2016.otcnet.org

Tuesday, May 3 | Houston, Texas

| THE OFFICIAL 2016 OFFSHORE TECHNOLOGY CONFERENCE NEWSPAPER | DAY 2

BP Executive: True Test Fiery Ice of Downturn Will Come Takes Center Stage During Recovery Leading experts to discuss advances n Energy demand is expected to increase by one-third by 2035, but oil and gas

companies need to start looking at hydrocarbons as products to streamline. BY DARREN BARBEE

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magine the oil and gas world as an assembly line, churning out cubes of oil and natural gas. Assembly lines are efficient. Changes mean swapping out one part—not the entire system. Industrial and aviation companies typically cut costs annually. But on the hydrocarbon conveyor belt, cost efficiency doesn’t seem to follow any logical pattern. “In oil and gas, specifically the upstream, costs as we know tend to follow oil price and in general have trended upward over time,” said Bernard Looney, BP’s CEO for upstream, May 2, at OTC. “We need to change this.” The U.S. shale revolution, Looney said, is part of the way forward—a fundamentally different mindset that the industry should adopt. “This combination of innovation and continuous improvement is the driving force for the future,” he said.

“It’s how we will improve through the productivity of our oil sector and put costs on a downward curve.” For instance, BP’s Mad Dog Phase 2 project in the Gulf of Mexico went through about $10 billion in cost trims, Looney said. “This was a $20 billion project, Bernard Looney and we’ve brought it down to under $10 billion with expected returns improved despite a lower oil price,” he said. However, the real value might be in opening up the company to using more technology and collaboration. In 2015, the company teamed with Maersk to train rig teams in an immersive simulator in advance of an Egyptian project. See DOWNTURN continued on page 23

Petrobras, Partners Rise to Challenges with Lula NE Pilot n Production from the field is pushing Petrobas closer to its 1-MMbbl/d

presalt goal. BY VELDA ADDISON

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hen Petrobras and partners began the Lula NE pilot project offshore Brazil, they had a tall order to fill—implementing new technologies as part of a fasttrack project facing several technical challenges. These include reservoir fluid variations, the presence of fluid contaminants such as CO₂, a high gas-oil ratio and water depths of 2,120 m (7,300 ft) with no “off-the-shelf” proven subsea technology capable of handling such field conditions.

Add to this the pressures of being a fast-track project in the early development stage of the Santos Basin Presalt Cluster, a new frontier in 2009, charged with not only gathering data that could prove beneficial in future field developments but also for generating revenues to help finance other nearby presalt fields while doing its part to help the company reach a 1-MMbbl/d target from presalt fields in 2017. See CHALLENGES continued on page 23

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in E&P testing of gas hydrates during Wednesday luncheon. BY JENNIFER PRESLEY

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t is the ice that burns, and it is more than an industrial hazard plugging pipelines. It goes by many names—fire in the ice or fiery ice being two of the more popular descriptors. Gas hydrate is the curious clathrate formed by natural gas and water. Found in the Arctic and in the deepwater continental margins around the globe, the energy potential of this other unconventional hydrocarbon is keeping researchers busy unlocking its secrets to better understand its environmental and economic impact. “Gas hydrates present an enormous potential to contribute in the natural gas supply basket and can affect the gas market, if commerciality is established within the foreseeable future,” said Pushpendra Kumar, Keshav Dev Malviya Institute of Petroleum Exploration, ONGC. In light of the current market difficulties, the importance of a goal like gas hydrate commercialization might not be immediately clear. However, for countries like Japan, Korea and India, the need is there. “Gas hydrates are very important for India in view of the huge demand-supply gap leading to the import of LNG at high cost and planning for natural gas transportation through transnational pipelines,” Kumar said. Encouraging results from recent exploration and field testing programs show that gas hydrate deposits are technically recoverable. These results and more will be the focus of a special lunch discussion on Wednesday, May 4, titled “Gas Hydrate Exploration and Production Testing: Encouraging Results and Future Plans” from 12:15 p.m. to 1:45 p.m. Scheduled to join Kumar on the panel are Dan McConnell, Fugro; Timothy Collett, U.S. Geological Survey; and Ray Boswell, U.S. Department of Energy. Collett will provide an overview of world activities, including the first gas hydrate marine production test in Japan. Boswell will present on current perspectives on gas hydrate evaluations as a resource, including the latest concepts of resource volumes, exploration approaches and production technologies. Kumar will specifically cover results from the 2006 Indian National Gas Hydrate Program Expedition 01 and from the recently completed Expedition 02 in his presentation. He also will speak to the efforts being made by India to commercialize gas hydrates within the next five years. n

Editorial Director Peggy Williams SM

E&P Group Managing Editor Jo Ann Davy Editor-In-Chief Mark Thomas Executive Editor Rhonda Duey Senior Editor, Drilling Scott Weeden Senior Editor, Production Jennifer Presley Chief Technical Director, Upstream Richard Mason Associate Managing Editor Ariana Benavidez Senior Editors, Digital News Group Velda Addison

SCHEDULE OF EVENTS

All events in conjunction with OTC 2016 will be held at NRG Park in Houston, Texas, unless noted otherwise.

Tuesday, May 3 7:30 a.m. to 5 p.m.................................... Registration 7:30 a.m. to 9 a.m.................................... Topical/Industry Breakfasts 9 a.m. to 5 p.m........................................ University R&D Showcase 9 a.m. to 5:30 p.m.................................... Exhibition 9:30 a.m. to 12 p.m.................................. Technical Sessions 12 p.m. to 2 p.m....................................... Distinguished Achievement Awards Luncheon (formerly the Annual OTC Dinner) 12:15 p.m. to 1:45 p.m............................. Topical Luncheons 2 p.m. to 4:30 p.m.................................... Technical Sessions 4 p.m. to 6 p.m........................................ Networking Event 7:05 p.m................................................. OTC Night at the Ballpark (Houston Astros vs. Minnesota Twins at Minute Maid Park)

Darren Barbee Contributing Editors Harry Brekelmans Domenic Carlucci George Griffiths Phaneendra Kondapi Philippe Lavagna Manoj Nimbalkar Oscar Rivera Chris Serratella

Wednesday, May 4 7:30 a.m. to 5 p.m.................................... Registration 7:30 a.m. to 9 a.m.................................... Topical/Industry/Ethics Breakfasts 9 a.m. to 5 p.m........................................ University R&D Showcase 9 a.m. to 5:30 p.m.................................... Exhibition

Vibha Zaman

9:30 a.m. to 12 p.m.................................. Technical Sessions

Corporate Art Director

12:15 p.m. to 1:45 p.m............................. Topical Luncheons

Alexa Sanders Senior Graphic Designers Robert Avila Felicia Hammons

2 p.m. to 4:30 p.m.................................... Technical Sessions 4 p.m. to 6 p.m........................................ Spotlight on API Global Standards Networking Event 4 p.m. to 6 p.m........................................ OTC Reaching Out and Reaching Up— Networking in the Downturn

Photography by CorporateEventImages.com Production Manager Gigi Rodriguez Vice President-Publishing Russell Laas

HART ENERGY LLLP President and Chief Operating Officer Kevin F. Higgins Chief Executive Officer Richard A. Eichler

Thursday, May 5 7:30 a.m. to 2 p.m.................................... Registration 7:30 a.m. to 9 a.m.................................... Topical/Industry Breakfasts 9 a.m. to 2 p.m........................................ Exhibition 9 a.m. to 5 p.m........................................ University R&D Showcase 9:30 a.m. to 12 p.m.................................. Technical Sessions 12:15 p.m. to 1:45 p.m............................. Topical Luncheons 2 p.m. to 4:30 p.m.................................... Technical Sessions 4 p.m. to 5 p.m........................................ OTC Closing Reception

The OTC 2016 Daily is produced for OTC 2016. The publication is edited by the staff of Hart Energy. Opinions expressed herein do not necessarily

Friday, May 6 7 a.m. to 4:30 p.m.................................... d5 at Rice University

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 2016 Hart Energy Publishing LLLP

OTC Night at the Ballpark Join your colleagues tonight for OTC at the Ballpark, an evening of major league baseball. Come out to watch the Houston Astros play the Minnesota Twins! The game starts at 7:05 p.m. at Minute Maid Park. For more information or to purchase tickets, visit astros.com/OTC.

OTC SHOW DAILY | MAY 3, 2016 | TUESDAY

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Industry’s Perspective on Subsea Separation Future n The challenges that still exist for subsea separation were discussed during a Monday breakfast panel at OTC. BY DR. PHANEENDRA KONDAPI

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ubsea separation technology is one of the fastest growing technologies due to its huge potential to increase recoverable reserves and to accelerate production. It also enables cost savings by moving some of the traditional topsides processing to the seabed. Subsea separation also eliminates multiphase flow for long distance transportation. Yet there are only a handful of subsea separators in the world that are in operation. On Monday morning during the “5,000 Wells and Only Five Separators: An Industry Perspective on Subsea Separation Future” breakfast session, an expert panel discussed the challenges that still exist for subsea separation such as cost and installation, improving an efficient compact design, achieving separation from heavy oil, disposal of

separated water, and opportunities to reduce bulky and heavy equipment. Welcoming the audience and panel speakers, session chairman Dr. Phaneendra Kondapi addressed that subsea separation projects have been installed in the North Sea, Gulf of Mexico, West Africa and Brazil, and many other subsea field developments are in the process of considering subsea separation systems. There have been only five projects that have been delivered and are in operation to date, though there are an estimated 5,000 wells in operation in deepwaters around the globe. Certainly there are limitations in making the subsea separation viable and accessible to all operators, but the technology needs and industry collaboration should overcome these challenges. James Pappas, president of RPSEA, added that he believed this discussion was not only about the past but

Left to right: Rune Fantoft, Fjord Processing; session chair Dr. Phaneedra Kondapi; James Pappas and Jeff Jones of Exxon Mobil; and Donald Underwood, FMC, prepare to take the stage for Monday’s topical breakfast, “5,000 Wells and Only Five Separators: An Industry Perspective on Subsea Separation Future.” (Photo by CorporateEventImages.com)

also an opportunity to focus on the longer term future of subsea separation. The successes to date have opened the door to the realities associated with separation, and facts show that there are certain gaps that must be addressed to take full advantage thereof. Among those issues that require further analysis are dealing with the all too common perception of added risk, simplification of the complexities surrounding separation in the subsea environment, potential standardization, using a systems engineering full life-cycle approach to determine value creation as well as handling reservoir uncertainty. He followed by comparing the expanded use of subsea separation and its potential to other oilfield advances such as horizontal drilling, in which adoption frequently results in serendipitous improvements that were previously not foreseen as well as other associated gains that can result in true and sometimes disruptive progress through new technologies. The first pilot separation system was installed on the Troll Field in 1999 for liquid-liquid separation and in 2001 for gas-liquid separation. The operating oil-water separation projects are Statoil Tordis and Petrobras Marlim, and gas-liquid separation projects are Shell Perdido, Shell BC-10 and Total Pazflor. Don Underwood, general manager of emerging technologies at FMC Technologies, mentioned the factors that have slowed down the subsea separation, which include cost, risk and complexity in designing the complicated systems and technology qualification programs. But things have been changing to close the gaps, he said; the new lower cost technologies and system architectures have allowed reducing or even eliminating the need for much of the costly equipment. Better qualifications programs are taking place for deeper water and tougher environments. The industry is finding solutions to reduce complexity and risk. Companies are streamlining their technical staffs and suppliers are combining to provide broad system level expertise. Based on the reservoir analysis, there are hundreds of wells that would benefit from subsea separation during this current economic environment. When the industry cannot go for greenfield projects in the current market and cannot drill more wells, subsea processing offers a way to get more out of existing reservoirs. See PERSPECTIVE continued on page 21

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TUESDAY | MAY 3, 2016 | OTC SHOW DAILY

Downhole Pressure Control, Safety Top Deepwater Agenda n Well control with MPD offers both faster reaction to kicks and less formation damage.

Technology continues to advance in MPD and mud pulse telemetry systems. BY SCOTT WEEDEN

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anaged-pressure drilling (MPD) is becoming more mainstream for deepwater drilling. Adding permanently installed MPD systems to newbuild rigs and as an upgrade to older rigs will likely follow the same acceptance path that top drive systems did 20 years ago. At 9:30 a.m. on Tuesday an OTC technical session will focus on “Offshore Drilling II: Managing the Pressure.” Six papers will be presented describing various aspects of managing pressure and data transmission in drilling deepwater wells and long onshore laterals. Highlights from two of the papers follow.

However one challenging area for HSMPT systems is drilling in HP/HT environments. “These operations must contend with the Arrhenius equation, which says the reaction rate for every 10 C [50 F] increase in temperature, therefore reducing the component life by a factor of two,” according to the authors. In the last few years, significant steps were taken to increase reliability of the HP/HT bottomhole assemblies. These critical technologies included multichip modules, sensors developed specifically for the HP/HT environment and active cooling methods.

“Recent experience shows that a higher percentage of land operations are starting to consider HSMPT systems as an alternative, depending on the complexity of drilling. The wide distribution of HSMPT has removed their special nature and a natural commoditization process is ongoing,” the authors explained. A MPT system was introduced in 2015 that is capable of reliably transmitting 10 bits per second and more. “Evolutionary improvements to the HSMPT system have been shown for general pulser hardware and the sophisticated surface system, enabling fully automatic tuning of the receiver to the current MPT channel conditions,” the authors said. n

MPD systems in GoM The industry faces several challenges in MPD for deepwater projects, including reliability, barriers, offshore environments, limited space, riser gas management, general riser interface issues, training and regulatory requirements. In the OTC-27265-MS paper, ABS presented information on lessons learned and challenges faced in the first classification of an MPD system deployment in the Gulf of Mexico (GoM). One of the more surprising determinations was that multiple-vendor MPD systems offer significant advantages over single-vendor systems. “Preferred operating features available from the manufacturer or supplier of each sub-system offer different performance advantages not available universally. More simply expressed, the ‘best’ control system software may not be available from the vendor offering the best RCD [rotating control devices] or the best drilling choke,” the authors said. There are countless decisions that go into selecting the MPD system. Each rig has a completely different set of conditions for designing, installing and operating the system. “Meeting the challenges of space limitations, weight restrictions, power requirements and economic realities like delivery time and purchase costs requires sound engineering judgement,” the authors continued. In one recent study it was concluded that electrically operated valve actuators would make a better system, but no commercially available MPD systems used that kind of valve. The company ordered a custom-built system that fully matched their specifications. “Electrically actuated valves have faster response times and are easier to provide with auxiliary or backup power than valves operated hydraulically or pneumatically,” the authors explained. The adoption rate of MPD systems “is likely to accelerate as more people become aware of the opportunities to save time and money while drilling faster and ultimately safer wells by using some form of MPD,” the authors concluded. HSMPT evolution About 10 years ago, the advent of highspeed mud pulse telemetry (HSMPT) began. Currently HSMPT system downhole tools are fully instrumented with improved hardware, according to OTC-26886-MS paper presented by Halliburton. “HSMPT systems enabled an increase in the drilling efficiency with a higher ROP, more stable boreholes and better hole cleaning, mainly due to the availability of drilling dynamics.”

OTC SHOW DAILY | MAY 3, 2016 | TUESDAY

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Subsea Tree System Optimizes Installation, Intervention Flexibility n Independent system components enable horizontal or vertical installation of subsea trees. CONTRIBUTED BY ONESUBSEA, A SCHLUMBERGER COMPANY

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ertical and horizontal subsea trees were developed to complement different subsea well designs, while yielding the same result: the highest degree of operational viability. The position tubing hangers occupy—installed below vertical trees and above horizontal trees—is of key importance when considering tree installation and completion times, functionality and intervention-related rig time. Not surprisingly, both types of trees and their corresponding tubing hanger positions offer operational advantages and disadvantages.

Vertical trees enable redundant completion settings, reducing the time a rig is used on each well. Taking advantage of this capability on large fields has the potential to substantially reduce operational costs. Plus, in the event a vertical tree requires maintenance, it can be recovered without pulling the tubing hanger. For many operators, eliminating the risk of this $40 million to $60 million operation makes vertical trees an obvious choice. However, vertical trees typically have higher equipment and installation costs than their horizontal counterparts. In contrast, since tubing hangers are positioned above horizontal trees, affording greater hanger access, the need to disconnect flowlines and move a horizontal tree in the course of conducting a workover is elimi-

The HyFleX subsea tree system is based on qualified, field-proven components. (Image courtesy of Schlumberger)

nated. However, if a horizontal tree has to be recovered, the tubing hanger must be pulled first, resulting in the aforementioned punitive operational price tag. The varying aspects of the two tree types often have presented those trying to choose between them with a familiar dilemma: incur lower equipment and installation costs at the beginning of a project and deal with higher intervention and workover costs later, or pay higher equipment and installation costs at the onset of a project to ensure future costs for intervention and workover operations are lower. Tree design offers operational flexibility OneSubsea, a Schlumberger company, offered an alternative to this dilemma at last year’s OTC by introducing the patented compact and cost-effective HyFleX subsea tree system. The system includes a tree, tubing head spool and tubing hanger—with a total weight of less than 40 tons—in a configuration that positions the tubing hanger in its tubing head spool, which is surrounded by the tree. Because the HyFleX subsea tree system’s tubing hanger is neither above nor below the tree, operators have the option of installing subsea trees horizontally or vertically. The tree’s modular design also gives it the interchangeability necessary to accommodate wells being converted from production to injection applications. The HyFleX subsea tree system is as simple to install as a horizontal tree and uses the same existing tooling. In the event a tree needs to be pulled, there is no risk of incurring the high costs associated with pulling the tubing hanger. Like vertical trees, the new subsea tree system enables redundant completion settings to minimize rig time, and its modular design allows the tubing head spool and tree module to be lifted individually, simplifying tree installation by reducing the weight of single lifts. The HyFleX subsea tree system’s flexibility also limits intervention costs and complexities that can impede future recompletion efforts. To learn more about the HyFleX subsea tree system, visit OneSubsea at OTC booth 3527 for an operational demonstration and daily technical presentations on this technology. n

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TUESDAY | MAY 3, 2016 | OTC SHOW DAILY

Subsea Production Systems Spend to Grow

Projected Subsea Capex (%) by Region 2011-2020

23%

n Infield’s 2020 subsea vision sees global demand rising. BY GEORGE GRIFFITHS, INFIELD SYSTEMS

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he outlook for the global subsea production market over the next five years remains optimistic despite the current oil price environment. Infield System’s current market projections show worldwide subsea capex increasing by 38% in comparison to the last five years, with capex forecast to grow by a compound annual growth rate of 7% between 2016 and 2020. Global subsea tree installation activity, another important market indicator, could increase by 45% in certain areas between the historic and forecast periods. The three regions expected to drive global demand are Africa, Latin America and North America, which together equate to 77% of Infield’s forecast global subsea capex and 62% of its forecast tree installations. Africa is expected to attract the largest share of global subsea capex demand, with African spending forecast to overtake Latin American spend in this period. African demand is largely generated in West Africa, where offshore developments in Angola, Nigeria and Ghana stand out.

first deepwater development. In Guyana, meanwhile, Exxon Mobil continues to look at the potential development of its ultradeepwater Liza oil discovery in the Stabroek Block. GoM focus North America, specifically the deepwater U.S. Gulf of Mexico (GoM), will continue to remain an important market for subsea equipment. Notable projects include Shell’s Stones and Appomattox fields, Anadarko’s Hadrian North Field and the long-awaited Phase 2 of BP’s Mad Dog development. Canada will make up the rest of North American demand, with Husky Energy’s White Rose Extension Project a notable project that received a final investment decision in 2015.

30%

17%

27%

Africa Latin America

2011-2015 25% 21%

North America Others

31% 26%

2016-2020

(Data courtesy of Infield Systems)

The impact of low oil prices will undoubtedly cause challenges going forward. However, despite these market conditions, Infield believes that there could be growth within the subsea sector over the next five years as operators work through their increasingly high-graded project inventories. n

Angola Angola contains 53% of the West African developments that require subsea production infrastructure, including Total’s ultradeepwater Kaombo project and BP’s ultradeepwater Block 18 and Block 31 expansion projects. North Africa’s demand is largely associated with developments offshore Egypt such as Eni’s giant Zohr Field and BP’s West Nile Delta Project. Toward the end of the forecast period it also is anticipated that there will be some initial spend on subsea production equipment for the frontier East African region, where a number of large deepwater and ultradeepwater field discoveries have been made in recent years. However, Infield does not believe that there will be actual subsea tree installations in the subregion before year-end 2020. Latin America Latin America remains a key region, and it is expected to represent a 26% share of global subsea capex demand over the next five years. Demand as usual largely stems from projects offshore Brazil, which account for 91% of the regional subsea capex forecast. Brazil is expected to continue to be the largest subsea spend segment for any single country. This demand comes from the large numbers of recent discoveries in deep and ultradeep water, with 70% of Brazilian fields in which Infield anticipates subsea spend being in ultradeep water. Petrobras continues to be the key operator in Brazil’s deepwaters despite moves by the country’s senate to try to end its monopoly on presalt resources. As a result of this leading position, Infield believes that Petrobras will continue to be a key player in driving global demand for subsea production systems. Notable projects include the Buzios multiphase project in the Santos Basin, located in water depths of about 2,189 m (7,182 ft), and the Lapa Pilot project. Other countries within Latin America that are expected to produce demand for subsea production systems include Mexico and Guyana. In Mexico the national oil company Pemex has begun to develop its deepwater Lakach subsea tieback project, the country’s

OTC SHOW DAILY | MAY 3, 2016 | TUESDAY

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Now’s the Time to Tackle Costs n How businesses can step up their performance in a period of sustained low oil prices. BY HARRY BREKELMANS, ROYAL DUTCH SHELL PLC

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t might not seem like it at times, but there are upsides to the low oil price. For one thing, it is compelling everyone working in the oil and gas sector to make their companies more efficient and competitive. This needs to happen to address the enormous increase in costs over the past two decades. According to the consultancy Independent Project Analysis, capital cost per barrel has increased by a factor of four between 1996 and 2014. This was caused, in part, by factors beyond the control of the industry such as more expansive regulations regarding the environment. But the oil and gas industry also has played a big role in pushing up costs. There’s been a vast expansion in the project doc-

umentation, specifications and assurance processes that companies require, for example. This is on top of a multitude of industry “standards” for virtually every piece of equipment. Other industries such as aerospace and car manufacturing have managed to put together more systematic and rigorous ways of managing requirements along the supply chain. But the oil and gas industry has failed to get to grips with the steady upward trend in project costs and delivery times. This needs to change, and for that to happen there are four main areas oil and gas companies should focus on. First is the scoping of a project. The design and technical specifications of a project should, first and foremost, aim to assure a minimum acceptable performance. No more, no less—at least to begin with.

Any scope changes to give a project greater value—say, by increasing profitability—or greater resilience against risks must only be accepted with full transparency of their cost and value trade-off. But above all, the project must be kept competitive with comparable projects. The second area is efficient projHarry Brekelmans ect execution. Increasing productivity by cutting out waste, minimizing idle time and eliminating duplication of effort must all be ruthlessly enforced, though never at the expense of safety. When it comes to efficient execution, the secret is the sum of many small steps, from better planning to better use of technology tools. The third area of improvement is affordable technology. This must be deployed quickly to increase the value or reduce the cost of projects and to enhance their operational reliability, productivity and profitability. The fourth theme is the transformation of the supply chain. It underpins the success of the other three areas. Shell sees three ways to extract more value from the supply chain: improving demand management, simplifying specifications and negotiating lower prices. Shell has adopted all four areas of improvement in the past year on some of its big projects, and the company is seeing positive results. With the Appomattox deepwater project in the Gulf of Mexico, for example, Shell reduced the total estimated cost of the project by 20% in 15 months from the time the original concept was proposed and when the final investment decision was reached last year. Ultimately, the oil and gas industry will only be able to tackle costs effectively by changing the way it works. It’s all about transparency, simplicity, focus and collaboration. This will help ensure long-term sustainable improvement in the industry united by a strong collective will and purpose. The oil and gas industry’s efforts to improve its safety performance are evidence that such a unity of purpose can be achieved. According to the International Association of Oil and Gas Producers, the fatality rate in the industry dropped eightfold between 1996 and 2014. But effective collaboration doesn’t happen overnight. Partnerships that stand the test of time have a common sense of purpose that’s aligned with the long-term business interests of all the companies involved. In short, all parties must strive for what’s best for a project. Such efforts are not only important given today’s low oil price. They are essential to the sustainable future of the oil and gas industry. n Harry Brekelmans is projects and technology director for Royal Dutch Shell Plc.

Need tickets? You may purchase special event tickets online (2016.otcnet.org) or at the registration counters until an event is sold out. Please note that food is not guaranteed 20 minutes past the event start time.

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TUESDAY | MAY 3, 2016 | OTC SHOW DAILY

Spotlight Award Winners Recognized for Innovations n The Spotlight on New Technology awards acknowledge innovations from companies of all sizes. independently of each other, it provides functional flexibility and the ability to batch set wells, risk mitigation, and significant cost savings in field development and over the life of the field. For more information about the HyFleX Subsea Tree System, visit OneSubsea, a Schlumberger company, at booth 3527.

BY HART ENERGY STAFF

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he 2016 Spotlight on New Technology Awards given by OTC recognize the latest and most significant advances in the offshore industry. Seven of this year's 13 winners appeared in Monday's show daily. They included AFGlobal Corp. for its Riser Gas Handling system and Baker Hughes for its Integrity eXplorer cement evaluation service. Barge Master, the small business winner, was recognized for its BM-T40, and FMC Technologies received an award for its InLine ElectroCoalescer. GE Oil & Gas earned an award for its SeaPrime I Subsea MUX BOP Control System, and Halliburton received an award for its BaraLogix Density and Rheology Unit. Lankhorst Ropes also was recognized for its Soft Rope System. Oceaneering has received an award for the Remote Piloting and Automated Control Technology (RPACT). The technology revolutionizes operational efficiency. Subject matter experts or ROV pilots can establish ROV control through a satellite or wireless network link to support operations at a remote work site. RPACT diminishes operational and environmental risk while reducing potential damage to tooling, manipulators and subsea assets. For more information about the RPACT, visit Oceaneering at booth 5833.

The RPACT system uses the latest control system programming and network acceleration technologies to provide real-time access to operate an ROV, either from onshore or from a vessel nearby. (Image courtesy of Oceaneering)

OES Oilfield Services Group has received an award for DOPP, which is a technologically innovative tablet-based four-stage program that evaluates each rig site’s ability to control, implement and mitigate dropped objects. Using this information, a bespoke awareness package is created and delivered to all personnel on the rig in the form of classroom and onsite hands-on training. For more information about DOPP, visit OES Oilfield Services Group at booth 4227.

The DOPP tablet-based four-stage program evaluates each rig site’s ability to control, implement and mitigate dropped objects. (Photo courtesy of OES Oilfield Services Group)

The AquaWatcher can measure the conductivity of produced water at any gas volume fraction and most water cuts. (Photo courtesy of OneSubsea, a Schlumberger company)

OneSubsea, a Schlumberger company, has received an award for the HyFleX Subsea Tree System. The system provides benefits of both vertical and horizontal conventional trees. Designed so the tubing hanger and tree can be installed and recovered

OneSubsea, a Schlumberger company, has received an award for the AquaWatcher Water Analysis Sensor. The sensor uniquely detects minuscule quantities of water in multiphase and wet gas flows, plus determines the salinity of that water. The patent-pending technology also can measure the concentration of chemicals in water to determine accurate dosage requirements, thus enabling significant risk reduction and reduced costs. For more information about the AquaWatcher Water Analysis Sensor, visit OneSubsea, a Schlumberger company, at booth 3527.

SkoFlo's subsea BPR can be delivered and retrieved thousands of feet below the surface of the ocean to a site via an ROV. (Image courtesy of SkoFlo Industries Inc.)

SkoFlo Industries Inc. has received an award for the Subsea Back Pressure Regulators (BPRs). The valves are anti-siphoning, self-regulating devices that create backpressure in chemical injection lines to prevent uncontrolled delivery of chemicals into production wells. BPRs prevent chemicals from draining into injection points when a chemical hydrostatic head exceeds injection pressure and production wells become sub-ambient. For more information about the BPRs, visit SkoFlo at booth 3101.

The EOFL is designed with a modular power converter, which allows different power inputs to be used without redesign. (Photo courtesy of Teledyne Oil & Gas)

The HyFleX Subsea Tree System is designed such that the tubing hanger and tree are completely independent of each other. (Photo courtesy of OneSubsea, a Schlumberger company)

Teledyne Oil & Gas has received an award for the Electrical Optical Flying Lead (EOFL). The lead features a hybrid wet mate connector and an electrical wet mate connector on either end of a jumper assembly, with a qualified electrical/optical converter integrated into the pressure balanced, oil-filled hose. Including the EOFL into a data transmission network can allow greater field architecture flexibility at a lower cost. For more information about EOFL, visit Teledyne at booth 5633. n

Trading in a Minivan for a Ferrari n Industry expert shares new optimized method for well decommissioning at Monday’s technical panel. BY JENNIFER PRESLEY

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t the beginning of 2011 there were more than 4,500 idle wells and 783 idle structures in U.S. federal waters of the Outer Continental Shelf. These aging assets pose an environmental risk, prompting operators to feel a renewed pressure to decommission idle infrastructure sooner rather than later, according Gary Siems of Montco Oilfield Contractors in his technical paper “Decommissioning Process Optimization Methodology,” OTC-26867-MS. Siems presented his paper along with six other presenters as part of Monday’s “Decommis-

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sioning and Well Abandonment: Case Studies and the Technologies Involved” technical panel on Monday morning at OTC 2016. “In a four-year period, there were 183 structures and 1,082 wells toppled by hurricanes,” he said. The increased number of topGary Siems pled assets led the U.S. Dept. of the Interior’s Bureau of Ocean Energy Management Regulation and Enforcement to issue guidelines that specified that lease operators had to permanently

decommission and remove wells and structures no longer useful for oil and gas production as soon as possible, but no later than five years after cessation of production, he said. In his presentation, Siems compared the old, multistep way of decommissioning a structure and well with a new and better optimized process that employs the newest technologies to get more work done safely and at a lower cost. He noted that the eleven steps typical to the traditional process are performed sequentially, with most requiring separate and specialized workers and equipment. See MINIVAN continued on page 21

TUESDAY | MAY 3, 2016 | OTC SHOW DAILY

Removable Packer Stays Removable, Even in HP/HT Conditions n The removable packer’s chassis has been engineered to

separate from the casing wall when released. CONTRIBUTED BY BAKER HUGHES

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emovable production packers can eliminate nonproductive time (NPT), costs and risks during well intervention operations. But they can become permanently set when exposed to high pressures and temperatures. The Baker Hughes BASTILLE HP/HT removable production packer creates a reliable seal between the casing and tubing while the well is flowing and just as reliably disengages when well intervention is needed. Previously, when downhole temperatures and pressures rise above 177 C (350 F) and 12,500 psi (862 bar), even HP/HT-rated elastomers and slips could permanently set inside the casing wall. When this occurred, the result was at least one day of unplanned milling and

fishing time at a cost of $1-plus million in deepwater wells, in addition to increased HSE exposure. Simply upgrading a conventional removable packer with HP/HT materials is not sufficient to ensure packer removal in HP/HT conditions. The BASTILLE chassis has been engineered specifically to separate from the casing wall when released, even after prolonged exposure to temperatures up to 204 C (400 F) and differential pressures as high as 17,500 psi (1,207 bar), an industry first at these ratings. When intervention is needed, a mechanical pipe cutter is run in hole and aligned below the bottom slips. It makes a cut to sever the inner mandrel while the outer packer wall stays intact. When the production tubing is pulled uphole the mandrel follows. This action releases the bottom slips and relaxes the elasto-

The BASTILLE HP/HT removable production packer will be featured at OTC 2016 at booth 3731. (Image courtesy of Baker Hughes)

mer. As pulling continues, the upward pressure shears pins that let specially designed segments break free. The packer wall flexes inward, and the upper slips pull free from the casing wall, reducing friction and letting the packer break free from the casing. On its way uphole shoulders on the mandrel catch the outer packer wall, and the entire assembly is retrieved with the production tubing. The BASTILLE packer extends the efficiency of removable production packers to HP/ HT wells. Baker Hughes also offers the SCION removable production packer for use in wells with standard (non-HP/HT) conditions. The BASTILLE removable packer will be featured at the Baker Hughes booth 3731 at OTC 2016. n

New Recommended Practice on P&A of Offshore Wells n The recommended practice is based on case studies

performed by DNV GL in projects dating back to 2011. CONTRIBUTED BY DNV GL

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lugging and abandonment (P&A) of offshore wells represents the highest cost within field decommissioning to operating companies and national authorities. DNV GL has issued a new globally applicable recommended practice (RP) on risk-based abandonment of offshore wells. The framework outlined in the RP provides the possibility for individualized, fit-for-purpose well abandonment designs, a contrast to the prescriptive methodology available in the industry today. Well abandonment is driven by economic decisions, when production of an oil or gas reservoir ceases or is no longer profitable. Authorities require that well operators sufficiently perform safe and environmentally friendly operations to establish permanent barrier(s) to prevent migration of hydrocarbons to the surface. Traditional P&A methods are time consuming, costly and have remained unchanged despite technological advances in the industry. The RP (DNV GL-RP-E103) is based on case studies performed by DNV GL in projects dating back to 2011. A thorough process is defined where the key stages in the risk-based methodology are assessing the well barrier failure modes, well flow potential, valued ecosystem and safety components, dispersion modeling and impact analysis. These steps allow a consistent method to be applied when assessing risks of the offshore well abandonment designs. The RP methodology provides assurance that selected well abandonment designs are robust, environmentally friendly and economically advantageous. The main obstruction to change in this sector has been today’s prescriptive

OTC SHOW DAILY | MAY 3, 2016 | TUESDAY

The framework of DNV GL’s new recommended practice facilitates individualized, fit-forpurpose well abandonment designs. (Image courtesy of DNV GL)

approach to the regulations, which represents a conservative interpretation of past experience and outdated technologies. Practice also differs from country to country. In the RP, DNV GL uses well-known and accepted risk-based approach methodology in which both environmental and safety risk aspects are key factors. Through the development of the RP, DNV GL worked with international oil and gas operators to establish an

initial set of risk acceptance criteria and cross-checked these using case studies. The criteria and methodology have been further strengthened through dialogs with regulators and industry players. DNV GL issued a technical paper and presentation on the RP held at OTC 2016. For more information about the RP, visit DNV GL at booth 5155. n

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Many Possibilities with Industry’s First Microfluidic Technology Application n A fully automated technique for measuring SARA in crude oil samples provides repeatable

and reproducible measurements while decreasing both turnaround time and the use of solvents. CONTRIBUTED BY SCHLUMBERGER

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raditionally, methods for acquiring asphaltenes weight percent in oil samples rely on conventional chemistry techniques such as precipitation, filtration, collection and gravimetric measurements. These methods usually require a significant volume of solvents and a sizeable glass apparatus. The traditional approach suffers from a number of performance shortcomings—specifically, long analysis times, poor repeatability of measurements and operator dependency. In addition, interlab comparison of results often is hampered by the traditional method’s poor reproducibility. These challenges have prompted Schlumberger reservoir fluids experts to develop a fully automated microfluidic technique for measuring saturates, aromatics, resins and asphaltenes (SARA) in crude oil samples. The new service from Schlumberger, known as Maze microfluidic SARA analysis, provides repeatable and reproducible measurements while decreasing both turnaround time and the use of solvents by more than 85%. Results from the new analysis have industrywide applications, including understanding of oil’s physical and refining properties, assessing crude value, performing flow assurance studies, validating samples quality prior to pressure/volume/temperature analysis, and supporting gradient and compartmentalization as well as geochemical studies.

Instead of using gravimetric techniques commonly used in conventional methods, the new technology relies on spectrographic and refractive index measurements for quantifying asphaltenes and SAR contents. For the asphaltenes content, an oil sample is titrated with a nonpolar solvent n-heptane to force precipitation and then is filtered through a proprietary microfluidic chip. The visible spectra of the oil prior and after precipitation are measured through a spectrometer; and the difference in optical absorbance between the asphaltene-saturated oil and de-asphalted oil correlates with gravimetrically measured asphaltene content of the sample. After the asphaltenes fraction is measured and separated, the oil sample is displaced into a miniaturized chromatographic column to analyze SAR fractions using refractometer and spectrometer technologies. Using the microfluidic technique, a complete measurement takes only 4 hours, which is a considerable improvement over conventional chemistry techniques that require a turnaround time of several days. Furthermore, conventional chemistry measurements are operator dependent. For the optical technique, the repeatability of measurement exceeds ± 0.3 wt%. The microfluidic measurements require only 1 ml of sample and 0.4 l of solvent, which significantly reduces the HSE exposure. The new technique is the first commercial application of microfluidic technology in the oil and gas industry

The microfluidic chip forms an integral part of the Maze microfluidic analysis service, a fully automated process for testing oil samples for SARA. (Image courtesy of Schlumberger)

and is accepted by ASTM International as a new D7966 standard for asphaltenes content measurement. More than 300 oil samples have been successfully analyzed using the Maze microfluidic SARA analysis in research, engineering and field tests. In addition, more than 1,900 runs have been completed using the microfluidics chip for asphaltenes analysis only. For more information about the Maze microfluidic SARA analysis service, visit Schlumberger at OTC booth 4541. n

Lowering Overall Costs, Operational Risk during Selective Perforating n New system targets three main areas to improve operational efficiency

and reduce operating cost: safety, reliability, and inventory and cost control. CONTRIBUTED BY DYNAENERGETICS

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n an operating environment governed by ever greater levels of efficiency, the industry is pushing to continuously lower the total cost of operations while simultaneously enhancing safety. DynaStage is an entirely new concept for perforating and incorporates groundbreaking addressable and selective technology and an improved mechanical design that completely eliminates potential human error. The system operates more efficiently than traditional perforating guns and, with its additional safety features, allows other wellsite operations to run in parallel during perforating. This results in improvements in perforation quality and performance reliability, fewer misruns and lower inventory. The DynaStage system has successfully completed operations in multiple basins. The system targets three main areas to improve operational efficiency and reduce operating cost: safety, reliability, and inventory and cost control. Safety A simple, intrinsically safe design eliminates the risk of inadvertent detonation from any stray, DC or voltage. The addressable and radio-frequency-safe firing system is built on a low-voltage, digital communication platform proven to successfully initiate on command during more than 300,000 perforating operations without a single safety incident. This technology enables verification during all phases of the operation. All electrical connections and component functions can be checked and full functionality confirmed during assembly and pumpdown operations. Surface explosive handling and arming can be con-

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ducted in less time and in parallel with other operations. The design eliminates the need to hold the gun system at shallow subsurface depth during simultaneous operations. Both factors reduce wait times at the wellsite. Reliability The design of the electronic system and simplified mechanical field assembly virtually eliminates misruns. DynaStage targets a 99.9% operating efficiency. One major design improvement covers the detonator to system assembly and wiring. A traditional detonator is assembled into a sub requiring wiring and ballistic connections and a port plug with O-ring seals. Wiring connection issues and leaking O-rings are among the most common causes of perforating gun misruns. With DynaStage the detonator wires have been replaced with an injection-molded connector, eliminating crimped wire connections and the associated risks of wiring damage and poor electrical connections. The detonator also was relocated to the gun body, which allows the use of a much shorter, disposable perforating gun connector sub and eliminates the port plug. Field assembly is simplified to inserting the plug-and-go detonator and threading the guns together (See image). Inventory, cost control The DynaStage gun modules are shipped to the wireline customer as specified and fully assembled, except for the detonator. All preshipping operations are performed in the DynaEnergetics gun assembly line, which has been optimized for high-volume assembly, automated quality control inspection and electrical verification of the final product. The production line process mitigates the risk

The DynaStage system operates more efficiently than traditional perforating guns and allows other wellsite operations to run in parallel during perforating. (Photo courtesy of DynaEnergetics)

of human error typical in the manual redress, cleaning, wiring and assembly of conventional perforating guns. This new industry model reduces the wireline service provider’s inventory and overhead. More than 7,500 guns have been run since the introduction of the 3⅛-in. DynaStage system during the summer of 2015. A 2¾-in. system recently was released to support the trend toward smaller gun sizes, and a 3⅜-in. system currently is being finalized. Each stage run with the DynaStage system cut an average of 32 minutes of completion time. Improved downhole reliability also was achieved, with an average decrease in nonproductive time of 2 hours per 100 runs. A significant part of the improved reliability was a reduced need for onsite user interactions that often lead to electrical issues and misruns in conventional wired perforating systems. The use of DynaStage resulted in fewer days on location and operator cost savings as high as six figures. The production success rate has been one misrun per 420 runs for a perforating efficiency of 99.41%. DynaEnergetics continues to refine the system components, assembly process and operating procedures with the ultimate objective of attaining the 99.9% plus efficiency rate and zero safety incidents. n

TUESDAY | MAY 3, 2016 | OTC SHOW DAILY

Industry News Siemens to Showcase Oil, Gas Portfolio at OTC Siemens, along with newly acquired Dresser-Rand business, will showcase its combined capabilities for the oil and gas sector during OTC. The Siemens portfolio includes motor and drive systems, automation technology and advanced industrial software designed to improve the safety and security of today’s oil and gas operations while reducing engineering, operating and capital costs. Siemens’ main booth will feature subject matter experts from a wide range of industry disciplines, available to explain the company’s extensive technology portfolio. The booth also will include an X-pert Center, where speakers are set to present more than 20 technical presentations from Monday to Thursday in several major categories including offshore solutions, digitalization, HSSE solutions and midstream solutions. The X-pert Center will include presentations from the company’s subsea portfolio, including a virtual tour of the subsea power grid, which Siemens is actively developing. This technology holds the potential to make previously unrecoverable resources recoverable. The company also will highlight smarter pump stations for pipelines and the power of its remote diagnostics portfolio in improving turbine performance. Dresser-Rand will join Siemens in booth 4424. Siemens also will have an outside display at booth 13321. Siemens will present a paper related to its subsea offering titled “Technology for Extension of Lifetime” on Wednesday, May 4.

Statoil’s Gullfaks A is shown. (Photo by Øyvind Hagen, courtesy of Statoil)

wellhead hydraulic power units (HPUs) for Statoil’s Gullfaks oil and gas field in the Norwegian sector of the North Sea, which is undergoing an extensive topside upgrade program.

See INDUSTRY NEWS continued on page 16

BMT Delivers CFD Study for Oil Major BMT Fluid Mechanics (BMT), a subsidiary of BMT Group Ltd., has completed a comprehensive computational fluid dynamics (CFD) study for an oil major operating offshore Nigeria. BMT’s scope of work included an assessment of the current loading to which the FPSO hull is subjected to, which has enabled the oil major to ensure its mooring systems are fit for purpose. Through the creation of a 3-D CAD model and representation of the FPSO unit below the water line, the team of specialists at BMT were able to run a comprehensive experimental and numerical study of the maneuvering characteristics. This looked at different parameters of current conditions to help build up a picture of how the forces and motions impact the vessel and how it performs. Proserv Seals Contract with Statoil Proserv has been awarded a multimillion-pound contract with Statoil for the provision of production control equipment in Norway. Proserv will supply five

OTC SHOW DAILY | MAY 3, 2016 | TUESDAY

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Universities Provide Additional Resources for Oil Industry Research n From drones in a wave prediction system to coatings to improve drillbit efficiency to recalibrating drilling data

from all the major ocean basins, participants in OTC’s University R&D Showcase tackle leading-edge projects. BY SCOTT WEEDEN

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he 2016 OTC University R&D Showcase features projects from universities in the U.S., Germany, Nigeria and Japan. These universities include University of Houston, Rice University, Georgia Tech University, Penn State University, Texas A&M University, University of Utah and University of Southern Mississippi in the U.S.; Hamburg University of Technology in Germany; University of Ibadan and Covenant University in Nigeria; and University of Tokyo in Japan. Descriptions of projects from three of the universities follow. Unifying access to 60 years of ocean drilling research When it comes to offshore technology, the land-locked Energy & Geoscience Institute (EGI) at the University of Utah was well ahead of its time. “You could say we were out of sync with time. Most of the Paleozoic and Cretaceous oceans were in Utah. If you go back in deep time, we had a lot of beachfront property here,” laughed Ray Levey, director, EGI at the University of Utah. The university will be presenting its EGI Oceans and Integrated Continent-Ocean Research Data System (iCORDS) projects at OTC. The Oceans research program will be a decade long and will compile academic and government data and cores that have never been evaluated before with petroleum systems in mind. The data are in three major repositories worldwide. “We’re analyzing that data and recalibrating the age and source rocks of the major ocean basins of the world,” he continued. “The governments that funded the original research never funded the accurate collation and integration of that data. It will be the first time there will be a single, unified platform to evaluate that information.” The primary sources of the data will be the Deep Sea Drilling Project, Ocean Drilling Program and International Ocean Discovery Program. “The purpose of the Oceans program is to go back over the government and academic research that has been collected by drilling in all the major oceans of the world for over 60 years,” Levey said. The University of Utah researchers also will be discussing the iCORDS platform, which is a subscription service. “We estimate $30 billion has been spent collecting research data, cores and information. Initially supported by 20 international oil companies (IOCs), iCORDS now has 10 IOCs that are subscribers,” he continued. This is the first time that the EGI will have a major presence at OTC. “This is the first opportunity to have the entire industry see what we’ve done over the last four decades,” Levey said. Wave predictions, floating logistics terminal Although Japan has no nearby oil and gas fields, many companies have competitive technologies for offshore

University R&D Showcase Video Contest Winner And the winner is ... Texas A&M University! This is the second consecutive year that TAMU has taken the title. Its video received 2,000 views with more than 300 likes. The project is titled “Stochastic Geomechanics to Improve Risk Assessment and Engineering Design Practice.” The University R&D Showcase is located on level 2, in the Lobby area of the NRG Center near the 600s.

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The Energy & Geoscience Institute at the University of Utah has completed more than 800 projects in studies covering more than 100 countries. They are available to EGI members. (Image courtesy of the University of Utah)

development. The University of Tokyo has a laboratory endowed by 10 Japanese companies. The laboratory acts as a platform for R&D for the university and industry, said Ryota Wada, associate professor at the university. Other researchers on the project are Prof. Ken Takagi, and Dr. Marcio Yamamoto and Dr. Ramnarayan Mondal, project researchers. The laboratory will be presenting posters and movies on its research projects, which include a wave-prediction system from multipoint drone measurements, a floating logistics terminal and mooring integ- This schematic shows the wave prediction system proposed by the University of Tokyo laboratory. (Image courtesy of the University of Tokyo) rity management. For the wave-prediction system, “We have developed a new concept and algointerrogation of the ocean surface; acoustics coupled rithm where we can predict the sea-surface elevation with marine biology; materials and additive manufacat a vessel point 30 seconds in advance by combining turing; improving corrosion resistance and reducing sea-surface elevation data gathered from drones,” Wada costs of materials; fluid mechanics; and AUVs. explained. “We also are developing drones with robust Being at OTC “gives us a chance to show our 75 years control under strong wind conditions and a safe-landing of experience in doing marine-related research in prosystem on floating vessels with motion.” pulsion systems, materials and design. We’ve been going The laboratory is developing the concept of a floating to OTC for about three years. We’re trying to show peologistics terminal for locations where a new onshore port ple we have a lot of capabilities that we developed workis not economically feasible. The floating logistics terminal ing with our [U.S.] Navy sponsors that could be directly would be deployed near a coast where the wave climate is applicable to the oil and gas industry,” said Tim Eden, moderate. The technical challenge is to design a floating head of the Materials Processing Division at the ARL and logistics terminal that could be used without breakwater associate professor of engineering, science and mechanand with a small mooring footprint, he continued. ics at Penn State. For the mooring integrity management, the laboraThere are two things that the ARL wants to accomplish tory is considering the high nonlinearity of mooring line at OTC. The first is to learn more about what the industry behavior where extreme load estimation is a complicated needs. The other is to be able to show the industry that issue. “Mooring line tension from offshore wind-power the ARL has the technologies that can be applied to solve generation systems and floating liquefied natural gas vesproblems, he continued. sels is being investigated,” he said. For example, the laboratory has two different HP test Being at OTC “is a great opportunity to introduce our facilities that can simulate up to 20,000 psi of ocean activity in this field. Japan seeks to develop its own offdepths, he added. shore resources, such as methane hydrates, seafloor poly“In the coatings area we’ve looked at coatings for drillmetallic sulfide, offshore renewable energy and so on. We bits to make the drilling process better and have the bits would like to interact with participating companies and last longer. We’ve also made pump components last lonuniversities for feedback and collaboration,” Wada added. ger when pumping the caustic fluids or a mixture of fluids and solids from an oil well,” Eden explained. Drillbit coatings, additive manufacturing For additive manufacturing Penn State has a metals The Applied Research Laboratory (ARL) at Penn State additive-manufacturing demonstration facility. “We’re University has a variety of capabilities that could be of going to talk about how to use additive manufacturing to benefit to the offshore industry, including high-pressure build complex components that may require several parts (HP), deep-ocean simulation; sonar that can be used for or reduce the number of parts,” Eden said. n

TUESDAY | MAY 3, 2016 | OTC SHOW DAILY

Data-intensive Operations Are Here to Stay n Several factors are facilitating the adoption of data-centric applications. BY CHRIS SERRATELLA AND DOMENIC CARLUCCI, ABS

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ncreasing regulatory demands, stakeholder oversight and the need for greater operational efficiencies have led offshore asset owners, designers and shipyards to look for new approaches to manage performance efficiency, asset health and longevity. The heart of the solution lies in improving the ability to collect, validate, analyze and ultimately leverage the data being produced by smarter, more data-intensive onboard systems. Equipment manufacturers and vendors are quickly adopting these tools and techniques, and more and more owners are coming to rely on them to drive performance efficiency, improve uptime and gain deeper insight into improving their bottom line. Adoption of data-centric applications has been driven by a recent rapid decrease in the cost of advanced sensors, the expansion of wide-area communication networks, the availability of high data storage capacity and increasing computer processing power. In today’s offshore environment, smart technology gathers real-time data from a broad range of systems, from the well to the export line. These applications and their reliance on data management and analytics have come into the limelight as a result of the buzz surrounding the big data phenomenon. In short, everything we can physically touch in our business will be virtualized and accessible in a smart data or Internet of Things environment. Opportunities for leveraging data exist in the full life cycle of an asset and can be aligned to support regulatory and classification requirements. Monitoring structural and machinery condition and performance is vital to effective asset management. Doing it properly involves identifying key data sources, developing data collection protocols, drawing conclusions from the data through proven analytics tools and transitioning information into actionable intelligence. Integrating data collection with the asset’s control and monitoring systems ultimately can reduce the burden on the crew and simplify an often complex puzzle of qualifying and analyzing condition and performance data into a standardized process for planning and decision-making related to asset operations. The information gathered from these processes can create a knowledge loop that, when implemented into an enterprise asset management strategy, can improve operational execution and ultimately influence the next generation of offshore asset designs. Recognizing that such opportunities also pose risks, ABS has stepped up to provide guidance for the industry. The role of classification societies has evolved to become data-centric in its verification activities during construction and commissioning, relying on a new range of expertise. Asset integrity verification will draw on class to verify robustness and reliability of sensors and control systems that capture data, the software that collects and processes it, and the “smart analytics boxes” used to draw conclusions from that these systems. Collecting and analyzing more data can add value. A “smarter asset” delivers the ability to develop dynamic and real-time risk profiles based on the type of operation being performed, its location and its current health. This information can

OTC SHOW DAILY | MAY 3, 2016 | TUESDAY

be used to manage and optimize both structural and mechanical integrity. The newly revised ABS Guide for Surveys Based on Machinery Reliability and Maintenance Techniques and the ABS Guidance Notes on Equipment Condition Monitoring Techniques were developed so post-construction survey plans can take advantage of this new data-intensive world to allow surveys that emphasize real-time performance and focus less on calendar-based schedules. As new concepts are introduced, it becomes increasingly important to collect and analyze data from a growing number of sources, and it is essential for safety to keep pace. As a class society, ABS will continue to work with industry in the search for solutions to its challenges. n

As new concepts are introduced, it becomes increasingly important to collect and analyze data from a growing number of sources. (Image courtesy of Bruce Rolff / 123RF.com)

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Pushing the Boundaries of Pipeline Capabilities n Pipelines face challenges in deepwater environments. BY VIBHA ZAMAN, LLOYD'S REGISTER

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he drive to push the boundaries of capabilities within the offshore oil and gas industry come with challenges on two fronts, those of internal origin and those derived from external sources. Internally, more and more pipelines are being required to operate at temperatures that reach or exceed the limits of traditional materials of construction. Depending on the service, pipelines must be able to withstand increasingly high operating temperatures or the extreme cold conditions associated with arctic exploration. Externally, the push is on to operate pipelines in deeper waters and increasingly hostile environments with bigger waves and stronger, more complex currents; these activities often are taking place in more isolated locations with dwindling amounts of supporting infrastructure while facing the possibility of significant environmental hazards such as icebergs or unsurvivable storm conditions. Challenges, design considerations Deepwater pipelines are exposed to high external pressures that require thicker pipe to withstand the subsea pressures and the stresses they are subjected to during installation. However, the added weight of the thicker diameter pipe together with the length of the catenary when the pipe is laid in deepwater environments has led to challenges associated with the tension capacity of pipelaying vessels and their ability to withstand the bending stresses that might result in collapse or buckling. The tension capacity of current vessels significantly limits how deep pipelines can be laid; as such, water depths are currently capped at about 3,048 m (10,000 ft) for traditional steel pipelines. To go beyond 3,048 m, new installation techniques, increased tension capacities from lay barges or alternative materials will be required. Once installed, deepwater and cold-climate pipeline operators face challenges of flow assurance due to the formation of hydrates or plugging from wax deposition.

Industry News The design, manufacture and supply of the workscope will be carried out by Proserv’s specialist engi-

Pipelines operating in frigid climates such as off the coasts of Nova Scotia, Alaska and the Arctic face extreme storm conditions that can affect their structural integrity and floating icebergs, which can result in mechanical damage, particularly to their risers. There are ways to mitigate these potential risks: Pipelines can be buried beneath the seabed or covered with protective concrete “mattresses,” and rigid steel risers or catenaries can be replaced with flexible risers that are designed to disconnect from FPSO units when floating icebergs approach or when extreme storm events threaten. However, pipelines situated in deepwater or remote areas both face challenges associated with a lack of supporting infrastructure. Each engineering project will have its own specific challenges which, to manage costs and maximize environmental performance, are best addressed in a holistic manner throughout the design, installation, operations, life-extension and decommissioning stages. New technologies Some new technologies that have been implemented in deepwater fields include subsea boosting and processing. These technologies have allowed many reservoirs to be more economically developed while reducing the risks of damage to assets from adverse weather conditions on the surface. Subsea boosting provides the pressure needed for the risers to transfer production fluids from the reservoir to the surface, thereby increasing the recovery volumes from mature wells and making viable the production of fields that might have been previously considered marginal. To support asset-integrity management programs, the industry is exploring the use of AUVs, which are docked and recharged subsurface to perform routine visual inspections, freespan pipe monitoring and cathodic protection surveys that detect erosion. In some cases, AUVs could replace current ROVs and their support vessels, potentially reducing cost and improving integrity-management practices and maintenance activities. Advancements in data analytics also are playing an increasingly important role in the integrity management

of pipelines. They are giving operators better visibility of the operating health of subsea pumps and the fluids produced in subsea processing facilities as well as helping to monitor the condition of the pipeline, including the use of leak-detection systems. Pipelines, too, are undergoing a technological evolution with composite pipes rather than reinforced thermoplastic pipes. The reinforcing fibers are embedded in the composite matrix, resulting in a solid pipe wall, whereas in a reinforced thermoplastic pipe the fiber reinforcement “rovings” (tapes) are wound around the liner pipe. This advance produces a collapse-resistant pipe that can operate at a wider range of temperatures. It is also less brittle and therefore more flexible and is less susceptible to the problems associated with sour service operations and corrosion. Another exciting emerging technology is the use of “additive manufacturing” for fabrication of subsea equipment. Since deepwater processing facilities require thick-walled vessels to contain pressure, equipment such as gravity-based separators have become very large and difficult to transport when fabricated using solid steel plate. These advancements have been enabled by significant innovation in materials (e.g., metal and thermoplastic powders, wire, resins and composite materials) and binding sources (e.g., laser melting, electron beam melting, photopolymerization and chemical reaction). One of the related short-term opportunities for the subsea industry appears to lie in the ability to rapidly generate or repair often-replaced or obsolete components from aging assets. But just as additive manufacturing offers an opportunity to customize materials, these variations from solid materials can compromise the structural integrity of an asset in ways that would be new to the industry. Clearly, a deeper understanding of the benefits and barriers to adoption is required. Meet the company’s experts at OTC 2016 at booth 5171 or visit lr.org/energy for more information. n

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neering and project teams in Stavanger, Norway. Work already has begun on the manufacturing of these sys-

tems and all five are expected to be delivered to Statoil by 2017. The agreement comes just months after Proserv was awarded a contract to provide topside control equipment at one of the largest field discoveries on the Norwegian Continental Shelf. Proserv is supplying Aibel, on behalf of Statoil, with a HPU and three chemical injection panels for the Johan Sverdrup development’s drilling platform. Seagull Oil & Gas Offers Safety Training Seagull Oil & Gas has released a cost-efficient and comprehensive e-learning training package in the industry for offshore personnel working in explosive atmospheres. Building on International Electrotechnical Commission standards, the new series covers basic understanding, installation in Ex-areas, Exi installation, cable entry, IP degree, and inspection and maintenance. The content of the courses includes e-learning modules that normally require two days of classroom study covering theory. ExTek, the only certified CompEx center in Norway, will offer the self-study course components so that an entire five-day 01-04 CompEx course can be completed with only three days spent in the classroom. n

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TUESDAY | MAY 3, 2016 | OTC SHOW DAILY

Industry Improves Monitoring of Offshore Rig Corrosion, Onshore Pipeline Leaks n Advances in monitoring systems allow inspection of rigs and FPSO units while offshore and detection of leaks in onshore pipelines. Enhancements in materials have led to fully dissolvable frack plugs. These topics and more will be covered in Tuesday’s “Materials Advancement” technical session. BY SCOTT WEEDEN

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orrosion and leaks can lead to catastrophic failures in both offshore vessels and onshore pipelines at considerable cost. The “Materials Advancement” technical session on Tuesday morning at OTC tackles those problems as well as the development and manufacture of dissolvable frack plugs. Three of the six papers scheduled to be presented at the 9:30 a.m. session tackle the latest advances in these topics. This is a preview of those three papers. Hull inspection techniques, strategy project Hull integrity is critical for FPSO vessels and mobile offshore drilling units. The Hull Inspection Techniques and Strategy joint industry project focused on the methodology for conducting inspections while still at sea. The OTC-26953-MS paper describes how close cooperation between regulators, operators, class societies and service providers resulted in underwater hull inspect in lieu of drydocking (UWILD). The key features of the diverless UWILD strategy includes conducting inspections from inside the hull and using advanced closed-circuit television methods to inspect isolation valves as well as inspecting hull appendages using mini ROVs. This new “continuous survey” method aligned underwater inspections with planned tank entry to provide better information, reduce and spread costs and provide planned scopes that helped avoid budget overruns. These new methods deliver enhanced safety, reduced cost and lower budget risk. Two FPSO units and four ultradeepwater drillships have been successfully inspected. About 12 vessels are scheduled for inspection in 2016. Onshore leak monitoring A pipeline leak and impact detection system, PipeLIDS, uses acoustic technology to listen inside onshore pipelines. Hydrophone sensors are installed typically every 10 km (6 miles) along the pipeline. Cybernetix, a Technip company, developed the system limit false alarms and improve the level of confidence in the results. Any leak is a noise source. The noise propagates in the fluid in the pipeline over long distances. With an appropriate data processing technique, the noise related by

See MATERIALS continued on page 20

OTC SHOW DAILY | MAY 3, 2016 | TUESDAY

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Metering Pumps Provide Versatility, Flexibility to Offshore Operators n Metering pumps offer modular design options including motor configurations, multiplexing

and liquid-end variations that can reach required depths and withstand high pressures. CONTRIBUTED BY MILTON ROY

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n most gas condensate wells, natural gas hydrates form when light hydrocarbons and water mix under high pressure and low temperature. Hydrates restrict flow that could block production and damage equipment. Typically, preventing hydrate formation is mitigated through methanol injection at extremely high pressures. This operation requires an efficient delivery method while ensuring accuracy and safety. Deepwater chemical injection Metering pumps accurately control the dosing of chemicals including methanol. While metering pumps are relatively small components on a production platform, they perform a critical role. If flow assurance chemicals stop flowing for any reason, production can come to a halt. In deepwater production operations, beyond the ability to deliver these chemicals thousands of feet deep, they also need to extend far below the seabed, where backpressure can measure five to seven times greater than the pressure on the seafloor. The pumps must be powerful enough to deliver reliable fluid flow to the required depths efficiently to ensure hydrate inhibitors reach the wellhead with minimal leakage. Power and performance is important, but it cannot come through tradeoffs in efficiency. Electrical energy is a precious commodity in offshore environments that must autonomously produce their own electricity so any pump used must be efficient. In addition, to accommodate different operator production and structure requirements, the modularity of the pump design is key to enable customizable configu-

rations to maximize performance while minimizing its operating footprint. Case study An operator was working to produce several gas condensate wells offshore Indonesia that were at depths up to 975 m (3,200 ft). When the operator for this project selected metering pumps, they considered all of the factors: power, accuracy, efficiency and reliability. They also needed flexibility, and sought out a modular design that could include different liquid-end options. They required variable stroke length and adjustable flow capabilities to address the wide range of chemicals required at the job site. After a comprehensive evaluation, they chose Milton Roy’s Primeroyal metering pumps because of its modular design options including motor configurations, multiplexing and liquid-end variations that could reach the required depths and withstand the pressures. Primeroyal pumps can accommodate flows up to 16,000 gal/hr and pressures up to 20,000 psi. At the customer’s request, the pumps were fitted with Milton Roy’s latest Packed Plunger NX Liquid End, which is specifically designed to reach higher pressures and higher flow rates. The NX Liquid End is best suited for projects where net-positive inlet pressure is an issue. The liquid end is designed to handle temperatures as high as 315 C (600 F), with pressures up to 1,000 bar (14,504 psi). As a result, the metering pumps were modified per the operator’s specifications and tested to ensure zero external leakage for up to 20,000 hours.

Primeroyal metering pumps can accommodate flows up to 16,000 gal/hr and pressures up to 20,000 psi. (Photo courtesy of Milton Roy)

Conclusion Metering pumps aid in critical process control of high-pressure methanol injection. The safe, efficient and reliable delivery of these chemicals is amplified in an offshore environment, and these factors should be at the top of the list when designing metering pump systems. For more information on Milton Roy’s technology, visit OTC booth 2765 or go to miltonroy.com. n

‘Less Is More’ Is Inspiration for Industry in Current Era n Turrets: determining the ‘must haves’ vs. ‘nice to haves’ in the low

oil price era. BY PHILIPPE LAVAGNA, SBM OFFSHORE

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s the major players pay even closer attention to project economics due to rising costs and plummeting oil prices, project viability becomes riskier and breakeven is often a moveable target. According to the Financial Times, “Companies have shelved more than a trillion dollars in investment plans.” In recent years, the complexity of a project is the major variable in the cost equation, and it is the turret that represents a significant part of the total investment for an FPSO or floating LNG unit. This is for many reasons including the bespoke nature required for harsh environments and the fact that the turret hosts the subsea equipment acting as the heart of the interface—a factor which dictates the complexity. The bottom line is that turret costs have risen due to complexity, while simple fields have been overlooked in the hunt for more productive and profitable but more challenging fields. Is there a way for turrets to be simplified and significantly reduce their cost? Yes. Less can be more. Advocating going back to basics, SBM has designed and engineered the world’s largest and most complex turrets for Shell’s Prelude and BP’s Quad 204, and said less challenging fields will become more attractive to the oil and gas majors because the capex is less by keeping it simple. New paradigms need to be found, and this is when a service provider like SBM Offshore can dip into its

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comprehensive range of turrets to find the best and least expensive solution. The company’s portfolio offers a range from A to Z—from top-end mooring solutions such as for Prelude and Quad204 to the other end of the scale such as the turret for floating, storage and offloading unit Ruby—where low complexity can mean a simple and safe turret mooring system with a basic level of functionalities. In a $100/bbl market the net present value equation is optimized by completely different parameters than in a $30/bbl to $40/bbl market where the delta revenue of the highest production uptime is no longer able to justify the delta LCC (i.e., capex and opex) of the more complex asset (vessel) required to achieve such a maximized production uptime. When well designed, less complexity and equipment does not compromise safety. Less equipment reduces the probability of equipment failure and reduces both capex and maintenance costs. Less maintenance also means fewer people exposed, which is another way to improve safety. Less capex/opex can mean more projects becoming economically viable. SBM Offshore has followed the path of increased complexity to match the target of highest uptime. However, its history harks back to simpler turrets. The company’s various sets of expertise mean that the “back to basics” concept is actually a reality now by using existing SBM Offshore products. Simple does not mean easy, and it is as a result of its expertise in the complex that SBM Offshore has perfected and optimized its

The world’s largest turret was designed and engineered by SBM Offshore for Shell’s Prelude. (Image courtesy of SBM Offshore)

See INSPIRATION continued on page 22

TUESDAY | MAY 3, 2016 | OTC SHOW DAILY

Life-of-Asset Advisory Solutions Help the Bottom Line n When budgets continually shrink, it’s time to cut costs, not corners. BY MANOJ NIMBALKAR AND OSCAR RIVERA, WEATHERFORD

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imple one-off cost cutting will no longer suffice in the current economic climate. Now is the time to find systemwide efficiencies throughout the life of a well and reservoir. The Weatherford Advisory life-of-asset solution series brings together hard science, proven processes, technical expertise and technologies to deliver intelligent solutions for oilfield challenges. The series, which includes the Drilling Advisor, FracAdvisor, Production Advisor and Well Abandonment Advisor products, delivers sound engineering strategy and technologies for any asset at any stage of development.

asset modeling, production management, digital-oilfield execution and field rejuvenation. The process begins with an integrated asset model that monitors the flow of gas, oil and water from the reservoir to surface facilities to the point of sale, which enables accurate production forecasting. The asset management team can then focus on real-time production management using the i-DO software platform. As the asset reaches maturity, this detailed knowledge about trapped oil provides guidance on the most cost-effective production rejuvenation methods as well as the overall investment strategy. See ADVISORY continued on page 20

The Weatherford Advisory series provides solutions for the life of the asset, from drilling to completion to production to abandonment. (Image courtesy of Weatherford)

Drilling By providing engineered well delivery, Drilling Advisor improves drilling performance and hazard avoidance. Each well—offshore, deepwater, conventional or unconventional—presents unique drilling challenges that can lead to kicks, losses, stuck tools and nonproductive time (NPT). Drilling Advisor brings a scientific approach to early prediction of well behavior by analyzing historical data to create a robust predrill plan and then performing real-time monitoring and dynamic modeling to reduce NPT. The proprietary software platform enables integration across the drilling process to deliver drilling optimization, wellbore stability and drilling hazard management. Once the well is brought safely to total depth, Weatherford experts provide a post-drill outline of successes and lessons learned, which can be applied to future wells. Drawing from best practices and drilling technologies, Drilling Advisor brings expertise to reduce uncertainty and improve the safety and efficiency of the drilling program. Hydraulic fracturing service This service delivers geoengineered well placement and completion designs optimized to the individual well and overall reservoir. Because completions often consume 60% of the budget in horizontal wells, efficiency in this area is especially critical. Through the integration of hydraulic fracturing, completion and formation evaluation technologies, the FracAdvisor service improves well productivity and hydrocarbon recovery in unconventional plays. This integrated approach uses proprietary, basin-specific algorithms to create the optimal stage, perforation cluster and frack designs, all of which are validated with production results from nearby wells. Engineers then determine perforation and/or packer placement decisions alongside stage-by-stage fracture modeling. Leveraging efficient completion tools, the service enhances life-of-well production by improving completion efficiency, optimizing production rate and recovery, and reducing overall completion costs. Production By accurately forecasting, monitoring and managing production, the Production Advisor delivers proactive and integrated asset management. Depending on the type and maturity of the asset, each customized solution can include integrated

OTC SHOW DAILY | MAY 3, 2016 | TUESDAY

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DRU Provides Density, Rheology Data at Far Greater Frequencies n The DRU can be added to any drilling program to help increase efficiency, reduce risk and communicate

performance of drilling projects. CONTRIBUTED BY HALLIBURTON

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utomation and real-time measurement capabilities can help operators more effectively manage drilling projects. Accurate drilling fluids data are critical to maintaining a stable wellbore and successfully drilling to total depth. Manual mud checks by fluids representatives at the rig site take considerable time, and data can potentially be up to 24 hours old. This gap between datapoints brings an opportunity for improvement. Frequent and accurate data collection can help provide a better picture of current fluid conditions in the wellbore and allow operators to make more informed decisions at a faster rate. Halliburton Baroid has developed a product to capture and analyze real-time fluids data. The BaraLogix Density & Rheology Unit (DRU) is a combination of density and rheology measurement capabilities in a single, modular package that allows real-time measurements combined with trending analysis that is autonomous and highly visible to the well construction team. The BaraLogix DRU can be added to any drilling program to help increase efficiency, reduce risk and communicate performance of drilling projects. The BaraLogix DRU also was awarded the 2016 OTC Spotlight on New Technology Award. Automating routine fluid property tests helps enable

fluid technicians to focus on more critical rig site responsibilities and can help allow operators and fluids specialists to take a more proactive approach to managing drilling operations. The BaraLogix DRU can provide highly accurate density and rheology data at frequencies far greater than manual mud checks. The ability to feed data to realtime hydraulics simulation software can help operators streamline decision-making, so adjustments to drilling parameters for increased efficiency can be executed faster than with previously available technologies. Additionally, the data frequency and accuracy can help operators predict potential problems or detect issues with faster response times, and intervention steps can be applied to help reduce or eliminate nonproductive time (NPT). The BaraLogix DRU is engineered to handle up to 14 days of continuous autonomous operation prior to maintenance servicing. The modular design can be configured for ATEX and IECEx Certification, so the unit can be placed near the mud tanks for easy installation. Data accuracy is critical, and the BaraLogix DRU has proven its capabilities in the laboratory, in liquid mud plants and through rig deployments. Six-speed rheology measurements can be captured every 15 minutes with accuracy within 1.5 dial readings of the industry-recognized FANN 35 rheometer. Density readings can be taken every minute with accuracy within 0.1 ppg of a

pressurized mud balance. Data captured by the BaraLogix DRU can be monitored remotely through the use of the Halliburton InSite Anywhere platform to help communicate performance across the drilling team and provide additional project oversight. In the Gulf of Mexico, a major operator recently used two BaraLogix DRUs to help monitor and maintain fluid density and rheology on a technically challenging deepwater well. Active monitoring of the data stream allowed the fluids engineers to make smaller, more frequent adjustments to maintain proper formulations. The operator was able to reduce fluid dilution rates and save about 143 bbl of base oil, resulting in net cost savings of about $22,868. The BaraLogix DRU provides new capabilities to help operators manage fluids properties in real time. The automated data collection helps identify trends in the drilling fluid properties that were unavailable with previous rigsite resources. Drilling performance and efficiency can be optimized through recognition of changes in the drilling fluid, analysis of the data trends and appropriate fluid adjustments in real time. This can help operators reduce NPT and return significant cost savings. The BaraLogix DRU can be added to any drilling program and offers measurable benefits for technically challenging wells, deepwater applications, offshore shelf and extended-reach projects. n

ditions and at 16 km (9.6 miles) in high noise conditions in the pipeline.

mechanical tests were conducted to determine the correct material composition and verify manufacturing quality. The complete dissolution of the frack plug eliminates the need for a separate mill run intervention, which helps reduce cost, operation time and risks to personnel. For a complete list of session papers and authors, see the daily technical program lineup at 2016.otcnet.org. n

MATERIALS (continued from page 17)

the leak is extracted from the global ambient noise in the pipeline, according to the OTC-27026-MS paper. By measuring the amplitude and phase-time shift of the sound waves and analyzing the acoustic signature, the system detects the origin and location of the leak and sets off an alarm. The paper presents the latest technical improvements on the acoustic sensors and software on the PipeLIDS that was installed on the Societe Pipeline Sud Europeen’ Fos-sur-Mer diesel pipeline in France. A leak was simulated in the pipeline by a ½-in. valve opening during commissioning. The simulation showed that the pressure surge of opening and closing the valve could be detected at 57 km (34 miles) in low noise con-

Dissolvable metal alloy for frack plug A high-strength metal alloy that is combined with a dopant allows dissolution of the alloy in water-based wellbore fluid, formation fluid or production fluid, according to the OTC-27187-MS paper by Halliburton. The cathodic dopant creates a galvanic reaction with the base metal and causes the base metal to degrade. The degradable metal is created by adding a dopant to the base metal while both materials are in a molten or near-molten state. The solid solution is a familiar foundry process. More than 450 dissolution tests and more than 400

ADVISORY (continued from page 19)

Assessing the reservoir and surface characteristics in real time, Production Advisor effectively enables operators to extend the economic life of their asset by reducing the total cost of production. Well abandonment A combination of technologies and project management delivers effective and compliant well abandonment. As wells reach the end of their economic life, proper plugging and abandonment can safely and permanently mitigate any adverse environmental impact. Through a combination of specialized technologies, proprietary models and project management, the Well Abandonment Advisor manages the complete project, from scoping to regulatory filing to rigup and close-out. A phased approach produces an effective risk-management and compliance-adherence strategy that identifies potential issues before work begins. This reduces the risk of scope creep and helps to ensure the job is done safely, on time and within budget. Beyond software, technologies The advisory series goes beyond proprietary modeling tools, products and services. Rather, these tools provide a means to engage clients in a collaborative relationship that informs a deeper understanding of each asset, reduces total asset ownership costs and meets client production goals on time and budget. n

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TUESDAY | MAY 3, 2016 | OTC SHOW DAILY

Service Provides Worldwide Coverage of 250-plus Offshore Projects n Live demonstrations of the new service will be held at OTC booth 3217. CONTRIBUTED BY STRATAS ADVISORS

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xperts from Stratas Advisors will host live demonstrations of the company’s new Global Offshore Projects Service at OTC. Attendees can stop by booth 3217 at Houston’s NRG Center. Seats can be reserved for the demonstrations by registering online. The Global Offshore Projects Service provides worldwide coverage of 250-plus offshore projects, with a focus on recent and future developments. The web-based application includes multiple economic measures throughout the project life cycle, analysis of publicly announced E&P projects and detailed fiscal models by country. The transparent modeling shows calculations, adjusts the assumptions as desired and analyzes the results. The amount of investment required for global offshore projects makes for high risks. Stratas Advisors’ valuable resource enables industry professionals to make more informed business decisions.

Who Benefits From This Service?

How Do They Use It?

Strategy teams at E&P companies, including integrated oil companies and national oil companies

Eliminate opportunity costs

Financial analysts at E&P companies

Use scalable, comparative data to make optimum business decisions

Business development managers at E&P companies

Accurately evaluate the economics of potential projects

Senior management teams at E&P companies

Compare planned projects to completed projects in the same field

Executives and analysts at oilfield service companies

Understand expected offshore drilling activity and who is spending money where

Executives and analysts at engineering, procurement and construction companies

Get a view toward expected capital spending on different types of fixed and floating platforms and vessels

Executives and analysts at institutional financial service firms

Analyze the relative exposure that different companies have in the offshore markets

“Our Global Offshore Projects Service gives a quick view of the key offshore projects around the world vying for discretionary capital budgets,” said Paul Morgan, executive director, upstream, at Stratas Advisors. “It’s a key resource to help companies get a gran-

ular and ‘big picture’ understanding of the competitive offshore landscape.” Stratas Advisors experts are available to answer questions and can offer insights to the energy industry. For interview opportunities, contact [email protected]. n

creation either through accelerated production and/or increased recovery. Involve a multidisciplinary team and use integrated simulation tools to evaluate subsea separation systems in early phase of project development. Develop a long-term development and commercialization strategy to lower the life-cycle cost of components, assemblies and systems. Consider qualification of components/systems over a wide range of operating conditions so as to avoid bespoke solutions that are costly and require extensive qualification. In addition, reuse qualified technology from previous designs where applicable. Promote standardization of physical interfaces (topsides, umbilical, subsea), equipment configuration (size, performance, layout), FEED solutions and qualification protocols, while allowing

innovation in the market place to bring about needed technical improvements. Rune Fantoft, CEO of Fjords Processing (formerly Aker Solutions), stressed the importance of focusing on the creative and attractive field development solutions, especially in the volatile environment like this. He addressed the obstacles that block simple and reliable solutions and optimize packages. There is technology out there, but it’s time to focus on the application of the technology across all disciplines, he said. n

For a complete list of session papers and authors for the “Decommissioning and Well Abandonment: Case

Studies and the Technologies Involved” technical panel, see the daily technical lineup at 2016.otcnet.org. n

PERSPECTIVE (continued from page 4)

Speaking of challenges from an operator’s perspective, Jeff Jones, senior adviser for subsea systems at Exxon Mobil, indicated that it’s a limited uptake across operators who are focused on low project capex, especially in this particular environment. Pull from senior leadership is necessary to see the “bigger picture” of subsea processing, including separation, and to unlock tremendous potential in deepwater, long distance tieback and arctic developments. He indicated that there are opportunities for improvement and that separator systems must be “custom designed” for reservoir suitability, field layout and topsides support. But it’s time to move forward to overcome any market situation. Jones indicated in a positive note that individual project business cases must focus on value

Dr. Phaneendra Kondapi is director of subsea engineering at Texas A&M University and an adjunct professor of subsea engineering at University of Houston.

MINIVAN (continued from page 10)

“The traditional method is what I like to call the ‘minivan’ model,” he said. “It’s very slow but gets the job done.” He highlighted in his talk a forecast conducted in January 2011 by an independent operator needing to decommission its idle iron inventory of 245 wells and 93 structures over a five-year period to be $409 million using the traditional methods. “That’s very expensive for a mid-size operator,” he said. “We had to look for something different. We needed a new idea.” That idea came in the form of a new optimized decommissioning methodology that employed the size and capabilities of a newly designed and constructed 335’ class self-elevating, self-propelled liftboat. The new boat provided the space and lifting capacity necessary to perform the majority of the work steps concurrently—rather than sequentially—and in just one spread mobilization. “This change from the traditional minivan approach is what I call the Ferrari method,” he said. “It is sleeker, faster and allows us to get more done in less time.” According to Siems, over a 30-month period the new concurrent model resulted in 140% more wells and structures being removed over the number expected to have been removed using traditional methods. Using the optimized method, decommissioning costs were reduced to $278 million, he said.

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A Total Mooring Solution n Faster mobilization and reduced drilling costs are key to operations. CONTRIBUTED BY GLOBAL MARITIME DEEP SEA MOORING

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he global offshore mooring industry is facing significant challenges as it seeks to balance the increasing complexity and remoteness of offshore developments with the need to manage expenditure in today’s cost-conscious environment. With every day a rig is in transport being a day lost to drilling, faster mobilization and reduced drilling costs are key to operations. At the same time, all operators must continue to operate to the highest standards of safety and asset integrity. It’s against this backdrop that operators and drilling contractors are looking to a total mooring solution that includes everything from pre-lay and pre-rig advances through to the very latest in anchoring, buoyancy units, fiber mooring rope, swivels and more. One such provider is globally positioned Global Maritime Deep Sea Mooring, which offers a comprehensive portfolio of offshore mooring services from pre-lay and rig move solutions through to marine engineering and mooring equipment rental. In March 2015, Deep Sea Mooring put its total mooring proposition to the test in securing a turnkey contract for the provision of mooring and rig positioning services to an Australian oil and gas operator. The contract represented the first time all four sister companies of Global Maritime have been involved in an Australian operation. As well as Deep

Sea Mooring, this included Global Maritime Vryhof, a pioneer in anchoring; Global Maritime MoorLink, which focuses on mobile, permanent and installation mooring solutions; and Global Maritime Consultancy and Engineering, a marine, offshore and engineering consultancy. Mooring services were provided for a semisubmersible drilling unit. Accompanying challenges included the need to navigate around existing subsea infrastructure such as pipelines, wellheads and umbilicals as well as the fact that the drilling unit would be in operation during cyclone season. Deep Sea Mooring designed, engineered and supplied an advanced 12-point mooring system with the initial installation consisting of 12 prelaid anchors that were set and tension tested prior to the arrival of the semisubmersible drilling unit. The total mooring solution, when the rig was operational, consisted of eight 1,750-m (5,741-ft) mooring lines—a combination of chain, synthetic fiber rope, rig chain, subsurface buoys and the relevant jewelry for connection; four storm mooring lines at 1,930 m (6,332 ft) to ensure maximum stability during the cyclone season (outside cyclone season only eight mooring lines were used); high-strength MoorLink swivels that were used to relieve the twist and torque that builds up in the mooring line; and 20-ton mK5 StevShark anchors from Vryhof, which facilitate performance in challenging soils. In this case, the mud line consisted of very silty sand (silt) and the formation sandy clay/silty clay.

Global Maritime’s sister company Deep Sea Mooring carried out an operation offshore Australia last year, designing, engineering and supplying a 12-point mooring system for a semisubmersible rig. (Photo courtesy of Global Maritime Deep Sea Mooring)

Deep Sea Mooring’s Advanced Distance and Positioning System (ADAPS) and Device Tracking and Control Systems (DTAC) also were used. The ADAPS helped attach the anchors prior to deployment, ensured that the anchor landed in the required position and provided the pitch and roll of the anchor along with the depth of penetration—vital when placing anchors in close proximity to subsea structures (as was the case here). The DTAC provided desktop tracking and buoy position monitoring prior to the rig’s arrival. For further information, visit the Global Maritime Vryhof at OTC booth 2233. n

INSPIRATION (continued from page 18)

back to basics turrets—offering unique and added value. Focusing efforts on the essence of simple and robust, passive weather-vaning mooring systems, it provides mooring solutions ideal for the low oil reality with no compromise on the HSSE commitment. Key to cost control is early engagement with the client to allow a review of the project and to assist the client in discriminating between the “must have” requirements and the “nice to have” items that add cost. Armed with the knowledge of what is required for each level of functionality, so the specification can be optimized for today’s new set of project constraints, SBM Offshore can leverage its know-how across complex to simple mooring systems along the engineering, procurement, construction and installation

(EPCI) chain to propose the best solution—not necessarily a complex solution—for a specific project. Cost savings and optimizations can be made at each stage: • Engineering: avoid recalculating to optimize a specific project by using standard and field-proven solutions. • Procurement: benefit from more standardization by using a functional specification rather than enforcing more demanding and more costly specifications. • Construction: the optimum scenario is when the client adopts a hands-off approach on the execution of this stage allowing the contractor to leverage its expertise while both the client and service provider jointly focus on the HSSE and QA/QC performance

of the project. Plus, less equipment/complexity means a faster construction stage with inherent cost and schedule savings. • Installation: this needs to be considered from the beginning (integrated at the engineering phase) and therefore the most cost-efficient and safe way is to include the installation scope in the mooring system contract (i.e., EPCI instead of EPC). Finally, in the execution of the project if less bureaucracy is married with more human interface, past projects by SBM Offshore have shown that this strategy clocks up less man-hours and more added value. The principles of standardization (stream lining work alongside a lean management) are a must for the sake of project economic viability. Keeping an open mind to trust the contractor to keep it simple (when possible) and safe (always) rather than imposing a prescribed specification will open up possibilities. n

International Attendees: Meet and Relax at OTC The International Lounge offers international visitors a place to visit and network during OTC. Multilingual members of the National Oil Equipment Manufacturers and Delegates Society (NOMADS) and the members of the Society of Petroleum Engineers (SPE) Gulf Coast Section Auxiliary are available to provide assistance with information regarding Houston-area shopping, restaurants, museums, theaters and emergency medical appointments. The International Lounge is located in NRG Center, level 2, room 700.

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TUESDAY | MAY 3, 2016 | OTC SHOW DAILY

DOWNTURN (continued from page 1)

“It has helped our rig teams in Egypt complete six of the best wells ever in the Nile River Basin,” he said. With climate change accords and greater use of alternative energy, the oil and gas industry needs to distance itself from the turbulence of the commodity market. Though alternative energy sources make up a small portion of overall energy production, each year it’s seeing the kind of improvement that E&P companies dream about. Looney said the cost of onshore wind electricity generation has been cut in half since 2009. In a similar time frame, the cost of solar manufacturing has fallen about 75%—and by 99% since 1976. Battery costs are on the same downward trajectory. Lithium ion batters used in electric vehicles are projected to drop 77% between 2010 and 2018. “The Tesla Model 3 will go over 300 more miles [483 km] on a single charge,” Looney said. Like their manufacturing cousins, oil and gas producers cannot be satisfied or stop challenging themselves at every step. “There’s a reason we still talk about Henry Ford 100 years on from the Model T,” he said. Over time, perfecting the company’s assembly line meant Ford could build a car in 90 minutes, instead of 12 hours. “We already have an example of how to do that here in the onshore in Texas and across the Lower 48,” Looney said. Despite the Lower 48 rig count vaporizing by roughly 80% to about 400, production is close to what it was when the downturn began in earnest in November 2014. The shale revolution has been about breakthroughs and technological responses that have helped maintain productivity. “In just a few years, our own Lower 48 business in BP has seen a 60% reduction in the development costs of the wells we drill in the San Juan Basin,” he said. Energy forecasts suggest that by 2035 demand will increase by one-third. Before then, the price of oil will doubtless see more cycles. Continuous improvement seems to evaporate in the good times, Looney said. As prices improve, the industry will need to hold fast to a philosophy of improvement and innovation or it will suffer again. “We need to hold onto this even when the oil price recovers,” he said. “That is when the true test will come.” n

“Most of the wells are intelligent completions, and the whole process involves eight producers, five water-alternating-gas (WAG) wells, two subsea manifolds and one gas injector well,” Cruz said. As detailed in an OTC paper about the project, the reservoir data acquisition and drainage plan studies provided guidance on artificial lift, flow assurance, gathering system and fluids processing concepts. A downhole fluid sampling and laboratory experiments program was established to “identify critical aspects of flow assurance, such as wax, gelation, hydrates, asphaltenes and inorganic scale.” There were also challenges with the gathering system, considering “there were no off-the-shelf proven technologies that could handle this amount of contaminates, at this water depth and pressure,” Cruz added. The strategy was to run a design competition to find solutions, Cruz said, targeting seven major prequalified subsea providers. The winning proposal, he said, had two submerged buoys for riser support. The proposal also included eight buoy foundations, 16 tethers, 15 catenary risers ending up with pipeline ends terminations, production clad lines and gas injection lines (steel catenary risers) and riser anchoring piles.

To reduce costs and gain flexibility, standardized christmas trees were incorporated into the well design. The design also included two WAG injection manifolds, which lowered the number of injection risers. However, the greatest risk of the project was the subsea construction, gathering system and installation, Cruz said. Subsea system fabrication delays prompted the consortium, which included BG E&P Brasil and Petrogal Brasil, to use flexible risers to connect the first producer well to start up the FPSO unit as scheduled. Other delays forced changes in the drilling campaign, adding value to the importance of having contingency plans. But installation of FPSO Cidade de Paraty was quick. Completing such a large fast-track while developing new technology required putting focus on key information, Cruz said. The first well was drilled in 2009, and first oil was reached in 2013 with plateau production hit in 2014. “We work in a risky business so there will always be uncertainties,” he said. “It’s a matter of strategy” and finding key information. Companies involved also set up what Cruz called a “war room” to enable fast decision-making and communication among stakeholders. n

CHALLENGES (continued from page 1)

But the mission was accomplished as Rafael Cruz, reservoir engineer for Petrobras, explained during a technical session on overcoming challenges on Rafael Cruz offshore field developments. In February 2015, production reached 950,000 bbl/d of oil and hopes are to reach the 2017 target one year ahead of schedule. “Lula has successfully met its business objectives so far. First oil was only nine days away from the three-year milestone,” Cruz said, adding a new subsea concept was developed and the FPSO unit is currently producing at its maximum capacity. One of the goals of the project was to gain presalt experience through data acquisition, Cruz said. Work included two seismic acquisitions, including a high-resolution one, along with a drillstem test program, extended well tests and an interference test along with production logging tests, fluid samples, special fluid analysis, large computer cluster and people to get the work done.

OTC SHOW DAILY | MAY 3, 2016 | TUESDAY

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