OTC14 Wednesday Lr

initiative encouragescollaboration for successful eoRn As ultradeepwater fields mature offshore Angola, an operator seeks new methods to extend production.

When Total began to see production wane for the firstof its deepwater megaprojects in Block 17, located

offshore Angola, it had some important decisions to make.Block 17 is the French supermajor’s principal productionasset in Angola and represents one of its largest investments.

Finding a way to maximize production once the wellshit their plateau and then keep them producing beyondtheir typical lifespan has become a top priority for thecompany. Just how to go about this delicate endeavor wasthe topic under discussion at Monday’s topical luncheon,“Deepwater Brownfields: Yes, We Have to Tackle It RightNow,” presented by Pascal Carrier, vice president of proj-ects for Total E&P Angola.

Block 17 comprises four major zones: Girassol, Daliaand Pazflor—all of which are currently in production—

and CLOV, the latestzone set to be completedfor production this year.Once Block 17’s fourthFPSO unit is in produc-tion, it can produce160,000 bbl/d. In themeantime, older FPSOvessels such as the oneat Girassol, which cameonline in 2001, havebegun to decline.

“An FPSO is designedto produce for 20 years generally and, aer this period,we can extend the life for five to 10 years maximum,”

By aMy Logan

By JenniFeR PResLey

Questions are like opinions in that everyone hasthem and rarely are either in short supply, espe-

cially in the oil “bidness.” e task of finding answersto some of the big questions—like possible U.S. en-ergy independence and the growth or shrinkage ofmarkets—falls to economists. ese modern-daysoothsayers consult not tea leaves but their less-exoticspreadsheets and reports for possible clues in fore-casting.

One such forecast—BP’s “Energy Outlook 2035”—is set to be the focus of a luncheon presentation to bedelivered on Wednesday, May 7, by Mark Finley, BP’s

general manager of global en-ergy markets.

According to Finley, the out-look reflects the company’s ef-fort to describe a “most likely”trajectory of the global energysystem, based on its views oflikely economic and populationgrowth as well as developmentsin policy and technology.

“Like the BP ‘Statistical Review of World Energy’—which will see the 63rd annual edition published laterthis year—we hope that the energy outlook will be auseful reference for those with an interest in the en-ergy industry and also governments, academia andthe media,” Finley said.

A lot can happen in a year, and the company ad-justed its views through this update of its year-old“Outlook 2030” report.

“By looking five years farther down the road, wewere able to see some interesting changes: India islikely to surpass China as the largest source of energydemand growth; renewable energy will no longer bea minor player, surpassing nuclear energy; and

discussing onshore unconventionals at anoffshore conferencen Different technologies are integral to deepwater and unconventionals. But in the future, the more common issue for both will be social license.

is onshore unconventional oil and gas and deepwaterdevelopment like oil and water?An eight-member panel tackled that philosophical de-

bate with an interactive electronic assist from the audi-ence during Monday’s OTC 2014 technical session.

e panel included representatives from Statoil,Marathon Oil, Shell, BP and Anadarko.

Rising volumes of unconventional oil are offsetting de-

clines in conventional oil and benefiting the domestic en-ergy balance in the U.S. While deepwater oil will add toconventional totals with large volumes from a smallnumber of wells, lead times remain daunting.

Meanwhile, lurking in the background is the issue ofsocial licensing, or the level of acceptance and approvala local community provides industrial endeavors.

“Getting it right in terms of public acceptance is actu-

Reading the Leaves,Casting forCluesn Energy demand is forecast to slowin China while demand increases forits southern neighbor, according toBP’s “Energy Outlook 2035.”

see initiative continued on page 37

see unconventionals continued on page 41

see demand continued on page 37

OTC2014SM

www.otcnet.org/2014 Wednesday, May 7 | Houston, Texas

| THE OFFICIAL 2014 OFFSHORE TECHNOLOGY CONFERENCE NEWSPAPER | DAY 3

Mark Finley

By RiChaRd Mason

Pascal Carrier

3oTC shoW daiLy | May 7, 2014 | Wednesday

sChedULeoF eVenTsSM

Wednesday, may 7

7:30 a.m. to 5 p.m. ...................................Registration

7:30 a.m. to 9 a.m. ...................................Topical/industry Breakfasts

9 a.m. to 10 a.m. ......................................Coffee

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

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

2 p.m. to 4:30 p.m. ...................................Technical sessions

3 p.m. to 4 p.m. ........................................happy hour

4 p.m. to 6 p.m. ........................................networking events: “innovations across

the Pacific Rim”

6 p.m. to 8 p.m. ........................................45th anniversary Celebration Concert

(doors open at 5:30 p.m.)

thursday, may 8

7:30 a.m. to 2 p.m. ...................................Registration

7:30 a.m. to 9 a.m. ...................................Topical/industry Breakfasts

7:30 to 3 p.m............................................energy education institute: Teacher Workshop

8:30 a.m. to 1:30 p.m................................energy education institute:

high school student sTeM event

9 a.m. to 10 a.m. ......................................Coffee

9 a.m. to 2 p.m. ........................................exhibition

9 a.m. to 2 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 Luncheon

2 p.m. to 4:30 p.m. ...................................Technical sessions

4 p.m. to 5 p.m. ........................................oTC Closing Reception

OTC2014editorial directorPeggy Williams

e&P Group managing editorJo ann davy

editor in chiefMark Thomas

executive editorRhonda duey

senior editor, drillingscott Weeden

senior editor, offshoreJennifer Presley

senior editor, Productionamy Logan

chief technical director,upstream

Richard Mason

associate managing editor, special Projects

Mary hogan

associate managing editor, e&PBethany Farnsworth

associate online editorVelda addison

assistant editorariana Benavidez

contributing editorsTerje Baustaddouglas Farley

Joel heinendavid hua

Bret MontaruliTom o’gallagher

Tom yost

Hart energy show dailycontributing editors

darren Barbeedeon daughertyCaroline evans

Joseph Markmanemily Mosererin Pedigo

corporate art director alexa sanders

senior Graphic designerJames grant

Photos bygary Barchfeld Photography

Production director & Reprint sales

Jo Lynne Pool

director of Business development

eric Roth

vice President, Group Publisher, e&P

Russell Laas

HaRt eneRGy lllP

President andchief operating officer

Kevin F. higgins

chief executive officerRichard a. eichler

The oTC 2014 daily is produced for oTC

2014. The publication is edited by the

staff of hart energy. opinions ex-

pressed herein do not necessarily

reflect the opinions of hart energy or

its affiliates.

hart energy1616 s. Voss, suite 1000

houston, Texas 77057713-260-6400

main fax: 713-840-8585

Copyright© May 2014

hart energy Publishing LLLP

oTC Celebrates 45th anniversary with Free Concertin celebration of oTC’s 45th anniversary, a complimentary concert will be held from 6 p.m. to 8 p.m. tonight,

May 7, at Reliant stadium. The concert will feature the Beatles tribute band “a hard night’s day.” enjoy a night of

networking and free entertainment. The first 1,000 attendees will receive a free drink ticket. additional drinks and

food will be available to purchase. The venue doors will open at 5:30 p.m., and parking lot and hotel shuttle

services will run until 8:30 p.m. to accommodate attendees leaving the concert.

Media from around the world enjoyed this view of the oTC 2014 show floor from the press room. (Photo by Joseph Markman)

4 Wednesday | May 7, 2014 | oTC shoW daiLy

Future of the uK continental shelfn Energy minister shares his views on the continental Shelf ’s future with luncheon attendees.

The U.K. Continental Shelf (UKCS), with more than 41Bbbl of oil and gas produced from it over the many years,

is one of the most mature basins in the world. As it and itsinfrastructure increase in age so have concerns regarding itsfuture. is future was the focus of an OTC topical luncheonheld Monday during OTC 2014 that featured the Rt. Hon.Michael Fallon, U.K. minister of state for business and energyand minister of state for energy.

Speaking to a nearly sold out crowd, Fallon said that gov-ernment has backed the industry from the start. He addedthat the development of the North Sea, since the passing ofthe UKCS act by parliament 50 years ago, has served as the“cornerstone for several generations,” and the industry is of“vital economic importance” to the country. Some 440,000

jobs are directly or indirectlytied to the industry, he said.e country also relies on theNorth Sea not just for jobs butto also “meet its energy needs.Even as we move to fulfill re-quirements to lower carboneconomy, we will still needlarge amounts of oil and gas.”

Reserves in the neighbor-hood of 24 Bbbl remain in thebasin, with the successful ex-traction of those remaining re-

sources a clear priority, he noted. “ere are challengesahead. It is a mature province, and the laws of physics meanproduction will decline,” he said.

e challenges facing the UKCS include an increasednumber of fields to more than 300, smaller new discoveries,marginal and interdependent fields and strong competitionfor aging infrastructure, he said.

To help fully realize the future potential of the oil and gasindustry, the government announced a review of U.K. offshoreoil and gas recovery and its regulation in June 2013, the finalreport of which was published earlier this year. is report—authored by Sir Ian Wood—concludes that the U.K. economycould receive about a $339 billion boost if able to recover anadditional 3 Bbbl to 4 Bbbl of oil and gas, Fallon said.

He added that the core recommendations from the reportinclude:

• Rigorous stewardship of remaining resources througha new, independent regulatory body and the oil and gasindustry;

• Stronger oversight by the new regulatorybody and development of a program ofchange and growth; and

• Greater collaboration by industry in areassuch as development of regional hubs,sharing of infrastructure and reducing thecomplexity and delays in current legal andcommercial processes.

Wood said in a release about the report thatthe country needs “to step up our game tomaximize the recovery of our hydrocarbonreserves and attract more investment.”

Industry’s engagement right from thestart, along with its willingness to imple-ment Wood’s recommendations was im-pressive, Fallon said. He added thatmaximizing recovery will require greatercollaboration on everyone’s part and that itis a common vision that is shared betweenindustry and government. n

Rt. hon. Michael Fallon

By JenniFeR PResLey

Fugro (booth 3721) is providingOTC 2014 attendees with details

about the new additions to their Gulfof Mexico (GoM) fleet: a new AUV,Echo Surveyor VII, and a new vessel,R/V Fugro Americas.

“Both the Fugro Americas and EchoSurveyor VII will join the fleet later inthe year,” said Melissa Jeansonne, vicepresident, Fugro GeoServices Inc.

AUVs are the ultimate choice of in-strument platform for deep sea and re-mote surveys. As well as providingimproved multibeam swath coverage, theEcho Surveyor VII will support the acqui-sition of sidescan sonar, sub-bottom pro-filer and CTD profiler data and will carryvarious environmental sensors.

With its tight turning circles thatgreatly reduce the time between surveylines, it will offer clients a wide rangeof features including an increase indepth rating to 4500 m.

e Fugro Americas is well suited forhigh-resolution geophysical surveysand seafloor mapping.

“At 193 [the Fugro Americas] is biggerand faster than our current vessels in theGoM, has more berths as part of our pur-pose-built design and is both quiet andfuel efficient,” said Jim Grady, asset man-ager, Fugro GeoServices Inc. “SOLASclassed, she is capable of undertakingseismic, conventional, AUV and geotech-nical surveys.” n

gulf of Mexico Fleet to grow


Pemex makes its casen An E&P executive at the Mexican national company details how the organization is changing to welcomeoutside investors to develop Mexico’s hydrocarbons.

The successful transformation of Pemex from a decen-tralized public entity into a state-

owned productive enterprise will be drivenby several key factors—including a healthydose of both competition and partnership,according to Gustavo Hernández-García,acting director for E&P at the Mexican na-tional company.

As Hernández-García spoke to a packedhouse during the Tuesday breakfast titled,“Mexico Energy Reform: Challenges andOpportunities,” during OTC 2014, he ex-plained that although the nation is well on itsway to opening the market to private invest-ment, there is still work to be done at Pemex.

e company, which is the only entitythat’s been able to develop hydrocarbons inMexico during the last 76 years, is undergo-ing a major transition from reforms that gotunderway in December. Sweeping changesby the Mexican government, some of whichare still in play during the multiyear process,are designed to permit foreign investmentinto the country’s energy market and openit to some competition. rough profit-sharing, production-sharing and licensingagreements, Mexico has high hopes for for-eign investment. Internationally, companiesare hoping to capitalize on opportunities toproduce the abundant resources beneathMexico, which include the Eagle Ford Shalegeology just south of the Rio Grande River.

Essentially, Hernández-García ex-plained, Pemex will be dedicated to explor-ing and producing for value.

“e change is a major overhaul forPemex,” Hernández-García said, adding thatthe chief goal for Pemex will be multifac-eted: to be the best investment option formonetization of Mexico’s hydrocarbons, toquickly transform into a competitor in anincreasingly technical environment and toobtain strategic partnerships.

An early step for Pemex leadership willbe to join the very competitive professionalmarket in which its top workers are paidaccording to the market established by the

industry, he said. e inclusion of competition will im-pact the hydrocarbon value chain, and it will generate a va-riety of changes within the company, including salary

changes for some of the company’s professionals.By deon daUgheRTy

gustavo hernández-garcía

see Pemex continued on page 33


Growing oil Production in eastern indonesian To meet production goals, increased technology and expertise are needed.

oil consumption in Indonesia is currently about 1.4MMbbl/d and is expected to increase to about 2

MMbbl/d by 2020. Of that amount Indonesia will be im-

porting 1.5 MMbbl/d. Because of that, Indonesia has avery aggressive plan for oil production, targeting 2.2MMbbl/d by 2018. But to do that, the country will needinvestment, partners and technology.

“Indonesia needs help, not only financially, but also [in

terms of] technology and expertise from playmakers likeyou,” said Susilo Siswoutomo, vice minister of energy andmineral resources, Republic of Indonesia, on Tuesday,May 6, at OTC. “ere are challenges. However, the gov-ernment is here to help in any way we can to see that ex-

ploration projects are executed properly. Ifnecessary, we can change the rules to ac-commodate what is needed.”

To meet that production target, Indonesiais focusing its exploration efforts on easternIndonesia where there is an estimated 30Bbbl of oil reserves. Until this time, E&P ef-forts have centered on western Indonesia.

“e remaining resources are in deepwa-ter,” explained Syamsu Alam, senior vicepresident of exploration for Pertamina.“e challenge is to go east. ere are lotsof areas to be explored.”

e eastern region basically covers the areafrom Sulawesi Island to West Irian. Fewerthan 500 wells have been drilled, comparedto several thousand in western Indonesia.

“e need for gas in Indonesia, especiallywestern Java Island where Jakarta is, willcontinue to increase. By 2030, the need fornatural gas for power generation will ex-pand a couple of times,” he continued.

Pertamina is offering several opportunitiesfor working with international oil companies.ese include: developing and improvingEOR projects; maximizing the value of ma-ture fields through new technology, buildingnew growth frontiers in the eastern area with75% offshore, accelerating coalbed methaneand shale gas development, and expandingthe capacity to be a broader upstream drillingand service company.

“We think the eastern area has lots of op-portunities,” Alam said. “We are looking fortechnology for cost effectiveness, how tomanage fields with high CO2 or sulfur, howto manage fields with high temperature andhigh pressure and expertise with carboncapture and storage.”

Siswoutomo pointed out that Indonesiais spending about $20 billion per year onoil and gas projects with about $2.5 billionon exploration.

A deepwater speculative seismic surveyhas been conducted offshore Indonesia, saidEdy Hermantoro, director general of oil andgas for the Indonesian Ministry of Energyand Mineral Resources. An offshore leasinground is being held in 2014 with mostblocks being offered in eastern Indonesia.

Production is declining in the westernpart of Indonesia, he said. “We are movingto the eastern part of Indonesia where thereare a lot of opportunities.” n

By sCoTT Weeden

all oTC sessions are protected by

U.s. copyright laws. Photography and

video/audio recording of any kind are

strictly prohibited in the sessions and

throughout the exhibition area.

With the expected level of energy demand in 2050likely to require at least similar levels of oil and gas

production as today, in addition to growing energy sup-plies from other sources, a global approach is needed tomeet that demand.

As existing oil and gas production declines, sustainingit to 2050 and beyond essentially means rebuilding theequivalent of today’s upstream business all over againover the next 40 years.

In the OTC panel session “Global Energy Outlook:Shaping the Future,” speakers gave their visions of how theindustry can meet the challenge, from onshore in the U.S.,

offshore in the Gulf of Mexico, emergingareas such as Mexico’s potential reserves indeepwater and onshore unconventionals,and frontier provinces such as Canada’sNorthwest Territories.

According to U.S. Rep. William Flores, it isvital that the U.S. adopts as robust an energypolicy as possible to ensure its energy security.At present, he said, he was not impressed bythe current situation. “I look now, and we havean out-of-control regulatory regime,” he said.

More must be done, he continued, if theindustry is to be able to invest enough tocontinue on its current impressive track to

become one of the world’s largest oil pro-ducers. “We are on the cusp of becomingenergy secure for the first time in decades.And an energy-secure United States is vitalfor the rest of the world.”

He also went on to describe hydraulicfracturing as “the battery of expanded oilproduction” and that, if regulatory or otherinterference hurts the use of hydraulic frac-cing, “we could totally gut the energy ren-aissance we are going through today.”

Fellow panelist Christopher Smith, prin-cipal deputy assistant secretary for fossilenergy at the U.S. Department of Energy,stressed energy production is “truly an in-ternational challenge,” made tougher by thefact that “the goalposts are always moving.”

“ese challenges are constantly chang-ing, as for example we move out to waterdepths of 10,000 [3,048 m] and beyond,and encounter increasingly higher pres-sures and temperatures in wells. But tech-nology brings more opportunities, and wehave to have an ongoing relationship withthe industry,” he said.

Looking north, David Ramsay, ministerof Industry, Tourism and Investment forCanada’s Northwest Territories, high-lighted the area’s “tremendous potential”for oil and gas, including opportunities inits Arctic territory. In April the ministrybecame responsible for the administrationof its onshore oil and gas interests, andRamsay was keen to highlight areas such asthe Canol Shale oil play in the CentralMackenzie Valley, where companies suchas Husky Energy, ConocoPhillips, Shelland Imperial Oil have interests. e CanolFormation is estimated to hold between 2Bbbl and 3 Bbbl of recoverable oil.

Turning to the U.S. southern neighbor,Gustavo Hernandez-Garcia, acting directorat Pemex E&P, updated delegates on Mex-ico’s upstream sector. For Pemex, it is deep-water that he said offers the greatestpotential to help boost its production andrecoverable reserves.

“Deepwater in 2010 accounted for about6% of total production globally, but that isexpected to rise to 11% by 2030. Deepwaterproduction’s contribution is critical for

Global approach needed to meet energy demand challengen Tuesday morning panelists shared thoughts on sustaining oil and gas production to 2050.

By MaRK ThoMas


on Tuesday morning a packed room of

oTC 2014 attendees heard industry ex-

perts discuss meeting global energy de-

mands to 2050.

(Photo by Barchfeld Photography)

see cHallenGe

continued on page 40

increased concern over soaring costs has led a growingnumber of oil majors to significantly scale back their

planned capex plans for 2014 and beyond.Oil price increases have failed to keep pace with rising

E&P costs since 2011, according to industry analyst JohnWestwood of Douglas-Westwood—but the future out-look still remains positive. Speaking to delegates at theOTC 2014 topical luncheon entitled “Capex Compres-sion and the Impact on the Offshore Services Commu-nity,” Westwood highlighted recent evidence of oil

companies tightening theirbelts and increasingly focus-ing on cost efficiencies.

Global E&P spendingsoared from the year 2000onward, but costs have in-creased dramatically, he said,by tenfold. “Productiongrowth has lagged behindspending growth,” he added.

Why has capex soared?According to Westwood,

simple factors, such as demand for products and servicesexceeding supply, increasing technical challenges, over-engineering and project management issues, have allcontributed. Specific sectors, such as the subsea market,have an order backlog that has nearly doubled in recentyears, while the floating production sector has sufferedsubstantial cost overruns. He highlighted a recent studycarried out by Douglas-Westwood in which nine FPSOvessel cost studies were examined, with the results high-lighting a rise in extra costs over-budget for all ninefloaters combined of $2.6 billion—representing a 38% in-crease. In terms of time, the total delays suffered by these

same nine FPSO projects amounted to 146months, he told the audience.

He also flagged other contributing factorsfor increasing costs, including the “peopleissue,” with the limited number of skilledpeople driving up prices, and the issue oflocal content (oen with a 70% figure in-volved). “While being very desirable anddelivering benefits locally, the local supplychain may be inadequate and also create ade facto purchasing obligation,” he said.

Westwood encouraged oil and gas oper-ators to better understand the supply chainand to better assess if the capacity will bethere to supply goods and services when itis needed. Determining local future supplyand demand pinch points will be key, hesaid, so that the companies know when andhow severe they might be. is will helpthem to better understand how these willimpact individual projects.

He also highlighted the industry’spropensity to over-engineer or “gold plate”on projects and stressed the need for a re-turn to “fitness for purpose” and standard-ization. “Will an existing solution suffice?If not, can an industrywide standardizedsolution be developed?” he added.

New approaches also are needed for de-veloping better technologies, with risk-averse operators reluctant to pilot newtechnologies on offshore trials. “New ini-tiatives are needed to get new technologiesacross the R&D ‘valley of death,’” he said.“And they must share the results.”

Lastly, he stressed the need for govern-ments to accept the realities of the industryand adopt realistic local content ambitions,for example. “Some will have to accept that itwill take time to develop capabilities,” he said.

So what does the future hold for the in-dustry? Westwood said there is “no singlesolution” to cutting industry costs and thatit remains a problem that has to be ad-dressed on a number of levels.

“e industry is facing a massive andgrowing demand, and the key fact here isthat we have to drill more and more wells.More than 670,000 development wells willneed to be drilled worldwide through2020,” he said. “We do not think there willbe a collapse. With growth areas such asdeepwater, for example, we see a five-yearcapex growing by almost 130%, totaling$260 billion. Deepwater is expected to be along-term secular growth story, and natu-ral gas is another growth story that will fol-low a similar path.”

Overall, the long-term outlook remainsgood. “ose 670,000 development wellsmust be drilled,” he said. “e industry willbecome more capital efficient.” n


Rising cost concerns Will impact but not derail long-term offshore outlookn Multiple factors have contributed to soaring capex, including more demand than supply, increasing technical challenges, over-engineering and management issues.

By MaRK ThoMas

John Westwood


on Monday during OTC 2014, the Women in EnergySharing Experiences (WISE) group heard a panel

discussion from three executives in the industry and then

discussed work-life balance and careers in a facilitatedtable discussion and networking setting.

e group heard from Lynne L. Hackedorn, vice pres-ident of government and public affairs for Cobalt Inter-national Energy Inc.; Donna Birbiglia, an engineer and

the general manager for deepwater completions and wellinterventions at Shell; and Gindi Eckel Vincent, counselfor ExxonMobil Corp.

As a trailblazer in her field, Hackedorn has worked as aprofessional landman and began her career as a land sec-

retary for an oil and gas company. She jug-gled caring for a young child and going backto college to earn a degree. She discussedhow she built a network during her career.

In 1984 when she began working in theindustry, there weren’t many dual-careerfamilies, and it was the “tail end” of an oilboom, she said. Also, there were few net-working opportunities. She advised womento seize networking opportunities. “Get toknow each other, and support one another,”she said, noting that women in the industrydo not always do that.

Hackedorn works today with several menwho are in dual-career families. ey under-stand the work-life balance issue, she said,noting that she struggled to get this under-standing from men in the late 1980s. “A lotof the younger men with whom I work arevery involved with their families. eirwives have careers. ey are really involvedin the kids’ Little League, swim team and allthose things. So that’s a real positive. I thinkit’s positive for these people’s kids, too.”

The panelists agreed that flexibility is achallenge. Birbiglia favored remote com-munications, such as Facetime and con-ference calls, in her work with amultinational operator, while Vincentsaid having the flexibility to use technolo-gies like that is “critical in certain con-texts.” Vincent recounted that on Mondayafternoon she got a call that her childneeded an X-ray after falling on the play-ground. She was able to coordinate viaphone with the school, her husband, thenanny and her child. She said later duringthe facilitated roundtable discussion, “IfI’d had my druthers, I’d have been in theER today.”

Vincent said that the opportunities forwomen “are absolutely limitless in this

Wise Gathering Highlights concerns for Women n Connecting in the industry, maintaining a work-life balance and recruiting and retaining women weremajor issues spotlighted.

By eRin Pedigo

The Women in energy sharing experi-

ences (Wise) event on Monday afternoon

drew many attendees for a discussion of

career-related issues. (Photo by Barchfeld

Photography)

see Wise continued on page 40

geoscience is an important factor in offshore devel-opment, where well costs can be astronomical. In a

Tuesday morning session during OTC 2014 titled “Geo-science Projects,” several presenters outlined technologyaimed at improving subsurface data qual-ity while reducing cost.

Chaired by Jim Kreamer of WeinmanGeoscience and Aurora R. Castelan ofSchlumberger, the session included a pres-entation by D.N. Dorran of Atlas Copco ti-tled “Evolution of High-Pressure, Flexible-Capacity Air Compressors to ConvertSmaller Vessels for Use in the Marine Seis-mic Exploration Industry.” Air compressorsare used to power the airguns that marineseismic vessels use for their sources.

Dorran said that most of the air compres-sors currently in use are purpose-built for aspecific contractor or vessel operator, givingthem a narrow performance range. But asexploration projects have moved into shal-lower water, there aren’t enough purpose-built vessels to meet current needs.

To solve this problem, contractors havetaken compressors built for other applica-tions, modified them and put them intoservice. ese compressors are plagued bya high level of unreliability, Dorran said.

“Reliability is critical,” he said. “It’s a bigpart of why we got into this market.”

It’s not a huge market, he added, but it isa growing market with specific needs sincethe current crop of unreliable compressorsleads to cost overruns and less confidencein the quality of the final data products.

Atlas Copco spent more than a year talk-ing and collaborating with contractors try-ing to determine their needs. Reliability wasthe top request, followed by the size andweight of the compressor; performanceflexibility; and the ability to meet environ-mental, regulatory and safety requirements.

e result is a reliable, flexible systemthat provides a wider performance rangethan purpose-built systems, allowing formodular designs. Noting that current re-furbished compressors are not tiered forany environmental regulations, the com-pany designed a system that provides con-tainment of fluids and particulate control.

“It’s critical that we be on the leadingedge, not just another converted compres-sor,” he said. He added that the units areDNV-certified.

He looks for the market to grow withcontinued advancement of hardware andsoware, expansion in the explorationmarket and industry demand.

“The market has accepted these typesof compressors,” he said. “It will continueto evolve.”

Yenny Shim of Schlumberger presenteda talk on the use of a real-time sonic log-ging tool for exploratory drilling in theSouth China Sea. Working closely with

CNOOC, Schlumberger has developed an improvedLWD tool that provides users with more confidence inthe real-time data.

CNOOC has ambitious exploration plans for its SouthChina Sea acreage. In 2013, the company made 18 dis-coveries, replaced 32% of its reserves and had a success

rate ranging from 46% to 67%.It plans to drill 120 to 130 wellsin 2014, and Shim said the com-


new tools aid explorationn Seismic and logging advancements reduce cost and risk.

By Rhonda dUey

see tools

continued on page 40yenny shim

offshore drilling has long been at work assuring thatthe hydrocarbons from the ocean floor make it to

the surface.But what the industry calls flow assurance faces a

multitude of problems. Well pressures change, water issometimes incompatible, corrosion can set in frombacteria, wax and asphaltene inhibit flow and gas hy-drates plug up holes.

On Tuesday, May 6, scientists at OTC 2014 presentedtheir latest research on combating some of the more fre-quent problems.

Francisco Vargas, a professor at Rice University’s de-partment of chemical and biological engineering, pre-sented findings of laboratory experiments that predictand even reverse the presence of asphaltenes.

Asphaltenes, first named for their asphalt-like proper-ties, are infamous for blocking wells and interfering withproduction. Under a microscope they look like tiny sliversof rock or like clumps of clay. Asphaltene components tendto bond together to form clusters. ey are present in mostpetroleum materials and in all heavy oils and bitumensfrom oil sands, according to the University of Alberta.

Vargas said that asphaltene deposits can create forma-tion damage, plug flowlines and jam equipment. e par-

ticles, which start off in the nano range, result in loss ofproductivity, and companies oen pay high costs of up to$3 million per offshore well to remediate the compounds.

In extreme cases, wells have to be plugged.Asphaltenes form from nano-aggregates, which are

nearly impossible to detect commercially. e nano par-ticles snowball into a primary particle, then a larger,macro-aggregate. At their final “aged stage” they aresolid-like, Vargas said.

In a series of experiments, Vargas studied the reversibil-ity of the asphaltenes. Using a drop of crude oil on a watchglass and adding a drop of iso-octane, he was able to sep-arate the asphaltenes prior to their final, solid state.

After the iso-octane is dissolved, theasphaltene aggregates are readily redis-solved in oil.

“Asphaltene precipitation is a fully re-versible process,” Vargas said.

Vargas also said laboratory experimentsshow that precipitation of asphaltenes canlead to the formation of primary particles,which can form bigger clusters and lead toa solid-like appearance.

Once in that form, they are difficult todissolve, he said.

Minwei Sun, a researcher at the Reser-voir Engineering Research Institute in PaloAlto, Calif., addressed another bane fordrillers—the formation of hydrates.

Gas hydrate affects both flow assuranceand spill recovery. Gas hydrate formationsoen block flowlines in oil and gas produc-tion. Small gas molecules, such as methane,ethane, propane, CO2 and nitrogen, in oiland natural gas oen form at low temper-atures and high pressures.

While they can be dealt with by anti-ag-glomerants, the challenge is maintainingperformances at a high watercut—the ratioof water produced compared to the volumeof total liquids produced.

Sun said he wondered if hydrate particlesare formed from water-in-oil emulsions.Experimenting with natural gases on n-oc-tane and oil, Sun found that the CO2 in nat-ural gas affects hydrate anti-agglomeration.

e method is effective in both naturalgas and crude systems and at watercuts of100%. However, a significant effect on pHis observed, and higher dosages of acidicoil are required.

e use of anti-agglomerates is attractivebecause of its effectiveness at low doses andhigh subcooling. Hydrate particles are keptsmall and allowed to flow in slurry form,avoiding the plugging of flowlines.

Until recently, researchers believed thatanti-agglomeration was based on the for-mation of water-in-oil emulsion. However,Sun said the process can occur withoutemulsion or through oil-in-water emulsion.

Sun said that natural gases in a crudesystem are effective in both water and brinein preventing hydrate formation. e workis particularly important given that the in-dustry has sought an effective AA for highwatercuts. For practical purposes, water-cuts of less than 50% have been the cutoff.

Sun said his surfactant can do far betterwithout a need for water-in-oil emulsion.e key to Sun’s process is to inhibit the ab-sorption of anti-agglomerate molecules ontohydrate particles. His formulation is effec-tive to a watercut of 99.6%, he said. n

Researchers Find Ways to Reverse deepwater Flow stoppersn A Rice University professor says the formation of asphaltenes is reversible.


By daRRen BaRBee

in operations critical to the oil and gas industry, wellsdrilled through naturally fractured rock oen suffer

extreme loss of circulation as conductive fracture net-works channel drilling fluid or cementing fluids. Partic-ularly problematic in surface holes—oen drilledthrough unstable formations—is fluid loss, which hasjeopardized operators’ ability to achieve hydraulic andmechanical integrity when setting surface pipe. One ofthe most critical phases of well construction involves me-chanical support of the wellhead and surface pipe as wellas perfect hydraulic seal. e challenge be-comes even larger when drilling into a nat-urally fractured reservoir, as fluid lossimpacts drilling performance and mightdamage the reservoir, and plugging thosefractures while drilling. Ideally the fluidloss pill should plug reservoir fracturestemporarily, which then significantly de-grades with time, to restore the desirableconductivity from natural fractures for im-proved production.

e Schlumberger Losseal family of re-inforced composite mat pills employsdegradable fiber treatment to plug lost cir-culation zones; then they degrade to restoreformation permeability. Aer deployment,the highly effective pills disperse into nat-ural fractures and high-loss zones. eybridge inside the fractures with a networkof fibers while the solids form a seal thateliminates fluid loss. ey sustain the pluglong enough to complete drilling and cas-ing cementing without fluid loss or degra-dation of cement bond. ereaer, thesystem can safely degrade leaving the for-mation undamaged for production.

Losseal pills can be blended in the fieldjust before pumping. Parameters that canaffect fiber performance include, but arenot limited to, fluid viscosity, fiber concen-tration, fiber geometry, flow rate and frac-ture width—the latter can range from 1mm to 5 mm in width. e product is de-livered in a fluid that has been designed foreasy preparation on the surface and can beconfigured to allow full compatibility withbottomhole assemblies, including thosewith LWD/MWD telemetry pulsers. eywill not clog bit nozzles or inhibit normaloperations in any way.

oroughly tested in wells worldwide,the Losseal family of degradable compositeseals has proved its ability to mitigatedrilling fluid invasion into the reservoir,reduce nonproductive time (NPT) whiledrilling and reduce time to reach targetdepth. Pre-job mixing and preparation israpid and easily done by field personnel.e Losseal for reservoir drilling sealsfractured reservoirs and prevents furtherformation damage, eliminating the needfor remedial treatments.

Two recent wells being drilled in con-junction with a development project expe-rienced total fluid losses at 341 m (1,120 )during drilling of the 8½-in. reservoir sec-tion. Drilling continued to a target depthof 472 m (1,550 ) with loss rates reaching200 bbl/hr. Since this section was intendedto be the production/injection zone, it wasimportant that any lost circulation treat-

ments neither inhibit future productionnor damage reservoir permeability. Withsevere losses of drilling fluid, operators didnot want to risk the same fate while ce-menting 7-in. casing. When injectinghigh-pressure cyclic steam, zonal isolationmust be perfect to avoid leaking steam tosurface. At the same time, treatmentsmight not inhibit oil production during

degradable Fiber solution for lost circulation during Reservoir drillingn A family of degradable composite seals has proved its ability to prevent drilling fluid invasion into the reservoir, reduce NPT while drilling and reduce time to reach target depth.

ConTRiBUTed By sChLUMBeRgeR


The schlumberger Losseal for reservoir drilling fluid is shown in varying

stages of degradation. For a configurable length of time, the fiber re-

mains stable (left image); then it degrades (center) to a clear liquid

(right), which leaves formations undamaged. (source: schlumberger)

see ciRculation



Rich in hydrocarbons and an up-and-coming world-beater in LNG exports, Australia is in possession of

known assets that have been a prime attraction for globaloil and gas majors.

But the unknowns might turn out to be a bigger draw.“Australia has potential for large discoveries of oil and gas,

with many offshore basins remaining largely or entirely un-explored,” said Kelly Ralston, senior trade investment com-missioner with the Australian Trade Commission, based inthe Australian Embassy in Washington. “Only 20% of Aus-tralia’s offshore basins are currently covered by petroleumtitles. Frontier exploration is definitely growing.”

BHP Billiton’s Rob Jellis echoed the optimism, espe-cially concerning LNG exports.

“We are currently thirdin the world, but comethe end of the decade,we’ll be at the top of thetree,” said Jellis, whomanages global nonoper-ated production assetsfor BHP from Houston.The next phase of devel-opment will be floatingLNG (FLNG) facilities.

“We’re seeing this newemerging technology re-ally as the next step as we

try to develop the really remote gas that Australia’s beenendowed with,” he said.

Country’s winning waysOTC and the U.S. Department of Commerce jointlyorganized Tuesday’s industry breakfast focused onAustralia. Chandra Brown, the Commerce Depart-ment’s deputy assistant secretary for manufacturing,listed three key factors of the country that businessescan count on:

• A stable political environment;• Transparent regulatory structure; and • Proximity to Asian markets.Ralston added Australia’s educated workforce to the

list as well as its embrace of new technology.“Australia has a long track record of innovation and

early adoption and is well-positioned to become a fastfollower in the growth of unconventional gas plays,”she said.

e resources to be exploited are abun-dant and likely to grow. e reserves Ral-ston cited, as estimated by the U.S. EnergyInformation Administration, included:

• 4.4 Tcm (157 Tcf) of natural gas;• More than 6.3 Tcm (223 Tcf) of

coalbed methane;• 11 Tcm (400 Tcf) of shale gas;• 4 Bbbl of oil, condensate and liquefied

petroleum gas reserves (currently netimporter, but talk of developing); and

• Significant potential to develop con-densate and shale liquids.

Follow the customersFigures like these might have captured theattention of majors like Apache, Hallibur-ton and Schlumberger, but Ralston notedanother trend.

“We’re seeing many small and midsize[companies]—U.S. companies in particu-lar—following those customers to marketand entering our market through those ex-isting customer relationships,” she said.

at was his company’s story, said AshrafJahangir of consulting firm Kleinfelder.

“We have existing clients who aredoing business in Australia, and we fig-ured it would be a good idea to followthem,” he said.

Kleinfelder opened its Melbourne officein 2010, gained a $28 million consultingcontract in 2011, bought two small Aus-tralian consulting firms in 2012 and con-tinued to grow its business in a sloweconomy through 2013. e company nowemploys 100 in three offices—Melbourne,Newcastle and Adelaide.

Jahangir said it is easy for a companynew to Australia to become immersed inthe abundance of industry data.

“If I can provide any advice to you: findyour story,” he told the crowd. Concentrat-ing on the data and intelligence that are ap-plicable to a particular company’s serviceor product will be of most use in growinga business. Understanding the country alsois critical, Jahangir said, calling it more im-portant than trying to time entry into themarket to ensure success.

Jahangir offered these tips as well:• Use in-country support services;• Establish vendor agreements early;• ink big but act small, especially for

companies experiencing financialconstraints; and

• Have a clear plan with the ability to ad-just it over time.

Potential, thy name is australian Onshore and offshore, the investment-friendly big country beckons with abundant resources.

By JosePh MaRKMan

16

Kelly Ralston

see austRalia



attendees at Monday aernoon’s OTC technical session“Challenging Well Completion Solutions” were treated

to a wide range of solutions, from nonradioactive tracertechnology to intelligent completions, ceramic sand screensand coiled-tubing stimulation in challengingwells. Led by moderators Russell Bayh andEarl Claiborne, the session delivered a well-planned, mixed bag of highly educationaland informative presentations.

ConocoPhillips’ Leon Zhou kicked off thesession with a presentation on his work. Heshared with attendees details on an en-hanced multizone single-trip sand controlsystem that successfully treated six zones ina well offshore Indonesia. In his paper, firstdelivered at OTC Asia earlier this year, Zhounoted that a high pump rate, high differen-tial pressure-rated single-trip multiple-zonesand control system was successful in treat-ing six discrete zones in an offshore deploy-ment in the Bawal well in Indonesia.

Seven technical papers on well comple-tions were delivered during the session. Inaddition to Zhou’s paper, they included:

• “An Environmentally FriendlyMethod to Evaluate Gravel andFrack-packed Intervals Using aNew Nonradioactive Tracer Tech-nology,” by Robert Duenckel,CARBO Ceramics Inc.; H. Smith,Harry D. Smith Consulting; and X.Han, CARBO Ceramics;

• “Hydraulic Fracture Design for theLower Tertiary Gulf of Mexico:Optimization Under Uncertainty,”by Seth Podhoretz and P.P. Valko,Texas A&M University;

• “A Review of Intelligent Comple-tion Installations: Lessons Learnedfrom Electric-Hydraulic, Hy-draulic and All-Electric Systems,”by Potiani Maciel and E.P. Motta,Baker Hughes do Brasil;

• “An Innovative Approach of Revivalfor Damaged Wells in High-ErosiveEnvironment Using Ceramic SandScreens,” by Kumar Gaurav, BGGroup-GTC; A. Nadeem, S.Ivanova, BG Group; and J. Wheeler,BG Group-BG Advance;

• “Successful Coiled Tubing-BasedSelective Stimulation of a RemoteWell in Challenging Offshore En-vironment—A Case Study,” byA.K. Singh, Cairn India Pty. Ltd.;S. Anand, Cairn India Ltd.; A.B.Nikam, A. Parasher, Cairn IndiaLtd.; S. Kale, Weatherford Interna-tional; and R.D. Cousta, Schlum-berger; and

• “Intelligent Casing-Intelligent For-mation (ICIF) Design,” by Harold L.Stalford, R.M. Ahmed, V.H. SorianoArambulo, University of Oklahoma.

In her review of intelligent completion,

Maciel said that since the first intelligent completion wasinstalled in 1997, it can now be found in most global oiland gas production areas, from mature land to ultradeep-water wells like those offshore Brazil in the presalt region.

She noted that only until recently, intelligent completionusing remotely actuated hydraulic systems has been widely

used, with Baker Hughes having installed 192 systems ofthis type (as of 2012) in 1,100 single and multizone wellswith intelligent completion installed worldwide.

Electric-hydraulically actuated systems present advan-

solutions to challenging completions sharedn Experts shed light on advances in downhole technologies.

By JenniFeR PResLey

see solutions continued on page 42


The global standard for Tropical Helicopter UnderwaterEscape Training (HUET) has become more rigorous to

address the oil and gas industry’s primary focus on enhanc-ing safety. OPITO, the oil and gas industry’s focal point forskills and workforce development standards, has updated itsHUET requirements to meet the demands of today’s offshoreenvironments, raising the bar for training rig workers bydoubling the length of the course from 4 hr to 8 hr.

ese new standards ensure workers have the skillsthey need to react effectively if an emergency occurs

while traveling to and from offshore oil and gas instal-lations and vessels by helicopter. Because the programnow provides a more robust offering, it has been ac-cepted by Shell Upstream America to satisfy its warm-water HUET requirement.

To meet the industry’s expanding training demands,Hi-Con Training, a partnership between Raytheon andPetrofac Training Services (PTS), is now offering theOPITO-approved Tropical HUET course at itsrenowned Hi-Con Training facility located within theNeutral Buoyancy Laboratory (NBL) at NASA’s John-son Space Center. Once used exclusively for astronaut

training, the massive 12-m-deep (40-ft-deep) pool now offers some of the mostauthentic and immersive survival andsafety simulations in the world for off-shore oil and gas personnel.

“Petrofac is excited to continue our in-vestment in Hi-Con Training withOPITO-approval of our Tropical HUEToffering,” said Marc Pretorius, operationsdirector at PTS Americas. “We are proudto stand at the forefront of this industryinitiative that increases the focus on safetyand emergency preparedness in the oiland gas sector.”

OPITO releases industry trainingbenchmarks and authorizes trainingproviders to deliver the approvedcourses. Tropical HUET was designedspecifically to meet the growing de-mands for realistic oil exploration safetytraining scenarios. The course also hasbeen reviewed and endorsed by the P&TWells organization.

“is advanced Tropical HUET is a safetyand survival game changer for the oil and gasindustry,” said Tracy Cox, director of per-formance consulting at Raytheon Profes-sional Services. “We fully expect this newtraining offering to have a significant impacton industry training standards—especially inthe most high-consequence environments.”

e course provides specific training onpreflight and inflight requirements fortropical environments, including the Gulf

training at nasa expands to include underwater Helicopter escape course n A 12-m-deep pool offers some of the most authentic and immersive survival and safety simulations in the world for offshore oil and gas personnel.

ConTRiBUTed By hi-Con

see couRse


hi-Con Training is offering the Tropical

hUeT course at nasa's Johnson space

Center. (images courtesy of hi-Con)

The Tropical hUeT course provides specific

training on preflight and inflight require-

ments for tropical environments.


an article in the Tuesday edition of the OTC showdaily described why floatover installation became an

attractive alternative to heavy-li crane installation foroffshore construction during the past three decades andhow it is gaining renewed interest.

To better understand the floatover concept, a brief in-troduction breaking down the process into steps mightbe helpful. ere are several phases involved when in-stalling an offshore topside with an HTV.

e load-out phase is the starting point of a floatover top-side installation. e integrated topside is built onshore andneeds to be loaded onto the installation vessel, by means ofself-propelled modular trailers or by the use of skid tracks.Requirements for the load-out stage are governed by the fol-lowing parameters: integrated topsideweight, tidal range and quayside dimensions.

Following completion of the load-out,the integrated topside has to be seafas-tened on board the vessel prior to com-mencing the sea transport phase. Stabilityof the vessel is critical for the transport.Stability is mainly driven by the width anddepth of the vessel.

Aer completion of the transit, the vesselneeds final preparations prior to the com-mencement of the actual docking operationof the vessel. During the standoff phase,preparatory works need to be executed suchas removal of seafastenings, startup ofmooring/docking/mating winches, startupof motion and weather monitoring equip-ment, startup of active load-transfer systemand preballasting of vessel. For these prepa-rations, the vessel needs to be moored at astandoff location. e mooring spread forthe vessel will be dependent on the field lay-out and the environmental conditions.

Once the preparatory work is completed,the docking phase can commence. Duringthis phase, the vessel is moved into thejacket. A few conditions need to be safe-guarded in this phase, including alignmentof the vessel stern with the jacket slot, lateralimpact loads on the jacket not to exceedlimit loads of jacket and fendering arrange-ment, no vertical impact loads between top-side legs and jacket legs, and control over themovement of the vessel in longitudinal andtransverse direction as well as control overthe alignment of the vessel.

Once the vessel is positioned directlyabove the jacket structure and docked,the topside legs need to be aligned withthe jacket legs. The tolerance for thisalignment is to a high extent driven bythe diameter of the stabbing cones. Dur-ing the premating phase, the clearancebetween the topside legs and the jacketlegs will be reduced by ballasting the in-stallation vessel. A few aspects need to betaken into account: limited lateral move-ment of the vessel relative to the jacket toensure alignment of the topside andjacket legs, lateral impact loads on thejacket not to exceed limit loads of thejacket and fendering arrangement, verti-cal impact loads on the jacket not to ex-ceed limit loads of the jacket and legmating units (LMU) design.

e mating phase is the most criticalpoint of the installation, leaving no roomfor uncertainty in the functionality of theload transferring equipment. In thisphase, the topside is lowered onto thejacket by the vessel’s rapid ballasting sys-tem where large quantities of water enter

the ballast tanks, enabling the vessel to submerge. Dur-ing this phase, the topside’s weight is completely trans-ferred onto the jacket. For a successful floatoveroperation, countless hours of preparation come down tothe exact moment when the topside makes contact withthe jacket. Custom-engineered elastomer is used in thedesign of the LMUs to dampen the impact during loadtransfer.

In the post-mating phase, the topside sits secure on topof the jacket, and a clearance gap is created between thetopside support unit (DSU) and the vessel to ensure lim-ited contact between the two. To further limit the impactloads, the distance between the vessel’s DSU and inte-grated topside needs to increase, while limiting lateraland vertical movement to avoid impact loads.

Aer the completion of the ballasting operations to in-

crease the clearance between the DSU and the integratedtopside, the vessel can be undocked from the jacket. Inthe exit phase, the vessel departs from the jacket slot onits own propulsion or with assistance from tugs. It is im-portant during this phase that the lateral impact loads onthe jacket do not exceed limit loads and that there are novertical impact loads between the DSU and the inte-grated topside. In addition, full control of the vessel’s lon-gitudinal and transverse direction as well as thealignment is important.

ese eight floatover phases might differ dependingon assets, equipment and the installation approach used.e floatover vessel plays a critical role as it both trans-ports and installs the integrated topside. While there aredifferent types of HTVs, not all are designed to installtopsides offshore. n

understanding the Process of Floatover installation n Several phases are involved when installing an offshore topside with an HTV.

By JonaThan MaRTinez, doCKWise

Comparing the results of the latest Gulf of Mexico(GoM) lease sales to previous sales could leave num-

ber crunchers with a not so upbeat picture.e sum of high bids for the central sale was less than

the previous sale for the area, and the number of com-panies participating was down. Blocks in the easternGoM lease sale went up for bid for the first time in aboutsix years, but no one wanted any of these blocks.

One might think that means interest in the GoM is wan-ing, but that isn’t the case, some say. e more than $1 billionin total bids might not have been record-setting or evenamong the best for central GoM sales, but it’s still a lot ofmoney, according to industry experts. Yet, the $850 millionin high bids is roughly 50% of a June 2012 sale, which at-

tracted about $1.7 billion in high bids for tracts offshoreLouisiana, Mississippi and Alabama. A total of 56 companiessubmitted 593 bids on 454 tracts for the June 2012 sale.

“Industry’s consistent commitment to the Gulf of Mex-ico is evident, which is remarkable given the relative easeof producing oil and natural gas onshore, the expansionof competing offshore programs in other countries andsome continuing regulatory uncertainty here at home,”National Ocean Industries Association (NOIA) PresidentRandall Luthi said in a prepared statement.

“In spite of these factors, industry has not given up onthe Gulf of Mexico, and NOIA members led the sale inthe amount of bids and high bids. Deepwater continuesto lead, but today’s bidding also showed that the shelf isstill worth pursuing,” Luthi said. “e majors demon-strated once again that they have the revenue to invest in

the deepwater frontier areas, and smaller operators alsoshowed they are serious investors on the shelf as well asin deepwater and are in the GoM to stay.”

Brian Gamble, research director for Simmons & Co.International, highlighted some statistics in an analystnote. He pointed out that the $851 million in high bidsgenerated in central GoM Lease Sale 231 was below the$1.2 billion in high bids posted for the previous centralGoM Lease Sale 227 in March 2013. e amount “marksthe lowest dollar amount exposed by high bids sinceMarch 2009 [$703 million]. Further, the average winningbid for an individual block was $502/acre, which wasbelow the $705/acre received last year and the $585/acreaverage from the last three central GOM sales.”

He also noted that the number of companies partici-pating in the sale reached a new decade low of 50. e

number was only two fewer than the 52companies that joined in bidding for LeaseSale 227, but the average for the last fivecentral GoM sales is 68.

“In aggregate, total bids exposedamounted to $1,085 million, down from anaverage of $1,833 million over the prior threecentral GOM lease sales,” Gamble wrote.

However, lots of factors go into the num-bers, and too much shouldn’t be read intothe overall number, according to AndyRadford, senior policy adviser for theAmerican Petroleum Institute (API), whopointed out that the $851 million sum ofhigh bids is still a lot of money.

“We had more leases bid on than the lastlease sale. ey just weren’t exposing asmuch money,” Radford said. “I think it’smore a sense of what they project in the fu-ture for oil prices or companies’ financialperformance has been down a little bit.ey are trying to cut costs some. ere isa lot of stuff that reads into that number.”

Focus instead should be placed on thenumber of blocks that received bids, he suggested.

e federal government offered 7,511tracts in the central GoM region, 212 moretracts than offered during the last centralGoM lease sale March 20, 2013. Of thetracts offered this year, companies placedbids on 326, six more than the previoussale. e bids were almost evenly split be-tween tracts with water depths of 800 m(2,625 ) or greater (165 tracts) and thoseof 800 m or less (161 tracts).

“e central gulf is one of the premieropportunities companies have to explore.It’s one of the only opportunities they haveto explore in deepwater in the UnitedStates,” Radford said.

e highest bid was submitted by Freeport-McMoRan Oil & Gas, which outbid five othercompanies vying for the same block—thecentral GoM sale’s most active—with its bidof about $68.8 million. e company said itswinning bids were primarily focused on“high-impact, drillable targets in the Missis-sippi Canyon and Atwater Valley areas tocomplement Freeport-McMoRan’s existinginfrastructure and production facilities andadd several new exploration plays.”

e top 10Freeport-McMoRan led the list of top 10companies that participated in the centralsale based on the sum of high bids submit-ted—16 total high bids for a sum of about$321.4 million, according to the Bureau of

interest Remains High in Gomn Results of the latest sale show various factors could be at play in companies’ spending decisions.

By VeLda addison


Continued on next page


Ocean Energy Management (BOEM) saleday statistics.

Chevron placed $103.3 million inhigh bids, six total high bids; while Mur-phy E&P had $49.8 million in high bids,16 total high bids. Others in the top 10were Shell Offshore, BP, EcopetrolAmerica, Ridgewood Energy, Cobalt In-ternational, Red Willow Offshore andLLOG Bluewater Holdings.

In all, Shell bid on eight blocks, expos-ing about $100 million, the company saidin a statement.

“Shell was the apparent high bidder onfour blocks, totaling approximately [45.5million], including a key block that willconsolidate Shell’s position in the greaterAppomattox/Vicksburg area,” the companysaid. “Shell continues exploration of theNorphlet play on the basis of its promisinggiant Appomattox and adjacent Vicksburgdiscoveries.”

Cobalt and Total E&P U.S. were the mostactive, each with a total of 44 high bids.Cobalt’s bids were worth about $25.8 mil-lion, while Total’s were worth about $17.2million. Another active company was EPLOil & Gas Inc., which will be acquired byEnergy XXI (Bermuda) Ltd. in a $2.3 bil-lion merger making it the largest public, in-dependent GoM producer. EPL made 21offers in the sale for blocks in the EugeneIsland, Main Pass, South Pass, Ship Shoal,South Timbalier and West Delta areas.

However, some companies that werepresent in the top 10 sum of high bids listfor the last central GoM were absent fromthe list this time around. Notables includedExxonMobil, BHP, Statoil and Anadarko.

But these companies, Radford said, will beat the top of the list if looking at total GoMlease sales. He speculated that maybe theyhave active inventory leases, didn’t see any-thing attractive or perhaps have ruled outcertain prospects and are looking for others.

It also could be a sign of more focusedspending.

“ey are actively managing these leasesall the time,” he said. “It may just be a yearwhere they have the prospects they need.Maybe they were active but didn’t have thehigh bid. … In general the companies thathave a number of active leases in the gulfare always looking for new opportunities.Some years are different than others.”

Other areasNo bids were submitted for Eastern Sale

225, the first sale in this area since2008. e lack of bids doesn’t neces-sarily mean there is no interest at all,but rather no interest in terms of buy-ing new leases, Radford said.

e reasons vary.“ere are active leases in the east-

ern gulf. ey sold 36 leases back atthe 2008 lease sale,” Radford said. “I’mnot really sure they have been able tofully explore the prospects that wereidentified. … Aer the spill, there wasa moratorium, so things might havebeen off schedule, and they haven’thad a chance to get back to that area.ose leases are still active.”

But he wasn’t too surprised thatthere wasn’t a lot of additional interestin this area.

During a media call following thesale results, federal officials also spoketo the dismal showing. Factors that

might have played roles in companies’ decisions couldhave been that the area is more of a gas play than oil play,Interior Secretary Sally Jewell said, adding that the priceof gas might also have been a factor.

BOEM GoM Regional Director John Rodi also said thatscientists are not 100% clear about the nature of structuresand plays in the eastern GoM and need more information.

Regardless of the lack of bids, another sale is plannedfor the eastern area in 2016. But there might be greaterinterest in the Atlantic. At least that is what Radford andAPI are hoping for, considering they have been workingto open the Atlantic to oil and gas drilling.

“I think what we need to have out there is a seismicsurvey, and the government has taken the steps neededto get us out there to do seismic surveys and get permits,”Radford said. “From that you’ll be able to have a muchbetter sense of what the interest will be in obtainingleases in that area. … e Atlantic is an obvious area ofopportunity that companies want to have a chance tofully explore. I haven’t heard specific interest, but I thinkthere is a general interest in getting out there and seeingwhat’s there.” n

Continued from page 20

Former astronaut Mike Bloomfield can remember sittingatop one of NASA’s rocket ships reflecting on how far the

human race had come in just one century, from the time atKitty Hawk jumping off sand dunes to rocketing into spaceat Mach 25. Now the vice president and general manager ofOceaneering Space Systems, Bloomfield continues to be im-pressed by the numerous advances that have been made inonly the last 50 years in subsea oil and gas operations.

Bloomfield presented the breakfast session, “Oil & Gas In-dustry Commercial Use of NASA’s Neutral Buoyancy Labo-ratory (NBL),” on Tuesday morning during OTC 2014.Bloomfield and Oceaneering are part of Team Raytheon,which partners with NASA to share the NBL located at theNASA Johnson Space Center in Houston. e NBL is avail-

able commercially to the oil and gas industry for underwatertesting, systems integration tests, tool tests or training andrehearsals of processes and procedures before deploymentof industrial projects offshore.

“If you look back over the last 50 years, there has been atremendous acceleration in deepwater technology and withthat comes some risks,” Bloomfield said. “Testing has longbeen a cornerstone of the human space flight and has playeda big role in reducing risk and unpleasant surprises that I, asan operator, can appreciate.”

He said oil and gas companies that test their equipmentand procedures in the NBL before deployment are likely toexperience fewer operational risks, lower operational costsoverall and improved safety knowledge that comes in handywhen needed in tightly controlled conditions.

“Rocket science is not easy,” Bloomfield said.

Bloomfield shared one of his favorite quotes from Germanrocket engineer and space architect Wernher Von Braun:“One good test is worth 1,000 expert opinions.”

Of course, testing is not without its risks, he said.“It’s important to note that testing can be dangerous, too,

just as we saw when we lost three astronauts because of thecabin fire during the launch rehearsal test of the Apollo 1mission,” Bloomfield said.

As a former astronaut commander, Bloom-field said he was always particularly keen ontesting as much as it took to ensure that heand his crew were well prepared for whatthey’d face in space.

“One of the questions I oen get asked is,‘What was I thinking about when I was sittingon top of that rocket getting ready to launchinto space?’” he said. “I can tell you the firstquestion that goes through your mind is,‘Who built this thing?’ And the second ques-tion is, ‘How do I know it’s going to work?’ese are very important things to thinkabout as you’re sitting on top of a rocket. ereason we think this thing is going to work isbecause of all the tests we’ve been doing.”

e NBL provides NASA and the commer-cial oil and gas industry with the means to testequipment in 6.2 MMgal of water at a depthof 12 m (40.5 ). It has skybox-style roomsoverlooking the pool for both direct and in-direct monitoring. Bloomfield said the skyboxcontrol room allows a team to monitor severalviews of the operation at once during systemintegration testing (SIT). e technology ishighly advanced and can be shared as neededwith teams located offsite as well.

Bloomfield cautioned that “testingdoesn’t always go as planned,” which is whythe NBL can offer such an advantage tocompanies that spend millions of dollars aday on deepwater operations.

“Failures can be seen as a good thing, espe-cially if that failure can be understood andeliminated from the design,” he said. “eonly way you can know for sure whetheryou’ve eliminated the failure from the designis to conduct another test.”

Conducting another test while already onthe rig in deepwater is costly. Bloomfield saidone operator told him that with a subsea as-sembly costing $35,000 per hour to perform,the training and testing received at the NBLmade him feel more confident the projectwould be completed safely and on time.

For companies that would like to use theNBL for testing equipment or training,Bloomfield recommends contacting NASAor Oceaneering—anyone on TeamRaytheon—and setting up an appointmentas soon as possible.

“We work around what NASA is doing,” hesaid. “e earlier we receive your request, thebetter.”

He said the NBL was available for commer-cial use about 50% of the time during regularbusiness hours, but if a company was flexibleand willing to test aer business hours, “wecan do that forever,” he said. In those cases, hesaid there is a 75% likelihood that the NBL fa-cility will be available for commercial use. n


train like the astronautsn NASA’s testing and training facility aids in subsea development.

By aMy Logan

Mike Bloomfield

it is oen felt in the archaeological world that deepwatershipwrecks are “safe,” because they lie far from human in-

terference. But human impact in deepwatermarine environments happens more oenthat we realize, according to Daniel J. Warren,a marine archaeologist with C&C Technolo-gies. Warren spoke during OTC 2014 onTuesday about the underwater shipwrecks in-vestigated during the Lophelia II researchprogram, a multiyear, multidisciplinary studyon the Gulf of Mexico (GoM).

“We determined that several of the siteshad anthropogenic impact, and they hadbeen impacted by trawling or oil and gas ac-tivities,” Warren said. “is was important tous, because there is, in some areas of archae-ology, a feeling that since deepwater wrecksare so deep, they’re protected. I think whatthis study showed was this was not the case.”

Warren referred to a piece of modern netfound at one of the sites—a 19th-centurycopper-clad wooden-hulled ship—indicatingthe site had been affected by trawling. atmight seem small, but at another site, the re-mains had been heavily damaged by “anthro-pogenic impacts,” specifically, anchor cablesfrom a drilling rig that had cut through thewreck and destroyed most of the stern area,according to Warren’s paper on the study.

When cultural resources are found off-shore, archaeologists map an area to protectthe site. e process involves “a little bit ofmath, a little bit of history and a little bit ofarchaeology,” according to Robert Church,also of C&C Technologies.

Larger archaeological sites, such as ship-wrecks, can be easier to spot, but prehis-toric sites pose different problems.

e paradigm for the populating ofNorth America through the Bering LandBridge between 10,000 and 13,000 yearsago doesn’t tell the whole story, accordingto Matthew Keith of Tesla Offshore.Rather, the archaeological record in Southand Central America shows that smallerpopulations from Asia followed the coast-lines, populating the area of the GoM, pos-sibly by watercra, Keith said. As the IceAge ended, the coastline was submerged,along with archaeological evidence.

is model has led archaeologists to re-think some of the oldest known sites on theGulf Coast.

“If you look at these sites and you lookat where the Outer Continental Shelf wasat that point in time, you realize that theseweren’t coastal sites,” Keith said. “esewere inland sites. And these coastal sites,where people lived along the coast at thetime and exploited those coastal resources,are all under water. So we don’t reallyknow a lot about the people who were liv-ing along the coast.”

When doing preliminary research, archaeologists lookfor waterways and then what Keith calls “high-probabilityfeatures,” or those landforms along the water channels,that would have been conducive for human habitation.

“e trick is those features at human occupation sitesare very ephemeral,” Keith said. “ese people didn’tbuild very large structures.” is makes finding archae-ological evidence geophysically challenging. n

natural, Human impacts create Problems for marine archaeologistsn Preserving underwater archaeological sites requires caution by offshore industry.

By CaRoLine eVans


BOOTH 4916COME VISIT US AT

The emerging floating LNG (FLNG) market has beenone of the most radical offshore trends of this

decade, moving from the drawing board to the fabrica-tion yard (admittedly aer several decades of conceptu-alization) in just a handful of years.

It is being driven by two main factors. One is the con-tinued growth in the world’s population, which along withfurther GDP growth in the major developing economiesis expected to see global energy demand surge by about50%. e other is that, while oil’s percentage share of theoverall energy mix is declining (although rising in actualterms), the largest growth will be in gas consumption.

Gas is the outstanding fuel for power generation, withgas-fired power plants having the lowest capex, while pro-

ducing less than half of the CO2 emissions of coal. It isalso relatively cheap, and there are abundant reserves. Ac-cording to the International Energy Agency (IEA), thereis enough to last 230 years at today’s consumption levels.

A succession of giant gas finds in remote offshoreprovinces ranging from the emerging frontiers of theEastern Mediterranean to the outstanding resources offthe east coast of Africa and the west coast of Australia alllargely offer the same challenges: significant distancesfrom potential markets and—unlike oil—being too ex-pensive to consider transporting via pipeline.

e conditions were in place, therefore, for the rise ofFLNG as a viable field development solution. Floatingliquefaction first saw development in the 1970s, but itwas only at the start of this decade (May 2011, in fact)that Shell was the first to take the plunge and commit to

the development of its Prelude gas field offshore WesternAustralia. e field was only discovered in 2007.

is is the most well-known of the first generation ofFLNG facilities destined to start up in this decade, withFLNG’s inherent advantages—eliminating the need forfixed production platforms linked by pipeline to shore,providing more secure operations than onshore plants inregions of potential unrest and offering a solution fordealing with associated gas from remote offshore oilfields—all now recognized as viable and achievable.

Many others have or are in the process of following suit.e predicted growth for the global FLNG market is aston-ishing, with expenditure expected to rise from “just” $3.7billion (for the period 2007 to 2013) to $64.4 billion (2014to 2020), according to analyst Douglas-Westwood.

According to the analyst, about two-thirds of the totalspend is attributable to liquefaction infra-structure, while the remainder is from im-port and regasification facilities. Australasiaaccounts for the largest proportion of globalcapex at 30%, driven by its queue of lique-faction projects with a forecast expenditureof $19 billion between 2014 and 2020.

Year-on-year growth between now and2020 is forecast to average 64% per annum,and the analyst expects this rise to be morepronounced aer the successful startup andoperation of the first wave of FLNG vessels,namely Shell’s 5.3 MMtpa Prelude unit in theBrowse Basin (likely to be onstream beforeyear-end 2016), and also Petronas’ smaller1.2 MMtpa PFLNG 1 unit offshore Sarawak,Malaysia (planned for startup by year-end2015). e former’s design, constructionand installation is being undertaken by aTechnip-Samsung consortium, while thelatter is under construction at the DaewooShipbuilding & Marine Engineering ship-yard in South Korea.

Size is a factor in FLNG thinking.ierry Milatec, a lead process engineer atItaly’s Saipem, has worked on anotherFLNG project, Inpex and Shell’s Abadi fa-cility destined to work offshore Indonesia.Speaking at the Australasian Oil & Gasconference in Perth, Australia, he pointedout that an FPSO vessel might normally beabout 300 m (984 ) in length, while alarge-scale FLNG vessel is closer to 500 m(1,640 ). “And a 100-m (328-) increasein length means you can essentially doublethe production levels,” he said.

Inpex recently awarded parallel contracts forthe FEED of the Abadi facility, with one goingto a JGC Corp./PT JGC Indonesia consortium,and the other to a PT Saipem Indonesia/Saipem consortium. e eventual winner willprogress into a full FLNG engineering, pro-curement and construction phase.

A further FLNG unit also has been cho-sen by Malaysia’s Petronas for its secondsuch project in its domestic waters. It hasissued a design, build and installation con-tract for the 1.5 MMtpa PFLNG 2 unit, tobe located in deepwater off the coast ofSabah on the Rotan Field in Block H, withstartup planned for early 2018.

e engineering, procurement, con-struction, installation and commissioningcontract went to a consortium of JGCCorp., Samsung Heavy Industries Co. Ltd.,JGC (Malaysia) Sdn. Bhd. and SamsungHeavy Industries (M) Sdn. Bhd.

Petronas stated that, once operational,

Gas supply, Population Growth drive FlnG marketn e global FLNG market expenditure is expected to rise to $64.4 billion by 2020.

By MaRK ThoMas


see maRKet


at OTC 2014, Baker Hughes is presenting theNSURE invert emulsion drilling fluid system for

high-risk environments—a new technology to meet thechallenges of deepwater drilling.

Given the complexity and cost associated with offshoredrilling operations, operators are concerned with safety,compliance and how to minimize risk. Also, safely improv-ing performance over what has traditionally been seen isvital to reducing the number of costly drilling days. Withthese concerns in mind, the company began working withcustomers to develop a new fluid system for offshore op-erations that would address these needs while working toexceed performance previously seen in con-ventional offshore drilling fluid systems.

e NSURE invert emulsion system foroffshore drilling is the product of years of off-shore experience, paired with key attributescustomers wanted to see in a new system. De-signed to address multiple facets of risk andperformance affecting today’s offshore oper-ations, the system can help operators drilltheir offshore assets safely by mitigating riskswhile delivering increases in performance.

One of the keys to this is the system’sability to exhibit a constant rheological pro-file across the range of temperatures typicallyseen in offshore drilling environments. Inconventional invert emulsion systems, thefluid’s viscosity is highly dependent on tem-perature. ose systems tend to thicken atlower temperatures, creating high equivalentcirculating densities and surge pressures,while at higher temperatures, they can losemuch of their viscosity, resulting in a loss ofhole cleaning ability, and in the worst cases,loss of suspension qualities. ese trade-offsin properties have forced operators tochoose between ideal properties at higher orlower temperatures, even though both con-ditions might exist on the same drilling job.With NSURE, the system remains moreconstant across a wider range of tempera-tures, resulting in more predictable fluid be-havior, increased wellbore stability and lessrisk to the operator and the job. is leadsto balanced hydraulics that eliminate theconventional compromise associated withviscosity response to temperature.

e NSURE story began with BakerHughes bringing a new methodology tohow a constant rheology system is defined.Early in the design effort, the companydrew upon its knowledge and input fromkey offshore operators to define what prop-erties would be central to the system and itsperformance specifications. e result is asystem that is rigorously defined around

specific fluid property ratios as measured at both mud linetemperatures (cold) and drilling temperatures (warm).

is approach provided a quantitative improvement inthe system’s ability to bring greater control to fluid propertiessuch as plastic viscosity, yield point and gel strengths acrossa wide range of densities, base oils, oil-water ratios and con-tamination conditions. is translates to the NSURE sys-tem’s ability to retain more stable properties and to reducepressure spikes when initiating circulation, which takespressure off of the formation through lower equivalent cir-culating density.

Most importantly, with the system’s downhole proper-ties, the risk of lost circulation during cementing opera-tions is mitigated. is results in better cement

placement and reduced risk of channeling while pump-ing, either of which could otherwise jeopardize the suc-cess of the cement job. Should a well-control event beencountered, having the NSURE system in the choke/killlines will offer a readily pumpable fluid with less pressurespike effects than conventional systems, even if exposedto cold static conditions for a prolonged time.

e NSURE system also has a strong environmentalprofile, making it an opportunity for risk reduction tooffshore basins worldwide. Components of the systemcarry no substitution warnings in the U.K., are rated yel-low in Norway and meet the environmental require-ments of the Gulf of Mexico and elsewhere.

Visit Baker Hughes at booth 3731 for more information. n


drilling Fluid system minimizes Risk offshoren An invert emulsion system remains more constant across a wider range of temperatures, resulting in morepredictable fluid behavior, increased wellbore stability and less risk to the operator and the job.

ConTRiBUTed By BaKeR hUghes

The nsURe invert emulsion drilling fluid

pours easily after being chilled to -15 C

(5 F). (source: Baker hughes)

For all the talk of the intelligent oil field and smartwell-based operations, there are still areas of the

reservoir where operators struggle to access the requiredproduction information. is brings with it significantimplications for production control, well integrity andoffshore safety.

e potential information gap and the challenges thatsurround it have only increased during the last few yearswith the remoteness and challenging conditions of manyfields and the growth in highly complex horizontal andmultizone intelligent wells.

Emerson will be at OTC 2014 looking to bring greater

intelligence and integration to well integrity and produc-tion monitoring.

Central to many of these activities is the Roxar Intelli-gent Downhole Network (IDN). e IDN allows opera-tors to install up to 32 measurement instruments onto asingle cable enabling them to manage a range of produc-tion wells or separate zones simultaneously.

e intelligent network acts as a hub for downholechoke position indicators, third-party sensors and thetransmission of power and data, thereby providing crucialproduction information on temperature and pressure,water cuts, gas fractions, sand rates and flow velocity.

e IDN also communicates to all sensors, so if a fail-ure of one sensor occurs, all other sensors will still be

able to communicate to the surface. isfocus on longevity and robustness is beingseen in Statoil’s North Sea Gullfaks Field,where Emerson’s downhole pressure andtemperature gauges have been in operationcontinuously since 1991.

However, information gaps still remainin subsea operations, particularly betweenthe well casing in a part of the well knownas the annulus—an area that Emerson alsois addressing.

A completed well normally consists of atleast two annuli with the annulus B oen lo-cated between different casing strings. e an-nulus B is important, because it is the arealikely to see the first indication of high pres-sures farther down the well if the cement sealsbehind the wellbore casing are of poor quality.

While such increased pressures are to beexpected, if pressures go above prescribedlimits they can lead to the deterioration ofthe cement sealing or casing collapse, re-sulting in injection or reservoir gas migrat-ing toward the surface along the outside ofthe casing. In worst-case scenarios, this canlead to a shallow-gas blowout and a signifi-cant threat to offshore safety.

To date, however, the annulus B and thepressure and temperature informationwithin it have remained inaccessible to op-erators following the sealing and cement-ing of the casing.

Given the potential stakes of high pres-sures in the well, this lack of informationhas unsurprisingly led to an excessive andoverdimensioning of the casing to com-pensate for worst-case scenarios.

e completion engineer is therefore facedwith either increasing the pressure ratings ofthe casing or relying on shallow well zonesto absorb pressure rises. In some instances,wells have even been unnecessarily shutdown in an effort to protect well integrity.

Directly addressing this information gap,Emerson will be showcasing its RoxarDownhole Wireless PT Sensor System atOTC as well as its successful first deploy-ment for a North Sea operator.

e system monitors annulus B pressureand temperature wirelessly and continu-ously online for the life of the well. is

a step change in Production control, offshore safetyn Downhole network enables management of a range of production wells or separate zones simultaneously.


The Roxar downhole Wireless PT sensor

system monitors annulus B pressure and

temperature wirelessly and continuously

online for the life of the well. (source:

emerson Process Management)

By TeRJe BaUsTad, eMeRson PRoCess ManageMenT

see cHanGe


in the simplest terms, getting the most out of an assetmeans maximizing return on investment. As floating

production units (FPUs) worldwide begin to approachthe end of their design life, the question owners and op-erators are asking is how they can safely keep their assetson site and in production. In some cases, that leads to thequestion of whether it is possible to extend the life of thatasset. Fortunately, there are ways to meet both the pro-duction objectives and safety requirements that assetowners are looking for.

Many FPUs working today were designed to operateon site for about 20 years. At the time of construction,that design life aligned with the estimated field life.However, with delineation of more re-serves than originally estimated in thefield in some cases and with additionalfields being tied back to the production fa-cility in others, the 20-year life expectancyoften is considerably shorter than the ex-pected field life.

Owners of units that are classed by ABSare made aware that their FPUs are nearingthe end of their service lives. ey receivenotification five years before the end of thetime period for which the asset is classed.is notification provides the date aerwhich the asset will exceed the design lifeand will no longer be in class. It usually isat this point that most asset owners beginto think about the repercussions of replac-ing an FPU and the costs associated withthat replacement. Many make the decisionto initiate a life-extension process with aclassification society. At ABS, this processis available for any ABS-classed installationand is applicable to floating production in-stallations of any hull form, including ship-shaped, semisubmersibles, spars, ten-sion-leg platforms and hybrid designs.

Many factors affect the survivability andlongevity of an FPU such as its design, itsstructural integrity and the level at which ithas been maintained. Additional factors in-clude fatigue life and environmental loadchanges. ere are major challenges relatedto the hull structure of an FPU over time,and in the case of FPSO vessels in particu-lar, these issues can be even more challeng-ing because of the large number of onboardcargo tanks that must be inspected andmaintained.

In the course of the asset’s service life, alot of things can change. Process equipmentcan deteriorate, and corrosion protectioncan be depleted. In some cases, there is a se-vere operating environment to take into ac-count, or perhaps the asset has moved fromone location to another. In some instances,the use of the asset has changed, and some-times, the units have suffered damage orhave undergone weight growth or struc-tural capacity changes. Meanwhile, regula-tions could have changed. All of theseissues must be addressed in the life-exten-sion evaluation process.

These are the reasons the life-extensionprocess has to be undertaken methodi-cally and must take into account the in-dividual asset, its operating environmentand its maintenance history. The firststep in this process is to determine abaseline for the unit’s current conditionsthat takes into account historical opera-tional data. The second step is to assess

the status of the unit and the actual strength and re-maining fatigue life using analytical tools and engi-neering software. The next step is to determine fromthe data collected and from the results of the analysiswhat the remaining service life of the unit is and tospecify required remedial action. The final step is toestablish the path forward.

While reassessing FPUs is a challenging undertaking,it has the potential to deliver significant benefits, includ-ing an extended service life, an improved inspection andmaintenance plan, greater confidence in the asset’s futureperformance and oen the ability of an aging asset tomeet new regulations. By following a structured life-ex-tension process, asset owners can safely extend the op-erational life of their assets and increase the return ontheir capital investment. n

new approach safely extends FPu Field lifen Life-extension process is applicable to floating production installations of any hull form.

By BReT MonTaRULi, aBs, and daVid hUa, aBs gRoUP


The P-54, built in the 1990s, is one of the aBs-classed

FPso vessels working offshore Brazil that is approaching

the end of its design life. (source: Petrobras)


as oil and gas companies venture into sensitive areasin search of making hydrocarbon finds, the possibil-

ity of accidents remains on minds, and regulators world-wide are demanding that proper leak detection systemsbe in place, according to an industry expert.

But there is room for improvement when detecting oiland gas leaks offshore.

“I think it’s fair to say that the current leak detection sys-tems are a bit immature,” Christian Markussen, businessdevelopment manager for DNV GL, told E&P. Currently,there is no single best method for detecting offshore leaks,and “there is no one system that will do it all.”

There are subsea sensors, acoustic sensors that listenfor leaks, radar systems that look for leaks at the sur-face and satellite systems aimed at detecting leaks. An-other type of system tracks the amount ofhydrocarbons coming out of the well and the amountat the processing facility—any discrepancy is an indi-cation of a leak. Some sensors detect only gas. Somecover a small area with high sensitivity, while otherscover a large area with low sensitivity, according toDNV GL.

These concerns are among the reasons why DNVGL is leading a joint industry project (JIP) to createrecommended best practices for designing and imple-menting hydrocarbon leak detection systems for off-shore projects.

“ere are a variety of sensors out there, but most ofthem are plagued with being too sensitive so they actu-ally give too many false alarms. It’s a bit like the storyabout the boy who cried wolf. ey report nonexistentleaks, and aer you’ve done that a few times, then theyquit paying attention to them,” Markussen said.

A false alarm can cost about $1 million to investigate,sometimes more, he added. “ere is a balance to bestruck between being sensitive enough and being toosensitive in terms of how many false alarms it gives you.”

Another issue is that leak detection sensors availablehave limited coverage.

“e JIP will define relevant functional requirementsand general specifications for a leak detection system aswell as developing a methodology for designing an inte-grated system, including surface and subsea technolo-gies,” according to a news release.

e JIP is scheduled to last 18 months but could in-clude a second phase that might go into more detail con-cerning testing of leak detection systems, commissioningand calibration, Markussen said.

“Today all of these systems are put in, but you don’t re-ally know what the detection level is. For instance, if youare using an acoustic system and it picks up a noise thatsounds like a leak, that’s an indication,” he added. “Butyou don’t know how much is leaking.”

e JIP is being undertaken as public scrutiny remainshigh following the Deepwater Horizon accident. “It’s im-portant that the operators are perceived as actually step-

ping up and becoming more diligent about detectingleaks. at’s one element of it. Also as more prospectsopen in the Arctic and other sensitive areas, there is in-creased demand from regulatory bodies worldwide to ac-tually have proper leak detection systems in place,Markussen said.

Regulators in Norway, for example, require operatorsto have a leak detection system to get a permit to developa field offshore.

So far, 21 companies have signed up to participate inthe JIP. However, that number could grow.

“We are looking for additional participants just to havemore industry practice established and get a better buyin,” Markussen said.

Lundin Norway is among the operators taking part inthe project. Other operators include BP, Eni, Petrobrasand GDF Suez.

“Today, it’s difficult to get a good system with a demon-strated track record that covers an entire field, both sub-sea and on the surface. ere’s a strong need for acommon approach so that the operators and supplierscan jointly improve these systems,” Arnljot Skogvang, acompany representative at Lundin, said in a news releaseabout the JIP.

“We also need to define reasonable specificationsand requirements,” Skogvang continued. “It’s equallyimportant to consider how different technologies canbe integrated into a system that is practical for theend user.” n

JiP aims to improve offshore leak detection systemsn Limited coverage and false alarms are among the concerns.

By VeLda addison

From his origins as a Norwegian engineer to his newposition as managing director (MD) of SBM Off-

shore U.S., Stein Rasmussen has made the rounds of theindustry. Along the way he has picked up the valuableexperience that made him stand out from other candi-dates vying for his position. His international career,which spans 20 years in offshore facilities, allowed himto take the reins as head of the Dutch service provider’sHouston base. e Texas oil industry and its focus ontechnological innovation are not new to Rasmussen,who has worked for Technip (U.S.) and more recentlyas president of Aker Solution ED&S.

SBM is responsible for the world’s deepest FPSO ves-sel for Shell’s Stones development. A project managedfrom SBM’s execution center in Houston, the vessel isbeing converted and refurbished at Keppel in Singa-pore, which is where Rasmussen started his career aercollege. Just back from a visit to Keppel to oversee proj-ect progress since he became Houston’s MD, he ac-knowledged that it felt like coming full circle.

“I have a good, solid relationship with the team at Kep-pel, and this makes for an easy transition in my new role.FPSO [vessels] are a dominating part of my career, and thisis the shipyard where it began for me,” Rasmussen said.

Under the helm of CEO Bruno Chabas, SBM’s focusis clearly skewed toward FPSO vessels—the growth sec-tor of the offshore market. He explained that the Hous-ton office also is heavily invested in developments forsemisubmersibles and tension-leg platforms (TLPs),which in some instances complement SBM’s FPSO ves-sels and allow the company to offer clients a compre-hensive product portfolio. Oen a TLP and FPSO vesselwill work in tandem.

SBM holds the record for the deepest water depthsemisubmersible floating production unit, the Inde-pendence Hub, installed at a water depth of almost2,500 m (8,202 ). e under Hawk, a semisub-mersible production facility located in the U.S. Gulf ofMexico in 1,847 m (6,060 ) of water, started opera-tions in 2009 and has a maximum throughput of45,000 bbl/d of oil, with a gas-li and export capacityof 2 MMcm/d (70 MMcf/d).

As MD, Rasmussen sees his main focus as project ex-ecution. e Stones FPSO vessel tops the list, with ascheduled delivery date of 2016. Shell recently officiallyrenamed the FPSO vessel Turritella.

e project will break records with a list of industry

firsts. “e FPSO [vessel] is one of the most challengingdesigns for conditions in the Gulf of Mexico. Once in op-eration, it will be the deepest production unit in theworld. It is also the first disconnectable system with steelrisers. As a result, the Stones buoy has the biggest dis-placement for a buoy ever built to date,” Rasmussen said.“e project comprises high technological content.

“SBM has a strong relationship with Shell, which hasdeveloped over time and over many successful projects.We have a mutual respect and synergy. With Stones wetook the time to do a thorough FEED to define and de-velop the concept before going forward, which helps tomitigate new technology risks,” Rasmussen said.

e integrated Stones team works in two locations atthe project office in Houston and at the site in Singa-pore, where another Shell project also is being managedby SBM: the BC-10 rigless intervention system (RIS).

“is is an excellent example of a brownfield upgradeto an FPSO [vessel],” Rasmussen said.

The BC-10 project is a first in the FPSO industryfor intervention on subsea boosting electrical sub-mersible pumps. The RIS was developed by SBM as acomplete and dedicated intervention module forFPSO vessels, which can be part of an FPSO unit’s ini-tial design or incorporated at a later stage as in thiscase for the FPSO vessel Espirito Santo leased by Shelloffshore Brazil.

SBM takes on projects at all stages, from newbuildsto in situ modifications. Brownfield and life-extensionprojects are often the option of choice as oil and gasmajors seek to get maximum return on investmentfrom vessels that are producing. Making upgrades asopposed to commissioning a new vessel is proving tobe the most economical option. The FPSO vesselsMondo and Espirito Santo are two examples. n

Rasmussen assumes md Rolen New director brings years of industry experience and expertise.

ConTRiBUTed By sBM oFFshoRe U.s.

sBM's Turritella FPso will be used to develop shell's

stones Field in the gulf of Mexico. (source: sBM

offshore U.s.)


The global drilling industry is undergoing fundamen-tal changes including significant structural change as

well as a shi in requirements for operational perform-ance. International drilling contractors face stronggrowth that requires new ways of handling increasedpressure on human resources, equipment utilization andasset performance. is growth coincides with rapidlyevolving legislative and political environments in whichthe “license to operate” puts procedures, systems, visibil-ity and traceability to the test.

Drilling contractors are continuously exposed to regu-latory and commercial changes, together with frequent al-terations of customer demands. In fact, the industry isaffected by operational, financial and regulatory processesthat are far more complex than in any otherindustry. Consequently, companies thatstrive to be successful in this project- andcontract-oriented business must be able toquickly recognize and act upon industrychanges and changes within ongoing proj-ects and contracts.

For most contractors, long-term assetmanagement and maintenance still remainthe number one priorities. To secure anoptimized asset management process, sev-eral key functions must be in place: a well-functioning logistics operation in whichspare parts and plans for execution mustbe secured; full visibility, whereby com-plete offshore and onshore replication ofdata is essential; and traceability across allvarying layers.

Information technology (IT) can cer-tainly play a major role in fulfilling theabove challenges. Unfortunately, manydrilling contractors still struggle with frag-mented business solutions with severalvarying, nonintegrated, proprietary IT sys-tems that result in poor information flow,inaccurate and cumbersome data retrievaland reduced decision-making capability.

What are the factors to consider whenlooking for an enterprise resource planning(ERP) system that will enable organiza-tional responsiveness and optimization ofyour processes?

Visibility and traceability in the value chain Full visibility and traceability of the completeequipment and material life cycle are crucialin the oil and gas industry. All material trans-actions and completed equipment documen-tation from “as designed” to “as installed”must be accounted for. Regardless of where apiece of equipment, system or component isused, contractors must always be able to traceit back to the relevant requisition, purchase orshop order; project, supplier or stock number;and receipt or certificate. It must be conven-ient to search for relevant data, and contrac-tors need a high level of confidence thatinformation is secure and accurate.

Today’s industry still struggles with frag-mented business solutions that lack integra-tion, which makes it difficult to produce acomprehensive asset life-cycle view. Cur-rently, contractors probably face these issues:

• Extensive data silos; • Poor-quality data in information sys-

tems; • Limited value for operational teams; • Difficulties in gathering information; • Poor visibility across the value chain

(i.e. projects, purchase, operations);

• Difficulties in using frame agreements; • Nonintegrated cost management; • Mostly done in Excel (except recording of actual

and committed costs that are stored in the financialdatabase);

• Incomplete decision support; and• Consolidating reporting is cumbersome. Needless to say, this produces several inefficiencies for

operations (in decision-making) and for financial budget-ing and control. However, with a strategic ERP approach,contractors can eliminate these inefficiencies by enablingan integrated ERP system that can connect businessprocesses onshore and offshore and between rigs and sites.Facilitating information flow across varying disciplines willincrease efficiency and allow full visibility and traceabilityof equipment, material and people in the operations.

Financial management, control Use of nonintegrated and fragmented systems is timeconsuming. Getting the overall financial picture is bur-densome—and even more complex for drilling compa-nies that operate globally with varying regulations and taxregimes. One critical success factor is the ability to finan-cially track asset transactions such as movements of rigsbetween asset owners and contract or operating compa-nies, yard stays and modification jobs.

e ERP solution should support: • One common solution for asset, logistics, contract,

projects and finance—to secure traceability and visi-bility throughout the life cycle of the asset/rig and to beable to trace and monitor the total cost of ownership;

eRP selection for Global drilling contractors n An ERP system can help manage integrated projects, asset life cycles, data communications and subcontractors.

ConTRiBUTed By iFs noRTh aMeRiCa

see system continued on page 42


Together, Houston-based Excel Engineering and in-ternational engineering and design consultancy

group Ramboll now take up competition on the U.S.market for oil and gas solutions.

In October 2013 Excel Engineering was acquired bythe Ramboll Group, and the agreement was officiallysigned in Houston by John Sørensen, managing directorat Ramboll Oil & Gas, and Mostafa Jamal, president andCEO of Excel Engineering. As of May 1, 2014, Excel En-gineering started trading under the Ramboll name.

e acquisition is part of Ramboll Oil & Gas’ growthstrategy toward 2020. is strategy includes farther geo-graphical expansion—the company currently has a pres-ence in seven countries—and an increase in the numberof employees from the current 1,000 to 4,000.

According to the Houston Business Journal, Excel En-gineering ranks among the top 25 energyengineering firms in the Houston area. eRamboll Group’s revenue exceeded $1.4billion in 2013, and the company wasranked No. 29 on Engineering News-Record’s list of overall global design firmsin 2012, making it the fourth largest con-sultancy group in Europe.

Playing with the big boys“We believe that Excel Engineering andRamboll Oil & Gas form a great strategicmatch. e American oil and gas marketholds enormous business potential and issoon set to regain its position as the world’slargest oil and gas producer. Gaining afoothold in Houston allows us to serviceboth existing and new clients on a new con-tinent and also may function as a steppingstone for realizing future oil and gas proj-ects in Africa and South America,” saidSørensen. “Houston has been dubbed theoil and gas capital of the world, and if we asa company want to play with the big boysand land the big projects, we need tobe active here.”

Multidiscipline group covering oil, gas andoffshore windBesides more traditional engineering disci-plines, Ramboll offers nontraditional serv-ices such as environmental studies andstrategic and commercial consultancy.

“Becoming part of a 10,000-personmultidiscipline organization such as theRamboll Group is exciting and obviouslyprovides us with a much larger pool ofresources to draw on,” Jamal said.

An example of this multidiscipline en-gineering spillover is that Ramboll’s ex-isting knowledge within offshorestructural design is now transferredfrom the oil and gas market to renew-ables. The company is responsible for de-tailed design of the steel monopileoffshore foundations for all 130 windturbines for the Cape Wind OffshoreWind project. This will be the first off-shore wind project to be developed, per-mitted and built in the U.S.

Ramboll works under several frame-work agreements with major oil compa-nies like Hess, Maersk Oil, Total E&P,Qatar Petroleum and Statoil, coveringmodifications, multidiscipline engineer-ing studies and subsea pipeline design.

In particular, Ramboll holds experiencefrom projects carried out in the North Seaand in the Middle East. Now it seems asthough the company has set its sight on de-veloping business in the U.S. n

europe’s Fourth largest consultancy Group moves to Houstonn e acquisition of two companies is part of a growth strategy, which includes geographical expansion and offering nontraditional services such as environmental studies.

ConTRiBUTed By RaMBoLL“houston has been dubbed the oil and gas capital of the

world, and if we as a company want to play with the big

boys and land the big projects, we need to be active

here,” Managing director of Ramboll oil & gas John

sørensen said. (source: Ramboll)

Well cementing is a crucial component of well in-tegrity, and in recent years the need for a high-

quality primary cement job has become more critical. Inresponse, the industry is pursuing enhanced cementingequipment performance standards.

e American Petroleum Institute’s RP 10F report pro-vides recommended testing practices to evaluate the per-formance of cementing float equipment, but it does notinclude cementing plugs. It is imperative that this per-formance is well understood, particularly in deepwaterwell construction.

A new plug locator system (PLS) devel-oped by Weatherford enhances this under-standing in critical applications by makingit possible to precisely locate the cementingplug at multiple points in the casing string.

Cementing plugs are not only used forthe separation of fluids inside of pipe butalso remove residual mud film and othermaterials from the inner surface of the pipeto improve well integrity. Currently, wipingefficiency is defined as the measure of me-chanical wiping of the tubular inside diam-eter (ID) performed by the cementing plugor similar device.

Wiping efficiency is directly related towear resistance of cementing plugs and bal-ancing the design for stiffness and pressurecontainment. is is only achieved throughrigorous material testing and design refine-ment. In addition, collecting and analyzingwiper cuttings samples provide a clear un-derstanding of the system’s ability to providea physical barrier to separate fluids andfunction downhole tools. is evaluationhas provided information on material lossand positive fin interference and corrobo-rates design performance on lengths of cas-ing greater than 4,877 m (16,000 ).

e operation of downhole tools andproviding a surface indication of a down-hole event are critical functions of a seem-ingly simple piece of equipment. Not

landing a top plug in a primary cementing applicationcan significantly increase time to drill the shoe track re-sulting in nonproductive time (NPT) at $50,000/hr ormore due to underdisplaced cement. Time to drill un-derdisplaced cement can range from half an hour tomore than 20 hrs.

Displacement errors and additional costs can be causedby plug wear, pump efficiencies, fluid properties and casingID tolerances. Nonaqueous drilling fluids with variablecompressibility characteristics increase the complexity offluid modeling, which could lead to displacement errors.is issue is of particular concern as long, high-volume cas-

ing strings become more prevalent in deepwater well de-signs. Alternatively, overdisplacement can lead to insuffi-cient zonal isolation and compromised well integrity, whichrequires costly remediation before continuing to the nexthole section.

Accurately locating the plugs during cementing is vitalto optimally placing cement, testing the casing, function-ing pressure-activated equipment, such as liner hangers,and minimizing drill-out time. A positive indication onthe rig floor of the plug’s exact position in the casing string

cement Plug locator assures Plug Performance in critical deepwater applicationsn A new plug locator system makes it possible to precisely locate the cementing plug at multiple points in the casing string.

By doUgLas FaRLey, WeaTheRFoRd


The Weatherford PLs ensures optimal ce-

ment displacement by providing positive

surface indication of the top plug’s exact

position in the casing string before the

plug bumps. The system is being used

successfully in deepwater applications in

the gulf of Mexico, Trinidad and the asia-

Pacific region. (source: Weatherford)

see locatoR continued on page 42

drilling contractors require reliable systems with con-sistent performance. e Stand Transfer Vehicle

(STV), a fingerboard-mounted pipehandling system,eliminates the derrickman’s manual duties. Critical to op-erational success is tripping speed, simplicity and follow-ing procedures that mirror manual operation. e STVremoves the derrickman from harm’s way and providesaffordable and robust pipehandling.

e machine, a collaboration between National OilwellVarco and a drilling contractor, provides a safer solutionwithout sacrificing manual tripping speeds. e pipehan-dling system was designed with the following parameters:

• Maintain or increase tripping efficiency;• Mirror operations of a manual derrickman;• Capable of handling 3½-in. to 10-in. drillpipe and

drillcollar without insert size changes;• Modular installation and removal of the STV dur-

ing rig up and rig down;• One-man operation, with a derrickman running

the tool on the rig floor;• Visual feedback of the STV position and operation

without the use of encoders; and• Manual racking is possible if the tool is down.

Design approachVertical pipehandling systems are oen on offshore rigsbut are not widely adopted in the land market. e exist-

ing offshore pipehandling solutions wereevaluated before starting prototype devel-opment for land drilling applications butdid not meet land design requirements dueto size, weight, complexity and cost.

The initial design was installed on a1,500-hp rig to test the concept of the tu-bular guiding head and movement of thestand between the fingerboard slots andwell center. The key to this first designwas to test the tubular guide head with avariety of pipe sizes and record the dex-terity of the head when moving standsbetween the fingerboard and the elevatorat the well center. The design needed toallow efficient installation and testingduring repeated rig moves. The guidearm was supported from the divingboard, which was integrated into themain fingerboard support structure. Thisallowed the machine to be fully factorytested as a system prior to delivery to thefield, which reduced installation time.The guide arm trolley uses a fingerboardindex camera that aligns the guide armand head with the fingerboard slots. Thisallows the operator to stop the machineat the required slot, which providesseamless movement of the stand betweenthe diving board alleyway and finger-boards. Additionally, line of site to themachine from the drill floor is greatlyimproved, because the guide arm isbelow the diving board.

The final challenge in the design wasa simple and robust control system thatallowed manual hydraulic control fromthe fingerboard and remote control fromthe driller’s cabin. Because the STV doesnot incorporate encoders for positioncontrol, a dual camera and monitor sys-tem provides visual feedback. One guidearm mounted camera follows the guidehead along its path to and from the wellcenter. The other fixed well center viewcamera monitors handover between themachine and the elevator. These camerasand monitors allow immediate verifica-tion of the operator’s joystick and switchcommands. This greatly reduces thetraining time for efficient operation ofthe STV.

Pipehandling in land drilling operations n Tool offers a combination of safety, reliability and performance and is gaining momentum with drillingcontractors and operators.

By JoeL heinen and ToM yosT, naTionaL oiLWeLL VaRCo


Continued on next page

national oilwell Varco and a drilling con-

tractor's pipehandling system provides a

safer solution without sacrificing manual

tripping speeds.

(images courtesy of national oilwell Varco)

Prototype trial period outcomese trial period started in the Barnett Shale and was a col-laborative effort that provided valuable feedback. etesting improvements include:

• Breakaway diving board. e prototype divingboard connection provided a breakaway designthat clamps in place and uses replaceable shearpins to allow board rotation if contacted;

• Passive fingerboard stand restraints. Each row ofstands is held in place by a pneumatic latch, whichis remotely controlled from the operator’s console.During the trial, inflatable air bags proved the mosteffective in retaining the finger’s worth of pipe withthe latch at the end as the other form of retention;and

• Installation, transport and storage frame. A multi-use STV support frame allows safe and efficient in-stallation of the machine into the fingerboard. isframe also allows on-the-ground and in-the-masttesting and maintenance of the machine. Finally,

this frame provides a storage area for maintenanceand troubleshooting, allowing manual racking ofthe fingerboard.

Features and benefitsRelocating the derrickman near the driller on the floorallows better communication and training among thecrew. When breaks or tour changes are required, the floorhands, derrickman, driller and toolpusher can operatethe tool.

e features and benefits include increased safety; im-proved communication; interactive training; no loss ofefficiency; heavy-weight drillpipe and direct current ma-nipulation; consistent tripping operations; easy, intuitiveand ergonomic controls; continuous operation; reducedcrew fatigue; simple and robust design; and easy trou-bleshooting and maintenance.

e STV is the result of a thorough design process andprototype trial period that produced a unique but simpletool that is quickly gaining momentum with drilling con-tractors and their operators. e tool offers a combina-tion of safety, reliability and performance. n


Continued from page 32

Pemex continued from page 5

The sTV increases safety and improves communica-

tion, according to national oilwell Varco.

“We would like to be a competitivecompany, but at the same time, we needto pay competitively. We have to con-vince people that we are committed toretaining talent [and] we will be compet-itive according to the international mar-ket,” he said, adding that Pemex will needto move in a “different way than we havein the past.”

Hernández-García said Pemex looksforward to partnering with other com-panies, particularly in areas wherePemex doesn’t have precise expertisesuch as unconventionals, deepwater, ma-ture fields and shallow water. WhereasPemex has been the only operator inMexico and had to contract with servicecompanies, the reforms will put partner-ships on the table. Those relationshipswill be key to bringing much-neededtechnological expertise, as well as capi-tal, to the company, he said.

To foster growth in potential partners’interest, Pemex must adopt a businessmodel that includes risk-reward parame-ters, valuation strategy and portfolio man-agement. What’s more, though, thecompany must develop a value proposi-tion to position it as an attractive partner.And, Hernández-García said, “We needthe ability to choose the right partner.”

What’s more, Pemex leaders are prepar-ing to compete for the first time to secureacreage during upcoming bidding rounds.As such, the company is working to fostertransparency and accountability with a re-sults-oriented culture that operates in a“fish-bowl” environment, he said.

All that activity will be subject to newmandates and newly created commissionsdesigned to enforce those mandates, hesaid. Agencies to oversee energy regula-tions, environment and safety—equippedwith appropriately trained technical staff—will be critical to the reforms’ success.

All told, Hernández-García said theseefforts are designed to increase opera-tions, share risk, strengthen the companyand bring together capital and technologythat will strengthen the company.

“More players and more investmentswill equal more production and more rev-enue for the country,” he said, adding thata critical function of the reform is to con-vince players on the world stage that “theycan go to Mexico to invest, because wehave a lot to offer.” n


aconsortium of leading oil and service companies ac-tive in the deepwater Gulf of Mexico (GoM) will de-

fine required modifications to the existing deepwatermodel from SEG Advanced Modeling Corp. (SEAM) andResearch Partnership to Secure Energy for America(RPSEA) using real rock and geophysical data (publicand proprietary) and active experience with deep abnor-mal pressure environments and shallow hazards to de-velop a methodology based on the upper limits ofseismic data for use in predrill pore pressure prediction.Integrated pressure predictions from many data sourcesand inclusion of avoidance and mitigation procedures inthe drilling plan are still ambiguous and not risk-freewith current technologies. One of the most importanttechnologies for pressure prediction in the early wellplanning stage, that is predrill, is 3-D seismic.

Gas and fluid-charged overpressure zones are seriousprimary drilling hazards, both in the shallow subsurfaceand at reservoir depths. Drillers routinely prefer highermud weights to force back formation pressure as a safetymeasure. Remote sensing prediction at depth is very dif-ficult and subjective. Direct pressure predictions meas-ured in a well during drilling oen are flawed.

Why do engineers and subcontractors not believe orfully trust either the reported pore pressure predictionfrom seismic or direct pressure measurements? Experi-ence with the methodology from their perspective ofyears of efforts told them it was only an approximationand oen incorrect.

“Although there are no sanctioned guidelines or reg-ulations governing how to run a negative pressure test,the critical importance of such tests requires that everycompany have formal procedures established for carry-ing them out,” according to an interim report releasedby the National Academy of Engineering and NationalResearch Council. “Sometimes these procedures needto be adapted for the configurations of a particulardrilling vessel and BOP. While there are also no formalguidelines for the interpretation and approval of the testresults, it is clear that pressure buildup or flowout of awell is an irrefutable sign that the cement did not estab-lish a flow barrier.”

No guidelines exist either, whether formal or informal,for prediction ahead of the bit. Most operators use in-

house rules of thumb; some are better than others. oserules all rely on velocity inversion equations establishedin the 1950s and applied to seismic in the 1980s. Allmethods apply theoretical assumptions that are difficultto determine by more than just anecdotal examples.Consequently, calculations of pore pressure ahead of thebit remain highly subjective. A significant barrier to im-proving the methodology has been the lack of accurateand precise data of the subsurface calibrated back to ei-ther well logs that are used in prediction or 3-D seismic.

A complex geologic and synthetic geophysical modelfrom SEAM is available for this project. e model wascreated around ultradeepwater reservoirs known in theGoM, including subsalt features. To determine accuratepore pressure numbers from a seismic dataset, the cali-bration must first assess rock with in situ fluid proper-ties. Most technologies today only determine fluidproperties with a series of assumptions that add to errorand uncertainty.

Objectivesis project will deliver a simulated seismic dataset thatwill be used by industry and academic research to inves-tigate improved approaches for prediction of shallowhazards and deep overpressured reservoirs. Subsets ofthese simulations will be made available to consortium

members and the wider industrial and academic com-munities for ongoing research on improved seismic ac-quisition, processing and interpretation methods forpredicting abnormal pressure at both reservoir depth andshallow hazards.

e second objective of the project will be to reducedrilling risk—both safety and environmental—throughimproved predrill pressure prediction methodologiesthat are derived from iterative interpretations of thebenchmark model. SEAM will create a pore-pressure andshallow hazard prediction methodology report and rec-ommendations for use in well planning.

is project meets the following Department of En-ergy (DOE) 2012 objectives:

• Improved well control technologies and techniques;• Assessments and quantification of risks of environ-

mental impacts from deepwater oil and gas E&Pand drilling activity on newly developed technolo-gies; and

• Research on sensors, instrumentation, commandelectronics and advanced data interpretation tech-nologies.

Funding for the project is provided from lease bonusesand royalties paid by industry to produce on federallands. RPSEA is under contract with the DOE’s NationalEnergy Technology Laboratory to administer three areasof research. Additional information on RPSEA can befound at rpsea.org. n

examining Pore Pressure Prediction methodology for identifying subsurface Hazards in avoidance strategies through improved seismic imagingn One of the most important technologies for pressure prediction in the early well planning stage, that is predrill, is 3-D seismic.

ConTRiBUTed By RPsea

The input geologic model of typical goM subsalt used

in the benchmark seaM Phase 1 study of “perfect” 3-d

seismic data characterization is shown. This geologic

model was constructed from the input of more than 42

companies working offshore in the goM.

(source: RPsea)

seismic by itself is meaningless in pore-pressure pre-

diction without quantified calibration with rock and

fluid properties. This caricature flow diagram illustrates

the logical relationship, creating geophysical properties

from surface and well technology from among reser-

voir rock physics and the physics of 3-d seismic, elec-

tromagnetic methods and gravity measurements as

used in building the Phase 1 data library.

(source: RPsea)

industry newsnew Report Predicts strong Growth

for us onshore Pipeline industry

Demand for onshore pipelines will increase in the U.S.,providing a positive outlook for the North American oiland gas industry, according to a new report conductedby Europe’s second largest steel producer, Tata Steel.

The study, produced by the company’s energy andpower division, points to a rise in environmental con-cerns shifting energy demand toward natural gas andthe continued growth in shale as the main drivers forincreased investment in production and transport in-frastructure.

e report also highlights that the reduction in theprice of natural gas combined with improved drillingtechnology will still mean high oil production, which will

result in further demand for pipelines going forward.“U.S. shale has been a game changer for the entire

North American industry, potentially putting the U.S.in a position to export energy for the first time,” saidRichard Broughton, commercial manager for the pipesdivision of Tata Steel. “However, there is still a massiveneed for investment in infrastructure particularly withregard to production and transportation if this potentialis to be realized.”

Overall, the report paints a positive outlook for theNorth American industry, with the findings suggestingthat while a slow economy has had an effect on produc-tion activity in recent years, the increased investment in

a new report by Tata steel predicts that demand for

onshore pipelines will increase in the U.s. (source:

Tata steel)

see industRy neWs continued on page 39

companies Warned about Project

delays in norway

Norwegian Prime Minister Erna Solberg has given oilcompanies a heads-up that they risk losing the govern-ment’s goodwill if they go in for unacceptable delays totime-critical projects.

“Licensees have a responsibility to society to extract allprofitable resources from the fields. If projects are put onhold with a view to cutting costs in the short term, thismeans that licensees will not be able to fulfil their obli-gations to utilize all available and profitable resources,”she said at a recent conference. “Cost reduction is impor-tant, but some measures are unacceptable.”

e industry is struggling at times to achieve viability.Last year, Shell shelved the proposed Linnorm develop-ment, while Statoil decided to review plans for Johan Cast-berg and cancelled the planned Kristin gas export pipeline.

Even Petoro, which manages the state’sdirect investments in the offshore industryand is a keen supporter of measures to im-prove recovery, warned recently that costinflation could lead to project cancella-tions. Rising costs would oblige it to investtwice as much in coming years as in thepast to stop production falling, Petoro said.

e Norwegian Petroleum Directorate(NPD) believes that oil reserves could growby 7.5 Bbbl during the next 10 years, an es-timate made up of improved recovery fromfields in production, the development of dis-coveries and so far undiscovered resources.

About one-quarter of the 400 plus discov-eries made in Norwegian waters to date arecurrently being developed or considered fordevelopment. Most of these will probably bedeveloped with subsea facilities tied into ex-isting infrastructure, the NPD said.

Cost trends pose a challenge, both fordeveloping discoveries and for projectcommitments that can increase recoveryfrom a field. “For example, drilling costshave more than doubled during the last 10years,” Director Jan Bygdevoll said. “iscost growth could threaten the profitabilityof future projects.”

castberg to Get vast

seabed infrastructure

Statoil is planning to use a vast array ofsubsea structures as part of the Johan Cast-berg FPSO development in the Barents Sea,according to a recent presentation at a con-ference in northern Norway.

e subsea infrastructure will include14 templates of 250 mt to 300 mt, 14 riserbases of 40 mt to 175 mt, 19 plems andplets of 5 mt to 105 mt, 17 tie-in tees of 10mt to 120 mt and 45 riser and floater an-chors of 60 mt to 180 mt.

According to the impact proposal issuedalmost a year ago, 38 wells will be requiredto develop Castberg’s 400 MMboe to 600MMboe. is number might havechanged during Statoil’s review of the proj-ect, which was prompted by a tax hike.

Decision soonThe concept selection is due to takeplace in June, when a choice will bemade between a floating productionunit (FPU) combined with an oil-exportpipeline to shore and an FPSO vesselwith offshore loading.

e local population is naturally verymuch in favor of the FPU solution, buteven if it doesn’t get it, there will still beservices, such as supply bases, to be pro-

vided locally. Local fabrication of some of the equipmentalso might be possible.

Meanwhile, a Technip official gave a rundown of theinfield pipelay scope, which includes 33 km (21 miles)of pipe-in-pipe production lines, 18 km (11 miles) offlexible water injection lines and 35 km (22 miles) of gasinjection lines as well as 37 km (23 miles) of umbilicalsand 16 risers. Up to 140 tie-ins will be required. Accord-ing to Statoil, up to 350,000 mt of rock will be dumped.

Subsea construction will take place from 2017 to 2020with startup in the latter year rather than late 2018 as ear-lier envisaged. Opex will be about $335 million per year,again offering opportunities for local procurement. n

is was compiled and edited by Steve Sasanow for SubseaEngineering News. Visit epmag.com/order/SEN for moreinformation.

subsea engineering news


Transocean’s Polar Pioneer rig in the Barents sea drills

the original discovery well on skrugard, since renamed

Johan Castberg, and is due to feature substantial sub-

sea infrastructure. (Photo by harald Pettersen, cour-

tesy of statoil)

The Caspian Sea is the largest inland body of water in theworld. It is, in fact, salty but is not connected to nor does

it drain into an ocean. Its sea level is regulated by evapora-tion and is just under 30 m (98 ) below sea level. Its 7,000-km (4,200-mile) coastline encompasses Russia, Kazakhstan,Turkmenistan, Iran and Azerbaijan. e sea has an averagedepth of 190 m (623 ), and its deepest point is 1,025 m(3,362 ). In winter almost one-third of the northernCaspian Sea freezes over. In summer the Iranian sector seeswater surface temperatures of about 30 C (86 F).

e major commercial activities in the Caspian Sea areoil and gas, tourism and fishing. Since 90% of the world’s

sturgeon population lives in the Caspian Sea, protectingthe natural environment is very important. Hence, all oiland gas activities must obey a zero-discharge policy duringdrilling operations.

Eurasia Drilling Co.’s (EDC) offshore division, known asBKE Shelf, has its origins in Lukoil Shelf Ltd., which itselfwas founded in 1999. EDC entered the offshore drillingmarket in 2006 with the purchase of Lukoil’s Astra jackupin the Caspian Sea. BKE Shelf has since grown to be thelargest independent offshore operator in Russia and cur-rently has three jackups operating—the Astra in Kazakhstanand the Saturn and Neptune jackups in Turkmenistan wa-ters. A fourth jack-up, Mercury, is under construction.

EDC also provides drilling services on Lukoil’s ice-re-

sistant offshore platform LSP-1 on the Korchagina Field inthe Russian sector. e contract for that rig is a “life-of-drilling” contract. Since the start of drilling on this plat-form, more than 16 wells have been constructed, andmany of these are extended-reach wells with the longestbeing more than 7,600 m (24,928 ).

e Astra is a Baker Marine Services BMC-150-H de-sign capable of drilling to 4,878 m (16,000 ) in waterdepths up to 38 m (125 ). It has been drilling in Russianand Kazak waters and has been the workhorse for manydiscoveries, including the eight fields discovered byLukoil. To date, the jackup has drilled 41 new wells andone workover.

Nineteen exploration and appraisal wells were drilledfor Lukoil in the Khvalynskaya, Shirot-naya, Rakushechnaya, Diagonalnaya, Sar-matskaya and West-Sarmatskaya fields. Afurther exploration well was drilled for theKNK Consortium (Rosneft/Lukoil) in theUkatnaya Field.

Astra also drilled 11 directional develop-ment wells and performed a workover forDragon Oil in the LAM Field in the Turk-menistan Sector.

e jackup also has been used in theKazakhstan Sector, drilling 10 explorationand appraisal wells across the followingfields: Tub-Karagan Field for KMT and Ros-ne; Kurmangazy Field for KMG andLukoil; Auezov, Khazar, and Tulpar fields forCMOC, KMG, Shell and Oman Pearls Co.;Atash Field for KMG and Lukoil; and N-Block for N-Operating Co. As of Aug. 1,2013, another well was drilled on PearlsBlock (Naryn-1) for CMOC.

e Saturn was purchased from Transoceanin 2011. Since then, this rig has drilled 34 newwells and performed 14 workovers. irty ofthe wells and all of the workovers were forPetronas in the Magtymguly, Diyarbekir,Mashrykov and Garagyol fields in Turkmenwaters. e year 2013 marked the beginningof a three-year contract to drill wells forPetronas in Turkmen waters.

Saturn also drilled two exploration wellsfor Japan Azerbaijan Oil Co. offshore Azer-baijan and two exploration wells in theKazakhstan sector—one for AGIP KCO inthe Kalamkas Block and one well for CMOCin the Pearls Block.

BKE Shelf recently was awarded a three-year development drilling contract byDragon Oil for its Cheleken developmentin Turkmenistan waters. BKE Shelf willservice this contract with its two newbuildjackups. ese LeTourneau S116E rigs werebuilt by Lamprell in modular form in Shar-jah and shipped through the Volga-DonCanal System for final assembly in As-trakhan, Russia. e rigs are capable ofdrilling to 9,146 m (30,000 ) in up to 107m (350 ) of water.

Neptune, the first newbuild, was recentlycompleted and commissioned. e rigstarted work in November. It will be re-placed by Mercury when the latter is com-pleted in November 2014. Neptune has acommitment to drill for another client inRussian waters at year-end 2014.

e future for the Caspian Sea looks verybright due to the large number of explo-ration licenses yet to be drilled. And if thisleads to more discoveries, there will be a sig-nificant amount of development drilling re-quired to put these fields online. n

drilling Poses challenges in caspian sean Two jackups were built in modular form in Sharjah, shipped through the Volga-Don Canal System and assembled in Astrakhan, Russia.

By ToM o’gaLLagheR, eURasia dRiLLing Co.



OECD countries will have started to ‘crack the code’ ofsustaining economic growth while reducing energy de-mand,” he said.

“We have [once again] revised our forecast higherfor U.S. shale gas and tight oil,” he said. “The dramaticincrease in domestic production in recent years hasmade the U.S. the world’s largest producer of naturalgas and liquid fuels and has allowed the U.S. to cut itsimport dependence sharply [in the case of oil, by half].For the past two years, the U.S. has had the biggest in-crease in oil production in the world and the biggest in-crease in our own history.”

Long-term energy trends demonstrate that achievingsustainable growth remains a challenge despite energyefficiency improvements as energy demand in develop-ing countries, and therefore global CO2 emissions, con-tinues to grow.

“Virtually all [95%] of the growth in global energy de-mand will be in the rapidly-growing emergingeconomies, especially in Asia,” he noted. “We believe that

the U.S. and other mature economies will eventually fig-ure out how to achieve continued economic growth with-out growing their energy demand. at partly is due tosignificant improvements in energy efficiency. We esti-mate that by 2035 the amount of energy needed globallyto produce a dollar of economic output will have fallenby 36%.”

Energy efficiency, combined with what the companyfinds to be adequate hydrocarbon resources, will fuelcontinued growth for many decades to come, he said.

“In our ‘Statistical Review of World Energy,’ we havetracked global proved reserves for oil and natural gas formore than 30 years, and the data rise strongly over time,”he said. “One reason we are optimistic the world can havesufficient energy is that we see competition and innova-tion driving rapid growth of new forms of supply, suchas shale gas and tight oil.”

e U.S. will continue to dominate global productionof tight oil and shale gas—even in 2035—due to factorsspecific to the country, according to Finley.

“The ‘above ground’ factors that have driven therapid growth of shale output in the U.S.—including a

large and highly competitive domestic industry and asystem of private ownership of property—are difficultto duplicate elsewhere,” he said. “And it’s important thatwe not take the success of these factors here in the U.S.for granted.”

To read more about the company’s energy outlook, visitbp.com/energyoutlook and bp.com/statisticalreview. n

demand continued from page 1

initiative continued from page 1

Carrier said. “Aer that, it is too expensiveto maintain the equipment needed for pro-duction on the FPSO.”

It will take a variety of EOR techniquesto optimize production in the fields oncethe FPSO vessels have reached their agelimit, Carrier said. at is why Total hasteamed with other operators and servicecompanies in an initiative called ProjectosBrown Field (PBF). e goal, he said, is toensure that the existing facilities, synergiesand production techniques are maximizedamong the area’s deepwater projects so thatthe maximum reserves are tapped.

“PBF is one of the largest projects of itskind in the world,” Carrier said. “e ob-jective of PBF is to maintain the directionof the plateau of the FPSO. We have tomanage the decline of the field and maxi-mize production from the FPSO by main-taining the plateau for as long as possible.”

Carrier said this project is particularlyimportant to Total and its partner, Sonan-gol, Angola’s national oil company, becauseit will help the country maintain its oilprices. If too many projects fall offline andoil becomes scarce in the country, it willdrive up demand and prices, making thesituation difficult for the country’s citizensand for its national security.

As PBF gains traction, Carrier said Totalshould be able to achieve its goals of pro-moting more efficient and longer-lastingproduction in its ultradeepwater Block 17.

“We are working very early in the con-tracting strategy to try to reduce the timeof the equipment wearing,” Carrier said.“We are welcoming different technologiesand theories from other companies.”

Carrier said a few of the main objectivesof PBF are:

• To maintain the production plateausof the operator’s existing and newCLOV FPSO vessels by limiting thenatural decline of the fields andmaximizing the existing productionon the FPSO units; and

• To develop infill wells, satellite fieldsand marginal reservoirs.

“We intend to rely heavily on EOR tech-niques and on our collaboration with our pro-duction guys in order to integrate the PBFproject as best as possible,” Carrier said. “Wehope to bring together this knowledge and ex-perience and work together very closely withour subsidiaries in order to develop thesemarginal reservoirs at a price that works.” n

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omv eyes new Wos Hub

OMV is serious in its bid to become a major player in theWest of Shetland (WoS) region by revealing plans for anew deepwater development hub based around its re-cently acquired Cambo oilfield asset.

Confirming its decision to buy the WoS portfolio heldby Hess, which includes the undeveloped Cambo discov-ery, OMV has gone on to outline its intention to use thefind as the basis for a new harsh-environment field centerto which other nearby discoveries will be tied back.

Deepwater International (DI) also has confirmed thatthis will be separate from the stalled Rosebank FPSO ves-sel project operated by Chevron (a partner in Cambo)located to the northeast, in which OMV also took a sig-nificant stake toward year-end 2013.

“We are considering a range of development concepts.As there are currently a number of potential tieback op-

portunities to Cambo and given other prospects that arelikely to be drilled in the coming years, we expect thatCambo will be developed as a separate hub,” an OMVspokesman told DI. Denmark’s DONG Energy also is a20% stakeholder in Cambo.

Work on Rosebank—previously tipped as whereCambo was to have been tied back to if developed—willcontinue as a separate project. “e Rosebank partnersare aligned in the need to optimize the development ofRosebank and are working effectively together to do this.is has not been impacted by OMV’s additional equityacquisition in 2013,” the OMV source said.

Cambo was discovered in 2002 in a water depth ofabout 1,100 m (3,608 ). Floating development solutionsare likely to be the way forward, although studies havenot yet been undertaken on whether to go for an FPSOvessel, spar, semisubmersible, tension-leg platform or

other facility. Conceptual studies are expected to get un-derway this year for the field in U.K. Block 204/5a.

Four wells have been drilled at Cambosince the initial discovery probe, includingCambo-4 in 2011 and Cambo-5 just lastyear, drilled by the Stena Carron drillshipwith Chevron as the operator.

With its latest asset deal, OMV is acquir-ing four licenses from Hess—includingP1028 and P1189, containing Cambo,where OMV increases its equity from 15%to 47.5%; and P1830 where OMV’s stakewill rise from 25% to 75%, which containsa prospect called Blackrock. Blackrock isscheduled for drilling next year. OMV alsois acquiring a 75% equity in P1831.

OMV is paying Hess $50 million initiallyfor the portfolio and a further contingentpayment of $35 million dependent on fu-ture development.

OMV indicated that the Hess transactioninvolves 60 MMboe of recoverable reserves,mainly in Cambo, and has plans for furtherappraisal of the area’s potential, includingBlackrock.

Outlining the rationale behind the Hessdeal, the company said, “OMV U.K. has aunique position in the Cambo area offeringpotential valuable synergies, with the adjacentOMV-operated Tornado gas/condensate dis-covery and the Suilven discovery. ere alsoare further prospects with tieback potential todevelop Cambo as a valuable area hub.”

At present, there is little infrastructure inplace, with other projects underway in theregion, including Total’s Laggan/Tormoreproject, currently being developed as a sub-sea tieback to shore.

In August 2013, OMV undertook a big-ger investment in the North Sea regionworth $2.65 billion, which saw it acquireStatoil’s equity in two Norwegian fields—Gullfaks with 19% and Gudrun with 24%—plus Statoil’s 30% in the Rosebank project.OMV also took 5.877% in the BP-operatedSchiehallion Field in the U.K. sector.

Gerhard Roiss, OMV’s CEO said at thetime, “It confirms OMV’s clear focus towardincreasing the significance of its E&P activi-ties. We are acquiring significant positions indevelopments lying at the heart of our NorthSea growth region. e development capitalwill be largely funded by the operating cashflows of the already producing assets, whichare part of the portfolio, while the purchaseprice represents a reinvestment of the pro-ceeds we have generated from disposals andworking capital reductions from our down-stream divisions over the last 18 months.” n

is was compiled and edited by Mark omasfor Deepwater International. Visit epmag.com/order/DWN for more information.

deepwater international news


The Stena Carron drillship drilled the Cambo-5 ap-

praisal well in the Wos region last year for operator

Chevron. (source: stena drilling)

large-scale projects is now pointing the market towardan upturn.

“There is no doubt that the slow economic condi-tions have hurt the industry, particularly the supplychain,” Broughton said. “We are beginning to see pos-itive signs in both the onshore and offshore sectorswith the deepwater Gulf of Mexico gathering pace oncemore. This upturn means that as an industry we mustcontinue to invest in infrastructure, particularly in oiland gas transportation, which will be crucial to sup-port the increased activity.”

Tata Steel is a leader in the supply of innovative deep-water and onshore pipeline solutions to the energy in-dustries.

Tata Steel is exhibiting at OTC 2014 at booth 2363. Formore information, visit tatasteelenergy.com.

statoil signs offshore safety

agreement with viKinG

VIKING Life-Saving Equipment hassigned a multiyear management servicingcontract with Statoil, covering the mainte-nance of marine safety equipment onboard 36 platforms in the North Sea.

e deal represents a landmark deal forthe VIKING Offshore Safety Agreementreleased last year, which harmonizes themanagement of safety equipment on boardwithin a single managed contract.

“Until the agreement, Statoil’s North Seainstallations have been servicing their safetyequipment under a variety of differentschemes with little or no synchronization orcoordination with other installations in thearea,” said Frode Lindseth, Statoil’s senior en-gineer in charge of maintenance manage-ment. “Now VIKING has taken on themanagement effort, creating a single point ofcontact for us and finding new efficiencieswith a minimum of disruption to Statoil’sproduction and production supportprocesses. And the new predictability of costsis also very important to us, too.”

VIKING said Statoil’s portfolio of marinesafety equipment for its oil and gas activi-ties is typical of similar-sized industry play-ers. e company’s rigs have been built atvarious times and were equipped with thebest of what was available at the time ofconstruction. Over the years, many of theproducts have been updated, but rarely ornever as a complete installation upgrade.Statoil’s platforms also are designed for avariety of purposes and environments andcan thus require slightly different types andspecifications of equipment.

e result is a mix of brands, models andvintages that demands significant time and re-sources to maintain. Unlike safety servicingfor passenger or cargo ships, which can becarried out when the vessel is in port, offshoreplatform owners oen are forced to choosebetween buying and renting a temporary set

of life ras to replace equipment being serviced or to con-sider reducing onboard personnel for days while vital safetyequipment is being maintained on shore.

VIKING Life-Saving Equipment is exhibiting at thisyear’s OTC in Houston at booth 1601.

trelleborg opens new Houston

office for marine operations

Trelleborg’s marine systems operation has opened a newsales and business development office in Houston.

Citing growth in the region as a strategic priority,Trelleborg Marine Systems’ U.S. president, Faiyaz Kol-sawala, will relocate to Houston as will a number of thecompany’s global sales team.

“At Trelleborg Marine Systems, our long-term strategyrelies heavily on investment in markets with stronggrowth potential,” said Richard Hepworth, business unit

president of Trelleborg Marine Systems. “We will join col-leagues from Trelleborg’s offshore operation in its facility,enabling us to work more collaboratively across functions.

“As a global company, we strongly believe that it’s im-portant to have local ‘feet on the ground’ within the re-gions that our customers operate,” said Hepworth. “Inparticular, we remain committed to growing our businessin the fast-moving global liquefied natural gas industry.”

e regional sales office will serve the local U.S. andMexican region across all five product areas of Trelle-borg’s marine operations.

e new Houston office will be supported by the Amer-icas’ headquarters of Trelleborg’s marine operation in ClearBrook, Va., which includes a polyurethane- and foam-basedmarine products manufacturing facility serving NorthAmerican and global customers. Additionally the Houstonoffice will be supported by Trelleborg’s engineering and de-sign center of excellence in Ahmedabad, India. n

industry news


statoil's platforms are designed for a vari-

ety of purposes and environments and can

thus require slightly different types and

specifications of equipment.

(source: statoil)

continued from page 34


tools continued from page 13cHallenGe continued from page 8

austRalia continued from page 16

field” but that to reach these possibilities,women must recognize that “there aredifferences in the way women approachchallenges” relative to the way men do.While interviewing women across thecountry for her recently published book,Learning to Lead: What Really Works forWomen in Law, Vincent discovered thatmany women “will personalize a careersetback” and might not realize immedi-ately how “that wrong turn can turn intoan opportunity. There may be some-thing you can learn from that lesson sothat you can channel it into a better de-cision next time.”

Birbiglia said one of the most pressingchallenges to date is “the retention ofwomen” in the industry. “e challenge wehave is being able to connect the womenin the industry with one another,” sheadded. She noted how, particularly in theoffshore well segment she has worked infor about 20 years, there are still very fewwomen. It might be hard to recruit and re-tain them, but she said women tend to “ex-pect to be recognized” for their work andthat networking might help women de-velop a certain confidence in their abilityto “benchmark” their own accomplish-ments and keep advancing in work andleadership roles.

“It’s OK to tell people I’m doing wellwithout being forceful or bragging, andI think the value of networking reallyhelped me understand that better,” sheadded. In the wells discipline therearen’t many women, so she had to go be-yond that group to find support. She andthe geologists “had a huge amount incommon, and we were dealing with thesame challenges.” She was able to ob-serve their leadership styles and createher own. She said that men in the indus-try need to be provided with good ex-amples of how competently women can“run a job.”

This was the third annual meeting for WISE. n

Wise continued from page 12

pany is moving into deeper waters.It faces several challenges, including stepping into

unfamiliar territory characterized by high pressuresand gas hydrates, narrow mud windows and wellborestability issues, all of which require sonic logging toolsto characterize. The region also is structurally complex,with an active fault system and stratigraphic compart-mentalization. And it is subject to severe weather suchas typhoons.

Sonic data are best acquired in a quiet environment,which the while-drilling environment is not, she noted.Filters and processing can eliminate some of these issues.But factors such as drilling noise, borehole conditions,shock and tool eccentricity can compromise the real-time data. In many cases real-time data when comparedto memory data show random noise.

The new sonic tool overcomes many of these obsta-cles. Dual stabilizers help keep it centered in the hole,and the tool’s stiffness helps prevent it from bendingin the hole.

Two case studies outlined the new tool’sefficacy. In one case, it was synthesized inreal time with seismic data to optimizethe well’s casing point. In another, itproved very accurate in predicting porepressure in a deepwater well. Over time,Shim expects the new tool to help opera-tors better understand their wells’ geome-chanics in real time. n

Paving the wayVenturing into new markets brings a new set ofchallenges, but Ralston noted the efforts of gov-ernment agencies to ease the process and en-courage investment.

The federal government has developed an en-ergy white paper detailing its cohesive policy onlong-term domestic energy needs and its plan tomaintain international competitiveness and growits export base. It has created a one-stop shop ap-proach to assist companies seeking environmentalapprovals as a way to improve the investment cli-mate. Ralston also said that federal, state and ter-ritory governments were engaged in ongoingreform in regulating both the onshore and off-shore sectors.

“If Australia isn’t on your radar,” she said, “then itshould be.” n

supply in 2030. By then we expect it to have risen toaround 12 MMbbl/d from around 5.4 MMbbl/d in2010,” he said.

In Mexico’s sector of the Gulf of Mexico, he forecastedeventual plans for at least 50 deepwater field develop-ments, helping Pemex to achieve a potential 156 Bboe oftotal recoverable resources by 2030, aided by its unconven-tional resources, which are believed could well exceed itsdeepwater recoverable reserves.

Last to speak was Michael Bahorich, executive vicepresident and CTO for Apache Corp. He focused on thetechnologies that have helped to enable the astonishingrise in U.S. oil production in recent years, including latestadvances in 3-D seismic. “We all know the jaw-droppingchange in production was caused by multifracking hor-izontal wells,” he added. “If you think about the increasein U.S. production, there is the chance of that happeningaround the world–although maybe not happening at thesame pace. But it has the potential to make a jaw-drop-ping difference.” n


ally more important than technology itself,” said GregGuidry, executive vice president of upstream Americasfor Shell. “If our activity is not accepted, frankly the tech-nology doesn’t matter.”

While both arenas rely on technology, specific tech-nologies don’t necessarily transfer between sectors.

“In terms of synergy of technology, there are certainlylearnings to be shared, but in terms of being a laboratoryone way or the other deepwater is an awfully expensiveplace to evolve onshore technology,” Guidry said. “Buton the reputational side, I can’t think of any major inci-dent in deepwater that wouldn’t have a dramatic impacton what we do onshore, and I can think of a number ofincidents onshore that would have an impact on the ac-ceptance of what we do offshore.”

Coastal Norway and Williston, N.D.According to Torstein Hole, Statoil’s senior vice pres-ident of development and production for NorthAmerica, transferring learnings between deepwaterand unconventionals might be better ap-plied to processes such as safety andmanagement techniques.

“In the safety area, my view is we cantake a lot of learnings from the offshorebusiness to the onshore business,” he said.“e technology and challenges are, ofcourse, different, but when we look at theincidents, the near misses and the under-lying factors, I see a clear tendency towardthe same underlying factors that we haveseen for a number of years in the offshorebusiness.”

Statoil was able to transfer its safetypractices offshore to the onshore sectorwithout a reduction in efficiencies. Simi-larities in operation between deepwaterand unconventionals are available in themidstream for both sectors, such as takingpositions early in pipeline capacity. Statoilis currently looking to gain efficienciesthrough the use of natural gas as a fuel forits onshore operations.

e company employs best industrypractices and technologies to run its oper-ations, Hole said, but also was sensitive tothe social license issue.

“ere is not a big difference betweenthe changes being experienced in Willis-ton, N.D., compared to the changes wehave been through in smaller coastal townsin Norway,” Hole said.

He also said that while technologylearnings from unconventionals mightnot apply offshore, they were a factor be-hind Statoil’s move into onshore Aus-tralia and Russia.

Spending more on unconventionalsMarathon Oil CEO Lee Tillman said both deepwaterand unconventionals were necessary to meet a projected60% growth in energy consumption during the nextthree decades.

“Fossil fuels, and especially oil and natural gas, aregoing to remain the largest source of energy going for-ward,” Tillman said. “When you consider unconvention-

als vs. deepwater, it is not an ‘either/or’ proposition.”However, technology has altered the balance from an

investment perspective especially in light of the “dra-matic cost escalation” offshore.

“Deepwater success is also largely driven by technol-ogy advancements, but it is burdened by a very differentrisk profile characterized by exposure to execution risk,higher costs and much longer lead time between lease,drilling and first production,” Tillman said. “e net ef-fect has been a moderation of capital allocation to theGulf of Mexico as the risk adjusted returns for resourceplays command investment.”

Tillman provided a laundry list of productivity en-hancements through a relentless focus on technology on-shore, including reduced drill times and increased 30-daywell productivity in spite of major downspacing. osegains have altered the capital investment calculation infavor of onshore despite the fact that the breakeven pricefor oil is similar between unconventionals and offshore.

Marathon Oil will spend $3.6 billion in its onshore un-conventionals in 2014, which is more than the companyspent globally—onshore and offshore—in 2008. n

unconventionals continued from page 1

Torstein hole

Lee Tillman


of Mexico. Trainees develop the essential emergency re-sponse knowledge and skills required in the event of ahelicopter emergency—with specific emphasis on es-caping the helicopter following an unexpected waterlanding and how to escape when the helicopter is fullysubmerged in water.

is highly authentic simulation is possible throughthe tools and machinery available at the NBL. During the8-hr course, trainees use a modular egress training sim-ulator (METS), a mockup helicopter that is suspendedfrom a crane and submerged in the NBL pool. Traineesalso learn best practices for survival at sea, including howto operate lifeboats and ras, managing coldwater shockand how to administer first aid. Certification lasts forfour years, and recertification requires another 8-hr re-peat course.

e robust OPITO approval process to deliver Tropical

HUET training can last more than four months. Trainingoperators seeking to have their program approved mustcomplete a desktop audit that includes a checklist of allmanagement systems, facilities, maintenance and moreto ensure the facility can handle the capacity the courserequires. OPITO then performs an onsite evaluation toobserve the execution of the course. Approved trainingfacilities undergo annual monitoring to ensure all stan-dards proved during the desktop audit are upheld.

The Hi-Con training program has received OPITOapproval for various courses during the past twoyears. As the industry’s need for training grows,Raytheon and Petrofac anticipate growth in accept-ance of the Tropical HUET course. For more infor-mation about Hi-Con Training’s offerings and towatch videos of HUET training using the METS hel-icopter, visit hicontraining.com. n

couRse continued from page 18

locatoR continued from page 31

cHanGe continued from page 26

provides positive confirmation of the pressure barrier’sintegrity, enables intervention to be planned and imple-mented in a timely manner and brings added certainty tothe well integrity monitoring process and offshore safety.

The new sensor system, consisting of a wirelessreader, a wireless PT transponder and antennae tomonitor activity, attaches to the same cable as otherreservoir monitoring gauges and forms another key el-ement of the Roxar IDN.

On the North Sea field in question, the sensor system,deployed as part of the field’s completion, is measuringonline and in real-time pressure and temperature infor-mation from behind the casing in the subsea productionwell. e entire system has been rigorously tested and israted to operate at temperatures of up to 225 C (437 F)and for a minimum expected lifetime of 20 years.

Emerson’s smart wireless solutions are being used inthousands of installations worldwide, enabling opera-tors to increase the visibility of their assets.

Such benefits facilitated by wireless are being seendownhole, providing a significant step forward in produc-tion control and offshore safety. For further information,visit Emerson Process Management at booth 5817. n

• High-data quality, which minimizes risk for errorsand manual handling and facilitates follow-up;

• Regulatory compliance in a global environment(for example, Nota Fiscal in Brazil, local GAAP vs.international financial reporting standards, andU.S. GAAP);

• Complex rig and corporate structure; • Improved performance management based on real-

time data; and • Traditional accounting such as invoicing and pay-

ment; supplier invoice workflow; currency calcula-

tions and adjustments; budgeting and forecasting;and fixed assets and project accounting.

To learn more, the experts at IFS, the provider of EAMsoware, have written an informative white paper on howa holistic ERP system can help manage integrated proj-ects, the complete asset life cycle, offshore and onshoredata communications, subcontractors and more.

Visit IFS at booth 7123 for a copy of the white paper,“ERP for Drilling Contractors: Integrated Value ChainRaising the Standard for Visibility, Performance and Con-trol,” or download it at ifshouston.com. n

system continued from page 29

maRKet continued from page 24

during displacement and the ability to accurately predictwhen the plug will bump reduces NPT and improves reli-ability of downhole pressure-actuated tools.

Special subs in the casing string above the plug’s land-ing surface produce the position indication. As the topplug passes through the sub, a brief increase in displace-ment pressure is recorded at surface. is enables the op-erator to confirm the plug’s exact position in the string,which mitigates the risk of cement overdisplacement, en-ables controlled bumping of the plug, optimizes cementplacement and minimizes drill-out time.

Weatherford’s PLS provides a new ability to acquire arecognizable indication of when a cementing top plugpasses through a locator collar located in the casingstring. e PLS collar is positioned several joints abovethe float or landing collar. A surface pressure increase be-tween 300 psi and 900 psi indicates when the top plugreaches and passes through a deflecting yield ring in thelocator collar. Displacement can be continued by pump-ing the calculated volume between the locator and land-ing collars until the top plug bumps. Multiple pressureindication points are achieved by adding locator collarsat various depths in the casing string.

e system is being used successfully in deepwater ap-plications in the Gulf of Mexico, Trinidad and the Asia-Pacific region to give clear indications of plug locationthroughout the displacement process and enable furtherrefinement of displacement calculations and fluid com-pressibility properties. e system uses polycrystallinediamond compact drillable material and is available as aWiperLok nonrotating plug in standard cementing, sub-sea release and liner-hanger plug configurations.

Better cement placement knowledge is allowing oper-ators to successfully bump plugs to prevent wet shoes andavoid expensive remedial cementing operations. Elimi-nating the need to drill out excessive cement is savingvaluable rig time.

e ability of the system to acquire a precise plug po-sition indicator at the surface and refine displacementcalculations greatly improves understanding of plug per-formance and the ability to eliminate most errors in dis-placement volumes such as fluid compression, casing IDvariances and incorrect pump efficiencies. n

ciRculation continued from page 15

the flow cycle. Over the years, the wells will be on pro-duction-alternating steam injection, and oil productionmust be able to communicate freely with the reservoir.

In less than 1 hr, fibers and solids were prepared onsite for deployment into the wells. Each well was treatedwith 8.6-lb/gal density Losseal fluid. Well No. 1 received50 bbl, and well No. 2 received 55 bbl. Both treatmentswere pumped without difficulty. When the Losseal pillentered the loss zone, a slight rise in pump pressure in-dicated the rising column of fluid in the annulus. ismeant that fluid already was bridging and plugging theloss zone. Returns to surface proved conclusively that thetreatment was a success. Before running casing, drillpipewas run into the hole, and circulation was established 61m (200 ) above the loss zone. Right at the top of the loss

zone, full returns indicated that the formation was sealedenough to permit cementing. In well No. 1, pretreatmentlosses of 160 bbl/hr were reduced to 30 bbl/hr, and inwell No. 2, losses of 190 bbl/hr were reduced to 18 bbl/hr.Both were deemed low enough to attempt to run and ce-ment casing, which was performed without incident.

Aer several months, the operator was ready to testthe well for IP. e measured production level wasslightly above expectation for both wells, concludingboth plugs had degraded completely with no residual ef-fects. e operation was therefore considered successfulfor both the drilling operation and well production.

For more information on the Schlumberger Lossealfor reservoir drilling, visit Schlumberger at booth 4441or slb.com/losseal. n

oTC MoBiLe aPP The oTC 2014 mobile app provides on the

go, interactive information that allows you

to stay up-to-the minute on the latest events

and special sessions.

both its PFLNG facilities are expected to “change thelandscape of the LNG business.” As such, it added, the fa-cilities will play a significant role in the company’s effortsto unlock Malaysia’s remote and stranded gas reserves.

ere are also other projects in process for Australia—Woodside wants to use Shell’s FLNG technology as thedevelopment concept for developing its Browse gasfields off Western Australia via not one but three FLNGfacilities, while ExxonMobil and BHP Billiton also arepursuing FLNG as the preferred solution for the Scar-borough Field also off Western Australia.

Elsewhere, the eastern Mediterranean has Noble En-ergy, Woodside and its partners progressing toward theuse of an FLNG unit for the second development phaseof the producing Tamar Field offshore Israel, while a fur-ther unit is expected to be employed on the giant neigh-bouring Leviathan Field, the world’s largest offshore gasdiscovery of the last decade. A third unit also is beingconsidered for the development of another large gas field(Cyprus-A) close to these two fields in Cypriot waters.

Off Africa’s east coast, Eni and its partners are consid-ering an FLNG solution for monetizing part of their giantgas reserves off the coast of Mozambique, while offAfrica’s west coast Ophir Energy has shortlisted biddersto supply it with a leased FLNG unit for its deepwater gasresources in Block R off Equatorial Guinea. n

tages and disadvantages, she said. Concerns regardingthe use of these systems are the same as those regardingthe use of hydraulic systems, including: installationdepth and operating pressures of flow control valves,fluid degradation, leakage in control lines and comple-tion in multilateral junctions and horizontal sections.

All electric intelligent completion systems presentseveral advantages, including no limitation to thedepth of installation of the flow control valves and noconcerns about high operating pressures of the flowcontrol valves, she said. An all-electric intelligent com-pletion system was first installed as part of a year-longfield trial in a Petrobras land well (8-VRG-7D-RN) inMay 2001. e well was remotely monitored and con-trolled through a satellite link between the well locationand the operator’s office located more than 322 km(200 miles) away. e success of this first installationled to the eventual installation of the system on a sub-sea well in the MarlimSul Field in the Campos Basin.

“e world’s first all-electric deepwater, subsea in-telligent well system was installed in August 2003 in awater depth of 1,180 m [3,540 ], with a single stringin a dual-zone injector well,” she said. “is technologyis proving to be reliable, because the system is still op-erational, almost 10 years aer its deployment.” n

solutions continued from page 17

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