THURSDAY, MAY 9, 2013
www.OTC.com
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OTC2013
OFFSHORE TECHNOLOGY CONFERENCE | HOUSTON, TEXAS
| THE OFFICIAL 2013 OFFSHORE TECHNOLOGY CONFERENCE NEWSPAPER | DAY 4
Brazil Focus of Second OTC Event
n Aer a highly successful inaugural event, OTC Brasil is back to
showcase technology and ideas from this industry hotspot.
I
BY RHONDA DUEY
t’s almost that time again – round II of OTC Brasil. e 2011 inaugural show brought OTC’s bright technical spotlight to bear on this booming area of the globe. Along with the Arctic Technology Conference and next year’s OTC Asia conference in Kuala Lumpur, OTC Brasil is one of the organization’s latest successes in broadening its technological impact. e show, scheduled for Oct. 29-31 in Rio de Janeiro, will showcase key leaders from around the world sharing their perspectives on the Brazilian market. Highlights will include a presentation by the director of the Brazilian National Petroleum Agency, who will discuss the upcoming presalt leasing round. e country has not had a licensing round since 2007, and this round is expected to generate considerable international interest. Other discussions will focus on industry “megaprojects” and how to avoid losses. An important panel will discuss the new perspectives
in E&P in the South Atlantic. Panelists will discuss current and future activities in the South Atlantic, especially the presalt and east and equatorial margins “e conference will be focused on brand new and state-of-the-art papers discussing new technologies, developments, and operations in the South Atlantic,” said Marcos Assayag, 2013 OTC Brasil program committee chairman. e 2013 conference is fully supported by Petrobras, with 59 approved presentations from the company. More than 260 papers were accepted to the conference, 145 from Brazil and 119 from abroad. A topical luncheon will address safety issues post-Macondo, discussing Brazil’s regulatory changes in light of the accident. Technical sessions will include a presentation on the first tension-leg platform installed offshore Brazil to develop the
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TC 2013 has had a bit of a Norwegian flavor. Crown Prince Haakon and his wife, Crown Princess MetteMarit, were on hand to help that country’s oil and gas industry celebrate its 40th year attending the conference, including a visit to Norway’s huge international pavilion. But this is not the only thing the Norwegian energy industry is celebrating. Major discoveries on the Norwegian Continental Shelf, including in the Barents Sea, have bolstered the Ola Borten Moe country’s international esteem,
n Advances in subsea processing
systems are moving the technology toward the point where a ‘subsea factory’ on the seabed by 2020 is nearing reality.
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BY MARK THOMAS
and it continues to expand its acreage options to continue its long-term development plans. Ola Borten Moe, minister of petroleum and energy for Norway, said the latest achievement for his country is the announcement that the government has presented a proposal to open up petroleum activity in the southeastern Barents Sea. e announcement comes aer Norway’s wrangling with Russia over the delimitation lines were finally settled. “We agreed with Russia three years ago,” he said. “is was the end of a process that had been going on for 40 years.” e intervening years have involved geologic studies and environmental impact assessments, he added. e
orway’s Statoil has been the offshore industry’s biggest proponent of the concept for transferring the processing of oil and gas from platform topsides to the seabed for both brownfield and greenfield projects. Once merely a vision, the concept of “subsea factories” is now close to reality as the various building blocks required for an all-encompassing system are being deployed on various fields around the world. e need for a subsea factory solution has become increasingly obvious as the industry moves farther away from land into deeper waters and colder environments such as the Arctic. e ability to carry out subsea processing tasks such as single and multiphase hydrocarbon boosting (pumping), gas compression, separation (gas/liquid and liquid/liquid with produced water reinjection), and raw seawater injection brings with it plenty of challenges. According to Statoil’s executive vice president of technology, Margareth Ovrum, the company is looking to apply the subsea factory concept, or elements of it, around the world, including the Gulf of Mexico, Brazil, Tanzania, and the Arctic. It also does not apply only to greenfield projects, as Statoil’s focus on improving reservoir recovery rates from its assets both offshore Norway and further afield means it intends to apply it equally to brownfield developments. Ovrum, speaking in a press briefing at OTC yesterday, said, “I believe the subsea factory is the most interesting project in the oil and gas industry today.” A key part of the seabed factory solution is subsea compression. In simple terms, the closer compression can be placed to a well, the more gas can be extracted. Statoil is on schedule to apply it first on its Åsgard field offshore Norway, with the operator expecting seabed compression on the field to get underway in 2015 using the giant 1,800-tonne compression module, although on a smaller scale its Gullfaks South subsea compression project also could start up in 2015. e Åsgard module is due to be installed 200 km
See NORWAY continued on page 3
See STATOIL continued on page 3
See BRAZIL continued on page 46
Norway Has Plenty to Celebrate BY RHONDA DUEY
STATOIL TO TAKE SUBSEA FACTORY SOLUTION GLOBAL
Editorial Director PEGGY WILLIAMS E&P Group Managing Editor JO ANN DAVY Executive Editor RHONDA DUEY Senior Editor, Offshore MARK THOMAS
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OTC2013
Thursday, May 9
7:30 a.m. to 2 p.m. ...................................Registration
7:30 a.m. to 3 p.m. ...................................Energy Education Institute Teacher Workshop
7:30 a.m. to 9 a.m. ...................................Topical/Industry Breakfasts 8:30 a.m. to 1:30 p.m. Energy Education Institute High School Student STEM Event
9 a.m. to 10 a.m. ......................................Coffee
9 a.m. to 2 p.m. ........................................Exhibition
9 a.m. to 5 p.m. ........................................University R&D Showcase
Senior Editor, Drilling SCOTT WEEDEN
9:30 a.m. to 12 p.m...................................Technical Sessions
Senior Editor, Production JENNIFER PRESLEY
2 p.m. to 4:30 p.m. ...................................Technical Sessions
Chief Technical Director, Upstream RICHARD MASON Associate Editors VELDA ADDISON MARY HOGAN Contributing Editors ANTHONY D. DARBY STEVE HAMLEN DR. PHANEENDRA KONDAPI FRANK LLOYD CHRISTINA NELSON HENK-WILLEM SANDERS Corporate Art Director ALEXA SANDERS Senior Graphic Designer JAMES GRANT PHOTOS BY GARY BARCHFELD PHOTOGRAPHY Production Director & Reprint Sales JO LYNNE POOL Director of Business Development ERIC ROTH Group Publisher RUSSELL LAAS
HART ENERGY LLLP President and Chief Operating Officer KEVIN F. HIGGINS Chief Executive Officer RICHARD A. EICHLER The OTC 2013 Daily is produced for OTC 2013. The publication is edited by the staff of Hart Energy. Opinions expressed herein do not necessarily reflect the opinions of Hart Energy or its affiliates.
Hart Energy 1616 S. Voss, Suite 1000 Houston, Texas 77057 713-260-6400 main fax: 713-840-8585 Copyright May 2013© Hart Energy Publishing LLLP
SCHEDULE OF EVENTS
12:15 p.m. to 1:45 p.m. .............................Topical Luncheons
4 p.m. to 5 p.m. ........................................OTC Closing Reception
STATOIL continued from page 1
(122 miles) offshore, and Ovrum pointed out that it is expected to enable the extraction of up to 280 MMboe of extra oil and gas from the field, where reservoir pressure is currently falling. “Why do we need a subsea factory?” she said. “We are going longer, deeper, colder, in harsher environments. It will be impossible in some areas to build platforms, and subsea facilities could be the key to the success in these areas.” Jannicke Nilsson, senior vice president, technology at Statoil, added that in the short term the company is focused on using subsea processing to help with increased oil recovery, while in the medium term it is looking to utilize the full subsea factory concept to produce oil and gas back to a host facility. at could involve greenfield developments transporting hydrocarbons back to infrastructure that may be up to 600 km (487 miles) away (for gas), 200 km (for oil), and 50 km (30 miles) for heavy oil. In the longer term, Nilsson added, Statoil is looking to have subsea factory solutions that are able to act as production hubs, with total independence from surface facilities, and transport processed market-quality oil and gas directly to shore. Key technology issues still being tackled include the large power requirements for long-distance subsea projects. “We need the power to be distributed and with high reliability,” said Ovrum. She added that other requirements include being able to remove much more of the liquids, like water, from the gas and needing to develop more technologies to clean and treat the water for reinjection. “We also need to work further on how to monitor the system,” she said. Turning her attention to the Gulf of Mexico, Ovrum noted that the subsea factory solution could have several spin-off effects there. ese could enable the doubling of the percentage of average oil recovery from its Paleogene fields, she claimed. Artificial li solutions such as downhole pumps and subsea NORWAY continued from page 1
proposal is now in front of the Norwegian Parliament. “I expect Parliament to okay the proposal before June 19,” he said. “ere’s nothing to keep this from going forward.” According to information from the Norwegian Petroleum Directorate, there is considerable potential in the area, with an estimated 300 MMcu m of oil equivalent. is corresponds to almost eight fields the size of Eni’s Goliat field, scheduled to begin production soon. It also increases the amount of undiscovered resources in the Barents Sea by more than 30%, according to the Ministry of Petroleum and Energy website. “Other parts of the Barents Sea are already open, and they’re not just fields in production – they have made some primary discoveries over the last few years,” Borten Moe said. “We’re looking at developing a whole new province.” Another recent announcement concerns the opening of a new blowout control technology center near Stavanger. e project was developed through the Subsea Well Response Project. e equipment is designed to stop emissions from blowouts quickly. “I commend the industry for taking responsibility aer Macondo for developing capping stack facilities,” Borten Moe said. “ey give companies the capacity to shut down wells. I think it’s very important work that has been done. It’s a broadening of
OTC SHOW DAILY | MAY 9, 2013 | THURSDAY
booster pumps were highlighted as key parts of the solution, with Statoil looking to apply them possibly by 2018 on the Logan field in the GoM, subject to further appraisal of that reservoir. Other benefits of a subsea factory, said Ovrum, apart from increasing hydrocarbon recovery and productivity, include health and safety benefits such as reduced fire and explosion risks, chemical consumption, manned offshore operations, environmental “footprint,” and improved energy efficiency. n
Newly appointed Secretary of the Interior Sally Jewell
addresses an audience during OTC. Jewell said her
department seeks greater collaboration with the
offshore industry.
(Image courtesy of Gary Barchfeld Photography)
their global work on HSE to increase that level offshore.” In addition to the new European facility, there are others in Asia, Africa, and South America, he said. One topic that is of great concern globally is the safe development of Arctic reserves. Borten Moe credited international oil companies (IOCs) in leading the way in this challenging new frontier. “On the Norwegian shelf we encounter areas of constant ice,” he said. “It’s not just the Norwegian companies exploring these provinces. e big US-based companies, ConocoPhillips among them, are also very active, and we promote cooperation between the companies and different governments to develop those resources in a way that is as good as possible to develop the technology. I have faith in the work the IOCs are doing. “Opposition to Arctic drilling is only natural – you are having a similar debate in the US,” he added. “At the same time, I think developing these resources internationally will be proactive. Over time it will give the ministry and the industry the necessary license to operate.” Overall, Borten Moe sees Norway continuing its success well into the future. “ere is outspoken optimism and energy in the industry and among the population,” he said. “ere are some exciting wells that will be drilled this summer. We might have more good news.” n 3
Petrobras Provides a Pre-salt Checklist
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BY RICHARD MASON
etrobras has come a long way in deepwater pre-salt development, but it still has a long way — and more than a quarter trillion dollars in investment to go — as it seeks to double its size by 2020 and moves toward 4.2 MMbbl/d of oil and 5.2 MMbbl/d of oil equivalent in oil,
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natural gas, and natural gas liquids. About half of that production will originate from Brazil’s pre-salt efforts. Piecing that puzzle together presents an enormous organizational challenge on top of a gnarly technological challenge in developing a world-class deepwater resource. e deepwater technological challenge may be the easier of the two.
How does an organization, for example, gear up for a multiple state-of-the-art long lead-time deepwater development programs while allowing enough corporate leeway to adapt new technologies that will debut over the next decade? at was the topic for Carlos Tadeu da Costa Fraga, E&P pre-salt executive manager for Petrobras, who provided a checklist pre-salt update at OTC 2013, the third Petrobras OTC update since 2009. Brazil’s pre-salt cornucopia underlies 150,000 sq km off the eastern coast, or the equivalent of 6,000 US Gulf of Mexico (GoM) blocks. To date, Petrobras is a dozen years out since the first seismic, seven years since the first discovery at Lula, six years since the discovery at Campos, and five years since Petrobras recorded an astounding five major deepwater discoveries in 2008. Petrobras has multiple plates spinning, including appraisal wells, reservoir characterization efforts, a series of extended well tests, experiments with separating CO2 gas out of production and re-injecting it back into the reservoir, intelligent completion designs, and a massive effort to supply local content. is including the construction or refurbishment of more than 24 FPSOs, “most under contract and most are being built” that are a key component in facilitating the development of an enormous deepwater resource. In all, Petrobras will have more than 38 new production units and drillships entering the fray over the next seven years. At the Lula pilot, which was put onstream in October 2010, Petrobras is processing natural gas and shipping it to shore out of four wells that are producing a combined 100,000 bbl/d. Petrobras is testing its first intelligent completions module at Sapinhoa with the first well producing 25,000 bbl/d. A Sapinhoa Pilot project was placed online in January 2013, one of seven initiatives scheduled for 2013. e pilot project involves the Ciudade de Sao Paulo, an FPSO that will produce 120,000 bbl/d from 13 interconnected wells. In April Petrobras’ pre-salt production reached 311,000 bbl/d out of 17 producing wells, with more than 165,000 b/d out of the Campos Basin and 114,000 b/d out of the Santos, “which will soon be higher because of new wells,” Costa Fraga said. In all, Petrobras has produced 192.4 MMboe out of the pre-salt from September 2008 to April 2013. During that time Petrobras has witnessed a 50% reduction in drilling time from 134 days to 70 days per well with an attendant 50% reduction in drilling costs. “We finished a well last week in 40 days,” Costa Fraga said. “We are progressing with the support of drilling contractors and our suppliers.” Optimization efforts at Petrobras have produced results that exceeded expectations. According to Costa Fraga, the Lula Pilot originally was expected to produce 15,000 b/d per well, but is now at 25,000 b/d per well. n THURSDAY | MAY 9, 2013 | OTC SHOW DAILY
Malaysia Hosts OTC Asia, Formula 1 Racing
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BY SCOTT WEEDEN
entlemen and women, start your engines! OTC Asia 2014 was officially launched with the unveiling of a Formula 1 sports car at OTC 2013 on May 6 in Houston. “OTC is a showcase for new technology, lessons learned, and sharing best practices,” said Steve Balint, OTC 2013 chairman. “A few years ago, we thought about taking OTC to other countries. We got great support in Brazil with OTC Brasil. Now we have a conference in the Far East for the first time.” Kuala Lumpur will host OTC Asia on March 25-28, 2014, at the Kuala Lumpur Convention Centre. Petronas will be hosting the event. OTC Asia will be held in conjunction with the annual Formula 1 Grand Prix in Malaysia, offering participants at OTC Asia and Formula 1 enthusiasts a unique opportunity to experience both events.
Why would Petronas sponsor a Formula 1 racing team? he asked. “ere are three key reasons. e first is about global exposure. About 100 million people watch Grand Prix races. It is a huge opportunity for marketing,” he said. “Second is technology development. e sponsors, including Petronas, provide technology for the cars in areas
like reduced friction and increased horsepower,” he continued. “ird, Petronas does a lot of good business with Mercedes Benz. A lot of fuel and motor oil are put in Mercedes Benz vehicles. “It is wonderful to be here in Houston, and I look forward to seeing you in Kuala Lumpur next year,” he emphasized. n
OTC Chairman Steve Balint is in the dri-
ver’s seat as plans for OTC Asia were
announced on May 6 during OTC 2013.
The conference will be held in conjunc-
tion with the annual Formula 1 Grand
Prix in Malaysia. (Photo by Gary Barchfeld Photography)
More than 4,100 people from Asia are attending the Houston OTC, Balint continued. OTC would expect at least the same level of support for OTC Asia. “is is being driven by the exciting pans going on in the industry.” Proposals for papers for OTC Asia are due June 5, 2013, at otcasia.org/2014. Nick Fry, consultant for the Mercedes AMG Petronas Formula 1 team, said, “We had a Formula 1 Grand Prix in Austin, Texas, last year, so it is a great pleasure to be here in Houston. When we came to Austin, we had a fantastic year. We expect a better year in 2013.” He invited the crowd at the OTC 2013 press event to join Petronas and the team in Kuala Lumpur for the Formula 1 events. e Mercedes team features drivers Lewis Hamilton and Nico Rosberg, who have finished in the Top 3 “a few times this year.” e Formula 1 race cars have about 750 hp and can reach a top speed of 220 mph. OTC SHOW DAILY | MAY 9, 2013 | THURSDAY
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China Steps up Its Supply Search
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BY STEVEN HAMLEN
hina remains as hungry for energy as ever and is looking to sustain and grow conventional oil and gas production, as well as build its unconventional sector and begin the exploitation of its potentially huge shale gas reserves. e battle to increase production to meet the country’s
soaring energy demand means maintaining a steady stream of field developments coming onstream and getting new projects off the ground. On the new offshore field projects front, US contractor DMAR Engineering recently landed a FEED contract from state-owned China National Oil Corp. (CNOOC) for development options on the Liuhua 11-1 and Liuhua 16-2 oil fields offshore China.
CNOOC’s research institute is currently studying the best development options for the fields in the eastern South China Sea, which lie in water depths of 340 m (997 ) and 404 m (1,326 ). A tension-leg platform (TLP) with full drilling capacity is being evaluated as one possible development concept, with a semisubmersible option being the other realistic choice. CNOOC will decide next month which development option to push ahead with. e operator said that the TLP would be the country’s first deepwater floating production platform and first dry-tree production platform. It also would be the first TLP to be made in China. Beibu Gulf field flows CNOOC also recently started production from its Beibu Gulf project in the South China Sea. e installation, hookup, and commissioning of offshore facilities for the project had been completed and first output achieved from the A5H and A2 development wells on the WZ-6-12 wellhead platform, said partner Roc Oil. e project will run on a trial production period until the next batch of three production wells is completed and brought online in the next few weeks. Roc said operations at the WZ-6-12 platform would be constrained “for a number of weeks” while drilling and commissioning works were finalized. e partners will now use the jackup drilling rig HYSY-931 to drill three additional development wells, while the successful A6 and A7 wells drilled late last year also will be equipped for production. Following the completion of drilling at WZ-6-12, the drilling rig will be moved to the WZ-12-8 West wellhead platform to carry out the final phase of development drilling for the Beibu Gulf project in 3Q 2013. e Beibu Gulf development plan incorporates two remote wellhead platforms and one joint processing platform, which will be connected by bridge to the CNOOC WZ-12-1A platform complex and will use existing water injection and gas processing facilities. CNOOC operates the Beibu Gulf project with a 51% interest, with partners Roc with a 19.6% interest, Horizon Oil with a 26.95% interest, and Oil Australia with a 2.45% interest. Ordos basin reserve boost As China also looks to increase existing reserves that can be developed in the future, the country was buoyed to hear that Australia’s Sino Gas & Energy has seen a huge increase in proven and probable reserves at its two production-sharing contracts (PSCs) in the onshore Ordos basin. See CHINA continued on page 37
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THURSDAY | MAY 9, 2013 | OTC SHOW DAILY
Stacking the Odds in the Industry’s Favor
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BY MARK THOMAS
ith more than US $1 billion invested so far in the Marine Well Containment Co.’s containment system, a sudden call last year from the BSEE (Bureau of Safety and Environmental Enforcement) put the system fully to the test. Marty Massey, chief executive of the not-for-profit
MWCC, recalled the moment while giving a presentation about the capping stack at a topical breakfast Wednesday, May 8, at OTC 2013. “I was sitting upstairs in my office and got a call that said the BSEE wanted to see me about the capping stack. ey were actually downstairs.” And so an oen practiced but never before used system for mobilizing and installing the capping stack in the ultradeep waters of the Gulf of Mexico (GoM) sprang into action.
Massey said that in 2012 the MWCC had carried out 20 exercises with its 10 member companies, spending 28 days practicing the call out of the MWCC and the deployment of the system. In this demonstration for the BSEE, Shell was the designated operator working in partnership with the MWCC throughout the demonstration. e MWCC’s liaisons were deployed to Shell’s command center throughout the exercise, with the BSEE team fully integrated with all the Shell and MWCC mobilization activities. Massey said communication links were maintained with the Department of the Interior leadership in Washington throughout the exercise, with daily briefings provided to the BSEE.
Thw MWCC capping stack was deployed
and successfully pressure-tested on the
seabed during the demonstration.
(Photo courtesy of MWCC)
Once all the kit had been pre-checked and tested, the capping stack was loaded onto the Laney Chouest and deployed to a simulated well in the GoM. Once offshore, the capping stack was lowered approximately 2,103 m (6,900 ) on a wire using a heave compensated landing system. It was latched onto a simulated wellhead, where all necessary functions were completed and pressure testing (up to 10,000 psi for 20 minutes) confirmed the ability to control the well. e mobilization, function, and pressure testing performed as expected and were within the anticipated timeline, Massey said. e capping stack and ancillary equipment were then transported back to See ODDS continued on page 37
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THURSDAY | MAY 9, 2013 | OTC SHOW DAILY
Leaders of the Future Learn the Path to Success
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BY RHONDA DUEY
ou know the industry is actively hiring when a journalist asked to cover a recruiting event is practically the only 50-something in the room. at was the setting at BP’s “Inside Track” event Wednesday morning, May 8, 2013. e event was geared for college students who might be interested in careers
with the company. Paul McIntyre, BP’s group head of resourcing, welcomed the group by stating that the two strengths BP prides itself the most on are its portfolio and its people. “is is a really exciting time in the industry,” McIntyre told the audience. “You’ve heard us in the media discussing our outlook for the world’s energy needs. “An increase in demand generates investment, which
in turn spurs activity. is requires a great deal of human capability.” McIntyre reiterated a quote that notes that all things are invented twice – first mentally and then physically. “All of this amazing technology started in somebody’s head,” he said. Despite hiring 10,000 people in 2012, the company is still on the hunt for qualified individuals. McIntyre said BP has reloaded its exploration portfolio and has a robust project portfolio for the future.
Quentin Dyson and Starlee Sykes answer questions during BP’s ‘Inside Track’ presentation Wednesday morning. (Photo by Gary Barchfeld Photography)
“We have to continue to invest in people,” he said, adding that the company spends US $500 million a year on training and development. Starlee Sykes, vice president of BP’s Global Project Organization (GPO), gave an overview of the company’s new upstream management structure. In 2010 BP decided to reorganize along global operating functions, creating groups for exploration, wells, projects, and operations. Currently the upstream group has 24,000 employees in 28 countries producing 11.5 Bbbl in 2012. e group invested $18 billion last year and generated a $22 billion profit. e GPO’s strategy consists of three prongs – growing its portfolio, maintaining an enduring presence in certain basins, and capturing value across the life cycle of a project. e primary portfolio targets are deep water, gas, and giant fields, while the group maintains its presence through building relationships, understanding the basins, and employing the latest technology. Value is captured in exploration, wells and projects, and operations. “We have a world-class portfolio in almost all of the major provinces,” Sykes said, adding that the three main areas of interest See BP continued on page 44
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THURSDAY | MAY 9, 2013 | OTC SHOW DAILY
See XXX continued on page 3
OTC 2013 Puts Spotlight on China
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BY PEGGY WILLIAMS
his year was a first for Chinese firms at OTC 2013, and they were proud. “e prospect of China’s development is a hot topic,” Xu Erwen, China consul general in Houston, said. “OTC is paying more attention to China, and this is the first time China is a spotlight.” e country is starting to achieve its dream of great rejuvenation, she said. It is look-
ing toward a future of high-tech, low-polluting energy sources, with three compelling initiatives driving its thinking: increased energy conservation, development of domestic resources, and cultivation of diverse energy supplies. Yan Cun-Zhang, president of China National Petroleum Corp.’s foreign development department, said that China surpassed the US in energy consumption in 2009. “But because of China’s big population base, per-capita consumption is still
quite low.” Coal accounted for 70% of China’s energy use in 2012, and its natural consumption is 5.4% of total energy. While oil prices are world level, gas-pricing mechanisms are more complicated. “e cost of importing gas from abroad is much higher than domestic fixed prices,” Cun-Zhang said. Today, China is shiing its emphasis to unconventional targets. e country sees good potential in unconventional resources and has substantial coalbed methane, tight gas, and shale gas targets. “We are right at the beginning of shale gas exploration,” he said. Overall, about 75% of China’s hydrocarbon endowments are in unconventional resources, and nearly 60% of its overall resources are unconventional gas. Zhang Yong Jie, president of Sinopec Oilfield Service Corp., said that strategic transformation regarding integration of services is occurring in China. “Currently, Chinese offshore companies can supply everything the industry needs, from shallow-water to deepwater equipment.”
Yan Cun-Zhang
Chinese fabrication yards are now able to supply the full range of equipment to global E&Ps, agreed Yang Yun, executive vice president of China Offshore Engineering Co. Ltd. China can build large-jacket substructure topsides over 30,000 tons, for instance. Worldwide, some US $1.24 trillion was expected to be invested from 2011 to 2015 with most of the focus on deepwater projects, and China fully aims to compete for a share of that market. Weaknesses that Chinese firms still need to overcome include improving their FEED design capability and growing their deepwater and subsea installation experience. But China offers cost-effective solutions. Most critical to customers are on-time delivery and high quality, and Chinese firms can deliver on both accounts, said Muthu Chezhian, chief technical officer of Rongsheng Offshore & Marine. “We are working on enhancing our competitiveness by focusing on standardization, securing high-level talent, enhancing our competence, and improving our ability to forge long-term alliances,” he said. Certainly, Chinese firms will be formidable competitors in coming years. n 12
THURSDAY | MAY 9, 2013 | OTC SHOW DAILY
Total’s Leviathan Deepwater Pazflor: A Technological Marvel that Will Drill for 20 Years
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BY DARREN BARBEE
otal’s Pazflor floating production, storage, and offloading (FPSO), as big as most US aircra carriers, is what Louis Bon, the project’s director, calls the tip of the iceberg. at’s because “the biggest part of the development is subsea and you don’t see it,” Bon said at OTC 2013. Below the massive ship is more than 160 miles (260 km) of pipeline and control lines that snake across the seabed. About 2,000 metric tons of equipment rest on the seabed. No wonder Bon calls the project the “great adventure.” “It is a huge investment, $9 billion, and it is in particular an offshore platform that uses new technology and equipment … specifically designed, engineered, and qualified for the project,” he said. At OTC 2013, Total was honored with the Distinguished Achievement Award for Companies for its Pazflor development. e prestigious award is presented annually to the company that has advanced deepwater oil expertise and technology as part of a major project. “It will be soon be two years to the day that Pazflor has reached the maximum operating capacity and is proceeding as planned, which proves the reliability and robustness of the technology that we have for that development,” Bon said. e platform operates offshore Angola in depths of up to 1,200 m. Production averages 220,000 b/d, and more than 45 MMbbl have been produced since August 2011. To get to that production, Total had to invent new ways of drilling underwater, including a groundbreaking subsea gas and liquid separation process. Commonly, oil is mixed with gas and water when it is extracted. e Pazflor deployed subsea separation units (SSUs) that strip oil and gas apart at depths where human intervention wouldn’t be possible. Once separated, the oil and water is pushed to the surface by seabed Pazflor pumps. e lighter gas rises naturally to the FPSO. e subsea modules are designed to operate for a 20-year period. Bon said the SSUs had never previously been used before on such a scale. “So we decided to run through a very intensive qualification program. is for each of the components of the subsea separation units,” he said. Commissioning tests were carried out in Norway and ensured functionality and simulate all steps of the installation sequence. In all, 13 different pieces of equipment were tested in 56 separate qualification tests, he said. “Strong quality assurance and quality control organization within the total team and contractors’ teams was in place and turned out to play a crucial role,” Bon said.
e project also required meticulous coordination at all levels. Total teams worked hand in hand with contractors, all of whom were located on the construction site and onboard during the commissioning. Supervision of projects spanned the globe in Angola, South Korea, Norway, and the US. Aer departing South Korea in January 2011, the Pazflor FPSO headed to its position in Angola in April 2011. One key was a well defined scope of work created through extensive front-end design and engineering studies. e project also strived to work in partnership with Angola by training technicians and management personnel in forefront deep offshore technologies. Finally, drilling into a pay of nearly 600 MMbbl of oil
required finding just the right spot. Total’s geosciences team also ensured the optimization of well placement and maximum well quality in coordination with the drilling team. Within six months all facilities, including water gas injection, were fully operational. “One of the important achievements of the project was to manage the good integration and good relationship between the geosciences and the drilling teams in order to optimize drilling,” Bon said. In August 2011, the Pazflor became one of the world’s largest deepwater developments. One year aer reaching its maximum capacity, the Pazflor is operating smoothly with an availability ratio of more than 97%. “We have made some new technologies and proven some new technologies to be useful to the industry,” Bon said. n
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OTC SHOW DAILY | MAY 9, 2013 | THURSDAY
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Rising to the Deepwater Challenge BY MARK THOMAS
A
ccording to Steve Wisely, executive vice president, Commercial, at offshore specialist Subsea 7, “As subsea projects continue to increase in size and complexity and they are more frequently executed in deepwater and harsh environments, new technologies and capabilities
have to be developed to meet the new operating challenges. At Subsea 7, we are investing in R&D and in our fleet to develop these new technologies.” e company has presented a total of seven technical papers at OTC 2013 covering novel solutions for ultradeepwater riser systems as well as advances in pipeline heating solutions and insulated pipe-in-pipe.
One of the papers discussed an uncoupled riser system for ultra-deepwater harsh environments called COBRA (Catenary Offset Buoyant Riser Assembly). e paper, authored by Daniel Karunakaran of Subsea 7 and Rolf Baarholm of Statoil, outlined the thinking behind the new uncoupled riser concept, highlighting the fact that steel catenary risers (SCRs) and hybrid riser towers have been an attractive choice for recent deepwater field developments. However, the design of SCRs for harsh environments or from large-motion host platforms remains a significant challenge, according to the paper. e key issues for the design of SCRs in harsh environments are the fatigue near the hang-off and at the touchdown point. Hybrid riser towers have their own challenges and need special bottom assemblies with heavy foundations and complicated spools. e COBRA system consists of a catenary riser section with a long, slender buoyancy module on top, which is tethered down to the seabed. e top of the catenary riser section is connected to the host platform by a flexible jumper. is concept combines the advantages of the SCR and the hybrid riser tower and eliminates the fatigue challenges at the touchdown point of the SCR while also avoiding the use of complicated bottom assemblies and spools of hybrid riser towers. Since the platform motions are uncoupled in this riser system, the fatigue in the SCR part is very small. Subsea 7 says COBRA is an efficient riser arrangement for host platforms with large motions, e.g. FPSOs or semisubmersibles. e flexible jumpers in this riser system effectively absorb the platform motions, and consequently the SCR section has almost no dynamic motions, which improves both strength and fatigue performance. e riser system has been developed for water depths ranging from 750 m to 3,000 m (2,461 to 9,843 ) in harsh northern Norwegian environments. “e results clearly indicate that it is possible to have a robust design of COBRA risers from large-motion host platforms in harsh environments using presently qualified material and technology. e firstorder wave fatigue response of the steel riser section is negligible, and the fatigue is purely controlled by vortex-induced vibration (VIV) and can be mitigated by the use of VIV strakes. e preliminary work also showed that this riser system can easily be installed in harsh environments. e riser components used in this riser system are all field-proven as they are used in other riser systems,” according to the paper’s abstract. Subsea 7 added that the concept also is applicable in less demanding environments such as Brazil. Furthermore, due to reduced dynamics in the SCR part of the risSee CHALLENGE continued on page 41
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THURSDAY | MAY 9, 2013 | OTC SHOW DAILY
Megaprojects Bring Huge Benefits, Huge Risks
T
BY DARREN BARBEE
he risks of a US $1 billion megaproject are, in many ways, like those of similar, smaller projects. Companies want to keep costs down, work with good people and contractors, keep workers safe, and hit their deadlines. e difference maker, of course, is scale, Clive Vaughn, Foster Wheeler’s CEO for upstream, said during OTC 2013, noting that the price tag for such projects may actually exceed $1 billion because of inflation. “A 10% overrun on a $100 million project is significantly different than the same percentage on a $1 billion project.” Vaughn said that despite the growing number of projects, “greater than 80% of megaprojects across industries fail to deliver on time or budget or both.” More are on the way. ExxonMobil is moving forward with Arctic projects and development of coalseam gas in
Australia. Projects under way include offshore gas on the northwest shelf of Australia, developments offshore Brazil, and the US shale plays in the Bakken in North Dakota and Eagle Ford in Texas. e main distinction of such projects is in sheer size and the timelines involved. But such projects are not “mega” simply because of the cost but also because of the complexity. Due to the scope of such projects, Vaughn said they are “like setting up a new company, right down to setting up a project email address.” Foster Wheeler has executed a number of these projects in recent years and said that all share essential elements to manage, including project management and controls, procurement and logistics, sheer size and timelines involved, subcontracting and contractor selection, and cultural factors. Contractors are becoming increasingly pivotal, Vaughn said, as contract work hours overshadow com-
Luc Messier of ConocoPhillips described the challenges
of building an LNG facility on Curtis Island offshore
Australia. (Photo by Gary Barchfeld Photography)
pany work hours. But each project is its own challenge, and creating a boilerplate for such projects would be formidable. at includes accommodating local workers. “Taking a model from one location to another location doesn’t necessarily work,” he said. “ere need to be adjustments.” Companies can even be hamstrung by older workers who have vital experience but face difficulty working in other countries. Recruitment is key, Vaughn said. “What you do need are key people to manage and organize the project.” Still, he said, projects should be carefully evaluated, especially those that require massive coordination and billions of dollars. And he ended his talk with a cautionary note: “Do we always question if the project was too big? Does the concept of diseconomies of scale exist?” Another challenge to such massive projects is competition. Luc Messier, senior vice president of projects supply chain for ConocoPhillips, said the company’s Australian LNG project on Curtis Island has been a test. e project will develop Australia Pacific LNG’s coalseam gas resources in the Surat and Bowen basins in central-southwest Queensland, a 520-km (320-mile) transmission pipeline, and a multitrain LNG facility on the island near Gladstone, Queensland. ConocoPhillips is responsible for the construction and operation of the Curtis Island facility in Gladstone. However, two similar projects are being built on the same island, “really next door at the same time,” Messier said. “That makes it really challenging from a resource standpoint and a construction labor challenge.” A downturn in local mining has helped, allowing easier access to local resources. At the same time, “We were competing at the time for access to LNG sales agreements, so being first was a key thing,” he said. Being on an island also requires excellent logistics, since ferries and boats as well as infrastructure are required to transport materials from the island to the mainland. Messier said that in looking back at megaprojects and most other sorts of projects, what divided the good from the notso-good was simple: “Successful projects always had good engineering up front.” It is a lesson the company will take to heart over the next five years as it plans to spend $16 billion, including 30% on major See MEGAPROJECTS continued on page 46
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THURSDAY | MAY 9, 2013 | OTC SHOW DAILY
Offshore Ethics Moves Onshore BY EMILY MOSER
E
thics is a topic that offshore operations deal with daily, but speakers at the OTC 2013 ethics breakfast on May 6 did not stop there. “OTC is an offshore conference, but ethics doesn’t stop at the water’s edge and only deal with the offshore,” Dan Tearpock, founder and chairman emeritus of Subsurface Consultants and Associates LLC, said. “It deals with the onshore as well.” Ethics are different in each country and for each company around the world, he added. While there is no complete solution to getting people to follow a set of ethics worldwide, the place to start is with young professionals. A couple of years ago, Tearpock was surprised about what he saw at an ethics talk he gave at Saudi Aramco. First, he was surprised that he was asked to give an ethics talk. Then, he was astounded to have nearly 200 people attend, many of whom, he said, were young professionals wanting to learn more about international ethics. “We’ve got to get the young professionals,” he said. “We’ve got to train them, and we’ve got to give them the guts to be able to go to managers and say, ‘This is wrong.’” Barbara Thompson, senior vice president of Aker Solutions, said every culture should have the option for whistleblowing that allows people to report misconduct without having to worry about being penalized. However, the biggest difference companies can make internationally is to be involved with community outreach, she said. People need to know that they are thought of as individuals. Tearpock added that professional responsibility leads to professional reliability, enabling others to count on you for what you do. Professional responsibility encompasses a number of things that require companies and their employees to act in a professional manner at all times. “When we’re doing professional practices in whatever we’re doing – exploration, production, or whatever – we have to deliver on promises,” he said. “If we’re not doing that, we’re not doing an ethical job.” When faced with a moral dilemma dealing with ethics, Tearpock recommended asking: • Who knows; • Who is impacted; • How are they impacted; • What is the downside; and • What is the worst-case scenario? “These are phrased in a way for you to examine the consequence of your decision rather than the benefits or justification of your action,” he said. “You can literally justify anything. You can justify things that are wrong.” Finally, Tearpock said education for professionals is a never-ending process. “As long as we’re in the business, we have to take courses and get trained because things are changing very fast. We have to make sure we understand it to be able to use it and then present it.” n
OTC SHOW DAILY | MAY 9, 2013 | THURSDAY
During OTC 2013 Weir Oil &
Gas is featuring its surface
control offerings including
the Seaboard wellhead and frac stack which is more
than 5 m (15 ft) high.
(Photo courtesy of Weir
Oil & Gas)
17
Afungi LNG Park Could Reach 14 Trains
T
BY SCOTT WEEDEN
he government of Mozambique asked Anadarko Petroleum Corp. if its Afguni LNG facility be designed to accommodate 14 trains, producing 70 million metric tons of LNG per year (MMmt/y). Anadarko was a little taken aback by the request, but the company showed the government that indeed its plant site could include up to 14 trains. With an estimated 170 Tcf of gas in place, Mozambique sees the tremendous growth potential of its offshore natural gas resources. And, the government wants to find ways to monetize that gas through an LNG project. “We are focused now on four LNG trains for Phase 1,” Cory Weinbel, project manager, Mozambique facilities, Anadarko, told participants at the topical breakfast “Mozambique Gas Development – An Exciting and Transformational Opportunity” at OTC 2013 on May 8, 2013, in Houston.
Anadarko, which operates Area 1, and Eni, which operates Area 4, are working together to develop the onshore LNG facility. “We signed a heads of agreement (HOA) in December 2012. Eventually we will form a joint development company for the onshore plant. The scope of the HOA does not include marketing or reservoirs that do not straddle both areas,” he continued. “We will focus on Area 1, but we will also work with Eni to make sure the system’s compatible,” he added. e initial phase will include two trains supplied from Area 1 and two trains supplied from Area 4. Each train will have a capacity of 5 MMmt/y and will need 850 scf/d of natural gas to feed it. “Anadarko is making sure we have enough gas from Area 1 to support two trains and sustain that for 25 years,” Weinbel explained. e company believes it has the recoverable reserves to supply those two trains.
In December 2010 its recoverable reserves were estimated at 5 Tcf. By March 2012 the estimate had grown to 17 Tcf to 30 Tcf. “e overriding message is that we have a lot of gas and can easily supply two trains,” he said. Prosperidade development Anadarko is putting its attention on the Prosperidade complex, which straddles the boundary of Eni’s Area 4. e company considers it to be the most prolific. It has another major complex with its Golfinho/Atum field, which is entirely within Area 1. “With these two worldclass offshore developments, we will have our hands full for years to come,” he continued. Another major discovery was recently announced with the Tubarao-2 well. e wells are located about 50 km (30 miles) and the field is about 50 km to 60 km (30 miles to 36 miles) long. e development includes three separate systems: offshore gathering, pipeline to shore, and LNG plant. “e field is huge and so is the gathering system,” he said. “We are using a conventional gathering system and a largediameter pipeline (22 in.) to the plant.” Wells should be capable of producing 100 MMcf/d to 200 MMcf/d each. For the LNG facility Anadarko issued three FEED contracts to Bechtel, CBI and Chiyoda, and JGC and Fluor. ree FEED contracts also were issued for the offshore field development to Technip and Heerema, Subsea 7 and Saipem, and McDermott and AllSeas. e Afguni LNG Park will be built near Palma. One of the keys to the site is the marine system and Palma Bay, where several deep channels facilitate movement of LNG ships. e bay does have a tidal change of about 4 m (13 ) per day, which will have to be included in the design of the dock and offloading jetties. e LNG FEED is due within 14 months and the offshore FEED in 10 months. e company expects to receive the environmental permit in 3Q 2013. Site improvement work has started. e final investment decision and engineering, procurement, and construction are expected in 2014. First sustained LNG production is set for 2018, Weinbel added. ‘It is all about the people’ In Mozambique the GDP per capita is about US $1,000 per year. As Anadarko continues to emphasize, this project will be transformational for Mozambique. “These are incredible people who have a love for life. The people are happy, excited about the project, and want to work,” he said. However, the local residents have little training. “Part of the development includes a training center, which we opened on March 6, 2013. We are focusing on teaching the people how to come to work, how to dress for work, and how to wear personal safety equipment,” he explained. There will be huge impacts to the communities socially and culturally. There are several villages within the Afguni LNG Park that may have to be moved, for example. “We have to understand how the people will be impacted so we can take the next step and develop mitigations,” he continued. e company is working within an environmental and social management plan that includes environment, health, resettlement, stakeholders, human rights, and community investment. n
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THURSDAY | MAY 9, 2013 | OTC SHOW DAILY
GoM’s Cascade, Chinook Fields Ring up Historic Firsts
I
BY JENNIFER PRESLEY
f there was a popularity contest for OTC technical sessions, then the Cascade and Chinook FPSO session held on May 6 would be a strong contender for first place. e crowd was standing room only. And with a number of technological firsts for the US Gulf of Mexico (GoM) under its belt, it is easy to understand why the Petrobras-implemented project would garner such an impressive turnout. Among the many Cascade and Chinook FPSO project accomplishments: the first use of an FPSO in the GoM; the deepest floating production system, at 2,500 m (8,200 ); the first use of purpose-built Jones Act shuttle tankers in the US; and the first single-trip multizone-frac pack system application in three-zone wells at depths of 8,230 m
(27,000 ), according to presenter Cesar Palagi, Walker Ridge asset manager for Petrobras. e project presented numerous development challenges over the course of 10 years, from the 2001 announcement by US agencies that made FPSOs a production option in the US, to first oil production in 2012. Drilling challenges e Cascade and Chinook fields are in water depths of 2,500 m (8,200 ) and 2,682 m (8,800 ), respectively. Wells are in the Lower Tertiary Wilcox sands at depths of approximately 7,620 m to 8,230 m (25,000 to 27,000 ), according to Flavio de Moraes, well manager for Petrobras, in his presentation on the project’s drilling and completion designs. “e reservoir itself has about a 1,200--thick gross
interval, a very thick pay,” he said. “e reservoir sands are separated by silt and shales, with very low permeability, and we can assume zero vertical permeability.” A well-design analysis performed by experts in Brazil and the US found that the wells needed to be drilled with vertical to low-angle wells because of the thick net pay. Completions design and production should be maximized using several frac packs, he said. Well design, according to de Moraes, was validated with the successful drilling and completion of the first three wells in the Cascade and Chinook project. It was “very important for us and for the industry in the near future,” he said. To market The two fields are located in the ultra-deep water of the GoM approximately 258 km (160 miles) south of the Louisiana coast, where there is currently no transportation infrastructure. In addressing the challenge of getting the produced crude to shore, the project opted to use an FPSO unit and shuttle tankers. “The first FPSO application in the US was put in 2006,” said Jeremiah Daniel, marine systems engineer for Petrobras. “It was based on the fact that Petrobras has a lot of experience with FPSOs in Brazil (and) Petrobras brought that experience with them to the US.” Capable of processing up to 80,000 b/d and storing up to 500,000 bbls of oil, the FPSO BW Offshore arrived on site in the GoM in 2010, according to Daniel. A key safety feature, the FPSO’s mooring system, allows it to go to sheltered waters when necessary. “If there is a hurricane, for example, the FPSO can be disconnected,” Palagi said. First oil was produced, offloaded and transported to shore in 2012 using two US-built shuttle tankers. The M/T Overseas Chinook and M/T Overseas Cascade were built at the APSI Aker Philadelphia Shipyard Inc. and are operated by OSG Ship Management Inc. The vessels can transport approximately 325,000 bbl of oil and as of May 2013, 15 offloading operations have been safely performed. n
INTERNET/ COMPUTER ACCESS
• Email stations are located in the Reliant Center Hall A entrance, level 1.
• Free, low-bandwidth wire-
less internet access is available in the lobbies of
Reliant Center, levels 1 and
2, and the lobby of Reliant
Arena. The network name is
Free Internet.
• Wireless access in the
meeting rooms is available
for US $12.95 per day.
20
THURSDAY | MAY 9, 2013 | OTC SHOW DAILY
GL Makes LNG-powered Seagoing Vessels a Reality
W
BY CAROLINE EVANS
hen people think of the global energy industry, they usually think about E&P companies, wildcatters drilling for oil and gas. Other times, they think about the midstream: pipelines, tankers, and railways. ey might even think about newer innovations, such as wind technology. But behind the scenes are consulting firms, helping these sectors find “safer, smarter, greener solutions,” according to Germanischer Lloyd (GL) business development director, North America, Justin McAdams. e company also acts as a classification society whose GLclassed ships make up about 45% of the world’s container fleet, McAdams said. He outlined how GL helps ship owners and managers run their vessels more efficiently and more affordably during a presentation at the Offshore Technology Conference on May 6.
One particular project that has brought this behindthe-scenes company to the forefront: the Bit Viking, the first seagoing vessel in the world to be converted to run on liquefied natural gas (LNG). It underwent successful sea trials in 2011. “e Bit Viking was retrofitted with a dual-fuel engine,” McAdams said. “It’s on the water as we speak.” e ship is owned by Tarbit Shipping and is operated by Statoil along the Norwegian coast, according to GL’s website. It has a range of 12 days, and its conversion to LNG qualifies it for lower Norwegian taxes. “e Bit Viking is one of the most environmentally friendly 25,000-ton product tankers in the world,” according to the website. “Ultimately, our entire job is to save time and save money, and this is another method for us to push,” McAdams said. “We were one of the first classification societies to submit rules on LNG fuel.” But for GL, that’s a good start. Futureship, another
member of the GL network, is developing a concept for a zero-emissions ship. “e aim is to make shipping free of carbon, sulfur, and nitrogen emissions by using wind and solar energy to power vessels. When the energy is converted to a carrier, such as hydrogen, and then transferred to a fuel cell or battery, it can be used to power the zero-emission ship, which has been specially streamlined for the technology,” according to GL’s January 2013 publication In Focus. GL, the maritime arm of GL Noble Denton, was founded in the 19th century as a ship classification society. e classification part still exists, but the company also helps ship owners with everything from design to decommission, McAdams stated. e company also assists with ship management and “develops state-of-the-art rules, procedures, and guidance for ship owners, ship yards and the maritime supply industry,” according to the GL website. n
Future of UAE Energy Industry is Bright
C
BY CHRISTINA NELSON
urrent trends, future goals, and overcoming challenges of the UAE’s energy market were the focus of the UAE Industry Breakfast on Wednesday, May 8, at OTC 2013. e panel was moderated by Richard Westerdale, director of policy analysis and public diplomacy for the US Department of State’s Bureau of Energy Resources. Speakers included Danny Sebright, president of the USUAE Business Council; Arafat al Yafei, CO2/N2 development manager at ADNOC (Abu Dhabi National Oil Co.); Guy Tennant, area vice president of the Southern Gulf at Halliburton; and Anthea Pitt, executive editor of the Petroleum Economist. Westerdale opened the panel by emphasizing the growing importance of the relationship between the US and the UAE, citing the three main goals of the US Department of State as energy diplomacy, energy transformation, and energy governance and access. According to Sebright, the importance of the relationship between the US and UAE cannot be stressed enough. “e UAE has been our top destination for export goods in the entire Middle East and North African region since 2009,” he said, detailing that the two countries shared upward of a US $25 billion trade relationship last year. “Proximity to international trading routes means that the UAE is becoming a real hub for energy exports to connect east and west – China and India with Europe and the US – and, increasingly, north and south – all the Central Asian republics and Africa.” Both Sebright and al Yafei discussed the country’s plans for sustainable See UAE continued on page 46
OTC SHOW DAILY | MAY 9, 2013 | THURSDAY
21
Playing It Safe
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BY RHONDA DUEY
ith the 2010 Macondo tragedy still fresh in people’s minds, safety and environmental stewardship are becoming increasingly important, particularly in the deepwater environment. During a Tuesday OTC lunch titled “Safely Pushing the Deepwater Envelope to Create Value,” Gerard Schotman, executive vice president of innovation and R&D and CTO of Royal Dutch Shell, gave his company’s perspective on the challenges involved in continuing the push into deeper waters. While stating that the future of deepwater development is “even brighter and more exciting” than what has already transpired, Schotman outlined key issues involving not only safety but also cost. “Innovation is more than just work; it’s the name of the game,” he said. “We even have to innovate the way we innovate.”
Deepwater challenges the industry at every step, beginning with the exploration phase. Schotman described this as “making the invisible visible.” Shell is combining ocean-bottom seismic (OBS) technology with wide-azimuth acquisition to obtain better subsurface images. To manage reams of data, high-performance computing (HPC) comes into play. “HPC is not just a ‘nice to have,’” he said. “It’s a step-change that’s required to deal with this increased amount of data.” Shell is collaborating with IBM and Intel in this realm. Visualization also is increasingly important, and Shell has partnered with Hollywood special-effects companies that have engineered 3-D effects in movies such as “Avatar.” In the drilling arena, Shell is collaborating with Noble on its Bully rigs. Schotman said the rigs are shorter and lighter than traditional drillships, boasting advanced automation and a reduced environmental footprint due to
Royal Dutch Shell executive vice president Gerard
Schotman addressed attendees at the May 8 OTC
luncheon, "Safely Pushing the Deepwater Envelope to
Create Value."
better fuel economy. ese rigs allow for safer, faster operations, he said. Shell also is working with Transocean on the seventh generation of its dynamically positioned drillships. The goal is to build four virtually identical vessels to enable standardization and operating efficiency. Regarding production, Shell already has had success with subsea boosting at its BC10 and Perdido fields, and Schotman said that Ormen Lange, one of the largest offshore developments in the world and completely subsea-operated, might eventually get this technology once the reservoir’s natural pressure declines. Although the company is having success with subsea boosting and compression, Schotman said that this technology “is not a mean technical feat.” Another production advancement is related to flow assurance. New hydrate-inhibition technology reduces “touch time,” he said, referring to the number of times intervention is required. To prevent future Macondos, the company is testing tools to nip a blowout in the bud, including an emergency-separation tool that severs the riser above the blowout preventer and an explosive that causes the tubular to collapse, shutting off the subsurface flow. Shell also is active in reservoir surveillance, equipping the BC-10 field with permanent OBS technology and making it Shell’s first and the world’s deepest life-offield-seismic project. “It’s exciting to have this type of technology in place,” Schotman said. “But not every field can afford this.” To that end, Shell is experimenting with reservoir monitoring on an interim basis. Called “instantaneous 4-D,” the technology deploys ocean-bottom nodes around water injection wells periodically to determine how effective the injection is. Currently a pilot project is taking place at Shell’s Great White Gulf of Mexico field in 3,000 m (9,843 ) of water. “Instantaneous 4-D will play a significant role and become the technology of choice in advancing reservoir monitoring,” he said. Overall, he said, advances in deepwater development over the past 30 years are “a great demonstration of the global reach of the deepwater industry. It’s good for the industry, and it’s good for the customers, investors, and partners. And it’s crucial to safe operations in the future.” n 22
THURSDAY | MAY 9, 2013 | OTC SHOW DAILY
ABS Expands to Asset Integrity Management, Performance Optimization
H
BY SCOTT WEEDEN
istorically, class societies have focused on offshore hardware – floating or fixed structures and the systems that support the function of the units and protect onboard personnel. However, “in today’s offshore operations, class societies have to do more. e role of class has to change as industry changes,” Ken Richardson, vice president of energy development for ABS, said. “e ‘class of the future’ has to be aware of the changing face of offshore operations, where automation is introducing performance improvements and real-time data [are] altering the day-to-day decision-making process,” he said during a press conference on May 6 at OTC 2013 in Houston. “is requires a shi in how class interacts with industry as we move from a safety certification role into an expanded role of performance verification,” he continued. “Our objective is to bring together real-time operational data in a collaborative way to develop tailored solutions. e ultimate goal is for the class process to be more focused, less intrusive, and more efficient.” e issues of asset integrity and performance optimization are among the most pressing in the industry. “ABS is tackling these issues with data management solutions that address the soware/machine interface, advanced hull and structural integrity management, and optimized maintenance and reliability practices,” he said.
said. About 10% of the asset base drives 90% of downtime and 90% of the repair costs. “Predictive/condition-based maintenance is nonintrusive, better aligned to identify pending failure, and massively more efficient,” he continued. “Average MRO [maintenance, repair, and operations] supply chains and storerooms are short [of] critical spares and overstocked by 20%.” Asset management and maintenance reliability, if done well, achieves two significant goals: Increased productive capacity is unlocked, and efficiency is improved. “e key to this part of return on investment is the reliability program,” he said. “is unlocks productive capacity by reducing unplanned downtime and improving efficiency. Assuring you have the right critical spares in place is the key to avoiding downtime. On the other
hand, not overstocking in other areas such as noncritical parts is also important.” ABS’ asset methodology is called “maintenance master planning.” It takes ABS about two weeks on an industrial site to baseline where the company is in terms of enterprise asset management. 3-D hull integrity management In the third area discussed by ABS, Chris Serratella, director of applied innovation, listed the issues with offshore floating hull integrity. “Offshore units do not drydock like ships, hence the need to track and monitor conditions in a robust manner to identify continuous safe operation, prevention of impact to the environment, See ABS continued on page 46
Soware verification alternatives Cris DeWitt, director of technology, soware, and control system integrity for ABS Group, described the work ABS is doing with soware verification alternatives. One of the things that makes this process complex is the number of soware vendors, and not all soware vendors are operating at the same level. One measurement of vendor effectiveness is the number of defects per 1,000 lines of code. e industry average is about 15 to 50 errors per 1,000 lines of code. Microso averages about 10 to 20 defects per 1,000 lines of code, he said. “When Microso soware is deployed it has about 1/2 defect per 1,000 lines. However, Microso has a lot of lines of code. For example, there are 40 million lines of code in Windows XT.” So how does a company verify soware? DeWitt listed six approaches: robust soware engineering; field soware verification and validation; soware-in-the-loop; emulation vs. simulation; complementary testing; and hardware-in-the-loop (HIL). e purpose of HIL testing of a “system,” for example, is to test that the outputs for a given system or subsystem are correct for given needs. HIL can test the behavior of specific hardware/firmware with specific soware, input/output noise tolerance, system response to power disruption, and instrumentation dri. Regulatory demand for reliability is one of major drivers of HIL testing. Enterprise asset management US industrial downtime runs between 3% and 5%, while industrial assets last only 60% to 70% of the expected life on average, Rob MacArthur, vice president of asset performance optimization for ABS Group, OTC SHOW DAILY | MAY 9, 2013 | THURSDAY
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Atlas Copco Adds Jet Sub for Pneumatic Drilling
I
BY SCOTT WEEDEN
n pneumatic (air) drilling, the amount of air needed to clean cuttings from horizontal wellbores oen increased the pressure on the hammer and bit, leading to damage. Atlas Copco Secoroc has patented a jet sub that has the potential to cut directional deephole drilling time by half and reduce costs by more than 50% by increasing penetration rates, reducing vibrations, eliminating equipment damage, and enhancing bit performance. e jet sub was one of three new products and services introduced by Atlas Copco at OTC 2013 in Houston on May 8, 2013. e company also introduced new polycrystalline diamond compact (PDC) drill bits, a monitoring service for its compressor service, and new compressors designed for offshore service. Prior to the development of the jet sub, air flow required to effectively clean the hole had to pass through The Atlas Copco Secoroc jet sub diverts
much of the air required for this applica-
tion to the hole before it reaches the
motor. (Images courtesy of Atlas Copco
Secoroc)
the hammer/motor assembly. at caused the motor to over-rotate, resulting in inefficient drilling with excessive wear and damage to the bit. A jet sub can be inserted in the drillstring in one or two places about 2,000 to 3,000 behind the operating hammer, explained Ray Shelor, product line manager, downhole drilling equipment, Atlas Copco Construction & Mining. e new tool monitors the air pressure in the drillstring. When a certain pressure is reached, a port in the sub opens, diverting air into the annulus to enhance removal of cuttings, he said. “With the jet sub in the drillstring, an operator can hammer through the curve. We have been able to do this on a couple of wells. We modified the hammer to increase the productivity,” he continued. By maintaining constant rotation speed, “whipping” of the bottomhole assembly (BHA), which can lead to motor damage, and vibration levels caused by whipping, which could destroy expensive MWD tools, are reduced. e system can monitor the performance of the hammer, allowing the driller to sees changes in operating characteristics in real time and make instantaneous adjustments in operating parameters to optimize ROP and avoid damage to the BHA. New PDC bit products With the acquisition of Newtech Drilling Products LLC, Atlas Copco Secoroc added a line of PDC drill bits, including Matrix Body and Steel Body PDC drill bits. e bits range in size from 3 in. to 17 1/2 in. “We now have the capacity to go up to 36 in.,” said Mark Jones, engineering manager, Atlas Copco Secoroc. e Matrix Body and Steel Body drill bits are impact, abrasion, and erosion resistant. To minimize whirl and drill a precise hole, the design features strategically placed, force-balanced PDC cutters for more effective bit performance. An asymmetric blade design also reduces drilling harmonics, he explained. See DRILLING continued on page 39
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THURSDAY | MAY 9, 2013 | OTC SHOW DAILY
Eliminating Rathole Cleanout Time
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CONTRIBUTED BY SCHLUMBERGER
rilling safely and efficiently in deepwater environments is expensive, and with increasing geological complexity, higher temperatures, higher pressures, and greater logistical challenges, costs continue to rise. A significant part of the energy from the top drive often does not reach the drill bit but is instead lost through shock and vibrations throughout the drillstring. By optimizing the total drilling system the surface energy can be better harnessed to ensure it reaches the drill bit and increases the ROP. Schlumberger achieves total system optimization by establishing computer models that can predict the behavior of the entire drillstring from top drive to drill bit as it rotates. These models are used both to optimize bottomhole assembly (BHA) design and in real-time during drilling operations. The i-DRILL engineered drilling system design uses predictive modeling to identify total solutions that minimize vibrations and stick/slip during drilling operations and optimize BHA p e r f or m a n c e for a given environment. Employing the IDEAS integrated drill bit design platform, the iDRILL drilling system design Using this engineered quantifies the drilling system incorvibrations and porating two reamers, ROP for a Noble Energy avoided given drilling a time-consuming system as a rathole cleanout run. function of (Image courtesy of time. This is Schlumberger) accomplished by combining a bit-rock cutting model with a finite element analysis of the bit and drillstring. In a project for Noble Energy the iDRILL design process was used to optimize surface operating parameters and reamer placement in the BHA to minimize the time required to enlarge the rathole in a deepwater well in the Gulf of Mexico. Hole enlargement while drilling is a common practice in this area, typically resulting in a rathole of more than 30 m (100 ft) at total depth (TD). In deepwater drilling the reamer is positioned above the long measurement and LWD (MLWD) tool string so that the enlarged borehole will not degrade the accuracy of formation evaluation measurements. To open the long rathole to the larger borehole size, the usual practice is to trip the drilling BHA back to surface and perform a dedicated cleanout run, which adds a day or more to the well construction timeline. Noble Energy wanted to avoid an extra cleanout run in the 12¼-in. by 14½-in. hole section, and the i-DRILL system was used to design an integrated dual-reamer drilling system to achieve this objective. A OTC SHOW DAILY | MAY 9, 2013 | THURSDAY
Rhino XS hydraulically actuated reamer was positioned above the measurement and MLWD tools, and a Rhino XC on-demand reamer was positioned below the tools and above a PowerDrive X6 rotary steerable system (RSS) and MDi716 PDC drill bit from Smith Bits, a Schlumberger company. e directional response of the RSS also was modeled to ensure that placement of the Rhino XC reamer did not interfere with its directional capabilities. During drilling of the section, the blocks of the Rhino XC reamer were locked at ⅛-in. undergauge from the 12¼-in. bit size to avoid interfering with the drilling operation. The Rhino XC reamer cutter blocks were special cement cleanout blocks with a minimum number of cutters on the gauge surface that would be passive when retracted during normal drilling mode. In this configuration the reamer acted as the control stabilizer in the drilling system, pro-
viding a pivot point for the PowerDrive X6 push-thebit RSS. Upon reaching TD, the BHA was tripped back to the depth where the Rhino XC reamer would be above the 12¼-in. pilot hole. The pumps were then cycled to activate the reamer blocks, so the reamer would enlarge 54 m (178 ft) of the rathole to 14½ in. The engineered drilling solution drilled the 372-m (1,221-ft) section in 14.5 hr at an average ROP of 25.8 m/hr (84.5 ft/hr) while opening the 12¼-in. pilot hole to 14½ in. with the Rhino XS reamer. After reaching TD the Rhino XC reamer enlarged the rathole from 12¼ in. to 14½ in. only 3.5 hr, eliminating the need to perform a dedicated rathole cleanout run after tripping the drilling BHA back to surface. This procedure saved Noble Energy an estimated 16 hr of rig time. To learn more about engineered drilling solutions, visit Schlumberger at booth 4441. n
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Seabed Production Innovation Boosts Expectations
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BY MARK THOMAS
ransferring the task of the initial processing of oil and gas from platform topsides to the seabed for both brownfield and greenfield projects has been one of the offshore industry’s greatest technological challenges. Once merely a vision, the concept of subsea factories – a phrase coined by Statoil, one of the biggest proponents of subsea processing solutions – is close to reality. Today, the various components required for an all-encompassing system are deployed with increasing confidence in long-term performance and reliability. e need to have subsea processing options – essentially the ability to manipulate the wellstream between the wellhead and host facility – at their disposal is vital for oil and gas operators, especially those at the forefront of pioneering ultra-deepwater projects or remote and harsh environment developments such as the Arctic Circle. ere are currently four main types of subsea processing application: • Single and multiphase hydrocarbon boosting (pumping); • Gas compression; • Separation systems (gas/liquid and liquid/liquid with produced water reinjection); and • Raw seawater injection. e main prerequisites and enablers for the above applications are: • Long-distance/high-voltage power; • Advanced process monitoring and control; and • Cost-efficient installation, maintenance, and retrieval.
New ways of applying subsea processing New technology development continuously opens the door to new ways of applying subsea processing, according to Simon Davies, project manager of Technology at Statoil (which receives more than 50% of its production from subsea production systems via 500 operated subsea wells). In the future there is likely to be even tighter integration of subsea processing building blocks used as part of a complete field development concept. Statoil’s Ormen Lange field will be one of the
world’s largest subsea processing systems in the
world and will set new benchmarks in terms of
the scale of seabed compression projects.
(Photo courtesy of Statoil)
Higher recovery rates With the generally accepted thinking that wet tree developments with boosters can deliver between 5% and 20% higher recovery rates compared to dry tree developments, the commercial benefits can be very persuasive. is applies to both new and existing projects, with companies like Statoil making it a key part of future plans to improve reservoir recovery rates from both brownfield and greenfield developments. Much of the company’s focus lately has been on seabed gas compression, the most recent subsea processing technology, which has not yet been implemented in any field worldwide. In simple terms,the closer that compression can be placed to a well, the more gas can be extracted. Traditional topsides compressors have a low tolerance for liquid, resulting in two approaches to subsea compression: • Separating the gas so that a “traditional” compressor can be used; and • Building a liquid-tolerant or multiphase compressor. e operator is planning to break first ground by using subsea gas compression for some of its domestic flagship North Sea projects such as Åsgard (expected to be the first to get underway in 2015), Gullfaks South (also possibly started in 2015), and Ormen Lange (to be started at a later stage in its producing life). e company also has at least 10 other projects that it is considering for the same potential application. But subsea processing covers a much wider remit than just gas compression and for some areas is considered an enabling technology for new projects without which fields cannot be profitably developed. 26
THURSDAY | MAY 9, 2013 | OTC SHOW DAILY
e industry’s vision of a subsea factory may drive the application of more sophisticated gas processing on the seabed (gas sweetening and gas dehydration). Reinjection of produced water for pressure support rather than disposal will bring more stringent requirements for produced water quality (effective subsea produced water treatment and monitoring). Longer and more remote step-outs also are raising interest in developing local, potentially renewable power generation concepts, Davies said. Pumping and compression technology will continue to evolve, he continued, while separation systems will also become more sophisticated, incorporating compact separation technologies and electrostatic coalescers. More compact wet gas compression units also will emerge to enable the development of small and mediumsized fields. e benefits So what are the basic benefits of subsea processing? Apart from increased hydrocarbon recovery and productivity, it also has the potential to reduce field develVital seabed processing experience has
been gained on pioneering projects such
as the Tordis subsea separation and
boosting development offshore Norway,
the world’s first application in 2008 of
produced water reinjection with sand
management, multiphase metering, and boosting of wellstream fluids, all in a
modular design. (Image courtesy of Statoil and FMC Kongsberg)
opment costs (both capex and opex), increase development flexibility through a reduced need for offshore topsides facilities or facility modifications, and as a result increase revenue. ere also is improved flow assurance capability and the enabling of longer tieback distances. With subsea processing increasingly important in today’s ever-more-stringent offshore safety regimes, there also are obvious health and safety benefits such as reduced fire and explosion risks, chemical consumption, manned offshore operations, and environmental footprint and improved energy efficiency. ere also is less to decommission at the end of the field’s productive life. Such benefits could be crucial in helping to open up or expand the production potential of offshore regions around the world. e Gulf of Mexico (GoM) can hardly be considered an untapped province. Yet according to a study by analyst Quest Offshore, over the next decade the introduction of some and extended use of other enabling technologies will be essential for the region to reach its production potential. Most prominent, Quest reported, is the use of subsea boosting and pumping in the Lower Tertiary areas. Shell’s Perdido field was the first Lower Tertiary development to come into production and use electronic submersible pumps (ESPs) to increase production volumes. Petrobras executed the second Lower Tertiary project in the GoM with the Cascade Chinook development and also used ESPs. Chevron’s Jack/St. Malo project is expected to be the third Lower Tertiary development to start production and will also use subsea boosting to increase flow rates to the production host, indicating that most, if not all, of future Lower Tertiary developments will use subsea See SEABED continued on page 35
OTC SHOW DAILY | MAY 9, 2013 | THURSDAY
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Connect with Social Media
O
BY ANTHONY D. DARBY
TC is in social media overdrive. e engagement and interaction is through the roof and encompasses conversation from the show floor, parties, technical sessions, OTC Night at the Ballpark, and more. Check out some of the happenings below and join us on the ones you frequent to get the most out of your OTC experience. Facebook: OTC on Facebook is all about photos. Log on to see photos from events and activities, Reliant Center, Reliant Arena, and the OTC Parkway among others. Who knows – maybe you are in one. Share, comment, and like at www.Facebook.com/OTCevents. Twitter: Twitter is active. From London, to Nigeria, to New Orleans, to Australia, a diverse mix of attendees makes up our followers who are discussing anything and everything
OTC. Follow the conversation by using the hashtag #OTCHOUSTON and be a part of the mix by following us at www.Twitter.com/OTCHOUSTON. YouTube: Catch up with everything OTC by watching video highlights of the conference. From in-depth interviews, to launch events, to OTC’s Chairman Steve Balint throwing out the first pitch during “OTC Night at the Ballpark,” we’ve got you covered at www.YouTube.com/eOTCvideos. LinkedIn: Did you attend the WISE, Project Management, or HSE networking events? Join the respective LinkedIn subgroup. The subgroups were created to take the conversation offline with like-minded individuals who attended the networking event. Join us by searching “Offshore Technology Conference (OTC)” in the groups search field and then clicking on “Subgroups.” n
OTC 2013’s Facebook profile was featured on the OTCTV screens during the conference. (Image courtesy of OTC Staff)
REVIEWING FLOWASSURANCE TECHNOLOGIES CONTRIBUTED BY FMC
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r. Phaneendra Kondapi, an engineering manager, Flow Management, at FMC Technologies, and a KBR adjunct professor of subsea engineering at e University of Houston, presented an informative topic about state-of-the art flow assurance technologies at OTC 2013. His presentation, “OTC24250 Today’s Top 30 Flow Assurance Technologies: Where Do ey Stand,” gave an overview of 30 Dr. Phaneendra existing and Kondapi developing flow-assurance technologies summarizing the current state of technology based on maturity level, solution type, applicability, and effectiveness. Kondapi mentioned that maturity level is a factor of the development stage of the technology and application of the technology in the subsea fields and is categorized into embryonic, emerging, matured or aging levels. In his paper, he classified all technologies into five different solution types: thermal, chemical, hardware, operating, and soware applications. He concluded that the key technology areas still at embryonic stage are cold flow, subsea coolers, and subsea compression. At the emerging stage are subsea separation and real-time flow assurance advisory soware. Most of the chemical and operating technologies are fairly established and See TECHNOLOGIES continued on page 41
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THURSDAY | MAY 9, 2013 | OTC SHOW DAILY
Reshaping the Barbell
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BY FRANK LLOYD, SMU COX SCHOOL OF BUSINESS
s attrition in the senior ranks of US energy companies continues to accelerate, the workforce gap widens between seniors and new hires. On one hand, industry firms face the challenge of “the great crew change” and its consequences, including the rising practice of “poaching” of high-potential leaders. On the other, firms struggle to accelerate young professionals into the “age of accountability” as leaders. A Hunt Oil executive called this a “barbell,” describing it as a workforce profile where high numbers of new hires and retiring senior leaders populate opposite ends of the graph with a stark deficit of middle managers obvious in between. In a recent Wall Street Journal interview BP Chair Bob Dudley emphasized the growing gap throughout the industry. “Industry veterans speak of a generational hole in the ranks. In the late ‘80s and ‘90s, nobody went into petroleum engineering, so now companies must rely on a cadre of aging graybeards plus an influx of newbies who can’t come onstream fast enough.” Many energy companies have turned to university business schools with focused leadership development programs to help them more quickly develop executive talent. And they have strengthened in-house learning and development teams by bringing in executives with advanced human resources experience and know-how. ese new learning officers challenge business schools to up their games. e goal? Accelerate progress of new and emerging talent by force-feeding them both business acumen and industry best practices – learning what once took decades to accomplish. To meet this challenge business schools must bring more to the table than faculty expertise. Today’s best schools are combining academic and operational expertise into executive development programs laser-focused on issues and challenges of top concern to the companies they serve. is oen involves program instruction from current and former industry leaders with application-oriented case studies and projects delivered alongside more research-based industry-relevant content brought by business faculty. e results of this highly customized programming can be powerful. One midstream oil and gas company CEO turned to Southern Methodist University’s (SMU’s) Executive Education program for just such a creative approach and realized measurable gains. Here’s a thumbnail of that program. e human capital challenges faced by the company included retaining good people, identifying high-potential candidates to build executive bench strength, and creating a succession planning process to promote from within. As part of the program three groups of 24 employees were trained over a four-year period. Each group participated in a series of learning modules – equating to 12 classroom days at SMU – over a seven-month timeline. Between modules, participants applied what they learned on the job. Each group was divided into teams that were assigned one of the organization’s real business challenges. ey were given four months to research its topic and propose solutions. During that time, dialog took place between the teams and the C-suite to discuss the issues and present and defend potential solutions. One group investigated the impact of large venture capitalists’ entry into all facets of the energy space – E&P, midstream, and service. With the assumption that the OTC SHOW DAILY | MAY 9, 2013 | THURSDAY
gave them more responsibility within existing roles. Additionally, participants cascaded a new language of leadership throughout the company, and decisionmaking became faster and more efficient. e organization also realized multimillion dollar financial performance improvements tied directly to the group’s capstone projects. The ‘barbell’ profile demonstrates the gap between new hires and senBased on post-program feedback evalior executives that continues to challenge the productivity of US oil uations, more than 70% of participating and gas companies. (Image courtesy of SMU) high-potential candidates improved leadership competencies such as interpersonal company could be a takeover target, the team assessed acsavvy, conflict management skills, managerial courage, quisition and divestiture opportunities and proposed ways team-building skills, and the ability to develop direct reto increase the company’s value over the next five years. ports. ese increased leadership competencies place this As a result of the program, the company promoted the industry player well on its way to eliminating the barbell majority of participants to senior leadership roles or from its leadership pipeline. n
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Geogrid Improves Production on Unstable Grounds
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CONTRIBUTED BY TENSAR INTERNATIONAL
perators and engineers are rapidly adopting new practices to stabilize well pads and strengthen roads around drilling sites, improving safety and saving millions. Tensar International’s TriAx Geogrid product can prevent rigs from leaning and can shore up roads pummeled by heavy trucks. e geogrid is a geosynthetic material that is manufactured from a punched and drawn polypropylene sheet. e triangular structure provides in-plane stiffness to reinforce weak subgrades under the well pad, which can prevent rigs from leaning and can also reinforce roads to better handle heavy traffic flow. Having been used in the construction industry, the product has now made its debut in the oil and gas industry.
“One producer saved [US] $1.4 million over 10 miles [16 km] of road,” David Lipomi, Tensar’s oil and gas market manager for the Appalachian region of the US, said. “is means this producer paid for the grid and put $1.4 million back in their pocket. Operators are thrilled because installing the geogrid prevents bottlenecks that oen occur during road and well pad construction.” Saving money on stone, damaged equipment When used under a well pad, the geogrid can allow operators to use up to 50% less stone when compared to traditional well pad construction. With high stone prices, removing 2 in. from the thickness of the road cross-section can sometimes pay for the grid. Additionally, the stone can be recycled and reclaimed at another well pad site because the geogrid does not allow the stone to become lost in the native so soil. The TriAx Geogrid can enable cost-effective road and well pad reinforcement.
(Image courtesy of Tensar International)
Weak soils at an unstable well pad can increase the risk of leaning rigs. In one instance, a leaning rig caused the drill head to rub against the caisson. e friction resulted in a hole forming in the pipe, and the caisson needed to be removed and replaced before drilling could continue. is type of a production setback could cost an operator millions of dollars in lost time and damaged equipment. Overcoming weather challenges Weather concerns also are a significant problem for operators. Rain, snow, or just cold weather can slow down the access road and affect overall construction time. Other reinforcement methods like chemical stabilization can be used, but clear skies and temperatures above 50°F (10°C) are needed for it to work successfully. Using a geogrid on roads can prevent any seasonality concerns and also can guard against damage caused by significant snowfall and ice lensing that can cause the road to deteriorate during the annual spring thaw cycle. Overcoming roadblocks Each month, access roads to drill sites are subject to severe damage from the thousands of sand and water trucks that pound unreinforced pavements. Severely damaged roads have become a hazard for the industry, and tremendous effort is under way to rebuild dangerous roads. Most roads are not designed to withstand the trucks’ heavy weight and the amount of traffic to and from an active well site. Using a geogrid to stabilize and strengthen roads can reduce the risk of trucks sliding off the road or bottoming out because of so spots. ese incidents can cause road blockage and delay any necessary timely transportations to and from the rigs. Operators who need to build or repair roads can reduce aggregate requirements up to 60% while also reducing labor and equipment needs by using a geogrid. e improved surface quality can create longer lasting roads with less maintenance requirements – meaning less cost. “As US shale plays continue to expand, geogrids will play an important role in ensuring access roads are safe and well pads are properly reinforced,” Lipomi said. To learn more about Tensar, visit booth 8559 in the Reliant Arena. n 30
THURSDAY | MAY 9, 2013 | OTC SHOW DAILY
Pemex Moving Toward Production, Human Sustainability
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BY CAROLINE EVANS
ydrocarbons make up 60% of the human energy consumption worldwide. at sounds like a lot until you consider that in Mexico, hydrocarbons make up 90% of energy consumption. And 60% of that is dedicated to oil alone. “We tend to think that the big reservoirs contribute mostly to our electricity production, but really what accounts for the increase in production in the last decade has been an increase in generation using gas,” said Carlos Morales-Gil, general director of Pemex Exploration and Production. “at is something that we have to take very seriously given the huge contribution that hydrocarbons make to energy consumption.” Morales-Gil, who spoke to a standing-room-only, early-morning crowd at OTC 2013 on Wednesday, added that hydrocarbon production also makes up around 30% of Mexico’s federal income. e topic of the presentation was “Moving Toward Sustainability in the Mexican Petroleum Industry,” and Morales-Gil outlined how Pemex is working to make production, as well as the human element in the industry, more sustainable.
cludes 20 Bbbl in conventional resources in the southeastern basins alone. ough the main activity is taking place in the southeast, the company is exploring gas resources in the northern part of the country and unconventional resources in Tampico-Misantla. In addition, there are 26 Bbbl to be unlocked in the deepwater Gulf of Mexico. Pemex’s Maximo-1 and PEP1 are being drilled at a depth of 3,000 m (9,580 ) below sea level and will be among the 10 deepest offshore wells in the world. “If we do not go to deep water, then we have to let go of half of the resources that we can find in the future,” he said. Human sustainability “All our projects need, essentially, three things: People,
investment and technology. e most important one is people, because with good people, technology will come. And if you have the resources, you can get the money. People is the critical factor,” Morales-Gil said. He went on to say that for a long time, Pemex “didn’t follow a recruitment policy that allowed us to capture the talent that we needed,” and thus did not recruit. Now, the company has a recruitment policy that includes going to universities to “capture the talent.” The company has also implemented integrated training programs that include workshops, mentoring, and graduate studies. More than 40 people in the company are currently working toward their master’s degree, and 15 are working toward a PhD. The program allows the company to foster talent within its own ranks, Morales-Gil said. n
Production e company developed a four-point strategic plan to grow its asset base, increase operational efficiency, modernize management, and adhere to corporate responsibility aer having learned the lessons of reserve replacement the hard way. With a huge reserve base, Pemex halted exploration in the ‘90s. “at put us in a very critical situation of nonsustainability given the fact that we were not only not replacing the reserves, but we were consuming the reserves,” Morales-Gil said. “We were having negative ratios on reserve replacement.” e company started exploration once again in 2004, aiming to diversify assets. In 2009 Pemex reached a 100% replacement level on its reserves, Morales-Gil said, but the company still wants to increase the reserve replacement rate, the exploration success rate, and recovery factors over the next four years. “We are exploring where we know the resources are,” Morales-Gil said. at includes the southeastern basins, which have produced 45 Bbbl of the 55 Bbbl of oil recovered by Pemex over the past 75 years, and the Tampico-Misantla region. “We still have 25 Bbbl of reserves in those basins,” Morales-Gil said. at in-
SHOW MANAGEMENT CONTACT INFORMATION OTC Headquarters +1.832.667.3014 Reliant Center,
Level 1, Room 103
OTC SHOW DAILY | MAY 9, 2013 | THURSDAY
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Slashing Downtime with Seal-Welding Technology BY HENK-WILLEM SANDERS, TRELLEBORG SEALING SOLUTIONS
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he offshore oil and gas sector has been going strong since the late 1940s. As the industry continues to move toward even more demanding offshore applications to drill deeper and reach farther, the use of FPSO vessels has become particularly popular. Eliminating the need to lay expensive long-distance pipelines from the processing facility to an onshore terminal, an FPSO vessel is suitable for remote or deepwater locations where seabed pipelines are not cost-effective. While offshore facilities have opened the vast frontier of the world’s oceans to oil and gas E&P, they also have resulted in new and unique challenges. Maintaining FPSO installations can oen prove difficult and time-consuming, especially as environments become more challenging. And with financial data suggesting that losses from an hour of
downtime for an offshore production facility are among the highest of any industry, every moment saved in downtime means significant cost savings for the operator. With a number of component failures able to easily lead an FPSO vessel to a shutdown that requires onshore maintenance, the cost and traveling time required to return an FPSO vessel to shore can quickly add up. Keeping operations afloat A critical element onboard an FPSO facility, the swivel stack is the heart of the turret, mooring, and fluid-transfer system. e swivel ensures that all fluids (liquids and gas), controls, and power are transferred safely from the geostationary components (wells, flowlines, manifolds, risers) to the rotating vessel and its process plant under any environmental conditions. Seals are vital when it comes to ensuring the continued efficient and safe operation of an FPSO swivel stack since re-
Seal-welding technology allows a seal to be installed
in the weld head enclosure onboard an FPSO vessel
without the need to return to shore. (Image courtesy
of Trelleborg)
placement of the seals in a swivel stack requires the FPSO vessel to travel back to shore so that components can be completely disassembled and seals replaced. In fact, this whole operation can be extremely time-consuming and requires huge preparation time. Typically, the FPSO vessel would be down for between six and 12 weeks, the cost of which could amount to hundreds of millions of dollars. For years leading manufacturers have been looking for a way to solve the issue, which in practice seemed simple: Remove and replace the seal in situ on the FPSO vessel offshore. However, to actually do this and create a technique that would fulfill this idea was not so easy. It would require the development of a technique that would bond the ends of a cut seal offshore – something that would prove extremely difficult. Adding to the challenge, seal-welding must be completed when other swivels are still in production; this could be extremely high-risk without special safety features incorporated into the welding equipment. A step-change solution e latest in seal-welding technology has more than met the challenge and is set to revolutionize the FSPO vessel market. Trelleborg has developed a new seal which, manufactured from the company’s established seal material, can be welded on the platform without the need to return to shore. By using a well-established and proven material as opposed to a modified substance, the company has been able to avoid integrating something that has not been fully tested into the new system to ensure full compliancy and reliability for the offshore operator. In a controlled manufacturing area Trelleborg starts the process by producing a seal that has been cut in one place using a specially designed tool. e product is then packed so that it is well protected and avoids any damage in transit. When the FPSO vessel has moved offshore, the seal is unpacked and installed onto the swivel by trained personnel. An engineer installs the seal in the weld head enclosure, which must be certified to ATEX Zone 1. e enclosure is then pressurized so that the welding can be completed. Aer it is fully enclosed, production on other swivel stacks can continue without risk. A control cabinet, which is purged and also must be certified to ATEX Zone 1, See DOWNTIME continued on page 46
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THURSDAY | MAY 9, 2013 | OTC SHOW DAILY
Annual Offshore Drilling Spending Could Hit US $17 Billion by 2016
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BY VELDA ADDISON
rilling activity offshore Africa and the Middle East, led by an exploration surge in West Africa, is expected to get even hotter, helping to push spending in the region past US $77 billion between 2012 and 2016. e forecast, delivered in a report by GBI Research, shows the expected cumulative spending spike represents about a 22% increase over the previous five-year period. Money spent annually on offshore drilling in the region could surpass $17 billion in 2016, up from more than $13 billion in 2012. Driving attention to the area are offshore discoveries, including 16 made offshore Ghana between 2008 and 2012, with countries such as Sierra Leone and Liberia emerging as new players on the oil and gas scene. Off the east coast, Kenya, Mozambique, and Tanzania are gaining prominence as gas and oil producers. Meanwhile, in the Middle East, development in Saudi Arabia, Iran, and Qatar has ramped up with increased activity anticipated to continue. “Compared to other regions of the world, a major portion of the potential offshore blocks in Middle East and Africa region are located in deep and ultra-deep waters,” said Bharath K. Sheela, analyst for GBI Research. “Drilling operation in the region is highly expensive as most of the wells are deepwater wells, and technical and operational costs associated with it increase drilling expenditure. Also, political instability and security issues in most countries of the region are delaying many deepwater projects leading to an increase in project development costs.” However, the challenges accompanying exploratory efforts haven’t deterred companies, considering the potential payouts. e latest move into the region included China National Petroleum Co. acquiring a 20% stake in deepwater acreage offshore Mozambique from Eni as part of a $4.21 billion deal announced March 14. And evidence of the region’s potential keeps flowing – Apache Corp. announced March 4 its Amoun NE-1X discovery in Egypt, which tested at a combined rate of 3,186 bbls of oil and condensate and 11 MMcf/d of natural gas. e well encountered 15 m (50 ) of oil pay in three Cretaceous Alam el Buieb (AEB-3) sands in addition to 31 m (101 ) of pay in the Jurassic Safa sands, Apache said in a news release. e well cost $4.2 million to drill and complete. Further potential lies in Angola, where the report noted a subsalt geological similarity exists between the country and Brazil. “As shallow-water resources decline, deep and ultra-deep subsalt areas are expected to play an increasingly prominent role in offshore oil and gas production,” the report stated. Angola is where GBI foresees companies will spend the most on drilling in the region, surpassing $6 billion in 2016. Nigeria and Egypt are expected to come in second and third, with about $2.3 billion and $1.5 billion in spending, respectively. Twentytwo discoveries were made in Angola between 2008 and 2012. Sheela said “Exploration in Angola’s offshore blocks continues to attract investors due to the following reasons: • Excellent petroleum working system; • Well developed seismic imaging with international oil companies already OTC SHOW DAILY | MAY 9, 2013 | THURSDAY
familiar with the country’s resource potential; • Political and contractual stability; • Presence of significant hydrocarbon reserves in presalt formations; and • Presence of low sulfur crude well suited for export to the major importing countries.” GBI anticipates Ghana will emerge as the most prominent West African country for oil and gas exploration following Angola. e report noted Kosmo’s Jubilee discovery in 2007 led to additional successful discoveries such as at West Cape ree Points and deepwater Tano blocks, including Mahogany, Teak, Akasa, and Banda. e Jubilee field produces about 110,000 b/d, according to the company’s website. Tullow Oil, which operates the Jubilee field and has interest in two offshore exploration blocks, is among the
companies planning further investment offshore Ghana. In the second half of 2012, the company submitted a development plan to the Ministry of Energy for its Tweneboa, Enyenra, and Ntomme project. In the Middle East, the report pointed out development in Saudi Arabia’s Manifa, Arabiyah, and Hasban fields as well as in Iran’s South Pars and Qatar’s North Dome as areas of increased drilling activity. Saudi Aramco’s Manifa development, scheduled to be complete in June 2013, contains 27 drilling islands along with 13 offshore platforms, and 15 onshore drill sites, according to the company’s website. In addition to Manifa, projected to go online in December See SPENDING continued on page 44
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New Technology Can Reduce Nonproductive Time, Improve Well Integrity
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CONTRIBUTED BY BAKER HUGHES
aker Hughes’ TORXS expandable liner hanger system, which is installed and released prior to the cement job, eliminates the risk of the running tools becoming fixed in place during cementing, requiring fishing or well abandonment. e expandable liner hanger system can be used across a broad range of applications including deepwater, subsalt plays, deviated wells, extended-reach wells, and monobore completions and is rig-ready. Maximizing well integrity Wells are oen drilled through depleted or problematic formations. To drill through these formations economically, operators need a liner system that can ream
through a previously drilled section or drill a new section with the liner itself to avoid time-consuming and costly non-productive time (NPT). e TORXS system offers an advanced torsion capability that allows the casing to be worked to depth in these challenging zones. e system enables a seamless, one-trip, two-stage hanger and packer setting for cemented liner applications. Setting the packer independently mitigates the risk of becoming stuck in wet cement. ere also is no need to add retarders that compromise the cement formulation or extend the cement pumping time. Optimizing the cementing job extends the life of the well and reduces the potential for future remediation work. Reducing milling time Baker Hughes recently introduced Metal Muncher adThe TORXS system offers an advanced
torsion capability that allows casing to be
worked to depth in challenging zones.
(Images courtesy of Baker Hughes)
vanced milling technology (AMT) cutters to achieve greater efficiency and longer runs with cutting and milling systems used for casing exits and wellbore intervention. Clean and efficient milling operations can help operators reduce risks and prevent NPT. e new cutting structures, featuring insert shapes and metallurgies customized for specific applications, can provide more efficient cutting as well as durability and impact resistance, which can result in longer runs and fewer trips.
Metal Muncher AMT cutters can provide
more efficient cutting as well as durabil-
ity and impact resistance.
Engineered using pressed sintered tungsten carbide, the AMT cutters are available in a variety of shapes and metallurgies. Depending on the application, a milling tool may include several types of AMT cutters to optimize various aspects of the milling operations. e cutters are designed to mill even the toughest steels, including high chrome and nickel-content materials. e technology can increase milling penetration rates, extend effective time on the bottom in high-volume milling applications, and enable greater flexibility during the milling process. Metal Muncher AMT cutters feature sharp profiles with chip-breaking features to control cutting size and shape, which can enable efficient cutting removal and debris management. Field operators have reported as much as a 300% improvement in wear resistance and longevity with Baker Hughes’ inserts. See TECHNOLOGY continued on page 46
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SEABED continued from page 27
pumping, according to the analyst. e complexity and depth of these reservoirs, combined with record-setting water depths, increasingly make this technology necessary to maximize reserve recovery rates on most upcoming, high-profile deepwater developments, the analyst concluded. Fast-growing market is is why a number of companies have been carefully positioning themselves to capture as much of this growing market as they can. Toward year-end 2012, FMC Technologies’ Chairman and CEO John Gremp in his company’s 3Q 2012 results presentation said that bidding and tendering activity for subsea processing projects was set to shoot up over the course of 2013 and 2014. As many as eight projects were in the offing for this year, he said, with at least that number lined up for the following 12 months. Rival contractor Cameron also said in November that it was linking up with Schlumberger to create the OneSubsea joint venture (JV). The JV’s stated aim to manufacture and develop products, systems, and services for the subsea market also enables it to specifically target the expanding subsea processing market. Cameron will hold a 60% stake in the JV, with Schlumberger holding the remainder. e latter’s reservoir, well completions, subsea processing, and integration platform expertise will be a major boost to the services Cameron will be able to offer as manager of the JV for the forecast 16 seabed processing projects over the next two years. e overall trends indicate that the number of subsea processing projects going forward will continue to rise sharply. A recent Bernstein Research report showed global deepwater production has risen from less than 500,000 b/d 15 years ago to about 5.5 MMb/d in 2012. Another 4 MMb/d of deepwater production could be flowing by 2020.
The Tordis processing system helped Statoil learn lessons and transfer them – lessons such as the requirement for higher speed
communications where sophisticated instrumentation is used – which was then applied on the Tyrihans subsea raw seawater injection EOR project offshore Norway. (Image courtesy of Statoil and FMC Kongsberg)
Future trends Around 200 deepwater subsea fields are expected to come onstream over the next four years, with more than 11,000 subsea wells forecasted to be in operation worldwide by the end of this decade. As subsea processing technologies continue to advance, the likely trends and focus areas are expected to revolve around the following: • Technology replication – reusing knowledge, designs, and qualified technology; • Continued qualification toward deeper waters, longer step-outs, and heavier or colder crudes; • Promotion of standardization of components, procedures, and qualification specifications; and • Greater processing efficiency (flow assurance). Bearing in mind that these processing advances also will be equally applicable to mature shallow-water areas, their increasing application worldwide is inevitable. n Acknowledgement: Excerpts have been included in this article from SPE paper 20619. is first appeared in the February 2013 issue of E&P. OTC SHOW DAILY | MAY 9, 2013 | THURSDAY
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Arctic Region Offers 136 Bboe Attraction
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BY STEVE HAMLEN
perators are being attracted to the offshore Arctic frontier by the region’s potentially huge oil and gas reserves – with gas seen as the dominant resource. A report by Infield Systems’ said the offshore Arctic holds 136.6 Bboe in discovered offshore reserves, with a 2008 US Geological Survey (USGS) report suggesting there could be another 346 Bboe le undiscovered. “Whilst Arctic waters are extremely rich in reserves, those resources are not distributed evenly. Infield Systems’ estimates suggest that more than 116 Bboe is natural gas, whilst only 17 Bboe is oil,” the analyst said. “Of the region’s vast gas reserves, as much as 95 Bboe, or 82%, is located in Russia’s high-Arctic (excluding Sakhalin Island). e potential of the offshore Arctic is, therefore, substantial. “However, bringing the region’s resources to produc-
tion has historically been a real challenge. According to Infield Systems’ data, just 33 of the 174 discovered fields have been successfully developed, representing just a tiny fraction of the region’s resource potential.” ose fields also have taken many years to go into production. e average field development lag – the number of years between field discovery year and onstream year – for the Arctic region is more than 13 years, which is the second longest in the world. “Of the region’s remaining undeveloped fields, many face a highly uncertain future. Infield Systems has identified 38 fields with production potential between 2012 and 2018, however, just seven are currently under development or have a firm plan,” said the analyst. “is is not just because of the obvious engineering challenges posed by intense cold, ice, remoteness, and even seismic activity. It is also due to more stringent operational and environmental regulations implemented by many governments
in the wake of the Deepwater Horizon disaster. “New best practice obligations, such as, same season relief well capability and enhanced oil spill contingencies have substantially increased costs and logistical hurdles. “Finally, and perhaps most importantly, offshore Arctic projects face increasing competition from shale gas and tight oil plays, which oen represent more attractive economics. is is not just affecting North America’s Arctic developments; Gazprom’s flagship Shtokman Phase One project was kicked into the long grass in August 2012, largely because it could no longer find markets for its LNG in the gas-glutted USA.” Infield Systems anticipates that offshore Arctic capex will rise fairly steadily until 2018, although the suspension of Shtokman Phase 1 now means that spending in the middle of the forecast period is much lower than previously expected. Norway will command around 34% of the total offshore spend. e majority of that will come in the latter half of the forecast period on the back of the Eni-operated Goliat project, as well as the development of Statoil’s Askeladden, Skrugard, and Havis fields. Next in terms of capex, with 22% of the total, is Canada’s sub-Arctic (Newfoundland and Labrador). Here, Infield Systems anticipates the integration of satellite developments at Hibernia and White Rose, as well as first oil from the Hebron/Ben Nevis development. Fields surrounding Russia’s Sakhalin Island are expected to draw around 20% of total capex. is will initially be focused on Kirinskoye (Sakhalin 3) and Arkutun Dagi (Sakhalin 1), both of which are under development. North Chayvo (Sakhalin 1) and Kirinskoye South (Sakhalin 3) should follow in 2015 and 2018, respectively. Meanwhile, around 18% of total capex will be directed toward Russia’s high-Arctic where the flagship Prirazlomnoye oil development and the Obskoye gas field will be brought to production. Infield Systems anticipates that more than half of total Arctic capex between 2012 and 2018 will be directed toward pipelines, reflecting the physical isolation of many projects in the region and the number of developments in the relatively deep waters of the Norwegian Barents Sea. Platforms will account for a further 31% of spend, with around 75% of this going towards fixed units. Norway looks to Lofoten is week the Norwegian government decided to go ahead with an environmental impact study for its Lofoten Islands just above the Arctic Circle. e move is seen as the first step toward opening the area for future exploration activity. e area, so far, has been off limits to explorers because it contains the world’s richest cod stocks, with environmental groups and the tourism industry rallying against any development of the area. e Labour Party voted for the study but added it would take another vote in 2015 before any drilling could be sanctioned. e area off Lofoten is estimated to hold 8% of Norway’s undiscovered oil and gas reserves, and seismic data has identified 50 prospects that could hold recoverable reserves of around 1.27 Bboe, according to the Norwegian Petroleum Directorate. See ARCTIC continued on page 46
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CHINA continued from page 6
Sino said independent assessor RISC Operations determined that estimated proven and probable reserves in the PSCs had increased by a factor of nearly 15 times from a January 2012 assessment of 623.2 MMcu m to 9.26 MMcu m (22 Bcf to 327 Bcf). Sino’s share of the reserves is 2.63 Bcu m (93 Bcf). Total unrisked, midcase reserves, and resources have been estimated at 161.5 Bcu m (5.7 Tcf), which represents a 56% increase. e assessment was based on 12 wells drilled last year, 70 km (43 miles) of seismic data from an infill drilling area in the northeastern corner of Linxing East, and 100 km (62 miles) of data from a previously unexplored portion to the southwest of the block, in addition to 100 km of north/south running seismic at Sanjiaobei. “Our intention is to progress development as the economics of the domestic natural gas market in China continue to suggest attractive returns, while existing pipeline infrastructure, which traverses our PSCs, presents low-
cost access to market,” Robert Bearden, Sino managing director, said. Shale gas potential China also has the world’s largest estimated shale gas reserves but is currently way behind the success being enjoyed by the US. e US Energy Information Administration has said that China has an estimated 36.1 Tcu m (1,275 Tcf) of technically recoverable shale gas reserves – more than Canada and the US combined. In a bid to kick-start its own shale boom China has been offering acreage in recent months. In January China’s Ministry of Land and Resources (MLR) handed out exploration rights for 19 shale gas blocks to 16 companies. e licensing round received 152 bids from 83 companies. e MLR expects the winners to invest US $2.06 billion into developing the shale blocks, most of which lie in south-central and southwest China. Shell gets Sichuan basin nod Shell also was recently given the green light to start work
with state-owned partner China National Petroleum Corp. (CNPC) on the Fushun-Yongchuan block shale gas PSC in the Sichuan basin. e companies have not disclosed details of the contract, but the approval suggests that Beijing has developed the regulatory framework needed to attract more international investment that will help to develop its fledgling shale sector. Shell CEO Peter Voser said his company is gearing up for what he described as a “significant drilling season in 2013 and in 2014.” Voser added that Shell and CNPC are continuing to explore which drilling locations are best suited for long-term development and production and said the company is committed to helping Beijing achieve its shale gas production targets. China has set a target of producing some 6.5 Bcu m (229.5 Bcf) a year of shale gas by 2015 and as much as 100 Bcu m (3.53 Tcf) a year by 2020, up from virtually zero in 2012. Visit CNOOC is at booth 9539 and CNPC at booth 1549. n
ODDS continued from page 6
shore for checks and refurbishment. He went on to outline what is next for the MWCC, pointing out that the system used is the interim containment system, which can handle a flow rate of up to 60,000 b/d and 15,000 psi. An expanded system will be ready by early next year which can handle flow rates of up to 100,000 b/d in up to 3,048 m (10,000 ) water depth and also handle pressures up to 15,000 psi. e MWCC also has a dual ram 10,000 psi stack available, and it is currently building another 15,000 psi dual ram stack. e MWCC also recently selected Technip USA’s Mobile, Alabama, as the shorebase location to house its subsea umbilicals, risers, and flowlines (SURF) equipment. It will use the facilities and services of Technip and Core Industries to store, maintain, and test the equipment. It also recently announced an agreement with Wood Group PSN for the formation of an offshore reserve response team. Made up of 100 select reserve operations personnel, the team will be activated should the MWCC’s modular capture vessels (MCVs) be called upon to respond to a well control incident in the GoM. The team would be deployed to the incident to operate the processing equipment on the MCVs should the MWCC’s expanded containment system be required to cap and flow a well. In this situation, the system redirects the flow of fluids from the well to the MCVs through flexible pipes and risers. Using modular, adaptable process equipment installed on the capture vessel, the system is designed to separate liquids from gas, flare the gas, and safely store the liquids until transferred to a shuttle tanker and taken to shore. n
Lost and found is located in OTC Headquarters, Reliant Center, level 1, in room 103 and is open during conference hours
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Fizzle Out Flaring on FPSOs
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CONTRIBUTED BY SBM OFFSHORE
hat if tomorrow gas flaring was even more restricted? Anticipating this scenario SBM Offshore teamed up with Compact GTL and following four years of collaborative design and engineering development, the two companies have come up with a unique solution for FPSOs, exclusive to SBM Offshore, which could change the way oil and gas companies view new offshore field developments. With oil field discoveries increasingly located in remote and deep waters the problem of associated gas disposal has become an expensive and tricky dilemma for the big players in the industry. Using pipelines to market is prohibitively costly for stranded fields where there is no infrastructure. Other alternatives include electricity generation or gas re-injection into the reservoir or flaring, which is becoming increasingly off limits in some
parts of the world, even in temporary settings such as for Early Well Test (EWT) work. e industry is calling for oil operators to reduce flaring by natural gas associated with oil production by a further 30% by 2017 – equivalent to taking 60 million cars off the road. A viable, industry approved, solution to eliminate flaring is offered by UK-based company CompactGTL who have designed an adaptation of conventional Gas to Liquid (GTL) technology for smaller scale applications, to accommodate operations where a small volume of gas is produced. Foreseeing the potential to adapting this pioneering technology for specific use on SBM Offshore’s FPSOs, the company signed an exclusive commercial agreement late last year with CompactGTL to collaborate exclusively on offshore projects. Together we are advancing the GTL technology in tandem to further develop the technological edge of our FPSOs. A commercial demonstration
plant (Figure 1) provided by CompactGTL has been in operation onshore in Brazil since December 2010, funded by Petrobras, further validating the importance of this technology. Mini-size GTL plants Conventional GTL plants are known to be very large structures, the Pearl GTL project in Qatar is said to be the size of 450 football fields, but now SBM Offshore with our partner propose a new smaller scale solution, enabling the GTL plant to fit on an SBM Offshore FPSO vessel. is agreement with CompactGTL represents a worldfirst for such vessels. Mike Wyllie, Chief Technology Officer at SBM says “CompactGTL has brought the technology to a point where we believe it can be integrated relatively easily on to an FPSO. From our viewpoint we are looking actively at a number of ways of increasing the complexity of converted FPSOs. We target the top-end of the market and GTL is one way of extending our capability into more complex units. We’re starting small, using it for associated gas disposal – we think that’s a good way to get it offshore and gain experience in operating a floating facility with GTL capabilities.” What are the benefits of GTL to FPSO users? For offshore solutions the gas to liquid technology solves the problem of the associated gas – the offshoot of oil production – whilst creating additional synthetic crude revenues for the operator. is represents a significant benefit by turning what was originally a liability into an asset and at the same time eliminating the need for flaring. Deploying a GTL plant on the deck of an FPSO represents a paradigm shi; first hand it becomes a project enabler, allowing oil companies to proceed with field development, where previously it was not commercially viable. According to Iain Baxter, Director of Business Development at CompactGTL “with smallscale GTL, because the end product is synthetic oil which can be easily mingled with the conventional crude oil, the oil company has a single, easily accessible market for the product, requiring no separate storage or transportation, irrespective of the oilfield location.” Bottom line for oil operators is that the new technology incorporated to an FPSO increases the productivity whilst addressing the legislative issue of flaring. CompactGTL Chairman, Tony Hayward, says “CompactGTL is the clear leader in a currently untapped sector of the oil and gas industry, helping to change the perception of GTL through providing a game-changing, economically viable solution to the global problem of gas flaring.” It is a logical step for the two companies, both leaders in their respective fields, having successfully worked together since 2008. By consolidating their respective strengths and expertise for the marketing and execution of projects involving associated gas challenges for offshore oil fields they represent a powerful duo in the expansion of the sector. e optimised FPSO with an integrated GTL plant can be applied to an EWT service or on a full field development. Michael Wyllie explains “In an EWT context, this technology is perfect. You can hop from field to field without flaring gas. We have done extensive studies See FPSOs continued on page 46
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DRILLING continued from page 24
Monitoring worldwide compressor fleet Atlas Copco Rental is now installing the first 1,000 of its intelligent Atlas Copco Equipment Satellite System (iACCESS) modules, which will relay information via satellite so that its units can be monitored from a distance. “Besides the main operating conditions of the machine, we will get live data of pressures and temperatures inside the units,” said Ben Fort, vice president operations-fleet, Atlas Copco Specialty Rental. The service is expected to reduce downtime by the notification system of iACCESS. When machines require maintenance, service teams can immediately take action to avoid malfunction. If downtime does occur, service technicians can arrive prepared with the right tools and parts based on detailed information. “We can monitor the components in the machine,” he added. Emissions from the compressors also can be reported. “We can show how much hydrocarbons are being burned and how efficiently,” Fort continued.
Atlas Copco’s line of PDC drill bits for the oil and gas industry are impact, abrasion, and erosion resistant.
Offshore compression fleet expanded Atlas Copco Rental has expanded its offshore dedicated fleet with rig-safe and Zone 2 compressors and steam boilers as well as high-pressure compressors, boosters, and nitrogen generators, explained Jan Verstraeten, vice president of marketing, Atlas Copco Specialty Rental, and Pieter Taljaard, factory product manager, Atlas Copco Hurricane. “New rental solutions will be offered during 2013 for specific applications in the offshore industry such as exploration and well testing, pipeline precommissioning, and production and maintenance of platforms,” Verstraeten said. e rig-safe compressors and steam boilers provide increased capacity and performance combined with a small footprint. e flagship compressor delivers 1,600 cubic feet per minute (cfm) at 150 psi and can go to 1,800 cfm at 100 psi. All equipment is fitted in a DNV liing frame and designed for use offshore. New Zone 2 compressors and steam boilers will be offered for platforms and rigs where no safe zone is available. Onsite nitrogen generators are available for applications where an inert atmosphere is required, Taljaard said. e company’s new XAS 375 Zone 2 compressor was designed to meet Zone 2 regulations for the offshore industry. Its XATS 1600 Zone 2 compressor will be available this summer. is design can be used with ATEX or Class 1, Division 2, certifications and the stainless steel canopy with the DNV certified frame is designed for offshore use, he continued. is pneumatically controlled compressor offers limited electronics for increased reliability in corrosive environments and is engineered with large, easy-to-read analog gauges and wide maintenance doors. A self-cleaning flame trap allows maintenance to be performed every 3,000 hours, he added. n
OTC BRASIL 2013 October 29-31 Rio de Janeiro
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Sub-based System Enables Continuous Circulation of Drill Fluids Downhole
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CONTRIBUTED BY CANRIG DRILLING TECHNOLOGY
on Stop Driller (NSD) is a sub-based system that enables the continuous circulation of drill fluids downhole while making or breaking drillpipe connections. Using technology licensed from MPO, this system has been designed to provide bottomhole pressure stability during mud flow interruptions, improving mechanical integrity and wellbore cleaning, reducing the risk of kicks, and optimizing drilling performance. With the NSD system continuous circulation and true constant bottomhole pressure while making connections can become a reality. Connection times can take up to 45 minutes when drilling with air foam in the Darai Limestone offshore Papua New Guinea. Once the connection is made, stable
foam-circulating conditions must be reestablished before drilling ahead. By allowing constant foam circulation over each connection using the NSD system, average connection times were reduced from 45 minutes to 10 minutes by eliminating the need to circulate the wellbore clean, depressurize the drillpipe, and then reestablish circulation. Approximately half of the connection time was taken using the NSD system and the other half in making up the next stand, resulting in considerable savings in rig time on what is a high spread-rate-cost operation. How it works Each stand to be drilled down requires a preinstalled sub. When the stand is drilled, the sub is used to create an access point into the drillstring. e system uses a highpressure mud hose with an integrated quick-connect
The NSD system provides bottomhole pressure stabil-
ity while making drillpipe connections for improved in-
tegrity and optimized drilling performance. (Image courtesy of CanRig)
mechanism. A human machine interface- (HMI-) controlled remote manifold is used to redirect the flow path of the drilling mud to the side-entry valve in the system. Closing the ball valve in the sub above the side-entry point isolates drillstring pressure, allowing constant circulation during connections. When the connection is completed, the flow of drilling mud is redirected through the top drive, the quick connect hose is bled off and disconnected, and drilling can continue, with the sub now an integral part of the drillstring downhole. e side-entry valve is protected from damage while deployed in the wellbore using a protective cap. Rated to 10,000 psi, the protective cap also provides a second barrier between the drillpipe and annulus. Features e NSD system manifold is 63 in. wide, 66 in. deep, and 76 in. high, weighing roughly 6,500 lb with a pressure rating of 5,000 psi. It features remote 41/16-in. actuated valves, an independent pressure relief valve, and four point-li lugs with sling and forkli pockets. Fully actuated valves are controlled by a dedicated HMI system incorporating multiple safeguards and system interlocks. e touch-screen HMI control panel is rated to Class 1 Division 2. e proprietary interlock mechanism eliminates the possibility of pressure release and pump dead-heading during operations. An integrated pressure release valve provides additional independent pressure protection for the system. e NSD system promotes wellbore condition improvements by providing continuous solids transport while maintaining a consistent annular pressure profile across the entire wellbore. is eliminates pressure fluctuation-induced wellbore stability problems. It also minimizes bottomhole pressure fluctuations when employed in narrow pore pressure/fracture gradient applications. Minimizing connection gas and reducing the risk of kicks on connections is an added benefit. e system provides seamless integration into underbalanced drilling and managedpressure drilling operations, offering bottomhole pressure control on connections. It improves operational safety by eliminating surface pressure increases during connections and eliminates post-connection stabilization time during multiphase drilling on air, foam, and two-phase wells. e system reduces nonproductive time by mitigating stuckpipe incidents and casing running problems related to hole condition. On high-temperature wells bottomhole assembly heat soak damage during connections is eliminated. For more information about Canrig Drilling Technology’s NSD system, stop by booth 1679 and ask for details. n
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CHALLENGE continued from page 14
TECHNOLOGIES continued from page 28
ers, cost-effective CRA materials like mechanically lined pipes can be used in the SCR section, thereby reducing the costs considerably. Another presentation outlined details of a new riser concept proposed by Subsea 7 for field developments in deep and ultra-deepwater. Many well proven riser concepts have been used in different deepwater environments, in particular steel or flexible risers in catenary or lazy-wave shape and single or bundle hybrid riser towers. Nevertheless, for some applications new concepts are deemed more attractive, such as the buoy supporting riser (BSR) for ultra-deep water off Brazil. But other ideas of riser concepts emerge from the review and comparison of the pros and cons of existing riser systems, trying to take the better aspects of each one. Subsea 7’s patent-pending tethered catenary riser (TCR) is an adaptation of the BSR but with a simpler tether arrangement and easier installation method. It also can be seen as a single hybrid riser (SHR) with a number of SCRs attached to the buoyancy tank. According to Jean-Luc Legras, the TCR concept consists of a number of SCRs supported by a subsurface buoy, which is tethered down to the seabed by means of a single pipe tendon and anchored by means of a suction pile. Flexible jumpers are used to make the connection between the floating production unit (FPU) and the buoy. Umbilicals run without interruption from the FPU to their subsea end while being supported by the buoy. e system has all the advantages of decoupled riser arrangements, said Legras. Flexible jumpers effectively absorb platform motions so the rigid risers and tendon have very small dynamic excitation. e system can be installed before the FPU’s arrival on site, which improves the time before first oil. Analyses have shown that, with adequate geometry of the buoy, the latter is sufficiently stable to induce acceptable tilt and twist when different arrangements of SCRs and flexible jumpers are installed and under accidental scenarios during the in-place life. e riser system is best designed for between four and eight risers in addition to a number of umbilicals; thus, it is convenient for one or two drilling centers. Results of the basic engineering work on the TCR indicate that it is possible to have a robust design using presently qualified materials and technology, continued Legras. e components used in the TCR are all field-proven since they are commonly used in existing riser systems. As a result of installation studies, a method very similar to the one commonly used by Subsea 7 for SHRs has been selected for the buoy and tether system. Placement of rigid risers, jumpers, and umbilicals is done by Subsea 7 for the BSRs. This method is well adapted for installation by the company’s new flagship vessel Seven Borealis, which is able to perform heavy lift and pipe-laying duties. Legras concluded that the TCR is a credible option for use in deepwater developments around the world. “Since all the components, design methods, and installation procedures are fully qualified and familiar to Subsea 7, the concept is cost-effective and ready for project application,” he concluded. n
at a mature level with more room for incremental improvement, he said. e development focus, he said, is on product performance optimization, chemical stability in challenging deepwater and Arctic conditions, and environmental friendly chemistries. Some of the thermal solutions, such as thermal insulation and direct electric heating, are matured; yet, these technologies have a lot of room for improvement for deeper-water depth, long tie-back applications, and other challenges. Finally, Kondapi stated that subsea separation technol-
ogy tops the list as the most targeted technology for rapid development and application because of its huge potential for cost savings by moving some of the traditional topsides fluid processing to seabed. In addition to facilitating flow assurance, subsea separation also improves oil production and recovery and contributes to increased earnings. More companies are driving toward using this technology to increase hydrocarbon recovery with the development of challenging and deeper subsea fields. Answering a question from the audience, Kondapi emphasized the importance of having joint industry partnerships along with university-industry research partnerships in developing and testing. n
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Subsea 7 is at booth 1641. OTC SHOW DAILY | MAY 9, 2013 | THURSDAY
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INDUSTRY NEWS Elektron Technology Showcases Circular Connectors Elektron Technology will be showcasing the Bulgin EXPlora range of environmentally sealed circular connectors for hazardous environments at OTC 2013 this year. e EXPlora series is designed and approved for use in ATEX Zone 2 and Zone 22 applications, providing fast and easy screw fixing connections without the need for special tooling. Visit Elektron Technology at booth 841 to learn more.
Balltec Secures Tubular Bells Contract Balltec Ltd. has been contracted by Houston Offshore to supply and install 10 off MoorLOK subsea mooring connectors for the Tubular Bells project, located in the Mississippi Canyon area of the Gulf of Mexico.
e contract covers the manufacture of 10 off 15,000kN MoorLOK connectors for the mooring of the Williams floating production system (FPS), Gulfstar GS1 on the Tubular Bells field at a water depth of 4,500 . e connectors will be manufactured in accordance with the ABS Guide for the Certification of Offshore Mooring Chain 2009, and are due to be installed during the first half of 2013. e Balltec MoorLOK is a disconnectable, subsea mooring connector designed for the temporary and permanent mooring of floating structures.
The Bulgin EXPlora range of environmentally sealed
circular connectors provides screw fixing connections
without special tooling (Image courtesy of Elektron
Technology)
Former Oil Exec Authors Book on Macondo John Turley, a longtime oil executive and former Gulf Coast manager for Marathon Oil, has published a nonfiction novel on the 2010 Deepwater Horizon disaster, e Simple Truth: BP’s Macondo Blowout. According to Turley, people still don’t understand the mechanics of what went wrong. He spent two years analyzing well data and investigative reports about the explosion and much of his research is technically spelled out in his book.
Petrobras Announces Oil Discovery Petrobras has announced the discovery of good quality oil in the Transfer of Rights area referred to as Entorno de Iara, in the Santos Basin pre-salt region. Well 1-BRSA-1146-RJS (1-RJS-711), known as Entorno de Iara 1, is located at a water depth of 2,266 m and 235 km off the coast of Rio de Janeiro state. e discovery was confirmed through wire test samples of good quality oil (26o API) collected from carbonate reservoirs of excellent quality located just below the salt layer, at a depth of 5,045 m. e well was completed at a depth of 5,580 m, aer achieving the objectives outlined in the Transfer of Rights Agreement. A formation test and the drilling of another well are scheduled in this area to evaluate the productivity of the reservoirs that contain oil, as outlined in the Mandatory Exploratory Program of the Transfer of Rights Agreement.
Talos Initiates Production in Recent Deepwater Discovery Talos Energy LLC, a privately held Houston-based oil and gas company, reported Monday that its wholly owned subsidiary, Energy Resource Technology GOM LLC (ERT), has initiated production from the previously announced Green Canyon 237 #5 discovery, which is located in the Phoenix Field in Green Canyon block 237 in the federal waters of the Gulf of Mexico. Production from the well has reached a sustained gross rate of 4,200 boe/d and 6,300 Mcf/d and no water, or 5,250 boe/d. ERT operates the Phoenix Field, located in 610 m (2,000 ) of water, and the net production added from the discovery is approximately 2,750 boe/d.
Group Successfully Completes Deepwater Well Containment Exercise e Department of the Interior’s Bureau of Safety and Environmental Enforcement (BSEE), Noble Energy Inc., and the Helix 42
THURSDAY | MAY 9, 2013 | OTC SHOW DAILY
Well Containment Group (HWCG) have announced the successful completion of a full-scale deployment of critical well control equipment to assess Noble Energy’s ability to respond to a potential subsea blowout in the deepwater Gulf of Mexico (GoM). BSEE Director James Watson confirmed that the HWCG capping stack deployed for the exercise met the pressurization requirements of the drill scenario. e unannounced deployment drill, undertaken at the direction of BSEE, began April 30 to test the HWCG capping stack system – a 20- tall, 146,000-lb piece of equipment similar to the one that stopped the flow of oil from the Macondo well following the Deepwater Horizon explosion and oil spill in 2010. During this exercise, the capping stack was deployed in more than 5,000 of water in the GoM. Once on-site, the system was lowered to a simulated well head (a pre-set parking pile) on the ocean floor, connected to the well head, and pressurized to 8,400 lb/sq in.
Parat Finds Hot-Water Coils Deficient Tests undertaken by Parat Halvorsen on oil spill response (OSR) equipment for offshore supply vessels reveal deficiencies with systems using hot-water coils. “We have shown empirically that steam injection is the one viable solution proven to keep heavy oil viscous enough for easy loading and offloading,” Kim Kristensen, marine and offshore at Parat Halvorsen, said. Any spilled oil is recovered by OSR-equipped vessels and stored in tanks until it can be delivered to recovery stations on land. e recovered oil has to be heated to maintain a sufficient viscosity for offloading. Parat Halvorsen offers a heating solution based on steam injection from a boiler onboard. It has supplied equipment to a large number of offshore support vessels delivered by yards including Havyard, STX Norway, Kleven, and Ulstein.
To verify whether alternative hot water-based solutions work, Parat installed a compact heating coil and a steam injection nozzle in a test tank at its facilities in Flekkeord, Norway. Watched by representatives from shipbuilders, owners, consultants, and the Norwegian Coastal Administration, the tests measured performance of both solutions in water and in heavy oil. e empirical results showed that heat transfer in heavy oil using the hot-water coil was just 10% of that achieved by the same coil in water. “e results from the tests clearly showed that using a heating coil is not a viable option,” Kristensen said. “When we started the steam injection system, live temperature logging recorded the way the oil was evenly heated in a matter of minutes. We believe that the laws of physics are against hot-water coil-based systems, particularly in cold, harsh weather conditions such as those in the North Sea.” n
TWMA Wins First Contract in Offshore West Africa TWMA, a leader in integrated drilling waste management and environmental solutions, announced Monday its first offshore processing project in West Africa. The 400-day contract is to supply TWMA’s industry-leading offshore processing services to support Glencore Exploration Cameroon Ltd.’s (Glencore) West Africa drilling campaign. The scope of work includes the installation of a TWMA TCC RotoMill and cuttings collection and distribution system (CCDS). This integrated approach provides a complete containment, treatment, and disposal solution for capturing drill cuttings and associated fluids onboard the Atwood Aurora jack-up drilling rig. A team of experienced TWMA operators are managing the project on location. As offshore production in Africa escalates, new operators penetrating the sector are being forced to consider implementing reliable methods of reducing the environmental impact of improperly disposed drill cuttings. The solution provided by TWMA treats all non-aqueous base fluid (NABF) drill cuttings by way of thermal desorption, recovering 99% of base oil for reuse by the operator, according to the company. The inert rock powder and recovered water are disposed overboard for sea dispersal in a process which is proven to have a near-zero impact on the environment. "The size of the rig combined with deck loading restrictions and a very tight design cycle made this a very interesting and challenging project from the outset,” said Kyle Duncan, TWMA project engineer for the Glencore installation. “In order to meet the project deadlines, TWMA’s engineering team travelled to Houston to complete a fast-track FEED phase with the client.” Upon completion of the preliminary design works, TWMA finalized and delivered the full engineering design package within a three-week time frame to obtain the client’s approval before mobilization. To learn more about TWMA’s integrated drilling services and environmental solutions please visit www.twma.co.uk or stop by booth 2165. OTC SHOW DAILY | MAY 9, 2013 | THURSDAY
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are the Gulf of Mexico (GoM), Angola, and the North Sea. Azerbaijan is becoming more of a high-margin play as well. She said that the 2010 reorganization has resulted in an 80% increase in project capacity through the creation of global teams to leverage economies of scale. Global capabilities have been mobilized to the areas that are the highest priorities. In 2012 BP started five new projects out of the 15 it intends to start up by 2014. ese included the PSVM, Skarv, Galapagos, Devenick, and Clochasw Mavacola projects. Between 2015 and 2020 the company has six “megaprojects” (projects budgeted at more than $1 billion) as well as nine brownfield projects in the works. Sykes noted that BP has been measuring its competitive performance through output metrics – schedule predictability, cost predictability, and first-year operability – and input metrics, including reservoir front-end loading (FEL), facilities FEL, and wells FEL. Between 2010
and 2012 the company improved in all of these categories compared to its competitors, ranking first in first-year operability. “We’ve revitalized our upstream segment,” she said. Quentin Dyson, vice president of discipline capability for the Global Wells Organization (GWO), said his group was unique because it works across multiple divisions. GWO is part of an upstream production group that includes GPO, procurement and supply chain management, and upstream engineering. GWO supervises global deep water, onshore, offshore, the GoM, and Azerbaijan. Its mission is to drill “safe, compliant, and reliable wells,” Dyson said. At any given time the group oversees around 100 operations with about 2,500 people and spends about $15.1 million net per day. It oversees drilling engineering, completions engineering, intervention engineering, and wellsite leadership. Dyson said his group’s strategy is based on reliable design and execution of projects and is characterized by distinctive capabilities and collaboration. Its plans for
2013 will involve 21 rigs drilling about 360 wells. Some of the features that Dyson outlined for potential employees include the Houston Monitoring Center, where offshore personnel can get “an extra set of eyes and ears” when examining their drilling data; the BP Well Advisor, which will take that monitoring concept to a global level; and its Applied Deepwater Well Control course, which Dyson said was “a nice example of our training and development offerings.” BP also offers a Global Wells Institute, which Dyson said was like a mini-college. “People development is a wonderful element of BP,” he said. Examples include BP’s Challenge program, which takes new hires just out of college through the first three years of their career, and the Excellence program, which takes them through about year 10. Additional programs that are more intense and operate on a shorter time frame include the Drilling Engineer of the Future program, which expands the knowledge of employees with a narrow experience base or those who come in from outside the industry, and the Wellsite Leader of the Future program for those with a little more life experience. Both of these courses run for 18 months. “We look for leaders to teach oil industry skills to,” he said. During the Q&A period, both Sykes and Dyson talked about their personal experiences with the company. “BP considers people to be the foundation of everything we do,” Sykes said. “I’ve gotten unparalleled support during my career.” Added Dyson, “BP takes care of its people quite well.” n
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2014 and produce 0.9 MMb/d of Arab heavy crude oil, the company’s offshore plans include a five-year program to increase natural gas production. Saudi Aramco’s 1.2 Bcf/d Arabiyah and the 1.3 Bcf/d Hasbah gas fields are expected online within five years, according to the US Energy Information Administration (EIA). In Iran, additional drilling activity is anticipated offshore South Pars, a natural gas field shared with Qatar in the Persian Gulf. e field makes up more than 47% of Iran’s total gas reserves and produces about 35% of gas produced in Iran, EIA data showed. e Pars Oil & Gas-managed project is a 24-phase, 20year development. e company said the field’s reserves have an estimated 14 Tcm of gas and 18 Bbbls of condensate. “e growth of drilling expenditure is expected to spread to all major countries in the region,” the report stated. However, this growth is not without obstacles. “Surge in exploration success and production activities led to huge demand for deepwater floaters and premium jackups in West Africa. As a result, rig availability has diminished rapidly,” Sheela said. “e market seems to be close to a supply/demand balance. However, increase in newbuild rigs is strengthening and these will be readily absorbed into the market without a significant effect on utilization or day rates. “Demand for skilled workers, especially subsea engineers which are already in high demand, has increased due to a surge in the continent’s offshore activity,” he continued. “Companies have now turned to on-the-job training to meet the demand.” n
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Gulf of Mexico Recruiters Step Up Efforts CONTRIBUTED BY OILCAREERS.COM
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n conjunction with OTC 2013, OilCareers.com released statistics on May 6 suggesting that staff roles offered by employers in the Gulf of Mexico (GoM) have increased almost sixteenfold in the last three years. Statistics show that the margin between contract and staff positions, that in 2009 reflected an equal split, now reveal a shi to five times as many staff than contract roles, equating to 80% of job types currently registered on OilCareers.com. is comes as part of a move toward longer term recruitment strategies to encourage experienced personnel to the area as highlighted by Pauline Redpath, global recruitment manager at Expro, who said, “Due to the increasing difficulties facing the sector in recruiting workers equipped with the desired skills, companies including Expro are now focused on capturing and retaining new talent and developing them into our leaders of the future - this has meant a move away from using temporary or contract workers.” Other factors such as the aging workforce may also have a part to play in a higher percentage of new permanent staff being recruited in trainee programs geared at reducing the potential skills gap in the coming years. Vacancies most in demand in the Gulf of Mexico are shown to be qualified designers, engineers (electrical, subsea hardware engineer, exploration reservoir, mechanical) and seismic interpreter/geoscientists. While primary skillsets of applicants are in line with these roles, it is clear that there is still a genuine need for manpower in the region and across the US. is desire for personnel continues to grow particularly in relation to deepwater developments in the GoM, as well as the shale oil and gas revolution in North America. Activity in natural gas has also cemented Houston as the top location for vacancies in the US, with Texas oil production seeing a 25% increase last year in comparison with 2011 being named the top gas producing state in 2012. Mark Guest, managing director of OilCareers.com, said, “Oil and gas majors view the on-going skills shortage as the biggest threat to the sector and it is clear that they are stepping up efforts to develop strategies that help present the energy sector as a secure, assured and affluent career path to individuals to best ensure the constant flow
of skills needed to fulfill the potential of their assets. e natural gas revolution has led to comments that the US may be close to energy self-sufficiency by 2030 from Bob Dudley, chief executive officer for BP, with President Obama also supporting this view to independence stating that the shale gas boom has led to cleaner power and that his administration will be accelerating new oil and gas permits. With 94% of applications in the US coming from American nationals, this attractive outlook and increased view to self sustainability is likely to mean fewer US residents pursuing the higher salaries on offer in countries such as Africa and the Middle East. It will also help to attract talent from overseas. “Ever-increasing activity and constantly evolving technologies in the Gulf of Mexico and across the wider US is extremely promising and it has never been more important for oil and gas businesses to implement robust
recruitment strategies in order to attract the talent needed to sustain their efforts,” added Guest. “It is up to employers to make the oil and gas industry an attractive proposition to new entrants by highlighting the wide range of possible roles within the industry, from engineering and geosciences to project control, health and safety and drilling positions,” he said. “Many companies already offer acclaimed graduate and apprenticeship schemes to attract young people into the industry, as well as offering training and development programs to ensure constant development of staff in line with industry breakthroughs. However, as [the report] revealed, 20% of recruiters highlight the biggest training issue as the lack of skilled trainers. is suggests a specific need to attract staff between the ages of 35-55 with over five years experience, to ensure a constant flow of knowledge and support to the existing workforce.” n
NAVIGATING OTC
Exhibitor locator touch screens offer a hands-on, visual experience to navigate the exhibit floor plans. You can search for exhibitors by name, booth, or product category, and find technical session details and locations. Look for them near the Reliant Center and Reliant Arena exhibit entrances. Cell phone charging stations are located in Reliant Center in Lobby B, Lobby D, and upstairs near the technical session rooms
OTC SHOW DAILY | MAY 9, 2013 | THURSDAY
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deepwater Papa-Terra field. Other sessions will focus on dry tree designs and their potential solutions and how they can reduce costs in ultra-deepwater field developments. Additional sessions will address HP/HT wells, new drilling units, presalt reservoirs, and FPSOs. More than 10,000 people from more than 65 countries are expected to attend the show. e conference is organized by the Offshore Technology Conference in partnership with Brasiliero de Petróleo and Gás e Biocumbustives. For more information, visit www.otcbrasil.org/2013/. n
Alaska unconventional study e Alaska Department of Natural Resources (DNR) and the US Department of Energy’s Office of Fossil Energy recently signed a memorandum of understanding (MoU) to work together, as well as with potential investors, to study unconventional energy reserves in Alaska’s Arctic. Under the MoU, the DNR will help the Department of Energy (DOE) with its ongoing assessment of unconventional energy reserves and DOE’s field evaluation of potential unconventional energy production technologies on the North Slope.
e DOE also has committed to sharing available technical data with Alaska. Gazprom-Shell seal Arctic pact Russia’s Gazprom and Anglo Dutch major Shell also recently signed a MoU outlining the principles of cooperation for exploration and development in Russia’s Arctic shelf, as well as some foreign deepwater plays. Alexey Miller, chairman of Gazprom, and Jorma Ollila, chairman of Royal Dutch Shell, signed the MoU in the presence of Russian President Vladimir Putin and Dutch Prime Minister Mark Rutte in Amsterdam. n
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in-house for such a vessel. Now the next step is to go into FEED study with a client for a specific application in either an EWT or full field development context.” With an exclusive agreement in place SBM Offshore, the leader in the supply of leased FPSOs, increases its competitive advantage by offering the world’s only floating production system with a fully integrated, modular GTL solution allowing for a capacity of 25MMscf/d, up to 32,000 bbl/d crude production and 2,000 bbl/d GTL liquids production. Mike Wyllie, comments “SBM Offshore and CompactGTL provide complimentary expertise, and by combining this we have been able to develop an exciting new FPSO product, which will be a very attractive solution for associated gas disposal in ultra deepwater fields”. n
minimizing operational downtime, and maximizing asset value.” ere is a need to demonstrate due diligence related to hull integrity. e trend in the industry is on life extension and reuse, which require prudent management, monitoring, and disposition of inspection findings, repair planning, and execution. Benefits from 3-D virtual condition tracking include providing owners with an asset-specific database tool for better management of the integrity and condition of the asset. An owner can manage inspections, track conditions, plan repairs, and interface with structural analysis tools for anomaly treatment and life-extension planning. n
e cutting structures are enabling operations that previously were not feasible due to milling inefficiencies.In the North Sea Metal Muncher AMT inserts are driving success in slot recovery and plug and abandonment operations where high-volume milling applications are commonplace. In North Dakota a Metal Muncher AMT mill was used to successfully mill out 79 composite plugs in two horizontal wells, in one trip per well, achieving a new record for fracturing plug removal.
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economic diversification strategies to ensure the UAE’s continued growth as a whole. As a part of that plan, said Sebright, “the UAE is working with international partners, including the US, to cultivate local expertise and regional authority in select commercial sectors [that are] ripe for growth.” e UAE’s Economic Vision 2030 is another integral part of that plan, said al Yafei. “By 2030, the [UAE] plans to be about 30 to 35% reliant on the oil and gas sector instead of 70%, as it is today,” said al Yafei, citing concerns that the country’s reliance on the energy sector could harm plans for continued self-sustainability. Sebright echoed that sentiment, saying that Abu
Dhabi’s petrochemicals “are the cornerstone of [the country’s] national economy,” producing around 2.5 million b/d, with a planned increase to 3.5 million b/d by 2017. Projects commissioned by the Abu Dhabi government to increase oil output include construction of an overland pipeline set to be fully operational in 2014, said Sebright. e pipeline would divert the country’s oil from the bottleneck of the Strait of Hormuz, decreasing the chance of oil flow disruption and significantly increasing exportation potential. Part of the diversification plan includes development of a new sector for peaceful nuclear energy. In accordance with relevant federal and local authorities, the UAE currently is working with international partners to build the world’s first nuclear reactor, said Sebright. A total of four reactors are planned to be fully operational by 2020. n
Reducing risk in HP/HT environments Baker Hughes has designed and manufactured completion and bridge plug technology for HP/HT applications. e ARCseal packer incorporates a built-in metal backup seal housing to ensure containment of the Kalrez element. It is V0-rated to remain bubble tight in ultra-HP/HT environments up to 243°C (469°F) and 20,000 psi and incorporates field proven FLEX-LOCK slip design for uniform casing contact, which can reduce damage to the casing. n DOWNTIME continued from page 32
ensures that the process runs smoothly, in addition to the monitoring and logging of all data. Aer the process is finished, the seal is safely removed from the weld head enclosure before being polished and checked. If the values from the recorded data are satisfactory, the seal will be released for installation. Trelleborg Sealing Solutions created a fully tested, portable system that can make life for the offshore operator safer and easier while improving the bottom line for the oil company. n
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projects. Another 15% will be spent on exploration for future projects. Conoco is working in many unconventional plays, such as Canada’s Duvernay and Montney, the Eagle Ford in Texas, and a recent agreement with China. e company also is developing deepwater and conventional resources across the globe. Major projects will account for 400,000 boe/d by 2017. Messier said he hopes the future holds possibility for better partnering, even in competitive situations. “Looking at those megaprojects, there’s always lot of opportunity for collaboration” among companies, Messier said. “In the future, I think that will be an area of opportunity.” n
First Aid is located in the Medical Center in Reliant Center Lobby C, level 1, and in Reliant Arena Hall B
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