principle throughout ExxonMobil’s downstream business – from refining and supply, to pipeline and marine transportation, to fuels and lubes marketing. As storms approach, ExxonMobil’s goal is to keep operations in the region going wherever it safely can. Where business is interrupted, company teams work quickly to restore product supply – or develop alternate, interim solutions. And they do it on a foundation of rigorous planning and preparation that has repeatedly kept ExxonMobil a step ahead of the industry in times of crisis.
Lessons learned Taking lessons learned from such storms as Gustav and Ike in 2008 and Katrina and Rita in 2005, the company’s hurricane-response teams routinely conduct training and other emergency-response scenarios. They fine-tune day-to-day storm watch action plans and update employee tracking data to make sure workers are safe if they have to evacuate. Team members conduct simulation drills with internal and external partners, and plan where extra fuel might come from. And they provide information, guidance and support to industry associations, states, counties and municipalities regarding fuel-specification and other waivers that are considered when a storm is on its way. “Our ability to supply fuel to a particular marketplace where and when it’s needed improves dramatically if we can temporarily shift from delivering, for example, 12 formulations to delivering five or six,” says Erskine Frison, Products Optimization Manager for the Americas.
“One of the core strengths that sets ExxonMobil apart from other companies during critical periods is the way we’re organized,” adds Greg Cunningham, US Supply Operations Manager. “We work with many groups within our company – production, transportation, refining, supply, marketing – on a daily basis within our integrated business team process. During a hurricane, we just take that process and accelerate it.”
Hurricane watch ExxonMobil operates four Gulf Coast-area refineries – in Baytown and Beaumont, Texas, and in Baton Rouge and Chalmette, Louisiana – accounting for nearly a quarter of the region’s industrywide refining capacity of about eight million barrels of crude oil a day. When a major hurricane is still seven days away from landfall, it is far too soon to predict which, if any, ExxonMobil refineries may be affected. Nevertheless, preemptive inspections and preparations occur to assure that facilities are well-prepared for severe weather conditions. As the landfall clock winds down, the hurricane’s path may still be uncertain. “But once it hits, you can’t hide,” says Moeller. So, with about four days to go, the coastal refineries (Baytown, Beaumont and Chalmette) proceed either to shut down or to shift into what’s called ‘safe park’, a reducedoutput state that helps conserve crude oil and other key supplies that may soon be interrupted by the storm.
“Our biggest challenge is to keep fuel moving, not only to customers in the hurricane zones but to all the others who depend on refined products from the Gulf Coast” While refineries close to the coast are more exposed to the effects of severe weather, Baton Rouge, a hundred miles inland, is more protected and more likely to maintain operations. After a storm, Baton Rouge’s continued output can become vital to the industry as a whole, providing emergency supplies to downstream pipelines and terminals to keep fuel moving to regions far away from impacted areas.
Helping communities and businesses “For hurricanes, we expand our philosophy of keeping our own system adequately supplied to one of helping the overall industry get back to normal,” says Cunningham. ExxonMobil refineries also help their surrounding communities during power outages, providing electricity from their cogeneration plants for use by area households and businesses. The company’s supply organization identifies and buys additional volumes of fuel before it’s clear that the company needs them to make up for the shortfalls that sometimes occur. Those sources might be from locations several days away, like New York. They may even be cargoes at sea – during Hurricanes Gustav and Ike the company diverted 14 waterborne cargoes from other geographic markets, including Europe and Asia, to fill gaps in supply while the Texas and Louisiana refineries were coming back up. “From the downstream perspective, our biggest challenge is to keep fuel moving, not only to customers in the hurricane zones but to all the others who depend on refined products from the Gulf Coast,” says Mark DiZio, Manager of Global Products Supply and Trading. “People in places like North Carolina sometimes wonder, ‘If the hurricane struck Texas, why are we without gaso-
Much more than a plan Last year’s hurricanes in the Gulf of Mexico left scars on the coast and affected chemical markets worldwide, but lessons learned from earlier storms helped ExxonMobil employees respond much faster this time around. Call it a worst-case scenario. A major hurricane ﬁlls the Gulf of Mexico and lands on the most heavily industrialized stretch of the upper Texas coast. ExxonMobil’s Houston offices lose power, and several of the company’s manufacturing sites are damaged. Specialty products – some supporting global supply networks – are suddenly unavailable to customers in the Americas, Europe and Asia. Although it’s the kind of emergency that ExxonMobil employees plan and practice for each year, only similar experiences following the violent Gulf storms of 2005 could fully prepare them for the hurricanes of 2008. “We prepare for this, but it was difficult to anticipate the extent of the damage caused by Hurricane Ike,” says Will Cirioli, ExxonMobil Chemical Company Regional Director, Americas, who also heads the company’s Emergency Support Group (ESG). “One enhancement we made to our emergency-response plan after Hurricanes Katrina and Rita in 2005 was to add a regional response team that can quickly relocate our headquarters operations from Houston to Dallas. Hurricane Ike was the ﬁrst time we had to put that plan in motion.”
A measured response The goal of ExxonMobil’s hurricane-response plan is to secure facilities, protect the public, make sure employees are safe and continue serving customers. The response is measured, following plans that are made well in advance. “This is not a situation that you make up as you go,” Cirioli explains. “We make our decisions long before there’s a threat. When hurricanes do threaten, our response is pre-programmed, based on a series of triggers that are dictated by the storm.” ExxonMobil operates many oil and gas facilities, four large reﬁneries, two lube-oil blending plants and
nine major chemical manufacturing sites along the coast from Texas to Florida. Some facilities can be shut down in as little as 12 hours, but others take two or three days, so the moment a tropical storm or hurricane threatens the Gulf of Mexico, the ESG begins communicating with all the sites and monitoring the weather several times a day. By Tuesday, September 9, there was enough certainty in the forecast that Cirioli moved Chemical’s ESG to Dallas. Other Houston-based ExxonMobil companies did the same, joining forces with ExxonMobil’s Regional Response Team. As Ike grew in size and continued toward the Texas-Louisiana coast, it triggered the next stages of the emergency response plan. Generators, food, water, radios and all the other equipment needed during recovery were pre-positioned so they could be trucked in quickly once the storm passed. On Wednesday, plants started shutting down. By noon Friday, the ones nearest Houston were bracing for the worst.
Landfall Early Saturday morning, the center of Ike surged through Galveston Bay and up the Houston Ship Channel. By dawn, more than 90 percent of the region was without power. Historic Galveston and communities all along the coast sustained widespread damage. The Beaumont Chemical Plant, on what’s called the ‘wet side’ of the storm, was impacted with more than 11 feet of storm surge. “When people saw the damage here, they thought we would be down for years,” says Dick Townsend, Beaumont Chemical Plant Manager. “By Saturday afternoon, we had a small group of workers inside, making sure there were no leaks or spills. Damage assessment crews moved in the following day.” Almost every part of the plant was damaged, and anything electrical that was lower than 10 feet from the ground was destroyed. “We had to replace approximately 5000 instruments, 2000 valves, 800 pumps, 700 motors, 650 junction boxes, 500 online analyzers, 45 air conditioners and 25 switchgear buildings,” Townsend says. “We removed 13 million pounds of debris and used more
Ominous clouds portending Hurricane Ike’s wrath loom over a Houston-area reﬁnery. The storm actually tracked up the ship channel where many reﬁneries are located.
than 300 generators for temporary power while we were doing all the work.”
Business continuity “The Beaumont Chemical Plant is a critical supplier of polyalpha oleﬁns,” says John Lyon, Synthetics Vice President. “PAOs are the basestock that our customers use to blend high-quality lubricants for heavy machinery, such as the gearboxes of the giant wind turbines used to generate electricity. The plant also produces synthetic basestock used in Mobil 1.” A nonstop effort by the various emergency groups and regional response members in Dallas managed the recovery, held supply networks together and advised global customers on what to expect. The companies that blend and market synthetic lubricants routinely keep some amount of basestock in reserve, but would they have enough to last until the Beaumont plant was back on stream? “Given the inventory levels of some of our lubes manufacturing customers,” Lyon says, “we began allocating our own inventory and working with them to develop options to maintain supplies to their customers.” As many as 2000 people worked in shifts around the clock to repair the specialties units at the Beaumont Chemical Plant. “The storm hit in mid-September,” Lyon recalls, “and by early December both the synthetics and the catalyst units at the chemical plant were back on line. We began
Photo by Robert Seale
Members of the company’s supply response team conduct drills before hurricane season to continuously improve the organization’s effectiveness when a storm hits. Seated in foreground (left to right) are Andre Pennington, Donna Scanlon and Ryan House. Adel Abunasser (left) and Greg Cunningham are pictured at rear discussing the exercise scenario. increasing allocations, and by mid-January, we were back to 100 percent.”
Efﬁcient manufacturing Once the synthetics and catalyst units were running again, they performed extremely reliably, and that helped increase inventories faster than anyone expected. “In most cases, we replaced damaged equipment with newer and more efﬁcient technology,” Townsend says. “Our goal was to come back strong, and we did. At least in terms of the electrical system, we have a brand new plant.”
Photo by Robert Seale
Coordination team ensures critical business continues Well before Hurricane Ike made landfall, ExxonMobil activated its Regional Response Coordination Team (RRCT) to monitor the storm and take the necessary steps to ensure business continuity, ultimately deploying more than 400 essential personnel to the company’s Pegasus Place facility in Dallas. The purpose of the RRCT, which consists of representatives from all business and service lines – including information technology, facilities management, procurement, safety, health and environment, security, human resources and other support groups – is to provide cross-functional coordination during the recovery efforts and to assist in operating ExxonMobil’s businesses as smoothly as possible while the affected infrastructure is returning to normal. For example, the company’s Global Real Estate and Facilities unit coordinated the inspection of more than 9000 Houston-area ofﬁces and workstations within ﬁve days of landfall, assessing damage and initiating repairs, and making
John Palaszczuk leads a hurricane preparation drill at the Fairfax, Virginia, headquarters of ExxonMobil’s Reﬁning, Supply, Fuels Marketing and Lubricants/Specialties organizations.
line?’” adds John Palaszczuk, Manager of US Product Trading. “The answer is customer allocations were required to manage supplies. Communication was key often related to the length and complexity of the supply chain, variations in throughout this process. We were in regular contact with our customers, providproduct specifications and industry infrastructure.” ing them with updates on our recovery plans.” Minimizing those disruptions on a local, regional or national level is a top priority for ExxonMobil and its affiliates. For example, the company’s marine afMarketing’s timely response filiates play a vital role in maintaining the critical flow of energy by safely and effiExxonMobil has 81 company-owned stores in the Houston area and 275 ciently moving or redirecting important cargoes to affected markets to help distributor locations, which are Exxon or Mobil-branded stations owned and restore the flow of crude oil, feedstocks, refined products and chemicals. operated by others. All were closed as a result of Ike. Few were damaged ExxonMobil Pipeline Company (EMPCo) also plays a critical in the storm but most needed emergency power to reopen. “We infrastructure role to minimize the impact of hurricanes on keep 100 large emergency generators staged in three cities crude and refined products deliveries. Securing and coordiwithin 200 miles of the Gulf Coast,” says Mike Gore, retail nating the placement of portable generators at key pipeline store manager of one such company-owned location. and terminal facilities is but one example of EMPCo’s ef“The generators are big enough to run all aspects of a reExxonMobil forts to restore power and resume operations quickly, safetail site. Since all of our stores are designed to ‘plug-andcompany-owned ly and flawlessly. play,’ we deliver the generator, plug it in and run the site stores in the as if it were on grid power.” Houston area The generators are loaded on flatbed trucks and ready Lubricants’ customer focus to roll well before a hurricane makes landfall. A generator can Similarly, the lube-oil blend plants on the Gulf Coast readbe powering any company-owned store within 24 hours. And after ied themselves for the hurricanes, idling operations, moving prodIke, ExxonMobil was able to offer 20 of its extra generators to distribuuct inventories into the network and staging response teams in the area. tor locations until power from the grid was restored. Within days of each hurricane strike, delivery operations were restored, and the “Before the storm, we made sure that our key stores on evacuation routes plants were operational, but raw material supplies were critically impacted. had plenty of fuel and stayed open as long as possible,” Gore says. “After the ExxonMobil’s Lubricants & Petroleum Specialties Company relies on ExxonMobil hurricane passed, we reopened those same stores quickly so that people could refineries for basestocks and company chemical plants for much of its supply of get back into affected areas. We had limited products, but we focused on the polyalpha olefins used in the blending of high-quality lubes and other products. things people needed most: fuel, water, batteries and ice. And our retail em“We built up significant product inventory in preparation for the hurricane,” ployees were crucial to this effort, going above and beyond what was expectsays Lynne Lachenmyer, Operations Vice President of Lubricants and Specialties. ed during the evacuation and recovery periods.” “Despite these efforts, the storm’s impact was significant. We took quick mitigaEach ExxonMobil store reopened only if members of Gore’s team were tion steps to manage the disruption of our base-oil supply, ensuring supply to sincertain they had what they call the three ‘Ps’ in place: People able to safely gle-sourced customers and those providing emergency response. Unfortunately,
sure facilities were safe for staff to return to work. Information Technology assigned personnel to the Houston datacenter who worked in shifts around the clock during and after the storm to ensure ExxonMobil’s critical processes were not interrupted. Facilities and IT also collaborated to provide close to 500 alternative work locations for employees in the early recovery phase. The company’s procurement group placed close to 1000 purchase orders to support the immediate recovery process, from portable generators to more than 10,000 bottles of water for employees, while utility and city services were unavailable. “Communication is key,” says Andreas Goldschmid, of the RRCT leadership team. “To ensure business continuity, we coordinate not only with every ExxonMobil company, but with the weather service, government and emergency-response officials, employees and contractors to make sure we understand and manage the cross-functional needs of the corporation while getting activities safely back to normal.”
After Hurricane Ike, ExxonMobil was able to open its Houston retail stores days ahead of most other suppliers, and extra drivers and trucks were brought to the city to keep deliveries moving to customers.
come back to work; Product to keep the location stocked with fuel; and Power supplied either by a generator or by the utility company.
More trucks and drivers After Hurricane Ike, ExxonMobil opened stores in Houston days ahead of most other suppliers, so additional fuel trucks were brought in to meet the demand. “Our base operation in Houston is eight trucks with 25 drivers,” says June Harper, North America Customer Service Manager. “To respond to Ike, we increased that to 14 trucks and 43 drivers. We brought in trucks from nearby cities and flew the drivers to Texas from across the country.” Normally, one truckload of gasoline – about 9000 gallons – lasts two or three days. Larger stores might take two truckloads a day, but when there are cars waiting in line, a load lasts barely four hours. For safety, extra drivers were used to make sure the trucks could keep running around the clock and that the drivers would get enough rest between shifts. In the aftermath of Gustav and Ike, the safety record across the entire retail organization was outstanding. Even with all of the extra drivers and more than 700 workers helping to reopen stores, there was not a single accident.
Focused response to hurricane fury Although hurricane landfall, severity and impact are unpredictable, the ExxonMobil response is second to none. The focus is on taking care of the people, facilities, customers and communities in which it operates. “We plan, prepare and have strong processes in place across the downstream to deal with hurricanes,” notes Denny Houston, who leads the downstream hurricane response organization. “We quickly and fully utilize our flexibility, experience and global collaboration to manage the response. The ExxonMobil response to Gustav and Ike is a great story for our shareholders, employees, customers and communities. We are all proud of what we accomplished as a team.”
Photo by Gary Blockley
This article originally appeared in the Q2 2009 issue of The Lamp, published by ExxonMobil.
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THE BIG INTERVIEW
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In an exclusive interview, Matthias Bichsel, Royal Dutch Shell Executive Committee member and head of one of Shell’s four main businesses – its new Projects & Technology group – discusses how the global oil and gas giant is looking to meet the world’s energy needs in economically, socially and environmentally responsible ways. By Rebecca Goozee
he oil and gas industry faces new challenges everyday: the economic climate; heavier and more complex crudes; increased safety and environmental legislation; erosion of expertise with the exodus of experienced workforce members; and constant pressure for innovative new products to raise the game. But with these challenges comes opportunity, and by drawing on extensive global operating expertise, Shell’s Projects & Technology division is leveraging technology, expertise and experience to do just that. Responsible for delivery of all of Shell’s major projects, technical services and technology capabilities in both upstream and downstream, as well as overseeing safety and environmental performance, Matthias Bichsel is perfectly placed to answer for the industry-giant’s environmental performance and explain where the company is heading in respect of the energy challenge. World energy demand is expected to increase by at least 50 percent by 2030. What role will oil and gas play in helping to meet that demand? And what are the challenges in order for oil and gas to remain a signiﬁcant part of the energy mix? Matthias Bichsel. In light of the world’s growing long-term demand for energy, the world will need to produce energy from all possible sources. Of course, a much higher share of the world’s energy must come from non-hydrocarbon fuels in the future, but Shell’s own scenarios planning work makes it clear that oil and gas will continue to be the world’s primary source of energy for decades to come. Even if a period of economic slowdown moderates demand growth, there is a major gap to meet. And we have to win that new production from increasingly
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difficult resources – smaller accumulations, in more complex geology or harsher conditions, that are more difficult to produce or get to market – all requiring new technologies, better capabilities and greater investment. Getting increased production from mature conventional fields and difficult unconventional fields will both put upward pressure on the energy-intensity of operations. The future of the industry depends on our efforts to both increase efficiency and reduce our environmental footprint. We will need new technologies, skilled people, lean processes and huge financial resources. As long as hydrocarbons are needed to meet the world’s energy needs, we will need to produce, process and distribute oil and gas effectively, efficiently and responsibly, using the skills and capabilities of all industry players. By combining the best of our technologies and skills through value-driven partnerships between national oil companies (NOCs) and international oil companies (IOCs), the oil and gas industry can achieve a higher production peak in the future, and push the peak back by years or decades. How much pressure have the booming economies of China and India, as well as the West’s dependency on oil, placed on E&P companies to locate and extract new reserves? And, how are you going about locating and extracting new reserves at Shell? MB. That is the energy challenge in a nutshell. Meeting accelerating energy demand will require producing increasingly difficult resources everywhere, applying greater understanding and new tools in complex projects. Many of the world’s future resources are located in the Arctic, or offshore in deepwater. And much is in the form of oil shale and oil sands – so-called ‘unconventional’ oil. Shell is delivering major new resources where technology, integration and scale are key factors – from the North Sea to the Gulf of Mexico, from mining oil sands to tight gas drilling, and from standalone oil developments to integrated gas pro-
jects. To make sure we achieve this, Shell technology is extendOrmen Lange was ing the lives of wells and maxideveloped with sea-floor mizing our existing resources through installations at depths of enhanced oil recovery (EOR), sophisbetween 2800 feet and 3600 ticated new digital programs and feet. Following processing clever drilling techniques. onshore, gas is transported In the 1960s, Shell used steam 745 miles through the world’s injection, which has proved to be one longest subsea pipeline to of the most successful ways of boostEasington on the east coast ing oil recovery, in the large and comof Britain. plex Tulare reservoir of the South Belridge field near Bakersfield, California. We continue to pioneer EOR capabilities. A good example is Petroleum Development Oman, where we are working on a number of pilot projects. At Qarn Alam, steam injection assists the gravity drainage system already in place by heating the oil to reduce viscosity. At Marmul, injected chemicals are expected to boost production by around 10 percent. And gas injection is used at Harweel to free trapped oil. Injected oils produce a flooding effect, increasing the pressure in the well, helping to push the hydrocarbons to the surface. Our smart fields expertise provides both knowledge and control by integrating digital information technology with the latest drilling, seismic and reservoir monitoring techniques. Combined with the experience of geologists, engineers and others, smart fields can help increase the total amount of oil recovered from a field by 10 percent and gas recovery by five percent, while also boosting the rate of production. New platform designs and new approaches to planning wells, such as our ‘Drilling the Limit’ methodology, have reduced the time it takes to drill wells, the energy used to drill them and the costs involved. With each advance in well design and drilling, more of these valuable deposits can now be accessed. Shell’s ability to conquer the challenging deepwater environment provides access to oil and gas that lies deeper, is located in dispersed reservoirs or is difficult to produce. Thousands of technologies are developed and used to meet these challenges, from large, complex production systems to smart chemical treatments to help the oil and gas flow. How have drilling and completion techniques evolved over the last few years? And how is technology helping drive advances in this area? MB. In 2005, it would take 60 days to drill a 13,500-foot well in a tight gas field. Now it’s a little over three weeks, with technologies like rotary steerables and under-balanced drilling (UBD). Meanwhile, the wells are producing three to four times more than in 2005, due to technology improvements in areas like fracturing. So a drilling rig in 2009 can put 10 times as many hydrocarbon molecules in the pipeline as it did in 2005. Shell has also found a way to adapt UBD, called pressurized mud-cap drilling. This technique facilitates accurate kick monitoring on wells with total
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loss of mud returns, reduces safety risks and dramatically reduces the fluid volumes required for safe annular feed. This can save $1 million per well by reducing non-productive time. In addition, we’ve developed a riserless mud recovery system that eliminates lost time on wells susceptible to seabed flow at depths up to 5000 feet. That has resulted in average mud and logistics savings of $1 million per well. Shell has also pioneered a surface blow-out preventer system for moored rigs, first used last year offshore Brazil. Not putting the BOP on the seafloor eliminates the need for long and heavy risers. This, in turn, allows us to use older semi-submersible rigs or drill ships that cost much less. Energy projects are becoming increasingly technologically challenging.Take the Sakhalin II project, for example, that centers on some of the largest oil and gas reserves in the world. Can you explain the challenges speciﬁc to this project and how you have dealt with them? MB. Sakhalin II is one of the world’s largest integrated, export-oriented oil and gas projects as well as Russia’s first offshore gas project. When the Sakhalin II project is fully on stream, it will supply around five percent of the world’s liquefied natural gas (LNG) and make a significant contribution to strengthening global energy security. The Sakhalin II Project is developing two oil and gas fields (PiltunAstokhskoye and Lunskoye) offshore northeast Sakhalin for production and export of crude oil and LNG. Sakhalin II has introduced the Russian Federation to a range of innovative technologies, from LNG production to offshore development of hydrocarbon fields. It has brought together Russian and international expertise to overcome formidable challenges and provides a potential model for similar collaboration in unlocking much-needed reserves in Arctic regions. Sakhalin II is the equivalent in size of five world-scale projects, located in a hostile sub-arctic environment, and covers a vast area in a region with almost no existing infrastructure. The float-over installation of the topsides for the PA-B platform set a world record at some 28,000 tonnes. The previous record was held by the Lunskoye-A platform at 22,000 tonnes. There are also environmental, ecological and social sensitivities to be tackled. Two 800-kilometre pipelines, which bring oil and gas from the fields in the north of the island to the ice-free export terminal in the south, traverse mountainous terrain in an earthquake zone and cross more than 1000 watercourses, many of which are ecologically sensitive. In all, the project adopted more than 800 additional environmental, safety and social commitments. As one of the early economic benefits, there are more than 25,000 jobs on the project, 70 percent of them filled by Russian citizens.
we offer it to the benefit of other companies facing the same challenges. Shell has been active in deploying technology across three key areas in order to reduce emissions: improving energy efficiency (such as energy optimization and operationalexcellence) generating energy cleanly (introducing renewable energy sources or switching to less carbon-intensive fuels) and mitigation of emissions (preventing the release of CO2 into the environment by capturing it for sale to industrial users or for underground storage). We assess a client’s energy use and CO2 production and compare its current position with optimum operating practices. Strategies for mitigation are then proposed, which may include energy-efficiency or operational improvement programs, carbon-abatement technologies, fuel-switching options, CO2 sales and carbon allowance trading and offsets. Energy cost savings are typically achieved through the intelligent application of technology and by modify-
Qarn Alam In November 2006, Shell launched Shell Technology Oman, an enhanced oil recovery (EOR) research and development hub that forms an integral part of the Shell Global Exploration and Production Technology organization and works in close partnership with the Oil & Gas Research Center of Sultan Qaboos University and Petroleum Development Oman (PDO). Qarn Alam is one of the three EOR projects currently up and running.
Shell launched an initiative several years ago to improve the energy efﬁciency of its reﬁneries and chemical plants. Can you explain more about this initiative and the impact it has had on improving efﬁciency at Shell? MB. Improvements at our downstream facilities are already delivering CO2 emissions reductions of about one million tons per annum. We have deployed a wide range of techniques for cost-effective carbon and energy management across our operations for a number of years. We identify opportunities for energy-efficiency improvements, changes in feedstock or power generation, catalyst optimization, carbon-capture technologies and CO2 sales. At Shell, we have established an award-winning carbon and energy management consultancy that integrates technology and expertise from across the company. Our expertise is gained in reducing Shell’s own carbon footprint, and
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ing behaviors and processes. Programs can be structured around minimal capital expenditure for rapid payback. Can you explain how the energy efﬁciency program was deployed at the Geismar facility and what impact it had? MB. The Shell Chemicals Geismar facility in Louisiana is a leading producer of ethylene-based industrial chemicals with a variety of end uses, including in the manufacture of detergents, antifreeze, plastics and textiles. The plant has a significant energy consumption; it uses, on average, 17 trillion Btu/yr of natural gas. In common with other Shell assets, Geismar places strong emphasis on environmental performance and continually assesses its energy consumption. In 2006, as part of a global initiative, we carried out an energy efficiency program. The team reviewed energy balances, calculated potential benefits and worked with staff to identify energy-efficiency improvement projects with technical and economic viability for implementation. Ten out of a possible 50 energy conservation projects relating to process equipment or systems were prioritized, including Matthias Bichsel the optimization of turbines, CO2 strippers and cogeneration facilities. After implementing the energy-efficiency projects, Shell Geismar estimated that it potentially avoided an extra $14.7 million in energy costs over the two-year period 2006-2007, and reduced CO2 emissions.
Champion West Located 56 miles off the coast of Brunei in the South China Sea is Shell’s ﬂagship Smart Fields project, Champion West. After laying dormant for almost 30 years, Smart Fields technology and new drilling techniques have turned Champion West into one of the world’s most advanced oil and gas ﬁelds.
What other steps does Shell take to minimize the environmental and social impact of its activities? MB. For Shell, sustainable development means helping meet the world’s growing need for energy in economically, socially and environmentally responsible ways. Through our portfolio and products, we deliver benefits by providing the modern energy that people need to prosper, and help reduce energy’s impacts by offering cleaner products like natural gas, improved biofuels, and gasoline and diesel that help customers drive fuel more efficiently. Our operations look to create lasting social benefits, whether through employing local people or using local contractors and suppliers. We work to reduce environmental and social impacts at our operations in a number of ways: safeguarding the health and safety of our employees and neighbors; reducing disruptions to the community; reducing our impact on biodiversity; and using less energy, water and other resources when producing energy. We have been working hard to reduce the emissions of local pollutants from our operations. Prime examples are nitrous oxide (NOx), sulphur dioxide (SO2) and volatile organic compounds (VOCs). This has involved a wide range of investments to upgrade facilities and install cleaner-burning equipment and SO2-capture technology. Since 1998, we have reduced SO2 emissions from our operations more than 20 percent and NOx emissions by more than 30 percent, even though we are now using much more energy to refine clean-
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What technologies are key to transforming E&P operations at your organization? Are there any technical developments you are particularly excited about? MB. Technology has delivered many positive surprises in the past and will surely do so in the future. New technology will help us achieve a higher production peak for hydrocarbons, push the timing of that peak back by years or decades, and to Shell Global Solutions has acquired Cansolv, a ﬁrm specializing in the deslow down the production decline that will take place later. velopment of emission capture systems. How do you expect this Simple technology breakthroughs have transformed the value acquisition to impact the business? How do you hope to utiof oil and gas resources in recent years. Our smart fields techlize the technology? nology is a prime example. The Champion West field in MB. As global energy demand grows and the availabiliBrunei contains hundreds of small accumulations, with ty of easy oil and gas diminishes, strong gas treating cathin reservoirs. Discovered in 1975, the field lay untapped pabilities will be required when unlocking new for almost 30 years, because we could not identify how resources, such as sour natural gas or clean coal enerto develop it economically. The eventual solution in 2005 has the potential to deliver gy. Cansolv Technologies Inc. develops ‘scrubbing’ was to drill smart wells that snake vertically and horian additional 50-60 billion barrels, twice the known technologies to capture industrial gas emissions. It ofzontally through several accumulations at once, with the reserves of the fers multi-emission technology for the control of sulphur ability to measure and control flow from up to seven sepUnited States dioxide (SO2) and other contaminants and a carbon dioxarate sections. In 2006, Champion West contributed up to ide (CO2) capture process for greenhouse gas reductions. The 50,000 barrels a day to Brunei Shell and we are only at the dawn Cansolv SO2 Scrubbing System is a regenerable amine technoloof the impact of Smart Fields technology. gy for the removal of SO2 from combustion gases and it has been demonTime-lapse seismic, or 4D seismic technology, is another breakthrough. strated in a variety of applications, including oil refineries, chemical plants, utilities A study by CERA estimated that 4D Seismic has the potential to deliver an addiand non-ferrous smelters. tional 50-60 billion barrels, twice the known reserves of the United States. Use of We want to further develop technology that has the potential to clean up con4D seismic in Shell has generated an extra half a billion dollars net income over taminated gases and flue gases, predominantly SO2 solutions in the first instance. the past 10 years in Europe alone. With the addition of Cansolv’s technology to our portfolio, we have enhanced our The application of new technology can significantly shift the global energy capability to treat various compositions for syngas – from coal gasification, from equilibrium by opening up huge unconventional oil and gas resources. A few contaminated natural gas and from refinery streams – and further differentiated years ago, the US National Petroleum Council warned that it would be hard to our technology. Cansolv’s promising capabilities in SO2 capture will also allow us maintain US gas production, and large-scale LNG imports would become necesto further explore post-combustion carbon capture technology and solutions. We sary to meet domestic demand. But advances across the industry could open some must ‘learn by doing’ in order to reduce costs, accelerate technology development 500 trillion cubic feet of untapped unconventional gas resources in North and ultimately make carbon capture and storage (CCS) commercially viable on America, possibly considerably more. That would supply current US consumpthe back of emissions trading schemes. tion for at least two decades. er, lower-sulphur fuel. And we have reduced VOC emissions from our operations by almost 65 percent since 1998. Contributing to sustainable development in this way requires a particular mindset or a different way of thinking about our day-today business. This means balancing our short- and long-term interests, and integrating social and environmental concerns into our decision-making.
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earching for oil and gas deep underground is more and more like our current TV detective shows: sifting through all the clues and data must be painstakingly and carefully considered. And even then it might be the very smallest molecule of evidence that nails the bad guy. So it is with petroleum exploration and development today – sometimes the very smallest molecules are the key to guarantee success.
Micro is the new macro
A new formula for success Daniel C. Hitzman, President of Geo-Microbial Technologies, Inc. (GMT), reveals how 3G has the potential to exploit advanced exploration and production projects for improved results.
Observing visible oil seeps at the surface – like outcrop stains or oil slicks on water – builds huge confidence that hydrocarbons are present in a basin or block area. Historically, parts of many North American basins were first targeted because of these visible surface macroseeps. However, macroseeps reveal only part of the seepage spectrum story and fail to offer strong location clues since they escape along larger fault conduits. But hydrocarbon microseeps of light hydrocarbon gases are being used to more accurately locate oil and gas reservoirs at depth. These microseep gases are invisible to the human eye, but to gas chromatographs and natural microbial cultures they are clearly discernible and are very potent indicators of hidden reservoirs with chimney signatures. Very small and very buoyant molecules of light hydrocarbon gases – methane, ethane, propane, butane and C5+ – naturally escape from oil and gas reservoirs and penetrate permeable reservoir seals and all reservoir seals, even shales and salts, can be penetrated by these tiny treasures. These C1-C5+ gases travel vertically through micro fractures up to the surface atmosphere forming a dynamic and measurable gas chimney signature. There are many seismic data sets that confirm such active gas chimneys. These direct indicator gases can be measured at the surface in both soil and offshore sediment samples.
The 3G approach Expensive geophysical data often determine where a prospect or development well is to be drilled. Such seismic data are imperative for making these structural interpretations. Unfortunately, disappointing dry holes tell us that not all seismic traps contain hydrocarbons. As an industry we still drill an unacceptable – and unnecessary – number of dry holes. We must improve our exploration accuracy and optimize our development programs. The combination and full integration of geology with geophysics and geochemistry – the new 3G
strategy – is leading us to additional discoveries and more accurate wells. Microseepage surveys are very precise tools for reconnaissance observations and for ranking seismic prospects. Detailed microseep signatures have been shown to reflect original reservoir heterogeneities before drilling and also accurately track dynamic reservoir pressures as production matures. Many more off-set and in-fill well locations must be executed in our maturing reservoir assets – drilling where we have already discovered reserves. Microseepage surveys are ideal to identify reservoir compartments and alternate zones for mature asset operators. Using such fast, low cost and efficient microseepage methodologies allows operators to test for and squeeze out more reserves where 3D seismic is not practical nor affordable.
reconnaissance surveys – sampling expansive frontier areas prior to expensive seismic shoots – are also conducted. In mature producing areas, more detailed sampling patterns to locate bypassed reservoir compartments, offset well locations, and help plan waterflood and in-fill drilling projects are completed. The number of samples, sample densities and sampling patterns are specifically matched to the exploration program and expected targets. Reconnaissance surveys are often simply conducted in public-right-of-ways along county or section roads. A two-man crew can complete up to 40 linear miles in one day with this strategy. The same two-man crew can cover at least one-and-a-half square miles with a gridded sampling pattern. Sampling densities generally range from 300 feet (development drilling situations) to 1000 feet (reconnaissance delineations). By design the collection methodology is very robust and extremely efficient. Men on foot with a shovel, small backpack and GPS create very little environmental or surface owner issues.
As structures become more and more scarce, we must look ahead for more subtle stratigraphic traps as future reserve builders. North American basins are very much under explored from a stratigraphic trap point of Little things, big view. Our extensive seismic results database has previously foFor the last 25 years, cused on finding structures Geo-Microbial Technologies and thus leaving stratigraph(GMT) has progressed to beRaised in Oklahoma surrounded ic prospect interpretations come the leading microseepby oil and gas, Daniel C. Hitzman received his geology degree from under-utilized. Just as some age provider in North Carleton College. Since 1985, he explorationists are ‘mining’ America. GMT conducts hyhas supervised all GMT service operations and travels old log library data for bydrocarbon microseep surworldwide completing geochemical exploration surveys. passed pay, old seismic data veys throughout North He has authored 30 papers and sets can be carefully re-examAmerica and the rest of the presentations for the petroleum industry as an AAPG, SEG and ined for stratigraphic potenworld – both on and offSPE member. tial using microseepage shore. GMT collects shallow surveys as lead indicators. soil and sediment samples Such 3G integration will breath new life into mature and then uses two hydrocarbon microseepage deprovinces. Microseepage surveys may turn out to tection methods: the Microbial Oil Survey be the preferred exploration tool for discovering Technique (MOST) and Sorbed Soil Gas (SSG). stratigraphic reservoirs. These microseep tools were first investigated by Phillips Petroleum Company and then further developed by GMT. Working with stripper well operKnowing natural seeps ators, both small and large independents, integrated Microseep surveys are very flexible in their demajors and NOCs, GMT has successfully integratsign and scope, which translates to great efficiency ed microseep data for selecting commercial discovand low cost. Microseep surveys commonly follow eries (>70 percent) and predicting dry holes (>80 seismic programs and rank their numerous strucpercent). A MOST survey tests for specific mitural prospects. These post-seismic surveys help crobes that consume thermogenic microseep gases. focus limited drilling budgets and avoid wasteful These natural microbial signatures are very reliable dry holes. In North American basins large-scale
and reproducible and serve as excellent vertical seep locators. To distinguish whether the reservoir source is oil or gas or condensate, GMT supplements the microbial MOST measurements with Sorbed Soil Gas analyses. These SSG tests are conducted on leftover and preserved MOST samples or from separate and sometimes deeper samples. SSG results are measured in parts per million and the gas ratios are excellent indications of reservoir source. The combination of microbial and sorbed soil gas surveys is the strongest, most integrated and costeffective microseepage exploration strategy available. Offshore analyses are completed on seafloor sediment samples (gravity or piston core samples).
Discover and recover Besides hydrocarbons, oil and gas reservoirs are also home to vast microbial populations. These microbes do not escape from reservoirs as part of the microseepage chimney signatures. They live in the reservoir feeding on carbon sources and constantly multiplying. In some respects, this causes a reservoir to act more as an immense bioreactor rather than as a simple ‘container’ for oil and gas. As production engineers realize, some microbial activity is good and some is very harmful to production practices. The huge expenditure for biocides for H2S and sulfide control is testament to the efficacy of microbial growth. So why not make microbes work for enhanced production rather than against it? GMT and its subsidiary, The LATA Group, provide for the manipulation of reservoir ecosystems and offer select formulae of nitrate-based treatments that will allow beneficial microorganisms to outcompete detrimental microorganisms. Beneficial microbial populations will control and prevent reservoir souring and corrosion, as well as create an in-situ IOR ecosystem including surfactant, CO2 and acid production. The world of petroleum offers many enticing clues. As exploration detectives we have seen budgets stretched and tolerance for dry holes rejected. The adoption of low-cost microseepage surveys obviously increases drilling accuracy and efficiency. The ability to discover stratigraphic reservoirs and optimize mature fields boosts microseepage acceptance. 3G integration will exploit advanced exploration and production projects. More information on Geo-Microbial Technologies, Inc. (GMT) can be found at www.gmtgeochem.com and www.latagroup.come or via email at email@example.com
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Play extensions, the application of horizontal drilling and strategic acquisitions marked a successful 2008 for Forest Oil. Cecil Colwell, Senior Vice President of Worldwide Drilling, gives an insight to operations in 2009 and reveals the increasing importance of technology at the company.
orest Oil ranks as one of the largest independent exploration and production companies in the US, and when Cecil Colwell joined Forest Oil in 1988 the company was predominantly an offshore company. Today the company has morphed into more of a resource play on land and Colwell has seen the industry itself change from wildcat-type drilling, commonly referred to as an exploratory well, to more resource plays. “Where we’re harvesting shells and tight gas with the latest completion techniques we are able to extract products that are commercial out of these tighter rocks. So we’ve seen a really big increase in activity and all the technologies that go with it, including horizontal drilling and fit-for-purpose rigs for example. So the movement has been to deeper and cheaper with more emphasis on the fracturing and the completion technology to get these products out of the rock.” Technology is undoubtedly an important aspect of drilling, exploration and production. So what technologies are key in transforming drilling operations at Forest Oil? “What we have seen of course is the application of top drives as well as the pluses and minuses of directional drilling, we’re now able to use horizontal wells and in a lot of the cases today we’re able to drill some pretty long laterals. One of the downsides of directional drillers is that they can’t keep their tools together – and even though we can send a man to the moon these computers fail at an alarming rate these days. I’m not sure if it’s because they’re getting old, if the fleet motors are getting some wear and in the downturn they’re not building anymore, but we’re certainly seeing a lot more down hole failure from the directional drillers and their motors. We defi nitely need to see some improvement here, particularly in regard to temperature limits – some of the formations in Haynesville and in deep Austin are requiring 350 degrees and the boards just aren’t rated for that.” According to Colwell, there has also been a lot of interesting technology opening up on the rig side too and he believes that there has been a huge evolution on the technical side, particularly with regard to completion. While the same main components still exist (mask, floor, pit), the pits themselves have evolved and are now easier to clean, plus the pumps have changed and become bigger. “We’ve seen the mast change where they lay some of the newer rigs down the back and they don’t need as much steel in them. If a person took a snapshot and looked at it 50 years ago, he’d say it’s the same piece of iron, but once he starts diving into it, he’d see that it’s not. And I guess the biggest technological change has been in the fracing from a production standpoint. Previously we had to move a rig to clean it out, to perforate the wire and
then there was a big discrepancy amongst ourselves in the industry on what we needed to frac it with. “And what we’ve seen is a genesis all the way back to where we started and that is slick water and perforating instead of a selective entry, but also more generous with the perforations. And we’ve really seen an explosion in slick water river fracs and we’re carrying low concentrations but a lot of liquid. And we’re getting fracs in these shells and the tight gas sands that are able to exploit these minerals and they’re a lot more efficient and we’re able to do them without moving a completion rig in there and without using wire line. We can just pump our tools down, use them selectively and with pump pressure bring them on.”
The personnel challenge Technology is not the only challenge facing the industry according to Colwell. He believes that there are several issues around personnel. “It’s very transient right now – people in, people out. I’ve been doing this for 30 years now and you’d think we remember but we don’t, and every time we bring in new people, it seems like we have to go through a new learning curve. At Forest we’re trying to do some things to avoid that – everybody in the industry is. “Lessons have been learned and we now think we have a leg up on some people in terms of personnel, although they probably say the same about us. This is a people business and always has been. I can’t say it always will be, but as long as we have people in the ﬁeld we are dependent on them.”
Hostile locations Despite technology moving in leaps and bounds there are undoubtedly still challenges in the drilling sector, particularly around unconventional oil deposits. Reserves can lie in some of the most remote and inhospitable places in the world, which can make work in these regions difficult for companies like Forest Oil. Conventional plays are more likely to pay out from the initial well, explains Colwell, whereas from a logistical standpoint initial wells in unconventional plays are pretty expensive and extremely unlikely to pay out. In fact, it may not be until the fi ft h or sixth well that the right techniques and infrastructure is used and money is made. “Much of the time a lot of money is spent on the first couple of wells and then as we improve our drilling and completion techniques, then
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we’re able to drop our prices,” explains Colwell. “When you’re not making money until as late as the sixth or seventh well, it really requires a lot of fortitude and a lot of insight into how the play is going to make money for the company. I think a big challenge for the unconventional plays is making it commercial as fast as we can. But of course, we are getting better at it.” However, even in the more remote places, the onus is on improving productivity and reducing costs, while at the same time meeting safety targets and environmental regulations. “Some of the environments we’re in are certainly considered hostile and we ensure that we keep our footprint as low as possible, and that means that we use a fit-for-purpose rig that maybe has three or four men rather than a five or six man crew. We also try and keep our interaction with the locals on location to a minimum,” explains Colwell. “And then of course from an environmental standpoint we’ll usually have a Cecil Colwell was appointed as Senior Vice President of Worldwide Drilling safety environmental guide on in May 2000. Previous to that he was location and able to handle acVice President of Drilling at Forest Oil. cidents or pollution. We’ll have that contained on site – not that we’re trying to hide anything – to be as proactive and fast as we can without relying on other people who perhaps don’t have the knowledge of what we’re doing.”
Economic impact There is no doubt that the world economic crisis has had an impact on every industry and the oil and gas industry is no exception. Forest Oil was previously running 50 rigs and that number has since dropped to just 10. Colwell explains that with prices down it has been difficult to get the product price and therefore make a profit, which in turn has affected the number of rigs Forest is operating. “We’re in this business to make money and if you can’t make money you’re going to curtail what you do,” says Colwell who goes on to explain how the company work off a plowback. “If we make a certain amount of money, then we’ll consider so much of it profit and the rest of it we’ll plowback in to future development. And we try to run at 70 percent plowback, so whatever our revenue is, we’ll take 70 percent of it and use it for other drilling, exploration and completion projects.” Will Forest go back to working on 50 rigs at a time again? Well, Colwell foresees Forest doubling current rig work to around 18 to 20, but is unsure that the company will reach the 40 to 50 range unless product prices improve again. “We have a lot of places that we could drill and they all held by production so they’re not going anywhere, so when prices improve we’ll probably try to run after those. The issue with tight gas and shells is that you get a flush production out of them, which means a hyperbolic curve is seen on production levels. The flush production is usually what pays for your adventure into that – it pays for the drilling, the completion and the hook up and after that you see the profits, but it
Operations Forest Oil has seen success in ﬁve key areas in the US, including East Texas/North Louisiana; the Greater Buffalo Wallow Area in the Texas Panhandle; the Arkoma Basin in Western Arkansas; South Texas; and the Deep Basin of Alberta in Canada. East Texas/Northern Louisiana: With two strategic acquisitions in 2008, a signiﬁcant prospective Haynesville/ Bossier Shale acreage has been added to Forest’s portfolio without signiﬁcant cost. From a geologic perspective, the opportunities in East Texas/North Louisiana expanded signiﬁcantly with successful completions in shallower Travis Peak intervals, further application of horizontal drilling in the Cotton Valley Sands and lastly with the emergence of the highly proliﬁc Haynesville/Bossier Shale. Greater Buffalo Wallow Area: Signiﬁcant expansion in acreage through both an acquisition and a step-out exploratory drilling program gives Forest an opportunity to exploit shallower zones that could be enhanced with horizontal drilling applications. A total of 14 previously undrilled sections had successful wells completed during 2008, resulting in an expanded inventory of drilling locations and production growth potential. Arkoma Basin: Multiple stacked gas pays continued to provide production growth in 2008. The low drilling and operating costs in this area yield attractive rates of return while generating signiﬁcant cash ﬂow. South Texas: After a slow down in activity in 2007, activity was ramped back up in 2008 after operations in the area with refocused. Identifying proliﬁc opportunities both on legacy and offsetting acreage means that the South Texas assets are expected to continue to generate signiﬁcant cash ﬂow for Forest, but also provide opportunities to explore offsetting acreage in Wilcox and Vicksburg. Deep Basin: Containing numerous multiple-zone pay completion opportunities, Wild River and Sundance/Ansell share similar geologic pay horizons, allowing Forest to beneﬁt from its successful four-and-a-half year drilling program that has seen the Deep Basin net production increase. With over 250 potential wells to drill in the Deep Basin, not including proved undeveloped locations, Forest has plenty of opportunity to expand the play, while further exploiting uphole potential through re-completion opportunities.
makes it really hard to get your revenue stream back out. So we’re not eager to give our gas away so it’s staying put, under our leases, and we’re going to hold for better product prices.” Looking to the future, Colwell explains that although he is yet to see a fi nalized budget, the company will be continuing to do more of the same. “We’re in the Panhandle, Haynesville and South Texas and I think we’ll be doing more straight holes as well as using horizontal development for more conventional plays. We have a lot of holdings in West Texas that we want to get back into. Our focus is on anything oily right now, it’s got a leg up on anything that’s considered more gassy.”
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igital oil field technology entered the industry in the early 1960s, originally to help assist with exploration activities, particularly in the form of digital seismic technology. It wasn’t until the next couple of decades that the term ‘digital oil field’ gained prominence and began to include the use of software, hardware, instrumentation, communications, business and engineering process improvements in EMP activities. Even then, it wasn’t until the mid 1990s that the term was used by the super majors who were working on cultivating strategies to further integrate technology into the business. Nonetheless, the advent of digital oilfields has had a significant impact on the way industry approaches the business of oil exploration and production. “It’s changed exploration in that it’s often allowed companies to leverage new or emerging technologies,” explains Catherine Madden, Research Analyst for IDC’s Energy Insights. “When I think of the digital oil field I’m thinking of technology that will help me achieve the ultimate goal – which I think is the
same for all oil companies no matter how large or small – of the economically feasible recovery of hydrocarbons.” While the digital oil field has essentially been around for 50 years, it is only now that the fundamental objectives of the concept – enhancing reservoir recoverability and optimizing production – have evolved to a point that people are looking at the digital oil field as a way to run all operations from exploration to the refinery, incorporating standardization and process integration. “Digital oil field efforts have essentially resulted in a positive impact on reservoir recoverability, production rates and total cost of ownership and those numbers probably vary from company to company depending on their strategy and the level of investment they have made,” explains Madden. “Energy Insights has done case study work as well as reports that have concluded that reductions of cost and improvements in productivity are possible, and many large oil companies such as Shell and Chevron have reported the same in relation to implementing a digital oil field strategy.”
Field of dreams In an exclusive interview, IDC’s Catherine Madden reveals the three vital factors in developing the next generation digital oil ﬁeld.
But while many of the largest oil companies in the world have a program in place to support the digital oil field, many are still looking at how to accelerate it. Madden believes that the top priority remains the same – namely, hydrocarbon extraction. However, she highlights that a critical link in the digital oil field remains the human element. “Initially there was much attention placed on technology as the means for companies to solve their problems, optimize the exploration and production processes and improve the ROI,” says Madden. “There wasn’t much attention paid to the role of people and processes in achieving those objectives. But now I think the top objective is to sustainably support the development of a holistic digital oil field strategy – IT spending to recover and that includes not only The impact of the economic technology as a tool to aid recession has not left the oil and gas that process, but also the industry untouched, and the spend on teams of people that do the IT has slowed as conﬁrmed by the work, as well as the differlatest forecast from IDC Energy ent business processes that Insights. Overall, the annual forecast are associated with explois lower from 2009 through 2012 and, ration and production.” in the ﬁrst look at 2013, IDC is In essence, companies forecasting total IT spending of $42.9 that wish to accelerate their billion. Spending declines from 2008 digital oil field will be reto 2009, begins to recover in 2010, and quired to understand the grows annually for an overall equation that permits the right balance between technology, people and processes. Looking at the digital oil field in 2009, Madden insists these three objectives need to be lined up together as opposed to implementing technology alone, and goes on to explain that the importance of this equation is slowly being recognized and that she sees improvement in many areas, including the degree of human involvement in the oil field process of exploration and production. “Some of the changes we’re seeing include looking at workflows and what can be automated. We’re talking about the integration of technology across distinct areas – so integrating more processes between exploration and production, for example. I think we’re currently talking about things like project management portfolios when essentially we should be looking at the entire value chain and allowing for as much integration and as much collaboration across that value chain as possible. And when I talk about the value chain, I’m really talking about everything from the moment exploration begins, through the process of drilling until the point you finally recover it and deliver it to its refinery source.”
The power of three Madden goes on to explain that each of the three main factors – people, processes and technology – will play a major role in the next generation digital oil field. Indeed, as each facet of these factors improves, so too will the digital oil field itself. On the technology side for example, Madden expects to see an increased use of sensors, as well as a continued improvement in high performance computing. “I also think remote visualization and service orientated architecture are going to continue to grow within virtualization; communications that allow collaboration and even communications around security will be imporcompound annual growth rate of 4.1 tant too,” she says. percent from 2008 through 2013. “Technology that aids The new worldwide IT spending collaboration is going to outlook supports the indicators that continue, and while it’s the market is taking a hit in 2009 with already playing an ima recovery in IT spending in 2010, and portant role, it’s going to long-term growth, but a slower pace become critical that you than the previous outlook. Despite the can share information – current economic conditions, the longnot just using email, but term demand for oil in the global maybe working in a vireconomy gives much incentive to tual room together or continue pursing current IT initiatives using virtual technology such as mobile devices and digital to look at the same docuoilﬁelds, as they are critical to a ment together and make competitive position in the oil and gas changes to it, or using a industry. In the short-term, a focus on virtual whiteboard to optimizing production point out certain things from existing you want changed.” reserves will play a In terms of the peokey role in improving ple factor, Madden berecovery of lieves a significant hydrocarbons. improvement is needed Information technology in addressing the top two can serve the production challenges facing the inprocess in many ways, but, dustry – the aging workin particular, technologies force and the need to that permit predictive work with geographicalanalytics and well ly dispersed teams. The monitoring remain critical aging workforce will play in 2009. a critical role in the number of available emSource: idc-ei.com ployees in the oil and gas industry over the next few years, and while the number may be mitigated to a certain point by the global financial crisis, the number of skilled workers available is set to shrink. In addition to a shortage of skilled workers, the increasing number of global projects impacts how these projects will be managed. Finally, in regards to processes, Madden sees one fundamental factor to the digital oil field strategy that must be addressed: aligning the business and technology strategy as well as implementing automated workflows, improving business practices and re-engineering existing processes in order to address the workflow. “There may be great new technology out
there, but IT alone can’t be the driver for the implementation of the digital oil field strategy, and neither can the business; the two have to be working together,” she asserts. “The business has a need to improve production and there’s technology out there that can aid that.” There is no doubt that some of the super major oil companies like ExxonMobil, Chevron and BP are working towards this right now. Many of these companies have either reorganized their company or realigned their goals regarding their digital oil field strategy to include business as well as IT and improve the communication between the two groups. Indeed, companies like Chevron, for example, have invested a huge amount in emerging technologies in the oil and gas industry. The largest oil companies are certainly looking at the next generation digital oil field and accelerating it from how it was perceived in the mid-1990s. “While it is not fully mature yet, there is a significant amount of investment happening. We’ve gone through the first wave of the digital oil field and learnt from that first level of implementation that it’s not all about technology; now we’re looking to ensure people and processes are aligned with the technology, using best practices, looking at getting a return on investment and improving production rates,” says Madden. “Energy Insights’ primary research indicated that in 2008, even national oil companies were looking beyond just investing in back office IT such as ERP systems; they too are looking at setting aside investment dollars for the digital oil field. And while it may not be on the same scale as some of the largest oil and gas companies, it is a priority for smaller companies too.”
the field is performing to different information about the reservoir. Such data floods in 24 hours a day and puts a great strain on the IT infratsructure. Madden believes this is certainly one aspect that companies are attempting to address. “Companies are looking at their approach towards structured and unstructured data in order to understand how best to use this information and ensure that employees don’t have to spend days wading through information as opposed to actually using it. It is certainly a challenge for oil and gas companies, but I think that if it is optimized in the right way it ultimately helps benefit the digital oil field. You have to address things like how to handle structured and unstructured data, using business intelligence and dashboards to indicate the performance.” Looking to the future of digital oil field, it is no surprise that the global recession has had an impact on this sector of the industry. Indeed, Madden cites the greatest risk associated with the recession is the likelihood that oil and gas companies will delay capital expenditure exploration budgets due to tight financials. “This is the area that has made the industry the most nervous,” she confirms. But while businesses are focused on the short-term boost to the budget sheet, the long-term risk is that by not making an investment to explore for new sources of oil, the company is left at a significant disadvantage four or five years (or even further) down the line. And with economically accessible reserves getting increasingly hard to find, companies are required to look for reserves further offshore and deeper in the ocean. So while Madden believes that the next generation digital oil field is in the pipeline, it is clear that the investment in people and processes – alongside the technology – must not be neglected at this crucial stage in its development.
“Companies are looking at their approach towards structured and unstructured data in order to understand how best to use this information”
Information overload However, while investment is being poured into the digital oil field, one criticism is the exponential explosion of data it generates. Implementing a tremendous amount of technology is bound to result in a wealth of information being collected, ranging from sensors that reveal how well
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ASK THE EXPERT
A new digital era Oil and gas companies are increasingly pursuing the digital oilﬁeld concept, particularly in light of the challenging economic and commodity pricing environment of the past year.
he term digital oilfield (DOF) can be described as follows: a program that leverages technology to transform E&P processes. Notice that the emphasis is on the transformation of process, not the deployment of technology. We have now ushered in the era of DOF 2.0 – a passage that is not marked by some remarkable new technology. Rather it is marked by the maturity of the concept itself, together with the ability to plan and execute the entire lifecycle of DOF solutions in a way that was not possible until recently. Because of this maturation of the concept and the complete lifecycle view, DOF 2.0 will be characterized by more rapid adoption of DOF solutions. In its early days, DOF as a concept was so nebulous that early adopters had to spend a significant amount of time defining what it would
mean to their company, and then build support in the business units where new tools and processes would be deployed. Initial adoption was slow as even the most committed advocates were required to sort through the hype of competing vendor offerings, most of which were based on product-centric software approaches to production optimization. Over the past couple of years, however, the DOF concept has matured in several important ways. While production optimization continues to be an important goal for DOF programs, next generation DOF solutions will be more integrated. Model-based, full-field optimization focused on increasing reservoir recovery is moving from abstraction to reality as we better understand how to integrate surface and sub-surface models. Forward-thinking companies are also evaluating the use of creative visualization technologies as a basis for real-time modeling and simulation. While there is much work yet to be done, as an industry we have crossed a tipping point in the maturity of DOF-related solutions and the knowledge of how to successfully deploy them in order to add measurable business value. Some consistent themes that have evolved in DOF programs are integration of siloed systems
and data, collaboration between locations and disciplines, the use of real-time data for remote operations and decision support, development of model-based optimization, and using all of the above to manage the full lifecycle of an oil and gas asset. The economic and commodity pricing environment has created challenges for operating company budgets, but we have seen most companies with existing programs at least hold their DOF spending flat. Many companies that are just starting to implement DOF programs are aggressively moving forward with their investment plans in spite of increasing competition for scarce budget dollars. This requires increased discipline in developing measurable and meaningful business value metrics. Knowing how to choose baseline metrics and then build defensible measurement into the deployment plan is critical to maintaining credibility as you report your results to management. Companies that are just starting programs are benefiting from the lessons learned from early adopters and are able to better define and justify their investment based on published case studies. Sharing experiences has proven valuable as companies define more comprehensive programs that subsequently require greater scrutiny of ROI. In fact, the industry has benefitted enormously from some early adopters who have tirelessly promoted the value of the DOF concept in the industry. Industry associations (most notably the Society of Petroleum Engineers), service companies, consultants and other industry evangelists have helped us all immeasurably as they have collectively succeeded in taking the DOF concept into the mainstream. Despite the challenging economic environment, DOF programs are evolving for the better. Practitioners generally have a better understanding of the DOF approach and the value it can bring to their company. Solutions and the whole DOF solution lifecycle are better developed and new, process-based support models are being put in place. The era of DOF 2.0 has arrived. n For more information please contact Bart Stafford on firstname.lastname@example.org or +1 713 835 3542
Bart Stafford leads the global Digital Oilﬁeld Solution for SAIC. He has over 23 years of experience in the application of technology within the upstream oil and gas industry. His perspectives reﬂect extensive experience within production companies as well as consulting and software companies.
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Thinking business in the oil ﬁeld Bill Kuzmich, Global Energy Sector Leader at CSC, offers his advice for dealing with digital oil ﬁeld data. ployee and team collaboration and better efforts around managing and using the digital information that digital oilfield projects create in great quantities.
Bill Kuzmich says: Executives, managers and engineers at oil and gas companies are challenged to make effective decisions on a daily basis throughout the exploration and production process. The application of various technology elements – like real-time data capture, modeling and simulation, collaborative visualization and business intelligence – during the evolution of the digital oil field has improved this capability. However, through industry research, work with our clients and other independent studies, we believe that there are still additional ways to improve the effectiveness of E&P decision-making.
“Improving decisionmaking in the oil patch is about finding out how individuals do their work” The challenge is to fundamentally improve an employee’s ability to be more effective in applying the significant technology investments that have been made over the last decade. These challenges can be met with renewed attention on em-
Social networking is the practice of using web technologies to connect people who have common interests. Many oil companies have adapted some of these practices and capabilities, like Facebook and LinkedIn, to help employees share knowledge more effectively. The age and knowledge gap between new employees and ‘seasoned’ employees is huge, and transferring knowledge now from the older to the younger workers is imperative. One of the first challenges to adoption involves really learning how people do their knowledge-based work. Who do they go to for answers? Where is the information that they need to do their jobs kept? How is information distilled into knowledge? Through collaboration and network analysis, very specific programs can be developed to allow users to share and improve their operational knowledge.
pricing information and contract documents. But these different types of data have multiple users and must not be stove-piped by job function. In this way, each member of the team can quickly make decisions in their area of expertise, derived from the same quality base data sets and in collaboration with other members of the asset team.
Business intelligence (BI) is a recent phenomenon in this industry. BI tools and processes were originally used by data-intensive industries, such as retail, to gather and analyze large amounts of ‘transactional’ or financial information; digging into what customers are buying or analyzing spend in a particular business unit. In order to provide better decision-making in the oil patch and extend the capabilities of existing E&P workflows, BI analytics need to be pushed lower in the organization where they are useful in helping organizations pull together the technical, operational and financial components of oil field decision-making processes. When properly implemented, petroleum BI would enable an engineer to provide the decision Bill Kuzmich is CSC’s Global Energy ‘Role-based’ view support tools and processes to Sector Leader. He has been involved in consulting, engineering and Another key task is to analyze the ROI of the recombusiness development activities for make sure that the informamendation by bringing togethmore than 30 years. tion is presented in a manner er real-time production data, that addresses the role and work context of the cost data from vendors, inventory availability and user. Production engineers have views of their past success on similar wells – as well as to deterwells and fields and their specific technical documine what the best technical remediation might ments and procedures. Operations managers can be for a well. have higher-level views of fields and profiles of In summary, improving decision-making fields with KPIs and indicators of problem areas. in the oil patch is about finding out how indiFinancial analysts have views of specific well and viduals do their work and providing the data, lease related cost and budget information with processes and tools that enable oil field workers project performance forecasts and ROI. to act like business people and think like shareProcurement has a view of preferred suppliers, holders. n
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NEXT BIG THING
Stepping stones for continuous optimization Intelligent oil ﬁelds are possible, says IBM’s David Womack, by taking advantage of a uniﬁed software framework and integrating operations. provides the foundation for integrated operations services such as asset turnerhaps the greatest challenge facing oil and gas companies today is around optimization, well and production performance reporting and conhow to increase recovery and production rates while simultanedition-based monitoring. ously reducing operating costs. Key ways of achieving this goal inThis framework allows oil companies to monitor platform rotating clude reducing unplanned and planned shutdowns in order to equipment in order to identify problems before breakmaximize production and decrease maintenance costs; imdowns occur, thereby improving the availability of drilling proving productivity from real-time visibility of measureplatforms. The same software platform can connect offments with data-driven visualization across environments; shore platforms with onshore experts for optimization of speeding decision-making with more intelligent alerts and turnarounds and real-time collaboration to help them reevents; achieving better cost control with easier replication spond more quickly and accurately as situations develop. of best practice event and alert capabilities across assets and Similarly, in downstream operations, refineries must processes; and collaborating with your experts across engiimprove unit operations performance and connect extenneering, maintenance, business planning, finance, etc. At sive control systems and other production systems at the fathe same time, safety and reliability remain paramount to cility and plant level with maintenance and resource all companies. planning systems to make more intelligent decisions to Taking advantage of a highly instrumented oil and gas David M. Womack is IBM Global Director of Strategy and Business reach desired optimization objectives. landscape, IBM has unveiled a new framework to help Development for the Chemicals and Petroleum and Industrial Products transform the way data is gathered, connected and anaSectors, responsible for creation and Enterprise asset management lyzed, creating actionable insight to improve production famanagement of the overall strategy, business unit plans, points IBM Maximo for Oil and Gas can help manage procilities. The Chemical and Petroleum Integrated of view and complex solution development activities. duction equipment, facilities, transportation and IT asInformation Framework enables stepping stone solutions sets consistently and efficiently, integrating asset that allow for continuous optimization and help increase management with planning and operational systems at facility and enterproduction while reducing ongoing operating costs. prise levels. The results of this continuous optimization can allow a transA unified software framework allows companies to aggregate real-time formation from a reactive to predictive asset management, reducing costs information from disparate assets to simultaneously monitor different oil platand increasing production.
“A unified software framework allows companies to aggregate real-time information from disparate assets” forms, oilfields and facilities. The result: a single, comprehensive view of the state of their production facilities whereby companies can improve extraction, production, operational and asset management activities. It enables visibility and process collaboration with alerts and event management to speed problem determination plus optimize existing resources in several domains.
Integrated operations The framework makes the vision of an intelligent oilfield possible by helping companies build an integrated reference semantic model that uniquely identifies facilities and operations based on industry standards, providing the abstraction needed to present data in the context of equipment without the custom logic of point-to-point integrations or siloed applications. This
Supply chain management optimization Another stepping stone to cost savings is optimization-based supply chain planning and scheduling, utilizing existing enterprise resource planning (ERP) and advanced scheduling and planning information. The optimization can consider factors such as cost, locations and carbon footprint.
Location awareness and safety For upstream and downstream processes, another step is using sensors with location awareness to build sensor event solutions for critical resources and processes. For example, applying real-time location tracking can help avoid safety issues. An industry framework provides a configurable software platform to accelerate deployment of business solutions. By combining industry-specific, business process management, business analytics and optimization capabilities based on industry standards, the framework is the foundation for continuous optimization from IBM Global Business Services (GBS) and partner business solutions. For more, see ibm.com/software/industry/frameworks/chemical_petroleum.html.
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Improving oil and gas collaboration According to a new report, oil and gas pros view social media as important for productivity and collaboration; however, few ﬁrms have the tools in place to capitalize on it.
esearch has revealed that the industry loses almost half a billion dollars annually due to inefficiencies around finding, using and sharing information among engineers alone. Around 40 percent of oil and gas professionals believe company adoption of new social media tools, including social networking sites, would boost productivity on the job, yet only one out of four report leveraging these newer tools to capture and share important information internally, according to a new Microsoft and Accenture survey released at the Microsoft Global Energy Forum 2009. The Oil and Gas Collaboration Survey 2009, conducted by PennEnergy in partnership with the Oil & Gas Journal Research Center, surveyed industry engineers, geoscientists and business managers worldwide and found that more than 70 percent believe that collaboration and knowledge-sharing are important for driving revenue, cutting costs and contributed to the health and safety of workers. However, in spite of this, most respondents stated that their organizations are still using older means of collaboration, such as face-to-face
meetings, emails and conference calls – even though newer, more sophisticated technology tools are available and in demand today. Perhaps more telling is that 61 percent of respondents said they spend at least one hour each working day searching for information and knowledge sources necessary for their jobs. With an estimated 65,000 engineering professionals in the global oil and gas industry today, this translates into a potential loss of almost 10 million people-hours a year among engineers alone – an average net annual loss of $485 million for the industry, calculated according to US Department of Labor salary statistics. “During this time of economic upheaval, when every dollar counts and effective decision-making is crucial, new technologies such as social media tools can help oil and gas industry professionals to find information, collaborate and generally be more productive,” says Craig Hodges, US Energy and Chemicals Industry Solutions Director at Microsoft. “In an environment with fewer workers and less resources, this is incremental productivity our indus-
try can use in finding new reserves, improving execution of capital projects, driving new innovations and reducing costs.”
enced hires coming into their businesses who need to understand a new corporate culture,” says Claire Markwardt, Senior Executive at Accenture’s energy practice. “Companies have an opportunity to supplement their exMore effective collaboration tools isting collaboration capabilities with newer tools The survey pointed to one path companies can such as podcasts and social networks to accelerate Emerging technologies take to help maximize productivity and facilitate the sharing of knowledge, increase teaming and When asked which of the knowledge-sharing and capture: specifically, 41.5 peraugment communication between their workforces social media tools would be most cent of those polled said they could save at least an in different regions.” beneﬁcial for this task: hour every day by using these newer and more effecWhile more than half the respondents favored tive collaboration tools. Surveyed professionals also adopting social media technologies to help shrink the 81% CITED INTERNET PORTALS revealed that advanced collaboration and informaproductivity gap, only 37 percent of respondents 58% POINTED TO SOCIAL tion-sharing capabilities bring value not only in think their companies are prepared to facilitate enNETWORKING SITES sharing enterprise knowledge but also in completing hanced sharing and capturing of the company’s intel56% NAMED VIDEO OR operational projects. For example, 74 percent said lectual capital. When asked why, almost half (48 PHOTO SHARING that these capabilities are very important in managpercent) said company management doesn’t view 44% CITED BLOGS OR MINI-BLOGS ing capital projects to drive down costs; 51 percent these issues as a problem. And 44 percent laid re43% PREFERRED WIKIS said they are very important in sourcing scarce techsponsibility for lack of readiness on older workers nical skills needed to enhance revenues; and 50 perwho do not typically use digital knowledge-sharing cent saw these new technologies as very important to the sharing of health capabilities. Still others said that vital company information is locked on inand safety advisories or experiences. dividual PCs or spreadsheets not available for easy sharing. “Companies are dealing with several trends right now, not only the aging “In the oil and gas industry, collaboration is a key strategy to reduce workforce walking out the door with decades of knowledge, but also expericosts, improve efficiencies and promote collaborative working relationships
among oilfield asset teams located in remote locations around the globe,” says Jill Feblowitz, Practice Director at Energy Insights. “Energy Insights believes that the momentum behind Web 2.0 will bring it to the oil and gas industry. Web 2.0 technologies can support the following industry requirements: connection with remote geographic locations, knowledge capture, knowledge access, informal knowledge sharing, and joint ventures and team projects.”
Capturing knowledge still challenging Survey respondents also confirmed that concern about capturing knowledge from experienced workers before they retire or leave the company is prevalent. As might be expected, more than half (53 percent) reported that aging workers are retiring in increasing numbers. However, survey respondents stated that the tools primarily used to retain this knowledge and intellectual capital from retiring workers are largely older methods, such as electronic file shares (64 percent), databases or repositories (58 percent) and written documents/physical files (58 percent). In fact, almost a quarter of respondents reported exit interviews as the tool used most often to capture knowledge from these workers. Respondents overwhelmingly said new collaboration technologies can help stem this flow of exiting knowledge. Yet when asked how well their corporate cultures support the adoption of these new tools, only about one-third of respondents think their company cultures are well aligned with implementation of new social media technologies. Far more view their organizations as not proactive, not encouraging and/or opposed to the use of these information technology innovations as business tools.
Technology in action Like countless other industry players, ConocoPhillips has three generations of employees working together side-by-side or dispersed around the world, and a significant number of the experienced workers are preparing to retire soon. That, plus regular attrition, creates the need for effective knowledge sharing. “With our intranet-based discussion forums, state-of-the-art browseand-search tools, and content management processes, our portal structure goes a long way towards addressing the looming generational gap and maintaining our intellectual capital. This is a key part of our strategy to retain critical knowledge,” says Dan Ranta, Director of Upstream Knowledge Sharing at ConocoPhillips. Due to the global nature of the oil and gas industry, workers must additionally work with internal and external contacts that are located halfway around the world and may never meet face to face. “Portal sites make it possible for a diverse, global workforce to connect with each other easily, aided by a business-focused network structure that encourages people to form trusted relationships regardless of their location,” he adds. Take the example of how an employee in Indonesia posted a question to the network’s online portal inquiring about whether it was safe to extend the run time of a power turbine beyond its scheduled maintenance overhaul. The timing of the overhaul would have resulted in a significant impact to production while the turbine, and the gas compressor it drove, were temporarily shut down. Expert engineers in Alaska, Australia and the corporate engineering group all responded, indicating it was both safe and permissible to continue running the equipment as long as the power it produced was acceptable and vibration levels were below alarm limits. By temporarily extending the tur-
bine’s run time and deferring the overhaul to a more opportune time, the Indonesian unit avoided millions of dollars in additional lost production without compromising safety. As the oil and gas industry becomes increasingly savvy in its use of information portals, new communities of internal and external users will emerge that share insight into resolving difficult industry challenges – from health, safety and environmental concerns to avoiding revenue loss. “The business impact of collaboration has made ConocoPhillips’ people and operations safer, lessened environmental impacts and helped our operations reduce or avoid lost production,” says Ranta. “Our operations have become more efficient, as in the case of our North Sea Business Unit that created and implemented a new Production Optimization Center. Along with reducing production losses, the POC has improved production coordination, planning and communication.”
The power of IT Long-term business success needs to be built on two things: innovation and productivity. New desktop and server solutions allow employees easy access to information anywhere at any time, while organizations can reduce risk through improved security and drive cost savings through virtualization and streamlined management capabilities. In 2000, subsea services and construction support ﬁrm DeepOcean was among the ﬁrst in its industry to implement the Windows platform for its onshore operations and offshore data processing. DeepOcean is now migrating to Windows 7 and Windows Server 2008 R2 because of its need to support its sales force and engineers who travel between onshore and offshore locations. These mobile employees rely on portable computers that make up more than 25 percent of the company’s computer ﬂeet. When DeepOcean migrated to the Windows platform, it implemented the Windows NT 4.0 operating system on its 50 client computers and the Windows NT Server 4.0 operating system on its 10 servers, which it is gradually upgrading from Windows Server 2003 to Windows Server 2008 R2. In an effort to enhance security for its portable computers and to address challenges with its virtual private network solution, the company also decided to migrate to the Windows 7 operating system. As a result of the upgrade, DeepOcean has simpliﬁed IT management, enhanced IT security and improved employee productivity. “Windows 7 has enabled our mobile work force to connect to the corporate network and access all the resources they need faster and more easily,” said Per Arne Strømø, IT manager at DeepOcean. “At the same time, the technology offers us a highly secure and reliable tool to help protect our conﬁdential data and intellectual property even when on the road.”
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Getting smarter about the future of oil and gas Every industry these days is facing upheaval and change, and the oil and gas industry is no exception. The initial reaction for most ﬁrms is to hunker down, cut costs and get through. But can we be more creative than that, asks Laura Mooney.
here is no doubt that cost cutting is a must – even if for nizations, like today’s oil and gas firms, are driven by an imperative need no other reason than executives and boards are forcing it. to optimize their systems and processes to achieve the fastest and most However, it is critical that you are able to understand and flexible automation possible, at the lowest possible cost. articulate the risks associated with the cuts you make, and BPM and EA soft ware can help you address major risks, including that you also, in parallel, consider how you can improve performance uncertain energy policy, price volatility, aging infrastructure and human along with the cost reductions. capital challenges while still containing costs. How? BPM soft ware gives Soft ware solutions like business process management (BPM), which you the power to fully understand, document and automate core business helps businesses define and automate core proceprocesses so they are repeatable, auditable and readily dures, and enterprise architecture (EA), which allows adaptable to change. EA tools allow you to model all enbusinesses to model, analyze and improve enterprise terprise assets and understand the impact of upgrades initiatives, can help you identify excess overhead and and change, allowing you to make the best decisions underutilized resources and enable you to automate at the appropriate times as you battle the ‘rust’ that so highly manual processes to generate greater efficiency often threatens your capital infrastructure and struggle and productivity – both functions that directly reduce to make the right process improvements while getting costs. In addition, BPM and EA technologies also prothe most out of your existing resources. EA and BPM vide the platform on which to identify and accelerate technologies can help with human capital challenges, innovations and become more agile in response to serving as a collaborative platform for capturing the change, giving your business an opportunity to actuexpertise of seasoned veterans while appealing to the ally gain a strategic advantage while weathering the younger, technology savvy workers who come on board, tumultuous market. to keep your business running in peak form. Laura Mooney is Vice President of Corporate Communications for While use of BPM and EA technologies is relatively BPM and EA solutions can help prepare you for the Metastorm. She has over 18 years of experience in articulating the value of new in oil and gas, the technologies themselves are not next generation of business. The extraordinary chalsoftware to business needs. new. Business process management and enterprise lenges facing the oil and gas industry offer a defining architecture soft ware solutions from one vendor – opportunity to implement innovative solutions today Metastorm for example – have helped over 100 US Federal government that will help you emerge as the market leader of tomorrow. Several firms organizations better understand and improve operations, plan for future in the oil and gas industry have already put EA and BPM soft ware in place needs, comply with regulations, improve visibility, and enhance secuand are reaping great rewards from the improved efficiency, reduced costs, rity and collaboration. Ultimately these technologies enable better peraccelerated customer service, and increased flexibility and insight that formance and allow companies to focus on important tasks rather than these technologies deliver. There is a huge opportunity right now for you administrative responsibilities, equating to lower costs and increased proto get on board and make an impact. ductivity while at the same time giving them the process improvements, Metastorm’s business process management and enterprise architecture software is visibility and technology they need to manage upheaval (terrorism threats, in use by over 1300 organizations worldwide, across a variety of industries. For more information, visit www.metastorm.com/oilandgas. natural disaster response, economic threats) with greater ease. These orga-
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Integrating IT Jens H. Schroeder, President and CEO of m:pro IT Consult, explains the important role of IT in the oil and gas industry. The search for oil and gas has become a precise science with millions of dollars ploughed into technologies to discover, develop and recover oil and gas. How important is it to have the right IT components in place? Jens Schroeder. The current challenges are unlike any faced by the industry so far. The associated issues are very costly, extremely complex and diverse. They cannot be resolved by technology alone, and will require substantial changes in enterprise management, culture and information processing. No doubt having the ‘right IT components’ is one important factor, but what exactly does right IT components mean? Do only the big names or the so-called market leaders deliver the right components? Do we always need over engineered components that produce results to five decimal places at the expense of time, labor and effort? For me the right IT components are pragmatic, and work together in a distributed service oriented architecture, not forgetting the original problem they set out to resolve. In your opinion, what are the main challenges facing the IT sector in the oil and gas industry in the current environment? How are you tackling these challenges at m:pro? JS. The current environment requires good decisions and the collaboration to reach, communicate and implement them. This requires the key stakeholders and experts to view, exchange and react on consistent and reliable information to known quality. IT should help to overcome these challenges. We at m:pro are tackling this by concentrating on three important areas.
“The current environment requires good decisions and the collaboration to reach, communicate and implement them” First is smarter data management and integration. Here we collect, distribute, abstract, aggregate, correlate and translate data from all sources into information. The objective is to have the information ready in any dimension if and when required. Next is providing easy to use but powerful user interfaces. It is impossible to foresee all information requirements of all persons in all situations. The objective is to access and present the information in a highly interactive, intuitive and common user interface. Fast navigation, drill-down and analysis tools also put the surrounding information at your fingertips.
Third is effective collaboration and workflow. With workflow as a building block, this level puts the areas above to work in a collaborative and documented fashion. The objective is to provide synchronous and asynchronous communication, conferencing and co-ordination activity through a variety of devices and channels. A common factor in failure to achieve value from technology investments is lack of access to the skills and experience needed to fully leverage the technology. What are you doing at m:pro to address this issue? JS. Capturing and distributing knowhow is fundamental. One example from our graphical user interface is that we visualize information in context and not just in rows and columns. This goes as far as visualizing how the information is processed to avoid black-box syndrome. The consistent look and feel, together with the standardization of key functionalities, makes the usage intuitive and minimizes training. You have to be able to connect people with different expertise and provide effective collaboration between them. Workflow creates not just documented and reproducible procedures but also provides guidance and the right level of automation for routine tasks even for the inexperienced user. Can you give an example of a recent project in which you have been involved – what were the challenges and how did your solution address these? JS. One of our recent projects integrates 11 refineries and their key data sources around the globe. To meet the required performance criteria, we decided on a distributed deployment and delivered our integration platform at each site. Providing global aggregations, cross-site lookups and keeping the overall system up-to-date were some of the many challenges. We introduced the concept of central integration, which synchronizes the local integration trees with the central instance using advanced message queuing. The standardization of presentation libraries together with the common functionality of the solution has further helped to overcome the language and other cultural issues. Now everybody can consistently and seamlessly work with the available information from anywhere in the world. Jens H. Schroeder is President/CEO of m:pro IT Consult, a project services and software products company that enables petroleum reﬁning, petrochemical and other industries to achieve total integration of information sources and applications. Schroeder has over 20 years of experience in the execution of international projects, IT consulting and software development.
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Professor Dean Neikirk and Sean Murphy (left) examine a solution containing dissolved nanoparticles at the headquarters of the Advanced Energy Consortium (AEC) in Texas
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Small solutions for
BIG RETURNS Rapidly depleting hydrocarbon supplies mean scientists are in a race against time to delay the dreaded peak oil scenario – but America’s Advanced Energy Consortium believes it has the answer. Diana Milne reports on why nanotechnology could be the small solution to a very big problem. iven the immense scale of the problem facing the world’s oil producers, it is ironic that millions of dollars is being spent to develop a solution so microscopic that it is invisible to the naked eye. Nanotechnology may be based on units that measure one-billionth of a meter, but, when applied to oil and gas exploration, its potential is huge. So much so that research projects are underway across the world to develop the technology; most notably at the US-based Advanced Energy Consortium, a research body funded by 10 of the world’s biggest oil companies at a cost of $1 million a year each. There are compelling reasons why companies are funding research into the application of nanotechnology in the oil field – a concept that is still several years from becoming a reality. According to the BP Statistical Review of World Energy, global proven oil reserves fell by three billion barrels in 2008 and the current reserves-to-production ratio is just 42 years. Meanwhile Faith Birol, the International Energy Agency’s Chief Economist, has predicted oil production will peak in 2020 and that the world’s 800 largest fields are seeing a 6.7 percent annual decline in production. The days of easily available oil are rapidly running out and oil companies must find ever more ingenious ways of extracting the remaining reserves from minute pores in the rock face. To do this, some say the technology they use to access the reserves must shrink. But size isn’t the only factor. As exploration goes deeper, already harsh conditions worsen – raising the need for more robust equipment and tougher coatings on drilling
tools. Finding the oil is a major challenge, too; even 3D and 4D seismic still lacks in resolution and the ability to penetrate deeply into the reservoir’s lithology.
Not-so-big ideas Scientists believe that nanotechnology could address all of these challenges. Sean Murphy is Senior Manager at the Advanced Energy Consortium – one of a team of four scientists charged with finding out whether nanotechnology really is the oil and gas industry’s silver bullet. “Right now we leave around 60-70 percent of the discovered oil in the ground,” he says, describing why the companies who are funding the project are so keen to find out whether or not nanotechnology can revolutionize the industry. “Even after applying enhanced oil recovery techniques like water and gas flooding technologies, we still don’t know how to effectively and economically remove it. Drilling more wells for oil recovery isn’t the answer as it can be a multimillion-dollar per hole proposition. The oil flows through pores that are not merely microscopic, they are submicron; and the pore throats can be nanometers in scale. Quantifying reservoir characteristics to enable improved recovery processes, like low interfacial tension surfactant flooding or carbon dioxide flooding, is where nanotechnology can really assist in improving total recovery from existing reservoirs.” Nanotechnology, however, exists on a scale small enough to penetrate these pores. And if scientists can produce nanoscale particles or sensors
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that are able to collect information about oil reserves and deliver the information back to the well or surface, these seemingly insurmountable problems could be tackled, delaying the days of peak oil even further. The AEC is focusing the bulk of its research on two areas: illumination of the reservoir, and developing nanosensors that can be injected into oil and gas wells to collect data on the reservoir rock, fluids and physical characteristics to then transmit or relay back to the surface for use. The center is also in the process of developing what David Chapman, Project Manager for Electronics describes as a “communications enabled robot”, an active electronics-based, nano-based device. “This would be something that has a physical or chemical parameter sensor built into it and is at least 100 times smaller than those in existence today,” he explains. “We need a telemetry solution that is capable of transmitting data topside, or alternatively some type of on board memory that enables them to store the data and keep track of location so that they can be interrogated when retrieved.” However, the notion of a robot built on nanoscale dimensions yet possessing such a high level of sensory, communications and storage capacity remains in the realms of “science fiction” for now, concedes Murphy. The process of making this concept a reality is fraught with complication – largely to do with the scale and the functionality of the technology involved. “The key is to shrink the sensor down to a size that enables it to move through the pores and the fractures in the rock; this may require difficult choices and tradeoffs in functionality,” he says. “For example, sensors might be event-driven, only communicating when a specific physical or chemical parameter is sensed, or communicating at specific time intervals, which would reduce power requirements. Communication is also a huge issue; geolocation and telemetry technology will have to be scaled to overcome the severe attenuation of traditional frequencies. Finally, it’s an extremely harsh environment with high temperatures and pressures that are not friendly to electronics, not to mention the mud and drilling fluids, and the saline solutions, waxes and asphaltenes all saturating the heterogeneous clays and rocks.”
International effort America isn’t the only country exploring the possibilities inherent in nanotechnology. Dr Mohamed Abdel-Mottaleb is founder of Cairo-based nanotechnology consultancy SabryCorp, which aims to make the Middle East a world hub for nanotechnology research. He believes there are still a number of issues that must be overcome before nanorobots can become a reality in the oilfield. “Nanorobots would involve a number of sensors with a motion, detection and transmission unit,” he says. One of the biggest issues with nanotechnology is the ability to integrate all of these systems together. They would need to have temperature sensors, pressure sensors and some sort of location
“If we can improve the recovery rate by only a small percentage, that represents an incredible amount of additional energy for the world” sensor to be able to pinpoint their exact location. They would also need a power source and the ability to transmit the information back. Each unit in the nanorobot already exists and it has been tested and verified. But a complete integration at that level of sophistication is still a bit far away. I’m not sure that the nanorobots, as currently envisioned, would be successful.” Mark Morrison of the UK’s Institute of Nanotechnology is also skeptical about scientists’ ability to overcome the challenges of developing a fully functional reservoir robot. “Providing power and sensors in a small particle size that is able to withstand different chemical environments and severe pressure requires concerted effort by a lot of different people,” he says. “One aspect of the robot might develop more quickly than another. But it’s combining all these things onto one platform that will be the big breakthrough.” It’s a breakthrough that Murphy says he and his team can’t make before they have explored the fundamental science behind the concept – for instance, the factors that control the retention and transport of nanoparticles through the pores in the reservoir rock. “We are funding a number of fundamental science projects that are related to understanding what it’s going to take to move micro and nanoparticles through reservoir rocks. Some are predictive studies that will produce modeling and simulation tools. Others are more experimental in approach and are underway at petroleum engineering departments. They started with glass beads and sand particles and now they are progressing to constructed permeable media and micro models that are representative of reservoir rocks.” He goes on to say that he and his team are currently figuring out how to get these particles to flow from one end of the rock to the other and whether there are coatings they can use on the particles to enable them to flow through more easily. He says that even if his team doesn’t succeed in moving onto the next level by creating nanoparticles equipped with sensors, communications equipment and data storage capacity, simply being able to un-
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Nanotechnology has been used to produce new materials for a range of industries. Here a scientist tests a sheet of ultra-thin foil
derstand how to create a custom-designed nanoparticle that will pass through the reservoir could have major benefits for the oil and gas industry. This is one area where the industry could benefit from biomedical research, with coatings developed to enable pharmaceutical nanoparticles to pass through the body having the potential to be used in briny oil fields. “Not only do we have to figure out how to pass a nanoparticle through heterogeneous rocks and complex fluids, but we need to find a material that can enhance the resolution of sub-surface lithogies and fluids using viable remote sensing technologies,” says Murphy. “Questions that need to be answered include can we discriminate these nano contrast agents from the background noise? What volume of material will we need to use? And can we functionalize them so that they will attach to hydrocarbons preferentially?”
The material world Nanotechnology’s potential in the oil and gas field is not limited to its reservoir mapping capabilities. Nanomaterials are already widely used across
a wide spectrum of industries including automobiles and consumer electronics products and scientists believe that nanocoatings, in particular, could have great benefits when applied to drill bits. Morrison says: “There is a lot of development that could potentially be used in the oil and gas industry – things like nano-structured ceramic materials that have increased hardness and durability compared with conventional materials, which could be used in drill bits.” He explains that at the nanoscale, materials can be harder and more sheer-resistant, making them less susceptible to different forces and able to withstand higher temperatures. Using this sort of coating could enable oil companies to drill deeper and cut down on lost time through having to replace drill bits. “If you can use a nano-structured ceramic material to coat a drill bit then you might have access to oil fields that you wouldn’t normally be able to access,” says Morrison. “Or you might have a longer time between replacing drill bits or pipes. So it increases, potentially, both your access to different reservoirs, and the amount of time those reservoirs are open compared to being offline.”
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An even more sophisticated use of nanomaterials in oil and gas reservoirs could be to coat well bore tubulars with material that is able to detect and react against corrosion or leakages. The most common terminology for this is ‘smart’ or ‘intelligent’ materials. These materials are aware of the environment around them and can change their properties accordingly. This – like the use of better coatings for drill bits – could make nanotechnology a way for oil companies to save billions of dollars in costs from well shutdowns and the replacing of equipment, notes Abdel-Mottaleb. “Smart casings for the bore hole are currently being tested in the lab,” he explains. “You need a material that can react to the environment around it so that if there is any leak, it can immediately interact and close it. The point of all this is that the oil industry has to invest in this sort of technology to improve its efficiency and reduce costs.”
Big oil turns to nanotech
Since 1999, the world’s five largest international oil companies have replaced only 82 percent of the reserves that they’ve consumed. Nanotechnology can help the oil and gas industry find new fields and extract more from existing ones – but only if new collaborations bridge the industry’s historical divides. “Nanotechnology fits oil and gas industry needs,” says Mark Bünger, Research Director at Lux Research. “Underground oil inhabits nanoscale pores; oil wells’ extreme temperatures and pressures benefit from nanostructured materials and coatings; and engineered nanocatalysts can upgrade heavy oils to lighter, more valuable ones. With these benefits in store, it’s no surprise that a high proportion of nanotech start-ups focus on oil and gas – and that associations like the Society of Petroleum Engineers and the Advanced Energy Consortium are investigating everything from subsurface nanosensors to autonomous nanobots.” To examine the landscape of nanotechnology developments in oil and gas, Lux Research developed a global inventory of research initiatives, corporate R&D programs and start-up companies in the field. The report concludes that: Tiny oil and gas R&D budgets constrain large companies’ nanotech development. International oil giants are spending just 0.2-0.5 percent of revenue on R&D – 50 to 100 times less than in other technology-dependent sectors like aerospace, biotech and information technology. Start-up companies are filling the gap. With oil prices on the rise, nanotech start-ups are prioritizing oil and gas applications over alternative uses of their materials. For example, Integran is developing nano-engineered coatings of tungsten carbide and boron nitride to harden drilling equipment and pipes, and Intrinsiq Materials is developing explosive perforators for burning holes through rock. The oil and gas industry’s fractured history keeps players from combining Money talks their efforts. Increasingly bitter rivalry keeps international oil companies Cutting costs is a major like Shell and ExxonMobil (which have a history of deploying new concern for the oil and gas technology) from collaborating on nanotech with national oil industry – with worldcompanies like Sinopec and Gazprom (who own the reserves but wide demand for oil have not focused on technology in the past). having plunged by New collaborations are required to unlock nanotech’s value in 0.6 percent in 2008. oil and gas. Four parties must come together to accomplish Despite these finanthe amount of funding interdisciplinary nanotech research with benefits for the entire cial pressures, howthe AEC is recieving industry: international oil companies, national oil companies, startever, funding for from oil companies ups and academic institutions. research into the use of each year “According to Chevron, the average new technology in oil and gas nanotechnology from naexploration has taken 32 years to achieve 50 percent penetration,” says tional and international oil Bünger. “In today’s environment, that’s an order of magnitude too long. To companies has been forthcoming accelerate development, NOCs should engage in joint ventures with start-up as companies seek to make investments companies and strategically acquire them as necessary; IOCs should set aside at least in technology that could result in lower one percent of revenue for R&D; and start-ups should tap oil and gas riches to fund costs and high returns on investment in technologies with applicability in other additional fields like the water market, which the long-term. The AEC is set to receive has similar needs in piping, drilling and filtration.” $10 million dollars a year for the next
three years from 10 of the world’s biggest oil companies, including BP, Halliburton, Shell and Total, and the decision by these competing companies to pool their resources builds on approaches developed in the semiconductor electronics sectors. “The miniaturization challenges facing the development of nanotechnology are parallel to those that faced microprocessor technology,” says Murphy. “It was an expensive multidisciplinary problem with many companies wanting to move onto the next shrink-level but unsure of the exact technology to bet on. In such pre-competitive situations, it makes sense to
leverage the funding from other companies so you can explore lots of problems and share the results.” Yet while a shared approach indicates cooperation amongst these companies, some have expressed concern about the proportion of funding going to US-based companies. Abdel-Mottaleb, understandably, wants to ensure that a more international approach is taken. “One of the issues is whether this is going to be led by American companies or European companies or whether
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Nanomaterials application The Society of Petroleum Engineers has identiﬁed the following possibilities for nanotechnology in the petroleum industry:
to research into nanotechnology, led by Saudi Aramco and the Saudi government. “Saudi Arabia is pouring billions of dollars into advanced technologies. The UAE and even Egypt are be• Nanotechnology-enhanced materials that provide strength and endurance to coming more active. In 2008 I found out the total amount of increase performance and reliability in drilling, tubular goods and rotating parts funding available in Egypt to get a project complete • Improved elastomers, critical to deep drilling and to improve drilling in highin the next three years is $100 million. That temperature/high-pressure environments is nothing compared to what the US or • Designer properties to enhance hydrophobic or hydrophilic behavior, European governments have come to enhance materials for waterﬂood applications up with but in 2007 we had no • Nanoparticulate wetting carried out using molecular dynamics, funding. So from zero to $100 which shows promise in solvents for heterogeneous surfaces and million is a significant jump.” porous solids And despite Abdel• Lightweight, rugged materials that reduce weight requirements Mottaleb’s fears, there are signs on offshore platforms, and more-reliable and more-energyare spending just 0.2-0.5 that the discipline is embracing percent of revenue on efﬁcient transportation vessels more international collaboration. R&D • Nanosensors for improved temperature and pressure ratings in The AEC, in an effort to be more indeep wells and hostile environments clusive, recently hosted a workshop in • New imaging and computational techniques to allow better discovery, Paris where 80 percent of the participants sizing and characterization of reservoirs were from European, Asian and Middle Eastern • Nanosensors deployed in the pore space by means of ‘nanodust’ to provide data companies. It is also currently reviewing proposals for its second on reservoir characterization, ﬂuid-ﬂow monitoring and ﬂuid-type recognition round of funding and is looking for opportunities worldwide. • Small drill-hole evaluation instruments to reduce drilling costs and to provide Murphy is reluctant to cite nanotechnology as the solution greater environmental sensitivity because of less drill waste to all the oil and gas industry’s current challenges. However, he says that even if this microscopic technology were to make a it is going to be an integrated effort,” he says. “What I’ve seen so far is that the small difference to the numbers involved, its impact in real terms would be Americans are very active in this and are looking at funding the American scimassive. “I wouldn’t say it’s the savior of the industry, but it has intriguing poentists rather than the Europeans or scientists from elsewhere. This is not the tential for being able to retrieve more oil than we can retrieve today. We’re right approach. This is an international discipline and we need to be looking talking about billions of barrels of oil that are left in the ground. If we can imat it globally and not excluding solutions that come from outside the US.” prove the recovery rate by only a small percentage, that represents an incredNevertheless, he says the Middle East is catching up fast when it comes ible amount of additional energy for the world.”
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The fight against corrosion Replacing corroded pipelines costs upwards of $643,000 per kilometer. Mark Byerley, President of NACE International, explains why maintaining and inspecting pipelines is vital in the battle with corrosion.
n 2002, the US Federal Highway Administration (FHWA) released a breakthrough two-year study on the direct costs associated with metallic corrosion in nearly every US industry sector, from infrastructure and transportation to production and manufacturing. The study, entitled Corrosion Costs and Preventative strategies in the United States and initiated by NACE International, revealed that corrosion is the primary factor affecting the longevity and reliability of pipelines that transport crucial energy sources throughout the nation. There are more than 528,000 kilometers of natural gas pipelines, 119,000 kilometers of crude oil pipelines and 132,000 kilometers of hazardous liquid pipelines in the US, amounting to an estimated $7 billion in average annual corrosion-related costs in monitoring, replacing and maintaining these assets. “Given the slow and destructive nature of corrosion we are looking at replacing a kilometer of pipeline for around $643,000 or more, which is an extremely expensive proposition,” explains Mark Byerley, President of NACE International, the leader in the corrosion engineering and science community. “Maintenance and inspection are of primary importance – at least they should be to many companies – so the driving force for that expenditure is to preserve the asset of pipeline and to ensure they operate safely without failures and jeopardizing public safety, the environment and everything else that comes with that.” The survey indicated that the primary loss of protection on the pipelines was due mainly for two reasons: the degradation or deterioration of the coating and the inadequate protection levels. So the major maintenance is associated with monitoring and repair problems, and in addition to maintenance there is the issue of integrity management and inspection focusing on condition assessment, corrosion mitigation, life assessment and risk modeling. “If you look at maintenance packages, you’re looking at between $3000 and $6500 per kilometer annually to maintain a pipeline and protect it from corrosion; compared to the offset from what it costs to replace a pipeline, you can see that the ROI is fairly extended,” says Byerley. Following a number of high-profi le pipeline failures, public safety concerns have driven new regulations and corrosion control practices for gas and liquid transmission pipelines over the last several years. Byerley highlights the various technologies that can help in maintaining and ensuring pipelines live a long and happy life. “First of all you need to look at the materials that go into the pipeline, the types of steel you use,” he advises. “Plus there’s a coating component, making sure that the pipeline is well protected dielectrically from the outside elements. And we do that through various coating technologies, whether it be fusion-bonded epoxies or tape-wrap systems. There are several spray-applied type systems as well. And then we get into the electronics side, where we’re inducing currents into the field to help slow the effects of corrosion, or to mitigate them in areas where the coatings are not present.” Byerley goes on to explain that as corrosion experts, the sector produces a different breed of engineers and with the increase in research and development, the industry is improving worldwide. “We’re one of the few disciplines in the engineering field that actually work every day
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to put ourselves out of a job, because once corrosion’s eliminated we’ll have nothing else to do.” Preventive strategies Much of the work done at NACE International continues to revolve • Increase awareness of signiﬁcant corrosion costs and around the US Department of Defense. However, NACE is looking at potential cost savings • Change the misconception that nothing can be done about different outreaches – not just in the US pipeline market, but around corrosion the world – to help mitigate the problems, including Australia and New • Change policies, regulations, standards and management Zealand, as well as Europe. And as pipelines improve around the world practices to increase corrosion cost savings though sound the industry is seeing a much more aggressive use of improved data corrosion management • Improve education and training of staff in recognition of gathering, through the use of multiple technologies and coatings in concorrosion control junction with the cathodic protection ECDA (external corrosion direct • Implement advanced design practices for better corrosion assessment) and other pipeline integrity management programs. management And as a result of the increased use of pipeline integrity manage• Develop advanced life-prediction and performanceassessment methods ment programs, NACE has seen a rise in demand for education on these • Improve corrosion technology through research, programs too. “If you look at the lack of knowledge of senior managedevelopment and implementation ment, it’s not a bad thing, just something that they usually don’t deal Source: www.nace.org in,” explains Byerley. So getting that senior management buy-in is a huge challenge for the corrosion department in these companies, and while there are over 21,000 NACE members per year. No-one educates more people on corroworldwide, the vast majority are not even considering sion prevention than NACE International.” corrosion until a calamity strikes. Along with education, Byerley believes “Th rough the media staff at NACE, we have the that the biggest challenge in the fight against responsibility of asking for an audience with those in corrosion is in inspection and maintenance senior management positions, and have done some frequencies. The more remote or hostile the encorporate outreach programs getting people to undervironment, the more difficult it is to get to the stand how easy it is to protect pipelines – especially point of inspection or a component that needs to cost-wise – in order to try to prevent having to replace be maintained. “It really starts at the lay of the that pipeline. Today’s technologies allow us to keep pipeline,” claims Byerley. “But that said we are pipelines in the ground well over 100 years, as long as now doing a lot of work with remote monitoring, they’re administered properly,” says Byerley. “However, where the pipeline actually reports to a central these are probably not as successful as we’d like, which hub via satellite or cellular communications, so is probably due to corrosion being a very unsexy topic, we can actually monitor the pipeline from an so it’s hard to get them in the doors at fi rst.” Mark Byerley, a 30-year corrosion industry office thousands of miles away.” The corporate outreach programs can involve anyveteran, is NACE International President for Byerley advises that companies looking to thing from tasking employees of the company to really the 2009-2010 term. improve the issue of corrosion need to start getfocus on their upper management teams to explain to ting involved in the industry and look at how they them what they do everyday, to NACE staff going to a can participate. “Whether it’s getting the members of their companies involved at a local section of an organization like NACE or whether it’s in a research committee at NACE, technical committees help drive standards which then form new education programs,” he says. “These are just some of the more vital areas in NACE International, but there are other things like supporting an employee and furthering their education on corrosion prevention, whether they get involved in formal training or attend conference and technical symposiums.” Moving forward it is clear that increasing research and development, as well as furthering education, could dramatically improve the board of directors of major suppliers, pipeline companies, oil companies, issue of corrosion in the US and around the world. While technologigas companies and working with senior management and teams within cal advancements are happening all the time, the best way to prevent the company to educate the management on corrosion and its effects on corrosion involves better corrosion management through preventive their systems or assets. “Knowledge is power. And if you look at what strategies in both non-technical and technical areas. NACE is doing in this respect, we hold 450 classes and train 9000 people
“We’re one of the few disciplines in the engineering field that actually works every day to put ourselves out of a job, because once corrosion’s eliminated we’ll have nothing else to do”
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In great shape
Richard Norsworthy of Polyguard Products Inc. argues that the pipeline industry is in good condition; it just needs to get smarter. We know that your company’s president, John Muncaster, states pretty strongly that the pipeline industry is allowing a lot of unnecessary corrosion through its use of corrosion coatings that block protective cathodic protection (CP) currents. What are your thoughts on the cathodic shielding problem? Richard Norsworthy. Pipeline operators across the world work hard to provide a safe and reliable mode of transportation for oil, gas and their derivatives. Overall they have done a good job of protecting these assets, the surrounding communities and the environment. But there is room for improvement. One area is developing a better understanding of how pipeline coatings work with cathodic protection. Most of the external corrosion problems we have today are caused from past and continued use of pipeline corrosion coatings that shield cathodic protection currents. If a corrosion coating literally breaks away and leaves a visible open area on the pipe surface, there is no shielding, because nothing blocks the protective currents. But if the coating loses adhesion and separates from the steel in a blister-like or tunnel-like configuration, the steel is now exposed to water. The corrosion process will now begin if the corrosion coating shields the cathodic protection current. Unless the protective current can penetrate the top of the blister (as it does with fusion bond epoxy coatings) or underneath
the lap of the coating (as it does with Polyguard’s RD-6 coating) the current usually cannot protect most of the exposed steel surface.
by pipeline operators on their systems. These experts, primarily CP service providers, regulators and researchers, believe that adequate CP protection is not provided using the present criteria. Their conviction, from what I can see, comes from their professional concern backed up by a limited amount of field and laboratory studies. On the ‘let it be’ side, you have the pipeline operators and a smaller group of experts. This group maintains that the present CP criteria have a 60-year track record of success, and that the type of problems that concern the ‘change’ people are isolated. Moreover, the ‘let it be’ side is really concerned about the level of new investment that pipeline operators will be required to make to expand their CP if the proposed changes are implemented. An engineer from one large multi-state gas utility told me that his company estimates over $100 million in investment will be required, and higher day-to-day operating costs will be needed as well. So this is serious stuff; it’s a very large potential
investment and you don’t feel it is necessary? RN. That’s absolutely right. As a matter of fact, I feel that our industry is in great shape if only we You’ve personally taken a controversial induswould do the smart things. The industry has realtry stance by acting, in the words of one inly good coatings technology, if we focus on just dustry member, as “the leader the non-shielding coatings. of the rebel alliance” in coordiFusion bond epoxies now have nating opposition to a proan almost 50-year track record. posed update to the NACE Corrosion is almost never found SP0169-2007 standard. Could on FBE coated lines, except you tell us about that? when there is AC or DC interRN. In the first place, our opposiference, which is a completely tion has little to do with the caseparate issue. And Polyguard’s thodic shielding concern non-shielding product, RD-6 discussed above. The existing wrap, has a 21-year track record SP0169 language is already fairly without a single case of corrospecific about shielding and is in sion occurring. line with our views. CP technology is also well Richard Norsworthy is Director Also, you really have to be developed. It is a mature techof Lone Star Corrosion Services at Polyguard Products Inc. of technically knowledgeable in the nology that is highly effective – Ennis, Texas. cathodic protection field to unexcept, of course, when used on derstand this debate, so I won’t lines with corrosion coatings even try to explain the finer dethat shield. Tools and methods tails of the controversy. From a big picture point for finding corrosion before it causes leaks and of view, however, you have two groups of indusother problems are improving rapidly and imtry experts at odds here, arguing whether CP stanpressively. The bottom line is that the industry dards should change to be more stringent. has almost everything it needs today. On the ‘change’ side, you have a group of exPolyguard has sponsored a blog so that the industry has perts who believe that more complex CP meaan open forum on this debate. Please visit surements and calculations need to be performed www.SP0169.com for further details.
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in compliance, but we still do not know whether that inspection frequency is rational or cost-effective. It is important to think outside of the box of mere compliance. The integrity management concept (both IMP for transmission pipelines and DIMP for distribution mains) requires a company to identify threats, and to develop a program to minimize those threats. This takes much more thought and effort, but the results can be very beneficial in obtaining information that can help the company to establish an effective inspection schedule and to minimize operating costs.
CAPTURING AND COMMUNICATING KNOWLEDGE Paul Oleksa explains how well-written procedures can help document a company’s operations, improve efﬁciency and limit risk and liability.
leksa and Associates was founded by its President, Paul Oleksa, and incorporated in the state of Ohio in 1997 as a small, flexible pipeline safety consulting company dedicated to providing professionalism and integrity in resolving pipeline safety issues throughout the United States and the world. Services include pipeline safety audits, procedures and manuals, and expert witness.
A modern and efﬁcient pipeline infrastructure will be critical in meeting rising demand for product. How can oil and gas companies ensure the smooth operation and maintenance of their pipeline infrastructures? Paul Oleksa. There are many factors involved in having an efficient pipeline infrastructure, and they are all important. These factors include good leadership, good staff, an understanding of the regulatory requirements and a good grasp of both typical industry practices and the changing technology. After having good leadership in place, having the right personnel on board is essential (see Good to Great by Jim Collins). A great company needs both seasoned veterans and sharp youngsters. Often, the seasoned veterans, while having
an excellent grasp of the company’s body of knowledge, do not have the ability to express that knowledge succinctly – either verbally or in writing – therefore a great deal of time is required to develop new talent. Time is not always available, and it is very costly. One way to increase the efficacy of this knowledge transfer is to capture that body of knowledge in very well-written procedures, so that a very talented but somewhat inexperienced person can find information when it is needed, quickly. By carefully documenting its body of knowledge, a company can help to ensure the consistent, smooth operation and maintenance of its pipeline infrastructure over time. What traditionally have been the limitations and challenges in effectively inspecting and measuring pipeline points of concern? PO. Dr. W. Edwards Deming emphasized that to effectively manage something, it is important to be able to measure it. Often, we have not analyzed what information is being measured. Is that particular measurement really effective in measuring what we need to know? For example, if we measure whether valve inspections are performed when required, we know whether the company is
As companies are scrutinized ever more closely by outside parties, good procedures are becoming more important than ever before. What is the value of having the right procedures in place? PO. Companies today are scrutinized much more than ever before by a variety of outside personnel, including the public, regulators and plaintiff attorneys. Compliance with regulations is essential. However, efficiency, cost-effectiveness and limitation of risk and liability may be even more important. The public’s perception of a company can translate quickly and directly to the value of the company’s stock, particularly if segments of the public organize to oppose particular projects or activities. Obviously, this can have a huge impact upon any firm. This perception is often impacted by how employees and contractors perform in field situations. Field activities must be based upon well thought out and clearly written procedures. Companies today do not have the luxury of providing employees long periods of on-the-job training to become qualified. To maintain efficiency, consistency and cost-effectiveness, personnel must be trained using good procedures. Regulators are examining a company’s procedures in ever increasing detail. Well-written procedures can help to minimize problems that may be encountered. Plaintiff attorneys may not have a good understanding of company operations. They may misread the procedures. Wellwritten procedures would minimize the opportunity to be misread, and thus greatly benefit a company during litigation. While compliance with state and federal regulations is essential, it is equally important to provide appropriate direction to personnel, and to limit risk and liability. Why is it impor-
tant that procedures are written correctly in order to take such concerns into account? PO. There are many standards that might be used to determine whether procedures meet a company’s requirements. Of course, compliance with
liability can save companies huge amounts of money that would otherwise drain profits. Procedures must be easily read and understood in order to minimize human error. Therefore they need to be clear and easy to read.
“By carefully documenting its body of knowledge, a company can help to ensure the consistent, smooth operation and maintenance of its pipeline infrastructure over time” Paul Oleksa
regulations is essential. However, procedures might be compliant, yet still not effectively limit risk and liability. Limitation of risk and liability is a much higher standard, and it is not easily accomplished. Nevertheless, limitation of risk and
Since there is training that accompanies the procedures, it is more effective to use proper wording than to write procedures to an arbitrary (say, ninth grade) level of writing that may not clearly cover all the nuances. Field personnel
require clear instruction, yet the written words need to address all the concerns of the attorneys. The correct balance is a matter of professionalism. How can properly thought-out procedures enhance emergency response planning and incident investigation? Why is this so important? PO. During an emergency there is very little time to think. Therefore it is necessary for as much of the thinking as possible to be performed ahead of time. This advance thinking is first captured in the procedures, and then through training. Training must be based on the procedures. Finally, this thinking becomes part of the company’s body of knowledge. By capturing this body of knowledge in the procedures, personnel can use their time much more effectively during an emergency occurrence. This is extremely important because emergency response and incident investigation can be very costly activities, and there is only one opportunity to get it right.
Improving offshore operations SatPos CEO John H. Edvardsen looks at offshore asset tracking and monitoring solutions.
n the open waters where the waves are high and the weather conditions are constantly changing, asset tracking and monitoring becomes especially hard. Your tracking and monitoring equipment must be able to handle tough punishment, complete submersion, rough treatment – and still work at the end of it all. Th is is where SatPos comes in; we design and manufacture products and solutions capable of working in such conditions year-afteryear. Our products are in use all over the world and our customers include major international seismic, offshore oil and gas and environmental companies. SatPos products are used for tracking, monitoring and control of buoys, vessels and other flotation or fi xed assets. We also have co-operation with offshore weather forecasting companies so that they can give you real-time weather predictions based on the position of your vessel or asset.
Asset tracking In coastal areas, you have many standard options for asset tracking like GPRS or radio transmitters; however, if you lose your asset and it drift s out of coverage, then you have a problem. We solve this by using a combined Inmarsat and GPRS transceiver. Inmarsat has global coverage and it is a cheap and very stable system (which is critical for retrieving your assets). If you purchase a SatPos M-200 device and in-
“HSE is a very important aspect in the offshore industry and that is why many companies see the value in choosing our products and solutions” stall it on your asset, you have a complete cost-effective solution. Th is device has a combined GPRS and Inmarsat transceiver that means that you can track and control your asset in any location. For offshore areas, satellite is the only option. If your asset has power on board, you can use our SatPos TB or the SatPos M-series; you also have the option of purchasing devices with integrated warning lights (SatPos SSD) so that they are easier to spot and other vessels will
see them from far away. For assets that do not have any power on board, you can use our SatPos DF-108, which comes with a 108Ah battery for up to one year of service; we also have custom devices that can utilize solar panels and water generators for charging the device.
Fleet management For fleet management we use our SatPos M-100 Inmarsat device. With this small dome (21cm in diameter and 20cm high) you can track your vessels all around the globe at low costs. It sends the GPS position, course and speed at user-defi ned intervals. Th is interval can be modified via the SatPos. com web interface at any time. If you use our SatPos M-101 device, you also have the possibility to add external sensors like temperature, wind, water salinity, NOx, gases, fuel consumption, etc. Th is can be very useful for maximizing fuel efficiency and saving valuable fuel to help minimize the environmental impact John H. Edvardsen has been computer from your vessels or assets.
Monitoring and control
programming since the age of six. Selftaught at everything, he started working with GPS positioning in the 1990s and quickly found a passion for tracking assets and has gained wide experience in this ﬁeld. He is currently CEO of SatPos AS. For more information, please visit www.SatPos.com.
HSE is a very important aspect in the offshore industry and that is why many companies see the value in choosing our products and solutions. If your assets drift off you can find them and prevent them from causing harm to people, environment or other equipment floating in the ocean. All your assets can be tracked and monitored online at www.SatPos. com. Different from standard GPS tracking technology, SatPos allows two-way communication – enabling messages to be sent to the equipment. If you’re monitoring position, direction, fuel consumption, gases, temperature or other parameters, you can tell the system to actively change or alter these parameters to what you want. All this can be accomplished through the internet.
TRACK | MONITOR | CONTROL
Satellite & Wireless Communication
your assets globally
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engine valve alarm emergency position
SATPOS A S Solem ,NO-6480 Aukra Nor way
Phone: +47 46 74 36 44 Fax: +47 71 17 30 95 E-mail: email@example.com
PPSA member John Smart of John Smart Consulting Engineers in Houston addresses the challenge of sediment in oil and gas pipelines.
lack powder, or sediment in pipelines, is generated by corrosion reactions in the pipeline and can either accumulate in the line or move from fluid drag in pipelines once the velocity reaches a certain minimum value. Or, black powder can be swept clean by pigging. Knowing the velocity required to move loose powder can help plan the cleaning of a pipeline. This helps to prevent sticking of pigs by solids accumulation in front of a pig. The bed height to which black powder can accumulate under existing flow conditions can help plan the amount of debris expected to be removed from a line and therefore the method of cleaning. Particulates consisting of iron oxides, sulfides, carbonates, sand, salt, clay, asphaltenes, and so on, can be generated in a pipeline if water exists in the line and the water can wet the walls of the pipe. Corrosion can also occur in nominally dry pipelines under upset conditions and during hydrotesting. Solids will accumulate as sediment if the velocity is not high enough to drag the particles along or if they are glued in place by hydraulic oil or corrosion inhibitors, or form crusty deposits. Sediment deposits will cause increased pressure drop through the pipeline and can lead to blockage of the line, especially during pigging. Build-up of solids in front of a pig can cause the pig to become stuck. For a 12-inch pipeline with Â˝ inch (1.25 cm) deep deposits in the bottom of the line only, the volume of solids is about 223 per mile, weighing over 4000 pounds per mile (1130 Kg/KM). If the depth of the deposit were one inch, the weight of iron oxides/sulfides would be over 18,000 pounds per mile (5000 Kg/KM). Build-up of solids in front of a cleaning pig can cause a plug to develop in the line, which can stick the pig.
Planning ahead Knowledge of whether or not the flow conditions can sweep solids through a pipeline ahead of a cleaning pig is thus of great importance when using pigs to clean a line, and of fundamental importance in designing the pig cleaning process. Sticking a pig in a pipeline is a problem on land, but absolutely cannot be tolerated in offshore lines. In deep water, it would be extremely difficult to handle these solids accumulations and would likely require replacement of the line if they could not be removed. Furthermore, when an offshore platform loses its sales line, the platform must be shut in, cutting off production. Pipelines must be cleaned for a number of reasons, including the need to maintain operating efficiency, to be able to successfully run ILI tools, and to distribute corrosion inhibitors over the entire internal wall of a pipeline in wet multiphase gathering systems. Solids can include produced sand, corrosion products such as iron carbonate, iron oxides and iron sulfide, metallic iron, weld spatter, salt, asphaltenes and scale. The term black powder is a good generic name for these solids, as sometimes they don’t seem to have a lot in common other than being black. When a disc, scraper or wire brush pig is run inside a pipeline, solids are scraped off the wall of the pipe and pushed in front of the pig. Whether or not these particles fall to the bottom and stop moving or are swept along by fluid velocity determines the extent of solids that will accumulate ahead of the pig.
• Use of fluid by-pass and jetting in front of the pig • Use of gel pigs to suspend the particulates depending on how much solids is expected to be in the line • Use of less aggressive cups and discs on the pig Other operating parameters such as how long the pipe can remain out of service are also important factors. Use of heavier more viscous oils will result in much longer particle settling times back to the bottom of the pipe if stirred up by turbulence in front of the pig.
Figure 2 : VELOCITY TO MOVE IRON COMPOUNDS IN 20OAPI OIL 20 8 inch
30 inch 5 0 0
Particle equivalent diameter, inches
Figure 1 : VELOCITY TO MOVE SAND PARTICLES IN WATER
4 8 inches 3 12 inches 2
18 inches 24 inches
1 30 inches 0 0
Diesel is sometimes used for cleaning pipelines as the compound is relatively inexpensive and available, and much of it can be recovered or sold. The velocity for entrainment of the same iron compounds is shown in Figure 3, with velocities similar to 20oAPI oil. In eight-inch lines, 1 mil (40 micron) particles will move at 1.9 feet/sec., and at 6.1 feet/sec for fivemil particles. For 18-inch lines, one-mil particles will move at 3.8 feet/sec., and 8.6 feet per second for five-mil particles. Thirty inch lines require 5.8 feet per second for one-mil particles and 10.3 feet per second for five-mil particles.
Particle equivalent diameter, Inches
Water velocity to move sand The velocity to move rounded sand particles with a shape factor of 1.5 in water at 60F is shown in Figure 1. Pipe diameter is given in inches. The velocity required depends upon pipe diameter but is fairly constant for sand particles greater than about two-mils (50 microns) effective diameter. The meaning of this velocity is that for a pipeline being pigged, if the fluid velocity is greater than that shown, particulates in front of a pig will not pile up to form blocking deposits.
Iron compounds in 20oAPI oil The calculated velocity to move iron compounds in 20oAPI oil by velocity is shown in Figure 2. Oil velocities from 10 feet/sec to over 15 feet per second are required, plus the 10-15 percent safety margin for uphill flow. Some types of pigging programmes designed to accommodate solids is still desirable. These include: • Progressive pigging
Figure 3 : IRON COMPOUNDS IN NO. 2 DIESEL. THE PROPERTIES OF THE DIESEL USED FOR CALCULATIONS WERE 32OAPI DIESEL AT 60OF, WITH A VISCOSITY OF 200 CP. 14 12 10
8 18 inch
2 0 0
one micron. Extremely fi ne powder like this can pass through normal pipeline fi lters. They also report that extremely fi ne powder such as one micron can be tolerated by reciprocating compressors, but can damage turbine compressors, even with fi lters in place. These velocities also illustrate the cleaning requirements when crude oil pipelines are converted to natural gas service. One technique to keep the amount of black powder flowing down a pipeline is to treat the line with corrosion inhibitor. Corrosion inhibitors put a tacky fi lm of the wall of the pipe to which the black powder sticks, making it immobile. Figure 5 shows the effect of pipeline operating pressure on the velocity required to move 1 mil diameter and fi ner black powder particles in an eight-inch pipeline.
Particle equivalent diameter, inches
Lines using No. 2 diesel should also be treated with caution as larger particles will collect in front of the pig and will need to be pushed by it. Th is means that diesel is not a particularly good fluid to use when cleaning very dirty pipelines containing black powder. Also, with the safety margin added in for up-hill flow, these numbers may be a bit optimistic. Therefore, by-pass pigs with jetting nozzles, progressive pigging or gel pigging is more conservative for lines with iron oxides, sulphides and carbonates in them.
Black powder in natural gas pipelines Figure 4 shows the velocity to move black powder in natural gas pipelines operating at 60F and 1000 psi. Gas velocity is 10.4 feet per second in eight-inch lines, up to 13.6 feet per second in 30-inch lines. Natural gas pipelines can vary in their flow velocity depending on the season, and may cycle above and below this number. If the pipeline was operated in a corrosive condition, even just enough to cause mill scale to flake off the inside wall, large amounts of black powder could result that could possibly be delivered to customers, or, at the least, require substantial fi ltering before delivery. These results explain why gas pipeline compressor stations need to have fi lters installed in front of compressors, to catch black powder coming down the pipeline. Pipeline operators report that as black powder is transported down a pipeline, it fractures and becomes very fi ne, with a size in the range of Figure 4 : BLACK POWDER IN NATURAL GAS PIPELINES 16 14
12 12 inch
4 30 inch 2 0 0
Particle equivalent diameter, inches
Figure 5 : VELOCITY TO MOVE BLACK POWDER PARTICLES IN AN EIGHT-INCH PIPELINE AS A FUNCTION OF LINE OPERATING PRESSURES 40 35 30 25 20
0.00001 inch diameter
0.0001 inch diameter
0.01 inch diameter
5 0 0
Gas pressure, psi
Challenges ahead Conversations with pipeline operators reveal that when pipelines are cleaned for such purposes as ILI inspections, using pigging with and without chemical cleaning initially results in a clean line. However, after some time, black powder is usually found coming down the line again when the lines are dry. Further, many gas pipelines are not dry, but contain compressor lubricating oil and possibly other liquids such as glycol which can adhere solids to the wall of the pipe and keep them from moving. One common technique to keep black powder from moving is to treat the line with a corrosion inhibitor. Inhibitors are tacky compounds and can glue black powder in place. Further, operators report, when black powder solids move down a pipeline, they tend to fracture and become very fi ne, in the range of one micron or less. These particles are more easily moved down a line. One advantage for fi ne powder in pig cleaning is that it settles much more slowly than coarse powder, and can be kept fluidized more easily by turbulence. However, it is much more difficult to fi lter. The most important problem with black powder movement is that it can destroy equipment such as gas compressors and turbine generators by the abrasive action of the particles on the equipment. â–
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Will universities and corporations develop enough talent to address the looming retirement deadline of 2016? Frank Rudolph, SVP of Human Resources at Devon Energy, explains how Americaâ€™s largest independent oil and gas producer is growing new talent and addressing the recruitment challenge.
act 114 www.ngoilgas.com
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or Frank Rudolph, SVP of Human Resources at Devon Energy, the biggest challenge facing the HR sector in the oil and gas industry is the huge amount of the workforce due to retire from 2016 onwards. “From an industry perspective there will be a whole host of people about to retire at once, and while the economic downturn may have pushed that out by a couple of years, the reality is that this remains a huge challenge,” he explains. This translates into a dire need to pull as much talent into the industry as possible. At Devon Energy, Rudolph is looking to attract graduates directly off the college campus in order to meet the technical and talent requirements that will be in short supply come 2016. “We do a whole host of things when we recruit off the college campus,” he reveals. “We are heavily recruiting from an internship, so we’ll start getting interns in around sophomore year and then we usually develop them and select which ones we want to have come back in the junior year, and then again from senior year. Just over 90 percent of our college hiring is right from our internship program.” Once they are hired, interns will be placed into Devon’s postgraduate development program, and depending on what discipline they choose this could take as long as four or five years. Rudolph explains that Devon has an extremely defined program for geoscientists, petrochemical engineers, accountants, IT and even HR. “The program will progress from improving their technical understanding in their discipline, to learning about the business and the industry and improving their application of skills, as well as specifically working in the particular area and assets they are dealing with,” he says. And after the postgraduate development program, employees are fed into the company’s succession planning process. A robust process that drives individual development plans means Frank Rudolph is SVP of Human that internal candidates will always be considered Resources at Devon Energy, America’s before the company looks outside to potential largest independent oil and gas producer. new employees, he explains. “We’re continuing to look at the company by division looking at bench strength to drive individual development plans, and from a development standpoint we will consider what additional development they need and what their career goals are. From there we are able to balance career goals off development needs and we’re able to make internal selections, so there’s a lot going on with respect to development.”
Fresh blood And while Rudolph considers the mass-retirement of current employees from 2016 onwards to be a challenge unlike many of his peers he believes that attracting new blood to the industry is actually becoming easier. “If you look at the numbers of college graduates in the mid-1980s, especially in the petro-science area, there was hardly anybody that went into it. Today, you are seeing colleges in the technical areas, particularly in the petro-sciences, get more students enrolled than they’ve ever had in the past,” he explains. “And that’s partly because of starting salaries for petro engineers versus an industrial engineer, for example. There’s undoubtedly been an improvement in terms of schools convincing people that this is a good industry to go into as well as some dramatic growth. So off the college campus it’s becoming a bit easier.” However, despite new talent being easier to come by and even with the growth on college campuses, the amount of people entering the industry is not going to offset the number of people leaving the industry in the next few years. In fact, Rudolph believes this crisis could have the same impact as the recent economyic downturn on the industry.
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Recognition This was the second consecutive year that Fortune magazine ranked Devon Energy among its 100 Best Companies to Work For, distinguishing the Oklahoma-based independent oil and gas producer as one of the nation’s most desirable employers. “While making the Fortune list is wonderful recognition for the company, it says even more about our employees,” said Devon’s chairman and Chief Executive Ofﬁcer, Larry Nichols, when the announcement was made at the start of the year. “Our employees’ values and their commitment are what make Devon a great place to work. We have an outstanding company with many wonderful assets, but we believe our people are at the foundation of our strength.” Even in the current recession, some companies are going out of their way to please employees. As Google slips to number four, 2009 sees a new number one. Will 2010 see another boost for Devon? 1. NetApp (14*) 2. Edward Jones (4*) 3. Boston Consulting Group (11*) 4. Google (1*) 5. Wegmans Food Market (3*) 13. Devon Energy (48* * 2008 ranking
“Look at the impact the current price of oil and natural gas has on your capital investment – look at the huge amount of declining rigs around the world, especially projects that are more short-term, and the amount of capital reduced there. If you don’t have the same capital you can’t go after the resources that the world needs, and I think this talent shortage situation will have the same impact. If you’re not able to grow enough talent to meet your needs, you aren’t going to be able to drill enough to meet the needs of a nation because you won’t have the technical expertise. And I’m not saying this is the absolute scenario, but that’s what every company, from the majors to the small and large independents, are working really hard to make sure doesn’t happen.” That said, continues Rudolph, when you are looking for people that are between the ages of 40 to 50 with high technical skills, there are some big issues. “Trying to fi nd people with 20 years of experience takes us back to the 1980s when the oil and gas industry had some really big-time issues. And again they couldn’t get anyone to go into those disciplines, which now means there is a big hole in the market.” So how is Rudolph attracting employees with the requisite experience? Well, he explains, fi rstly from a total compensation standpoint, Devon pay more at a competitive level. The firm also made a decision a couple of years back to look at the retirement program and went from a defi ned benefit to a defi ned contribution. Indeed, Fortune also tabbed Devon at number six on its list of ‘Eight Great Places to Retire From’ in October 2009. After beefi ng up its retirement program in 2007, overhauling its program and contributing eight
percent of a new employee’s salary into a retirement account, boosted to 16 percent after the employee completes 15 years of service. And Devon will match employee contribution up to six percent, unlike most companies that typically match only half of employee contributions up to six percent, meaning the company’s total offering can reach 22 percent. “Our defi ned contribution amounts, which are when someone gets to around 10 years experience, receive 22 percent of their pay matched onto that defi ned benefit program – and as such it’s been described as a 401(k) on steroids. With this we can convince people to make a midterm career decision based upon what they can see in front of them from a retirement point of view, and that has really helped a lot.” Rudolph also believes that the working culture at Devon, driven by these values and attributes, has made a big difference to how potential employees perceive the independent oil and gas giant. “I’m not just talking about the recent economic recession; people look for a culture that they can relate to, for values that are practiced in the company, and that helps to attract the talent.” And in respect of the values of the company, Devon was voted the 13th in Fortune’s 100 Best Companies, moving up 35 places from the previous year – which, according to Rudolph, significantly added to Devon’s employment brand. “It’s a powerful brand and provides great recognition internally that we’re doing the right things and that our employees recognize that too, so it’s a great feedback loop that we can use,” says Rudolph. “And mostly I would say that once in a while it’s just nice to get recognized for doing positive things, especially in the climate we’re looking at today. And we’ve seen a huge increase in the amount of unsolicited resumes that we get, particularly as over 90 percent them reference the 100 Best Places to Work For status.”
Talent Absolutely critical to Devon’s success is the development of top talent at the firm. While the company continues to attract employees, people development is key if Devon want to keep its best staffi ng resources. “It’s really about what I would call a world class approach,” says Rudolph. “With a creative approach, processes drive quantitative results around people development. Looking year over year and asking ourselves whether we are moving the needle with respect to developing our talent is critical. And whatever you’re doing on a short-term basis, it has to feed into a longer-term workforce planning model that deals with and understands your drivers for adding people – which could be capital investment, wells drilled, etc. You then need to understand how that spreads to the rest of the company. “We’ve moved very quickly from a soft approach on developing staff to a very process, quantitative, disciplined approach to developing talent both in the short-term and the long-term too. Understanding your needs tomorrow and making sure that you’re balancing the need that you’ll have tomorrow with what you are doing today with regards to developing talent is key.” It seems Rudolph has a balancing act on his hands to ensure that both new recruits continue to be attracted to the company as well as prepare for the inevitable departure of the babyboomer generation from 2016 onwards. That said, Rudolph is working hard to ensure that the disruption to his fi rm is kept to a minimum.
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RWD AD.indd 1
NEXT BIG THING
Critical tools for tough times Frank R. Lloyd explains why planning for growth is essential – even in a downturn.
here are a few critical tools oil and gas companies must use to survive and thrive past the current and unprecedented economic conditions. Primary among these is sustaining investment in training and development. Many companies today are continuing to do so even when instincts honed in the past dictate otherwise. Why? First, even with recession, in the next five to 10 years many skilled and experienced oil and gas professionals will retire. Assuring leadership succession in the face of this exit of knowledge and talent is among the industry’s top challenges. In addition, aging infrastructure, price volatility, increasing mergers and acquisitions, escalating costs and diminishing reserves all combine with shift ing global political landscapes to raise the standards for effective leadership. Finally, investments in training communicate value to employees that firms wish to retain when mobility becomes easier in a strengthening economy. Investing in current talent is an important tool for forward thinking firms that wish to position themselves ahead of the competition when business conditions rebound. Here are five more. Attract the best employees. This economic downturn is unleashing legions of qualified and experienced people into the job market. Shrewd
companies, acting countercyclically, can select and choose the best talent from a deep reservoir of manpower. Plan for debt coming due. Avoid becoming a victim of the credit freeze by reviewing longterm debt, loan covenants and any major interest payments coming due in the next 12-18 months. Plan to refi nance debt with the assumption that it will be difficult to extend current terms. Inform existing shareholders if a debt for equity exchange is planned so that major fi nancial stakeholders can be prepared for future possible dilution.
customers and work with them to design more customized solutions. Look out for problems in your supply chain. Look to alternative suppliers for off-the-shelf needs just in case. On core products and technologies, work with suppliers to share costs and risks. The upside is that both will profit handsomely when the economy recovers.
Prepare for new types of competitors with the upturn. It may feel tight now, but the heat will really be on if you are unprepared for a whole new wave of competitors in the future. Th is is a good time to look for strategic alliances that provide an advantage Frank R. Lloyd, PhD, is Associate Keep your customers over a potential future rival. Dean of Executive Education for the Cox School of Business at without discounting. CusRecessions are breeding Southern Methodist University. He is responsible for programs for tomers are stretched, and grounds for innovative techexecutives, managers and working competitors may be cutnologies, so don’t slam the professionals. He joined SMU from the Thunderbird School of Global ting prices to stay in busidoor shut on new ideas. Management where he served as Vice President of Executive ness. To avoid destroying Using these tools, this Education. hard-earned brand equity, downturn can be an opreposition your product or portunity to re-evaluate and service around its distinctive attributes. Offer redefi ne your position over the next five years. your best customers longer payment terms. Try Chances are someone else – your next newest short-term promotions that attempt to reel in competitor – is already doing so and targeting new customers. Large firms should visit their your customers.
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ASK THE EXPERT
Bridging the talent gap The oil and gas industry has woken up to the fact that its people aren’t getting any younger and that within the next 10-15 years, much of its talent will retire and leave. Mark Guest explains the importance of continuing to invest in talent despite the drop in oil price.
he ‘Big Crew Change’ has become a major topic over the past few years when forward thinking businesses began to look at how they would bridge the future knowledge gap. Industry bodies invested in attracting young people into the sector and individual companies developed their own program to attract both graduates and mid-career employees with existing skills – the oil and gas industry jobs market boomed. In the last quarter of 2008, the oil price dived, dropping by 70 percent in a few months. In terms of jobs, this could have led to a similar crash and many expected it would. However, the oil and gas jobs market has contracted slowly. Vacancy numbers on our international jobs board, Oilcareers.com, continued to grow until the end of 2008 before easing back and stabilizing at levels comparable with those of the previous summer. Despite headlines of tens of thousands of jobs being shed, in reality, the industry may have learned the lessons of earlier oil price drops where severe cuts in manpower led to the loss of whole generations of oil and gas workers. In previous periods of oil price contraction, jobs were shed quickly and ruthlessly,
careers. Th is is why there wanting a long-term are the age gaps in today’s future in renewables to industry demographic. first cut their energy teeth The Big Crew Change in oil and gas. remains a serious chalEveryone who works lenge to the industry. in the oil and gas industry Although energy demand has prospered with high has eased in 2009, growth oil prices and we will still will inevitably return in do so even if oil prices the future and the global continue at the $60-$65 output of oil and gas will level, which they are at increase again to meet now. We shouldn’t forget demand. Th is means that even this price per that the skills that leave barrel is still high, even the industry in the next when historical prices are Mark Guest joined Oilcareers.com as decade will still have to be adjusted for inflation. Managing Director in April 2009, tasked with driving UK and international growth. replaced. We will need an Operators and serPrevious to this he was Company Director at AVC PR Partnership, developing an even greater skills base in vice companies need extensive knowledge of the oil and gas the future, as hydrocarto make sure that they industry from working with operators and service companies in the UK and bon production becomes remain employers of internationally. increasingly challenging. choice, and that any cut The oil and gas inbacks due to drops in dustry has been at the forefront of engineering profit don’t lead to the skill base going in other challenges and innovation for decades and this directions. BP Group Chief Executive Tony will continue. Renewable energy will become Hayward, recently said: “The challenges the increasingly important and it will be an atworld faces in growing supplies to meet future tractive career path for young people forging demand are not below ground, they are above their careers. However, much of the expertise ground. They are human, not geological.” Hopefully the industry will listen to this advice and remember that the challenge of the Big Crew Change is still present. Using Oilcareers.com as a benchmark, with more than 550,000 registered users, right now the industry is still seen as a desirable career choice. However, if the industry stops investing in its needed by this growing sector will come from people, it may reduce costs in the short-term, the oil and gas industry through skills transfer. but in the not too distant future it will face a In many respects, the established sector will real crisis: a human crisis without the skills lead the newcomer, so it makes sense for those needed to prosper.
“However, much of the expertise needed by this growing sector will come from the oil and gas industry through skills transfer” resulting in many vital, experienced people turning their back on the industry. More significantly, the sector was seen as far less attractive for clever young people beginning their
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The International Association of Oil and Gas Producers has been publishing safety data since 1985. Hans Jorn Johansen, Head of the Safety Committee, examines the improvements the industry has seen in the past 24 years and looks at what can be done in the coming years to enhance current industry standards.
n the last 20 years or so the oil and gas industry has acknowledged that accidents are preventable, that safety is a value and that it is not a competitive edge. It is important to emphasize that accidents are not unmanageable, they are simply something of the past. I was attending a conference in Tehran just a month ago and it was particularly impressive to hear in the opening ceremony that accidents are preventable, that we do not need to have accidents happen. Lifting and hoisting, driving safety and diving safety are our absolute number one killers and we now see statistics that these three areas are the ones that we still do not have a good handle on and continue to see too many fatalities occurring. These are the accidents where we see a high frequency, meaning they occur frequently. They may only kill one or two at a time but they are just as important as the accidents that occur less frequently but incur a high number of fatalities. We have therefore targeted our work in the last five years towards these three particular areas. A few years ago, a set of best practices was issued in regards to lift ing and hoisting to address recommendations from the best operators in the world and we are hoping that everybody will be using or implementing these best
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The International Association of Oil and Gas Producers has been publishing safety data since 1985. Hans Jorn Johansen, Head of the Safety Committee, examines the improvements the industry has seen in the past 24 years and looks at what can be done in the coming years to enhance current industry standards.
n the last 20 years or so the oil and gas industry has acknowledged that accidents are preventable, that safety is a value and that it is not a competitive edge. It is important to emphasize that accidents are not unmanageable, they are simply something of the past. I was attending a conference in Tehran just a month ago and it was particularly impressive to hear in the opening ceremony that accidents are preventable, that we do not need to have accidents happen. Lifting and hoisting, driving safety and diving safety are our absolute number one killers and we now see statistics that these three areas are the ones that we still do not have a good handle on and continue to see too many fatalities occurring. These are the accidents where we see a high frequency, meaning they occur frequently. They may only kill one or two at a time but they are just as important as the accidents that occur less frequently but incur a high number of fatalities. We have therefore targeted our work in the last five years towards these three particular areas. A few years ago, a set of best practices was issued in regards to lift ing and hoisting to address recommendations from the best operators in the world and we are hoping that everybody will be using or implementing these best
Hans Johansen.indd Sec1:122
practices. The documents are freely available to anybody and we promote them at all the safety conferences we can around the world. Last summer we published another recommended practice on diving safety also because this was the third area we have been targeting in the last five years. Low frequency, or the accidents that happen very rarely – say every one to three years – have something to do with what we call process safety. The purpose being that you maintain your plant such that you know you can rely upon safety features and that it will not all of a sudden break down or cause a series of events that eventually cause the whole thing to blow up, killing or injuring a lot of people. While we are less likely to see these accidents it is nevertheless an important area to deal with because the accident may have had a long time to build up, slowly breaking down the very complicated system that has been set up to ensure the safety and integrity of the plant. These accidents are much more complicated to deal with than a straight-forward accident that just kills one person at a time.
Pressure Oil and gas companies are engaged in exploration projects in some of the most inhospitable regions of the world requiring high standards of safety. While best practices are developed and can be taken and implemented around the world there are many more challenges when starting from scratch in the middle of nowhere as opposed to being in a fairly developed region of the world where facilities are available. The International Association of Oil and Gas Producers (OGP) represent around 50 percent of the world’s oil and gas productions and from our perspective best practices are increasingly being developed and taken around the world. That means our members represent a large proportion of the oil and gas exploration and production that takes place. Of course I can only speak on behalf of the 50 percent of the world’s oil production that our members represent so we still have challenges as regard to the other half of the oil production that takes place through other companies that we are not directly dealing with. Will we come to represent more than 50 percent of the world’s oil production? Well, only time will tell, but over the last two years we have been quite active in promoting OGP as an organization that gives something to its members and I have seen interest from companies in parts of the world were we haven’t been so strongly represented, such as Australia and the Far East. We have actually seen seven new members just recently, including a company in Greenland, and I have seen the growing interest of being part of a good organization.
Best practices With so much experience in the oil and gas industry available today it should be possible to take down and state the way you do business and then reapply that in a different part of the world in a different plant, and in a sense provide comprehensive safety guidelines, or best practices, for all workers. However, for some reason it doesn’t seem to be as simple as that. In my mind if you do not try to accumulate your experiences and learning’s and transfer them to other parts of the company then you
are wasting your energy. And that is one of the good things about being active in OGP, you are no longer competing with best practices, you are sharing your best practices and opening up completely to anybody who wants to know something; you can get this information through a couple of mouse clicks on the computer or by calling somebody, to help you immediately. I believe that is truly inspiring. In order to achieve this, we at the OGP will need to better manage our documents and we need to have a more interactive webpage that people can really use, because sometimes it is not enough to have the telephone numbers of the right people to call. Sometimes you are not ready to call somebody and say, ‘Look here, I need help, I’m standing in the middle of Alaska’. Sometimes people want to go to a webpage and look at a Q&A, and so that is what we’re developing at OGP right now. We have set ourselves a target to be the foremost reference point as regards to health and safety in the world and we are going to build databases of all this information that anybody can access from anywhere in the world. In addition we will be developing key performance indicators because we need to have these in place before we can start saying these are the best practices. We will be starting to collect information to know what to manage and this will be the starting point for safety integrity works, but before this we need the indicators. We will start publishing them from next year onwards and this will ultimately result in a best practice document. We are defi nitely spreading the safety
A global industry The International Association of Oil and Gas producers (OGP) encompasses most of the world’s leading publicly-traded, private and state-owned oil and gas companies, industry associations and major upstream service companies. OGP members produce more than half the world’s oil and about one third of its gas. OGP has been publishing safety data since 1985. Though there have been improvements in terms of fatalities in recent years, much remains to be done, particularly in the areas of land and air transportation, marine transfer and lifting and hoisting, as well as diving and marine operations. In particular, OGP’s Safety Committee aims to: • Promote the integration of safety into the everyday business of OGP member companies and other E&P companies and contractors • Provide safety leadership with cost effectiveness • Promote a level playing ﬁeld for safety that is recognized by the E&P industry and administered by national and global regulatory authorities.
message around the world and are also hoping to gather more information on performance indicators and on experiences, but we need more information before we can publish a best practices document on this because it is such a complicated subject.
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WAKING A SLEEPING GIANT Given its former status as a gulag for exiled Tsarist dissidents, Sakhalin Island has long had a reputation as one of the bleakest places on the planet. But thanks to its abundant reserves of oil and gas, the island could yet prove an unlikely source of hope for global energy markets â€“ a fact not lost on IOCs, argues Senior Editor Ben Thompson.
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s operating environments go, the oil and gas fields of Sakhalin in Russia’s Far East are up there with some of the harshest on the planet. Offshore temperatures in the North of the island regularly plunge as low as 40˚C, and storms whip the waves up to 10 meters in height. For at least six months of the year, the Sea of Okhotosk is covered in thick ice, complicating navigation and oil production. The frequent typhoons can produce up to 220mm of rain during a single 24-hour period, while winds often reach hurricane strength. And to complicate matters further, the island sits atop one of the most active seismic areas on Earth. There are more than 40 active volcanoes on the island, while some 2000 people died in the 1995 earthquake in Neftegorsk in the north of the island. With the risk of seaquakes just as great, any structures – onshore or off – must be designed to withstand the worst. Dramatist Anton Chekhov, visiting in 1890 when the island still housed the largest prison camp in the world, described it as “hellish” – and in such an elemental environment, it’s easy to see what he meant. Still, for those willing to brave the extreme climate, the rewards are rich indeed; the 600-mile-long island is also home to some of the world’s most lucrative hydrocarbon reserves. An estimated 45 billion barrels of oil equivalent lie beneath the icy seas off its shores – recoverable oil reserves of almost seven billion barrels, and natural gas reserves reckoned to be in the region of approximately 80 trillion cubic feet. As such, Sakhalin has proved a magnet for international companies looking to gain a foothold in Russia’s significant oil and gas plays. And even though developing those resources is proving lengthy, difficult and expensive, there are signs that progress is finally being made.
International experience When the Russians first discovered oil at Sakhalin in the mid-19th century, the find was so inaccessible that it was all but ignored. Even as recently as the 1980s, when geologists began to understand the vast scope of the offshore resources, it was unclear how the remote oil and gas could ever be brought to market. It was only when the Russian government invited tenders from international companies with the offshore experience required to develop such fields that Sakhalin’s long-held promise began to be realized, through the creation of a number of multinational consortiums. The Sakhalin II project is one such example. A joint-venture between Russian majority shareholder Gazprom, Anglo-Dutch company Shell and Japanese firms Mitsui and Mitsubishi, the project is operated under the Sakhalin Energy Investment Company and represents the world’s largest integrated oil and gas project. It comprises six large-scale subprojects being advanced in parallel to develop the island’s Piltun-Astokhskoye and Lunskoye fields, and includes three large platforms located off the north coast, an onshore hydrocarbon processing plant, a gas liquefaction plant in the south, an oil export terminal and many hundreds of kilometers of connecting oil and gas pipelines. “Sakhalin Energy has been at the forefront of developing this new province,” explains the company’s CEO Ian Craig proudly. “We installed Russia’s first offshore platform in our initial phase of development. Now, we have just finished Russia’s first LNG plant as well as the TransSakhalin Pipeline system, two new platforms and an onshore processing facility. To be able to contribute to the development of such a frontier is very satisfying.”
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It’s been a significant undertaking for Craig and his team. The project employed some 25,000 people from more than 30 different nations at the height of the construction phase in 2007, during which Sakhalin Energy transported goods and people a distance of six million kilometers monthly – the equivalent of seven trips to the moon and back each month. The onshore pipeline system entails a total of 1600km of pipe, equal to the distance between Moscow and Berlin, and crosses more than 19 seismic faults and 1000 watercourses. Offshore pipelines have been rerouted to address environmental concerns over the endangered Western Gray Whale. And the Lunskoye-A offshore gas platform, Russia’s first, incorporates a series of trail-blazing (not to mention record-breaking) engineering and technology innovations. Total costs are estimated in the region of $20 billion, with around $500 million spent on much-needed infrastructure upgrades to the island alone.
Global energy challenges Despite initial concerns over the size of the budget, a growing body of evidence suggests such investment is critical to the world’s energy markets. Global demand for power is expected to more than double by 2050 as economies and populations grow, and supplies of easy-to-access oil and gas will have difficulty keeping up with surging demand. At the same time, environmental stresses are increasing, with rising carbon emissions a major concern. As such, natural gas – the cleanest-burning fossil fuel – has a key role to
play in meeting future energy needs, with Sakhalin’s vast reserves a major part of the plans of both national and international oil companies alike. The industry is betting that liquefied natural gas (LNG) will provide the means to bring clean, abundant, affordable natural gas from the fields where it is produced – often in remote areas far away from customers – to local markets where it is needed. LNG can be transported and stored more easily than natural gas because it occupies up to 600 times less space; it also reduces dependence on costly pipeline systems for transportation, a significant handicap to the profitability of the natural gas sector to date. Transforming the gas into a liquid makes transportation more efficient and brings geographically remote gas fields such as Sakhalin into play as serious energy sources. It’s a view shared by energy analysts. “A widening separation of supply from the demand centers favors the economics of LNG over pipeline gas,” explains Daniel Yergin, Chairman of Cambridge Energy Research Associates. “LNG also brings something else that is very compelling: flexibility. This becomes increasingly important as the global gas market develops. The next two years will see a giant step-up in LNG supply. Global capacity will rise by almost one-third by the end of 2010, and Sakhalin II is an important contribution to that growth.” The centerpiece of the Sakhalin II project is its LNG production plant and offshore export terminal, located near Prigorodnoye on the south coast in Aniva Bay. Two identical processing units (or trains) process gas to produce
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Sakhalin II project: KEY MILESTONES
The value of collaboration
Shell’s successful collaboration with Gazprom on Sakhalin II proves that there is a signiﬁcant role still for international oil companies in developing regional projects. But in the ongoing effort to access hydrocarbons, IOCs 1984 increasingly face a major challenge: convincing national oil companies and host Lunskoye ﬁeld is discovered in the governments that they provide value beyond merely ﬁnding and producing oil northeastern part offshore Sakhalin and gas. According to a recent report from Ernst & Young entitled What Next for 1986 International Oil Companies, to be successful in today’s environment IOCs must Piltun-Astokhskoye ﬁeld is discovered in demonstrate and communicate that they seek long-term partnerships with the northeastern part offshore Sakhalin NOCs and possess an organizational culture that is focused on listening – and responding – to the full range of host governments’ social and economic needs. 1991 “IOCs must realize that investing in and developing local workforces and The USSR announces an international supporting economies is a necessary part of doing business around the world tender to conduct a feasibility study for today and that their ability to do so is yet another competitive advantage over the development of the Piltunsmaller, single-service competitors,” says Rob Jessen, Global Oil & Gas Sector Astokhskoye and Lunskoye licence blocks Leader at Ernst & Young’s Houston-based Global Oil & Gas Center, and author of the report. 1994 The report suggests IOCs must learn to package elements of their core value The Sakhalin II PSA is signed by the proposition – technology, ﬁnancial resources, access to markets, project Russian Federation, the Sakhalin Oblast execution expertise and vertically integrated offerings – in innovative ways that Administration and Sakhalin Energy are customized to each individual market. “Adaptability is the watchword for future contractual negotiations,” says Jessen. “The willingness to seek out 1999 balanced win-win agreements is key.” Commercial oil production begins from Meanwhile, IOCs must recognize and respond to the looming talent the Molikpaq platform at the ﬁeld, shortage in the energy industry by designing enterprise-wide human capital Russia’s ﬁrst offshore oil production programs that strengthen their ability to attract, train and retain key employees who bring the unique skill sets and expertise that NOCs need. And they must 2003 continue to work to develop their in-country relationships with experts in tax, Construction starts on the TranSakhalin ﬁnancing and other ﬁnancial and business regulatory issues in order pipeline system, one of the largest to negotiate from a position of knowledge and understanding. systems in the world “The global power shift is real, and it has serious implications for the future business prospects of 2004 international oil companies,” he concludes. “But those Sakhalin Energy delivers ﬁrst that are willing to adapt to the shift – and who do so No. of people working cargo of Russian Far East quickly and successfully – will maintain their on the Sakhalin II crude oil to Tohoku Electric competitiveness and viability in the decades to come.” project at the height Power Company in Japan
2006 The LUN-A platform is installed, Russia’s ﬁrst ice-class gas production platform
2007 Sakhalin Energy successfully installs the PA-B platform
2008 Year-round oil export begins through the Oil Export Terminal in Prigorodnoye
2009 Sakhalin Energy delivers its ﬁrst LNG shipment to Japan
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A pioneering project Sakhalin II represented many Russian ‘ﬁrsts’, including: • The ﬁrst production sharing agreement (PSA), signed in 1994 • The ﬁrst offshore oil and gas development • The ﬁrst LNG plant • The ﬁrst opportunity for AsiaPaciﬁc customers to access Russian gas
17.3 trillion Estimated recoverable natural gas reserves at Sakhalin II, in cubic feet
9.6 million tons of LNG annually. The complex also includes storage tanks for LNG and oil, a 480-megawatt power supply, an undersea pipeline to the tanker loading unit and a seaport. The new plant lays the foundation for Russia to become a leading energy exporter to the highly competitive energy markets of the Asia Pacific region. “When the Sakhalin II project is fully on stream, it will supply around five percent of the world’s LNG and make a significant contribution to strengthening global energy security,” explains Craig. “About 98 percent of our gas is contracted on a long-term basis over 20 years, with two-thirds going to Japan and about 15 percent to Korea. Japan is the largest LNG market in the world, while Korea is the second largest. And they’re both on our doorstep. Sakhalin has now firmly established its position on the global energy map.” That position was further solidified when Japan received its first imported liquefied natural gas shipment from Sakhalin earlier this year.
Craig believes that Sakhalin Energy is now well placed to capitalize on that upward trend, and can even improve on its current nameplate capacity. “Once the system is fully operational, we’re looking at de-bottlenecking and other operational improvements in order to try and get an additional 10 percent out of it, so we’ll have a little bit of flexibility with those volumes,” he says. “If you look at most LNG developments, they rarely stop with the first two trains. We have decided not to progress a third train right now – we want the
An important milestone
company to focus on getting the first two trains up and running, and then the shareholders will take a look at future expansion – but I think there are sufficient reserves within the Sakhalin II PSA area to underpin that expansion.” Further exploration, in areas outside the boundaries determined by the Sakhalin II project agreement, is purely hypothetical at the moment as the company is only currently able to develop the reserves within the license area. However, in the long-term, he concedes that third-party gas could be looked at, as well as additional fields. “There is gas in Sakhalin I that hasn’t found a home yet. And there will be further exploration and development in Sakhalin III. So there’s loads of gas on the island, and we’ve invested in substantial infrastructure for its development.”
It’s a big step both for the company and for Russia as a whole. During the unveiling of the Sakhalin plant, President Medvedev conceded that its completion was an important milestone for the Russian government. “The project is of strategic significance, both to our country and to our foreign partners,” he said with barely concealed excitement. “It will promote our capabilities on gas supplies and Russia’s position as a global supplier of natural resources in the world.” Estimates indicate that LNG’s share of the international gas trade will grow significantly over the next two decades, with demand volumes forecast to increase 180 percent by 2020 and 250 percent by 2030.
“There’s loads of gas on the island, and we’ve invested in substantial infrastructure for its development” Ian Craig, CEO, Sakhalin Energy
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PRIGORODNOYE PRODUCTION COMPLEX
he liqueﬁed natural gas plant at Prigorodnoye is designed to receive, treat, process and liquefy natural gas. Annual gas import to the plant will total about 13.8 billion cubic meters, primarily from the Lunskoye ﬁeld. Gas treatment, processing and liquefaction will be performed on two parallel processing trains. Each processing train is ﬁtted with an acid gas (CO2 and H2S) removal unit; a gas dehydration unit with molecular sieves; mercury removal using activated carbon; fractionation for refrigerant and stable condensate production; and a gas liquefaction unit. To liquefy natural gas (clean methane CH4) it must be cooled to –162˚C through compression. The gas undergoes a 600-fold volume reduction and becomes liquid at ambient pressure. It can then be shipped by large tankers to a receiving terminal where the LNG will be re-gassiﬁed and delivered to
power generator customers and gas consumers through local gas distribution systems. Shell, the global leader in LNG technology, developed the proprietary double mixed refrigerant process especially for the Sakhalin II plant. This leading-edge technology is optimized in
The LNG is kept in the tanks until being loaded to LNG tankers. As the tanker approaches, LNG loading through the specially constructed jetty is started. The LNG jetty is 805 meters long and ﬁtted with four arms – two loading arms, one dual purpose arm and one vapour return arm. Water depth
“When the Sakhalin II project is fully on stream, it will supply around five percent of the world’s LNG and make a significant contribution to strengthening global energy security” Ian Craig, CEO, Sakhalin Energy such a way that it offers maximum efﬁciency in the cold Sakhalin winters whilst keeping the compressors running at their best performance. Liqueﬁed gas is directed to two isometric storage tanks with a capacity of 100,000 cubic meters each. The tanks are designed as two-wall structures 37 meters high and 67 meters in diameter.
at the tail of the jetty is about 13 meters, and the jetty can accept liqueﬁed natural gas tankers with capacities from 18,000 to 145,000 cubic meters. According to preliminary estimates, loading operations will take from six to 16 hours, depending on vessel capacity. The jetty will be able to load around 160 LNG tankers per year.
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For now, Craig insists the company remains firmly focused on the task at hand. “It’s entirely possible for us to get involved in other areas of exploration, but that would require further negotiation between the shareholders and the Russian government. Within our license, however, we have additional prospects to drill and appraise. For example, at Lunskoye we have prospects below the level of the current reservoir that we want to assess. We also have an oil rim that we want to take a look at, as well as various other structures that we’d like to assess south of our existing fields. But the key priority in the next couple of years is to get the current facilities up to full capacity. So any further exploration activity will be secondary to that objective.”
Getting up to speed Now that Phase 2 of the project is complete, attention has turned to the ramp-up stage – part of which involves the technology transfer from foreign specialists to local operations teams. “In the construction and startup phase there was a very heavy dependence on foreign specialists, primarily from Shell, but as time goes by those numbers will reduce,” says Craig. “Our technology transfer program involves training up Russian staff to take over those roles. In five years’ time, 90 percent of the company will be Russian, with 10 percent being outside specialists – nominated on a rotation basis from amongst our shareholder companies – to keep ideas fresh. We currently have a split of about 70/30 in favor of Russian employees.” Besides the obvious benefits of having a Russian workforce, the move is also a reflection of the recent ownership change that saw Gazprom assume a majority stake (of 50 percent plus one share) in the company. Until Sakhalin II, Gazprom had no LNG expertise, despite being the world’s largest gas producer and reserve holder. Being the largest shareholder of Sakhalin II, how-
ever, gives the Russian giant a very big window into this increasingly important industry. As far as Craig is concerned, however, the behind-the-scenes changes have had little impact on the project. Gazprom has few technical experts involved in the project at present, preferring to cede technical responsibility to Shell – although a Gazprom subsidiary will soon operate the onshore pipelines. “In terms of the day-to-day operations, there isn’t a huge change, to be honest,” he says with a smile. “We tend to drink vodka with dinner as well as wine, but there isn’t much difference in the day-to-day running of the company. It’s an international company with over 40 different nationalities, and Russian has always been the predominant nationality – even when Shell had a 55 percent ownership, there were many more Russians in the company than other nationalities. My own view is it will remain a very international company because it’s customer-focused, and because of where it is. And I’ve seen no inclination by Gazprom to change that. I think they see the business imperative of keeping that international aspect.” Indeed, he feels that Sakhalin II could serve as a model for other Russian megaprojects, such as the one that will be needed to develop the resources of the Yamal Peninsula, and that as a result Gazprom will want to make the project a success. “If you look at some of the developments that Gazprom has going forward, then the mix we have here at Sakhalin – where you’re blending Russian expertise, foreign expertise and both domestic and foreign capital – is a good basis for success.”
Opening new frontiers Experience demonstrates again and again that the development of large gas reserves in remote locations – particularly when using LNG – brings significant and sometimes daunting technical, financial and operational challenges. “The very size of LNG investments, with many billions of dollars in upfront capital, has often encouraged a joint-venture approach to share out the burden and risks,” confirms CERA’s Yergin. “Often the combination of the skill sets of national oil companies and international oil companies is what is required to bring about successful execution.” Viktor Martynov, Rector of the Gubkin Russian State Oil and Gas University, agrees. “The oil and gas business and its technologies are essentially international,” he says. “The era of easy fields is over; projects are becoming more complicated, and technological and financial challenges are often insurmountable for a single company. Tackling projects through international consortiums leads to lower costs, better budget planning and more qualified workers.” The alignment of interests between many different stakeholders can be challenging, but is critical if such developments are to be successfully executed. And it is this quality that Craig believes provides the defining success story of Sakhalin. “You may have a department or a company that produces oil or gas, a department that sells, and perhaps a department or company that makes LNG. In Sakhalin Energy we have all of that together – from the reservoir to the customer,” he states. “My vision of Sakhalin in 10 years time is that the island will have developed its capabilities much further. It will have homegrown contractors that can service the international oil industry, not just the Russian sector. They will be competing internationally, going out in the world and doing equally challenging work, perhaps in the Arctic. I’ve seen this model develop in other parts of the world. So in the future, when I bump into a Sakhaliner in some remote corner of the world I will know that we did a good job here.” n
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IN MY VIEW 132
Global upstream challenges In an October panel discussion on global upstream challenges at the Oil & Money Conference in London, ConocoPhillips CEO Jim Mulva provided an IOC response to turbulent times and challenges.
n discussing our upstream challenges, I’ll start with the obvious – the world economic downturn. It has caused the largest decline in energy demand in 25 years. Oil prices that took eight years to reach $147 per barrel – after stagnating for two decades – lost more than two-thirds of that value in eight months. Today, they are $70 – but may not hold. Compounding this are government fiscal takes. A number of countries raised their takes during the boom, assuming that prices would remain high. Now, most have not lowered them. Also, reserve replacement costs are more than double their 2003 levels. They are not falling as fast as prices did. All these factors challenge the economics of new investments. Government seems to assume that we will invest anyway. But perhaps the screws have now been tightened too much. World upstream investments are down by $100 billion this year, or 21 percent, according to the IEA. There are other challenges, like restricted access. In many resource-rich countries, the best (if not all) opportunities go to NOCs and IOCs are left out, despite their expertise and access to capital and markets. There is also climate change legislation pending in key countries. This creates uncertainty over what the rules and costs will be. Investment flees uncertainty. We need the world to decide what it will or will not do. And finally, we face political hostility. Fossil fuels are unpopular because of their price volatility and perceived carbon impact. So governments are promoting renewable sources. At best, they are ignoring oil and gas policy – while overlooking how natural gas could ease the transition to a low-carbon economy. Since fossil fuels must provide 80 percent or more of world energy even by 2030, this is like Nero fiddling while Rome burns. These challenges and flawed policies have serious implications. They could lead to new energy price spikes once the world economy recovers. Further, today’s energy downturn is not like the 1980s. We are unlikely to have a long production surplus and weak oil prices this time. The drop in oil demand then was three times today’s decline. Conventional non-OPEC
crude production was rising then, thanks to the North Sea and Mexico. Now, it is falling. And unlike then, world demand now is primarily driven by the rising prosperity of the developing world’s 5.6 billion people. They outnumber the population of the OECD countries by nearly five to one, and the margin is growing. So demand growth will inevitably resume, and renewable energy cannot meet it alone. Unless our industry is ready, and governments have the right policies, supply could fall short. This would damage the world economy and undermine living standards. At ConocoPhillips, we are dealing with these challenges today, while also anticipating tomorrow’s needs. We have adjusted our operating and capital programs to live within our means; the best projects continue, while others have been deferred. We are working with suppliers to reduce costs. We are maintaining balance sheet strength by managing our debt. And we are engaging in the public debate over climate change, energy security and taxation. But despite these immediate steps, we are maintaining our long-term strategy. We are funding our commitments and preserving optionality. We continue spending through the cycle in our resource-play drilling programs. And we are focusing on our core businesses, while continuing renewable energy R&D, but at a measured pace. Obviously, there is much government must do. First is improving access. The world has ample oil and gas, and we can produce it efficiently while protecting the environment. We just need access. Second, government must stop viewing our industry as a cash cow. Some $12 trillion in global oil and gas investment is needed by 2030 to ensure adequate supply. These investments cannot occur if our funds are taxed away. Third, government must encourage development of all energy sources, and not pick ‘winning’ technologies. The public, through the market, can determine the best sources far more efficiently than government. And finally, government must coordinate its policies on energy and climate. Otherwise, policy conflicts could undermine both. So there are solutions to our challenges, provided that we, and most importantly government, take the right steps. n
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“These challenges and flawed policies have serious implications. They could lead to new energy price spikes once the world economy recovers”
ENERGY INNOVATION 134
n the center of a state-of-the-art research lab at California State University in Long Beach, a helix of brightly colored fluorescent lights rotates inside a bell jar full of murky looking water. At the next workstation sits a vat of bubbling green liquid, slowly separating into different layers. All around, industrial equipment buzzes and hums while a team of scientists busy themselves monitoring progress on a bank of powerful computers. It may seem a million miles from the world of beam pumps and boreholes, but the team at the University’s Institute for Integrated Research in Materials, Environments and Societies believe their work could hold the key to the future of oil production. However, this is not oil as we know it. Driven by rising oil prices, the Kyoto protocol and global warming concerns, countries worldwide are quickly embracing petroleum alternatives such as ethanol and biodiesel to help curb their dependence on imported oil with minimal changes to their energy infrastructures. To date, doing so in a carbon-neutral and environmentally friendly way has proved a challenge; traditional oil-producing feedstock such as corn and sugarcane often destroy vital farmlands and rainforests, disrupt global food supplies and create new environmental problems. But thanks to the work of scientists such as those at Cal State and using technology developed by players such as alternative energy firm OriginOil, such concerns could soon be a thing of the past.
Can a breakthrough in technology transform algae from merely a promising source of renewable energy into a true competitor to petroleum? By Ben Thompson
OriginOil’s breakthrough technology, based on algae, is targeted at fundamentally changing the world’s source of oil. Much of the world’s oil and gas reserves are made up of ancient algae deposits, and by commercializing the process used to extract oil from industrially grown and harvested algae, the company argues that an endless supply of alternative fuel can be manufactured for use in products such as diesel, gasoline, jet fuel, plastics and solvents – without the global warming effects associated with traditional fossil fuels. “Instead of drilling for old oil, we can now produce clean, new oil, anytime and anywhere, through a cost-effective, high-speed manufacturing process,” explains OriginOil founder and Chief Executive Riggs Eckelberry. “We’re talking about a true competitor to traditional petroleum.” Eckelberry is one of a growing number of people who believe that cultivating algae as a fuel source could help solve America’s current energy challenges. To date, OriginOil’s focus has been on developing the solutions required to successfully commercialize the algae-to-oil process. Harvesting algae is a challenge, as it grows suspended in large volumes of water. Once ready for harvest, the algae culture must be concentrated and the oil extracted from each cell, before the oil, water and biomass are separated for processing. OriginOil’s single step extraction achieves all these steps in one pass, using the company’s proprietary Quantum
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Next generation fuel? If the costs of production can be brought down and the process effectively scaled up, algae’s advantages include growing much faster and in less space than conventional energy crops. According to Professor Roger Ruan at the University of Minnesota, an acre of corn can produce about 20 gallons of oil per year, compared with a possible 15,000 gallons of oil per acre of algae. In addition, an algae farm could be located almost anywhere, wouldn’t require converting cropland from food to energy production, could use sea or wastewater and could gobble up pollutants from sewage and power plants.
Fracturing technology combined with electromagnetic pulses and pH modification to break down cell walls and release the oil. Algae oil then rises to the top for skimming and refining, while the remaining biomass settles to the bottom for further processing as fuel and other products. In terms of technology Eckelberry is confident that the right applications already exist; it is now a case of scaling up so that the algae-to-oil process can be performed at an industrial level, taking the growing and harvesting of algae from an agricultural approach to an industrialized process approach. To this end, OriginOil has been working with the US Department of Energy’s Idaho National Laboratory (INL) to develop a process model for the commercial production of algae for biofuels and other value-added products. The collaboration has produced a productivity model to provide data on the projected efficiency and recovery values for the various steps involved in the algae-growing process, including lipid and biomass production from algae. “The new algae industry needed a comprehensive economic model to ramp up quickly,” says Eckelberry, “and INL has played an integral part in our efforts to quantify the performance of key steps within the OriginOil algae production system. Through this collaboration we will facilitate the growth of the entire algae sector, and create a domestic renewable fuel industry that will benefit both the environment and the economy.” He hopes that such findings could lead to commercial applications for algae-to-oil technologies being found in the not-too-distant future, and believes that applying such techniques onsite in energy-intensive industrial environments could reap significant rewards. “You need three things for algae production. One is plentiful CO2; atmospheric CO2 is just not sufficient to really get algae going at industrial rates of production, and it takes it takes two tons of CO2 to make one ton of algae. The second is plentiful water; even though algae is far more water efficient than any other crop, it still requires 0.4 tons of water for every ton of CO2 absorbed. And the third is energy. And it’s far preferable to use waste CO2, wastewater and waste energy than to have to come up with any of those yourself. So really that defines the environments in which we will be able to make a lot of algae in a green way.” Eckelberry uses the example of a gas-fired furnace that generates a lot of CO2 to illustrate his point. “A furnace in a large plate glass rolling plant will generate something close to two million tons of CO2 per year – and given impending carbon legislation, that could invoke a major financial penalty,” he explains. “But by siting an algae plant there, you could suck
up that CO2, use the waste energy from the furnace on a co-generation basis and immediately gasify the algae on the spot right back into the kilns. And that’s a very attractive type of application because it does not require pipelining or any kind of post-processing. It essentially simplifies it into an on-site use scenario.” He also believes there is strong potential for such applications in the wastewater treatment environment. Indeed, establishing numerous different revenue models for the use of such technologies is one of the key challenges his industry faces. “We’ve got to have multiple ways of making money from these plants, especially in the early days when algae will still be relatively expensive,” he says. “Carbon mitigation is obviously one revenue stream. Th rough the algae process we can also make non-potable water into good water. And there are other revenue scenarios that can be explored too. But I think for a long time we will see algae quietly at work sucking up CO2 in industrial applications rather than powering people’s homes or cars, at least until we’ve figured out how to productize the applications.”
Scales from the scaled chrysophyte, Mallomonas canina, a yellow-green algae.
Nevertheless, it’s an industry that is seeing an increased amount of interest and Eckelberry’s firm is not alone in hoping to capitalize on the green gold rush. Scores of scientists around the world are racing to turn algae into a commercially viable energy source, with researchers trying to figure out how to grow enough of the right strains of algae and how to extract the oil most efficiently. Over the past five years they’ve enjoyed an upsurge in funding from governments, the Pentagon, big oil companies, utilities and venture capital firms alike. “Just as the oil industry benefited in its early history from accelerated investment, so we’re going to need that kind of preference to jumpstart this industry,” says Eckelberry. “I think that there’s a tremendous will to repatriate the trillion or so dollars that we export every year for our fuel and plow that back into local businesses and jobs. So there’s going to be lots of support for this industry going forward.”
IN THE BACK OIL SANDS OIL SANDS
Cracking the code Could cold cracking technology save the oil sands and heavy oil sector hundreds of billions of dollars?
Raleigh, North Carolina-based company founded by a former Presbyterian minister, claims to have developed a technology that could be used to lower the cost of producing, pipelining and upgrading heavy oil in the Canadian oil sands. “We think we can build a 10,000-barrel-a-day project for $30 million, or $3000 a day per barrel,” says Bud Brainerd, CEO and founder of PetroBeam Inc. He believes the privately owned company’s cold cracking technology, which uses highenergy electrons instead of energy-intensive catalysts to reduce the viscosity of heavy oil, can potentially save the oil sands and heavy oil sector hundreds of billions of dollars. “Our technology uses electricity rather than heat
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generated from natural gas to effect changes in the crude oil and does not require expensive catalysts. The capital cost of a commercialscale PetroBeam facility is a fraction of the cost of alternative upgrading processes due to the simplicity of the technology.” The process, he adds, is also more environmentally benign than the thermal and chemical-based methods currently in use. The high-energy electron technique has been tested successfully on heavy oil from the Athabasca oil sands as well as from other areas of the world. Although the technology is not new, its application in the petroleum industry is. Electron beam technology has in fact been used for more than 50 years, and evolved from the early days
of the nuclear technology. The technology has been applied in the pharmaceutical industry, the medical field (radiotherapy diagnostics and radio therapy), the industrial field (X-ray irradiation is used in the manufacture of tires, in the production of wires and cable) and in the food processing industry (used in packaging). “It’s a very versatile technology,” says Brainerd. The story of PetroBeam sounds like a plot for a bizarre novel. Before he founded the company, Brainerd was a Presbyterian Church minister for 17 years and holds a Doctorate in divinity studies. But after suffering burnout after six years as a minister in Montgomery, Alabama, he turned to working in the real estate development and sales business. He was then approached by one of his friends, Walter
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One truck of oil sands can produce 200 barrels of oil, once processed. Syncrude’s Aurora mine near Fort McMurray, northern Alberta, extracts almost 350,000 barrels a day from the sandy soil.
Chappas, who informed him of the potential application of electron beam technology in the energy sector. That conversation led to Chappas – who has a PhD in nuclear engineering and is a recognized authority in radiation chemistry and radiation processing – forming Allasso Industries, located in Raleigh, in 2000. Allasso concentrates on the application of various technologies in materials production. Brainerd decided against joining Allasso, choosing to remain in Montgomery. However, a couple of years later, both men began to look at how the technology could be used in the oil industry. They came across two scientists in Kazakhstan who had been doing work on the use of electron beams in the oil sector. “We decided that if the technology could do what
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they claimed it could do, it would be a significant advancement,” says Brainerd. “We had their technology tested by a third party and it verified their research,” he says. Brainerd says that his firm’s technology is an improvement on the Rapid Thermal Processing (RTP) technology now owned by Calgarybased Ivanhoe Energy Inc. Ivanhoe acquired California-based Ensyn Group Inc. in 2005 after it discovered the company’s RPT technology had been successfully applied in a heavyoil-to-light-oil (HTL) plant in the San Joaquin Valley in southern California, where it is used at a 1000-barrel-a-day facility. The HTL process uses a continuous, short contact time thermal conversion process that takes place at moderate temperatures and at atmospheric pressure. It uses a circulating transported bed of hot sand in the system, in the absence of air, to heat the feedstock and convert it to a pipeline-ready crude. Ensyn has also used the technology for several years to convert biomass into fuels. “Their goal is similar, but their process is different than ours,” says Brainerd, adding that PetroBeam’s strategic partner, Ion Beam Applications, will be doing significant tests in the next month or so at a facility it owns in Long Island, NY. PetroBeam officials have been in talks with some Canadian heavy oil producers about the technology, discussions that the company will be accelerating over the next several months. “We haven’t spent a great deal of time in Calgary. We’re a small company, with only 13 employees and we’ve been doing our work under the radar. But this is the year that will change.” Brainerd explains that the company is looking for strategic investors wanting to apply the technology to replace thermal upgrading processes, which would greatly reduce the use of natural gas in the process, as well as water consumption. “It would also make it easier to clean-up the coker,” he says. Brainerd adds that the company believes the process will render heavy oil pipelineready, while ensuring the crude won’t create any problems at the upgrading and refi ning stage. Because nothing is being added to the crude, he says, “it doesn’t complicate the refi ning process”. ■
Oil sands: a brief history Oil sands reserves have only recently been considered to be part of the world’s oil reserves, as higher oil prices and new technology enable them to be proﬁtably extracted and upgraded to usable products. Many countries in the world have large deposits of oil sands, including the United States, Russia and various countries in the Middle East. However, the world’s largest deposits occur in two countries: Canada and Venezuela, each of which has oil sand reserves approximately equal to the world’s total reserves of conventional crude oil. As a result of the development of Canadian oil sands reserves, 44 percent of Canadian oil production in 2007 was from oil sands, with an additional 18 percent being heavy crude oil, while light oil and condensate had declined to 38 percent of the total. Because growth of oil sands production has exceeded declines in conventional crude oil production, Canada has become the largest supplier of oil and reﬁned products to the United States, ahead of Saudi Arabia and Mexico. Heavy crude feedstock needs pre-processing before it is ﬁt for conventional reﬁneries. This pre-processing is called ‘upgrading’, and includes the removal of water, sand, physical waste and lighter products; catalytic puriﬁcation by hydro-demetallization, hydro-desulfurization and hydrodenitrogenation; and hydrogenation though carbon rejection or catalytic hydro-cracking. As carbon rejection is generally inefﬁcient, catalytic hydro-cracking is preferred in most cases. The big challenge in such hydroprocessing techniques is to deal with the impurities found in heavy crude, as they poison the catalysts over time. Many efforts have been made to deal with this to ensure high activity and long life of a catalyst.
THE RISE OF PIRACY 138
Piracy is back. And with oil supertankers seen as a prize catch for new-age pirates, can the industry ward off potential attacks or is it merely a sitting duck? By Julian Rogers
n early January of this year, a bright red parcel attached to a small parachute glided gently toward the deck of a Saudi supertanker 500 miles off the Kenyan coast. Onboard the 330-metre long Sirius Star was a 23-man crew, a gang of armed Somali pirates and two million barrels of oil – a quarter of Saudi Arabia’s daily output. Inside the package was believed to be $3 million in high denomination bills – paid by oil giant Saudi Aramco to release the supertanker, owned by its shipping arm, and bring an end to a terrifying two-month ordeal for the hostages. The hijacking of the Sirius Star was the bandits’ biggest booty to date, and has fueled fears that other tankers could be snared by pirates in the future. Indeed, most attacks are directed at merchant ships connected in some way to the oil industry. The lion’s share have occurred in the Gulf of Aden off the Somali coast – one of the world’s most important shipping lanes with 20,000 vessels passing through annually. There is 1.1 million square miles of water in this region alone, meaning shipping companies and their crews face the daunting prospect of trying to predict where and when the pirates will strike next. And with the Sirius Star ransom being paid so publicly, there is growing concern that handing the pirates
millions of dollars to relinquish control of a vessel will only fuel more attacks and even bigger wallet-busting ransoms. Kenya’s foreign minister claimed that up until November 2008 the pirates had received over $150 million, which is being ploughed back into purchasing faster boats and increased hardware. “The big ransom payments have fuelled attacks – there isn’t any real doubt about that,” suggests Roger Middleton, Consultant for the Africa Programme at Chatham House, formerly the Royal Institute of International Affairs. “As ransoms go up it becomes a more attractive business for people, but it is a very difficult position for ship owners to be in because no-one wants to be the first not to pay a ransom and jeopardize the safety of their crew.” Nick Davis, a former British army pilot and Chairman of the Merchant Maritime Warfare Centre (MMWC) – a not-for-profit organization addressing ship security – is also of the opinion that payoffs are spiralling out of control. “The pirates keep pushing for as much as they can get,” he says. “The industry, the insurance companies and the negotiation teams are letting the ransoms get out of hand, which is making the situation worse because the bigger the ransoms, the more people want to get
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involved. There is no shortage of manpower for the pirates to send out and there will never be enough warships to effectively prevent them.” According to the International Chamber of Commerce’s International Maritime Bureau (IMB), the number of attacks so far this year off Somalia has far surpassed 2008’s total. Last year witnessed 111 incidents, with 42 vessels hijacked. But by mid-May of this year 29 successful hijackings were recorded from 114 attempted attacks. And while a total of 815 crew members were taken hostage in 2008, this figure stood at 478 by the middle of May. “These guys have found a business model that makes a lot more money than their traditional fishing industry,” says Jeroen Meijer, a security consultant for threat and safety advisors Control Risks. “Keeping that business model in tact is crucial, so they constantly adapt their modus operandi. We saw them operating in the Gulf of Aden, off the coast of Mogadishu [Somalia’s capital] and we have seen them going into the Red Sea and Omani waters. So they are constantly adapting where they operate to minimize the threat to their operations.” A knock-on effect of the piracy has been a sharp rise in shipping costs, with many firms choosing to avoid the Suez Canal and navigate their vessels thousands of miles further via South Africa’s Cape of Good Hope. On top of this, insurance costs have soared by as much as 100 percent. And while there are more than a dozen naval forces, as part of a multinational coalition offensive, flexing their military muscle and patrolling the Gulf of Aden in a bid to thwart the pirates, this asymmetrical warfare has just forced the pirates to scour for victims in less policed waters, namely the western Indian Ocean. If they can pass under the radar of the multinational naval armada the pirates typically approach a target by speedboat or skiff (a shallow, fast boat), fi ring on the ship until the captain submits and allows them to board by means of grapple hooks and rope ladders. Some pirate gangs are particularly well equipped for the job in hand, says Middleton. “They are generally armed with AK47s, and sometimes RPGs (Rocket-Propelled Grenades), while their boats generally have outboard Yamaha engines, GPS and satellite phones.” In a similar fashion to how burglars seek to target the house on the street with the weakest security, the bandits go after the ships easiest to board and take control. Those vessels capable of 25 knots are generally too fast for the pirates but boats sailing at around 14 knots and with a freeboard five metres or less in height are deemed easy prey. Ship owners are doing their best to ward off potential attacks by installing barbed wire and fi ring onboard water canons should the assailants venture too close, while deck patrols and ‘lookouts’ have also been ramped up. Davis says the crews who wind up getting hijacked invariably have little or no understanding of the threats and have been given no training in how to defend their vessel. He is also concerned that ship owners are deploying a mishmash of anti-piracy measures instead of adopting a standardized approach. “We have such a divide across the world,” he notes. “For instance, the Americans are putting armed guards on everything, which is not very helpful and will lead to all sorts of problems because the ultimate authority on that ship should be the master. He is still liable, irrespective of who pulled the trigger and I know a lot of masters who are very uncomfortable with the arms issue and civilian guards.”
Fighting back How ship owners can protect their cargo and crews One deterrent is a long-range acoustic device (LRAD), which is simply a satellite dish hooked up to a humble MP3 player. The LRAD, which has a range of around 1000 meters, ﬁres out high-pitched messages or sirens to warn pirates that they have been spotted. In fact, this piece of kit can reach excruciatingly painful levels if the pirates get too close. More simple but effective measures include attaching barbed wire to the boat to hamper pirates’ attempts to clamber aboard. Some vessels are also ﬁtted with powerful hoses used for blasting anyone who gets anywhere near, while some ship owners have taken a more hard-line approach by providing machine guns. Austrian company Schiebel has developed an unmanned helicopter ﬁtted with advanced sensors to alert crews of advancing maritime gangs. The three-meter long Camcopter S-100 can be ﬂown by remote control or by pre-programmed GPS waypoints, and is capable of 120 knots powered by a 55hp rotary engine. The most effective and practical measures, maritime experts suggest, is to sail at a speed exceeding 25 knots, pull up the ship’s ladder and have a high freeboard.
So can piracy be stopped on land? Experts are in agreement that the failed state of Somalia is a perfect breeding ground for piracy, while a lack of law means the pirates can hijack vessels with impunity. Piracy first became a problem in the region at the outbreak of Somalia’s civil war in the early 1990s when the government was overthrown, and a continuing lawless atmosphere in the country has magnified the problem. “Somalia is a completely failed state with no political structure to speak of and no law enforcement capability so these gangs operate with total impunity,” says Meijer. “Those who live on the coast see the wealth of the world sailing by everyday; in an extremely benign maritime environment where you can operate a small boat for very little cost, it’s too tempting to find a Kalashnikov and an RPG and hijack the riches on your doorstep.”
VANTAGE POINT 140
Stepping on the gas The Qatargas 2 project is the world’s ﬁrst fully integrated value chain LNG venture, boosting the Qatargas portfolio’s total LNG production to a whopping 42 million tonnes per annum by the end of the decade.
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VANTAGE POINT 141
atargas 2 involves the development of two world-class liquefied natural gas trains, each with a capacity of 7.8 million tones per annum (mtpa) and 0.85mtpa of liquefied petroleum gas, 140,000bpd of condensate, three storage tanks, power utilities and water injection systems, a fleet of 14 ships and a receiving terminal.
Onshore construction • 30,000 people from 50 nationalities worked to create Qatargas 2 • The facility contains enough cable to stretch from Doha to London • Every month, 11.2 million man-hours were worked on site • Onshore construction involved the consumption of 31 million gallons of water, three million liters of diesel, 1200 trucks of sand and 300 trucks of cement • The two trains are powered by a stateof-the-art generating unit producing 200MW of electricity, enough power to run a small town • Over 300,000 separate systematic tests were carried out before commissioning each train
Offshore construction • All 30 wells were completed a full 27 rig-months ahead of schedule • Pre-fabricated modules weighed up to 1000 tons, equivalent to 700 family cars • The three platforms combined will produce 2.9 billion cu ft of gas per day • Qatargas 2 saw the fastest wells ever drilled in the North Field. The record now stands at 14,500 feet of rock in just 33 days, nearly 20 feet per hour • Over 4500 coral colonies were carefully detached from the seafloor, numbered, tagged and moved to new locations. • The main pipelines are over 34” wide and made from carbon steel almost an inch thick
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IN REVIEW 142
On the shelf Taking an in-depth look at the impact of the economy across all industries, O&G uncovers the best of this quarter’s business book releases.
The World is Curved Hidden Dangers to the Global Economy, by David M. Smick
A timely, controversial and engrossing examination of global fi nance and the crisis engulfi ng us all, The World is Curved highlights the next potential crisis points and the thicket of hidden problems facing the entire global economy. Picking up from where Thomas L. Friedman’s The World is Flat left off, Smick focuses on the globalization of finance and how today’s risky environment came about. He provides an insider’s perspective on the potential nightmare scenarios of the future. O&G SAYS: A must-read for investors, business people and anyone interested in the fi nancial crisis. Smick provides a thoughtful insight and raises important issues that need to be fully debated. A great guide on how to survive in these turbulent times.
Crossroads The End of Wild Capitalism and the Future of Humanity, by Peter Nolan
Drawing on thinkers as diverse as Karl Marx, Adam Smith, Sigmund Freud, Charles Darwin and Confucius, Nolan analyzes the achievements and shortcomings of capitalist globalization over the past three decades. For Nolan the global fi nancial crisis marks the end of the era of ‘wild capitalism’ and what follows next is an open question as humanity stands at a crossroads – one path leads to cooperation, one to confl ict. O&G SAYS: A dense, detailed and carefully constructed argument stating a case for a tripartite alliance between the US, China and the Muslim world. Nolan remains upbeat and places equal weight on mankind’s instinct for survival through cooperation as well as the equally inherent destructive competitiveness of globalization.
It’s Not as Bad as You Think Why Capitalism Trumps Fear and the Economy Will Thrive, by Brian S. Wesbury
An upbeat antidote to the doom and gloom forecasts of the fi nancial future, Wesbury demonstrates that while the future may be hard to predict, it will ultimately be profitable over the long haul. Ranked as one of the top economic forecasters by the Wall Street Journal and USA Today, Wesbury shows how to prosper now and in the future with an analysis of tomorrow and a guide through yesterday. O&G SAYS: In this easy-to-follow and engaging forecast of the future, Wesbury’s objectivity and optimism provide welcome relief to the daily bad news stories that have dominated the news for so long.
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FINAL WORD_nov09 13/11/2009 16:39 Page 144
FINAL WORD 144
The new world order A recovery in the value of oil has led to a surge in conﬁdence at the world’s drilling companies, kick-starting a ﬂurry in production around the world as energy prices rise. But is it too soon to call the recession over?
ccording to recent reports in the press, some oil executives have already declared the year-long slump in petroleum over, pointing to a hike in exploration and drilling operations across the globe. At around $80 per barrel, oil prices are finally at a level that is getting drillers excited again. And the increase in value is expected to create more jobs as companies reach out across the world in search of more reserves, especially shale gas deposits. But a number of experts are calling for a more cautious approach to the upturn. Carl Hughes, Lead Partner for Deloitte’s Energy Practice, highlights the key challenges for the oil and gas industry. “The credit crunch has hit the oil and gas sector particularly hard, with a dramatic reduction in the lines of credit and available finance,” he says. “I believe that there is now an increasing body of evidence that bank finance is coming back, but only for the right projects and the right players. One thing is for certain: the days of the banking sector throwing money at anything associated with oil and gas are behind us.” And while Hughes also believes it is possible that private equity and sovereign wealth funds will be attracted by the investment opportunities offered in upstream and downstream alike, he identifies a number of obstacles to
“One thing is for certain: the days of the banking sector throwing money at anything associated with oil and gas are behind us” widespread investment in the sector that must be addressed first. “Oil price volatility, alongside the fiscal deficits of nation states, remains a roadblock to investments in the short-term,” he says. “Emerging economies that tie in energy needs with economic growth in the long-term could ease the market by making appropriate investments.” Indeed, a greater consideration of the benefits the oil and gas industry can bring in terms of economic development will be key to recovering from the current recession. “Producing and consuming countries should not take the oil and gas industry for granted,” Hughes warns. “Each country should
balance economic rent charged through royalties and tax in a way that still attracts sufficient new investment to ensure that reserves are fully exploited and energy remains affordable for consumers.” He also sees looming climate change legislation as a potential challenge for the industry. “Depending on the outcomes of the Copenhagen climate conference later this year, we may see significantly more governmental activity around regulating petroleum-related carbon emissions,” he says. “One recent example of such activity is the new complex rule passed in the State of California regulating the greenhouse emissions from cars and trucks. This is expected to cut the state’s gasoline consumption by one quarter in the next decade by increasing the number of electric and hydrogen-fuelled cars. A number of other states are also looking into the model used by California. If the model is successful, we may see similar initiatives in the developed world.” Alongside such developments, the rise of alternative energy sources will also challenge the oil and gas industry’s traditional dominance over the coming years. “Nuclear power generation has seen a recent renaissance. Depending upon whether the policy makers will manage to maintain public and corporate support for nuclear, it is likely that this industry will form an increasing part of the future global energy mix.” So while higher oil prices offer the opportunity for increased R&D spend and a rise in new E&P activity, there is also a warning sign on the horizon: after all, if oil prices become too high, will consumers turn away from oil completely? n
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