OS_20130501_May_2013

May 2013

Houston London Paris Stavanger Aberdeen Singapore Moscow Baku Perth Rio de Janeiro Lagos Luanda

World Trends and Technology for Offshore Oil and Gas Operations

For continuous news & analysiswww.offshore-mag.com

Deepw

ater R

ecord

s

& Conce

pts p

oster

International E&P report

Recruitment trends

Drill bit review

FPSO topsides

Deepwater well construction

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INSID

E:

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1/3// of deepwater drilling NPT is associated with geomechanics-related problems, with

total NPT increasing by a factor of four for subsalt wells in water depths over 3,000 ft. With basin and well-level

geomechanics modeling experience in every major province, combined with industry-leading Drillbench dynamic

well control software applied through a global network of PTEC PetroTechnical Engineering Centers, we will help

you meet your deepwater objectives.

Confidence comes from understanding

your risks and preparing for them.

Can we be confident that this deepwater drilling program will achieve all our well objectives?

Drill with confidence.

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THE WORLD’S NEWSSTAND®

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International EditionVolume 73, Number 5

May 2013

C O N T E N T S

Offshore (ISSN 0030-0608) is published 12 times a year, monthly by PennWell, 1421 S. Sheridan Road, Tulsa, OK 74112. Periodicals class postage paid at Tulsa, OK, and additional offices. Copyright 2013 by PennWell. (Registered in U.S. Patent Trademark Office.) All rights reserved. Permission, however, is granted for libraries and others registered with the Copyright Clearance Center, Inc. (CCC), 222 Rosewood Drive, Danvers, MA 01923, Phone (508) 750-8400, Fax (508) 750-4744 to photocopy articles for a base fee of $1 per copy of the article plus 35¢ per page. Payment should be sent directly to the CCC. Requests for bulk orders should be addressed to the Editor. Subscription prices: US $101.00 per year, Canada/Mexico $ 132.00 per year, All other countries $167.00 per year (Airmail delivery: $234.00). Worldwide digital subscriptions: $101 per year. Single copy sales: US $10.00 per issue, Canada/Mexico $12.00 per issue, All other coun-tries $14.00 per issue (Airmail delivery: $22.00. Single copy digital sales: $8 worldwide. Return Undeliverable Canadian Addresses to: P.O. Box 122, Niagara Falls, ON L2E 6S4. Back issues are available upon request. POSTMASTER send form 3579 to Offshore, P.O. Box 3200, Northbrook, IL 60065-3200. To receive this magazine in digital format, go to www.omeda.com/os.

Celebrating Over 50 Years of Trends, Tools, and Technology

INTERNATIONAL REPORT

Deepwater operators look to new frontiers ...........................34Analysis of variable data sets, including global E&P, petroleum basin geology, political risk, costs and fiscal terms reveals remarkable new reserve-growth trends in global deepwater domains, and identifies criti-cal success factors for deepwater operators.

Gulf of Mexico E&P activity maintains momentum ................42Oil and gas development in the Gulf of Mexico continues to rebound after the nadir of 2010, and activities are ramping up in all phases – leas-ing, exploration, drilling, field development, and production.

Exploration and development resurgentthroughout main NW Europe regions ......................................48Britain’s dwindling reserves of offshore gas have been further drained by an unusually prolonged winter. But BP provided a gleam of light last month with its North Uist gas/condensate discovery west of Shetland.

Eastern Mediterranean gas draws international investors ....50Gas production started from the 10-tcf Tamar field offshore Israel on March 31. Aside from being the country’s first deepwater develop-ment—and at over 90 mi (145 km), the world’s longest subsea tieback to a platform—the project has lain the foundation for a new gas prov-ince in the Middle East region.

Brazil gears up for new wave of offshore activity .................52Brazil’s National Petroleum Agency has finally outlined the process for the bidding to be held in May 2013. This 11th round has 166 offshore blocks and comes five years after the previous round.

Supply and demand in the Asia/Pacific region try to reach equilibrium ...........................................................58With growing energy demands in China and India, and huge LNG export projects under way off Australia, the Asia/Pacific region is a tale of two complementary ends of oil and gas exploration and development continuum. Add to that the continuing work offshore Indonesia, Viet-nam, Myanmar, and others, and you have a region of extreme contrasts.

Exploration continues to spread offshore Africa ...................64From huge gas discoveries off its undeveloped eastern coast to presalt exploration in the west’s mature markets, Africa is the focus of intense activity among major operators and independents alike.

E&P activity rises in Arctic, sub-arctic regions ......................70Despite the challenges the Arctic and sub-arctic regions present such as ice, low temperatures, darkness and remoteness, the substantial amount of oil and gas reserves propel operator and industry interest and the resultant exploration and development activity.

RECRUITMENT TRENDS

Industry steps up recruitment in response to ‘great crew change’ ........................................74Even with a buoyant job market, many recent surveys of oil and gas professionals have found that the industry’s greatest concern is the skills shortages presented as many baby boomers prepare to retire over the next decade.

GEOLOGY AND GEOPHYSICS

Dolphin responding to demandfor wider seismic arrays, more in-depth processing .............78One of the fastest-growing contractors in the entire offshore ser-vices sector is Dolphin Geophysical. Since its formation in 2010, the Norwegian-owned seismic acquisition company has grown from zero turnover to $220 million in 2012, with sales revenue heading potentially for $500 million in the next two years.

Isometric marine seismic technology delivers true 3D ..........81 The WesternGeco IsoMetrix marine isometric seismic service which, for the first time fully captures the 3D wavefield using towed streamers, en-ables reliable high-resolution imaging of complex subsurface structures.

Towed streamer CSEM coming of age ....................................84Can a towed streamer EM system really deliver valuable information? PGS has designed a system with several key features to overcome noise and to achieve the necessary signal-to-noise ratio for effective survey-ing. Based on survey results collected late last year, PGS is confident that proof of concept already has been achieved.

DRILLING AND COMPLETION

Bit technology continues to advance......................................86Progress in drill bit design is being made on all fronts by all bit manu-facturers. Improvements range from major design changes to better manufacturing techniques. Operators are the ultimate beneficiaries, because they get better quality boreholes drilled in less time, reducing rig time costs while improving time-to-market.

Advances in MPD enhance deepwater opportunities .............90Closed-loop systems and the attendant managed pressure drilling (MPD) methodologies provide the basis for new methods and technolo-gies that significantly increase the safety and efficiency of drilling deep-water wells. These advances mark step changes in well construction capabilities and the factors that define a deepwater prospect’s viability.

Tender-assist TLP with coiled tubing optimizes Moho Nord Albian wells .........................................94 Total and partners Chevron and SNPC have committed to the complex Moho Nord development offshore Republic of Congo. What is more novel on Moho Nord is the selection of an unmanned wellhead TLP designed for simultaneous tender-assist drilling of dry-tree wells and coiled tubing intervention.

Simulation and sensors advance the digital oilfield ..............98Detailed engineering simulation, coupled with system-level modeling, is empowering engineers to effectively design and deploy next generation sensors and smart products to gain additional efficiency and reliability in oil and gas drilling, production, and processing.

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An operator in the Gulf of Thailand’s ‘Ring of Fire’ used the RHADIANT drilling fluid systemto efficiently drill a high-angle well with a BHST of 432°F (222°C) with zero lost circulation.A total of seven open-hole logging runs were then performed, all with excellent results.

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4 Offshore May 2013�t�www.offshore-mag.com

International EditionVolume 73, Number 5

May 2013

ENGINEERING, CONSTRUCTION, & INSTALLATION

Flare-less requirements drive innovation on the Okha FPSO ................................. 102 Flare-less operations can be implemented with relative ease if factored into a project from the beginning. With drivers that include environmental regulations, emissions reduction, production optimization and improved working conditions, it is expected that flare-less designs will become the new standard for FPSOs and platforms.

PRODUCTION OPERATIONS

Asset integrity management extends reach ............................................................ 110Bureau Veritas’ VeriSTAR AIMS is an open Web-based system with controlled access that allows AIMS teams to work worldwide. The system is designed to improve inspection management and information control for different types of facilities. Information is stored and secured in a unique database and can be accessed in real time through the Internet or an intranet.

Silicon-free defoamers and antifoamers improve performance, safety ................ 114As gas-oil proportions change in oilfield production, non-silicon-based antifoamers/defoamers of-fer a viable solution for solving offshore foaming problems, such as oil carryover in the gas stream, gas carryover in the oil stream, and the presence of silicon and fluorine in exportable oil streams.

Statoil records first successful North Sea HP/HT coiled tubing milling job ........... 116Statoil learned valuable lessons during the planning and execution of a high-pressure/high-temperature coiled tubing milling job on the Norwegian continental shelf in the North Sea at Kvitebjoern field.

Pitting and crevice corrosion of offshore stainless steel tubing ............................ 122 The two prevalent forms of localized corrosion are pitting, often readily recognizable, and crevice, which can be more difficult to see. Many factors contribute to the onset of localized cor-rosion. Inadequate tubing alloy and suboptimal installation practices can lead to deterioration of tubing surfaces in a matter of months.

Resin emerging as alternative to cement ................................................................ 126In the past year, WellLock resin has overcome challenges and has been applied in situations where conventional cement cannot be effective. This resin lends itself to specific adjustments of rheology, density, and curing time to allow reliable placement. The resin can withstand impuri-ties in the wellbore without significant degradation in performance and is compatible with water.

PIPELINES & FLOWLINES

Pre-commissioning the Nord Stream pipeline ........................................................ 128In September 2011, the pre-commissioning of the Nord Stream Line 1 was completed ahead of schedule. Line 2 pre-commissioning was completed one year later. The authors discuss some of the challenges experienced during the planning, engineering, and preparation for the pre-com-missioning of this pipeline, and relate the relevant field experience collected during execution.

Robotics improve insulated pipe cutbacks ............................................................. 132Bredero Shaw has developed and commercialized a robotic technology to prepare cutbacks safely and reliably.

NOIA SUPPLEMENT

Offshore development contributes to American energy renaissance .................... 137

Opening new offshore areas will create new jobs, produce more energy, and enhance federal revenue .............................................. 138

NOIA represents all phases of offshore energy ....................................................... 140

NOIA Officers, Board of Directors, and Executive Committee ................................. 142

2013 NOIA Membership ............................................................................................ 144

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International Edition Volume 73, Number 5 May 2013

D E P A R T M E N T S

FRANCE SUPPLEMENT

GEP-AFTP helping French suppliers to penetrate emerging offshore sectors ....... 148Offshore talked to General Manager Gérard Momplot of French suppliers council GEP-AFTP to find out how the association is responding to its members’ demands.

Sodexo helping installation owners improve quality of life offshore ..................... 151“Quality of Life Services” specialist Sodexo, founded by Pierre Bellon in Marseille in 1966, has been attending to the offshore sector’s needs for more than 40 years, adapting its services to reflect changing priorities.

Ponticelli adapting Nigeria platforms for next-phase Ofon production ................. 154The Ponticelli Frères Group has been awarded the $200-million contract for the Phase 1 modifi-cations of Total’s Ofon Phase 2 project offshore Nigeria.

Spring-energized seals selectedfor world’s first subsea gas compression station ................................................... 156The OmniSeal-103A seals that Saint-Gobain Seals Group will supply for the Åsgard subsea gas compression station were engineered and manufactured with a unique blend of the company’s Fluoroloy material, qualified to the NORSOK M710 standard.

Ofon accommodation construction on schedule..................................................... 157Nigeria’s most “home-made” living quarter platform to date should sail out later this year to Total’s Ofon field.

EQUIPMENT & ENGINEERING

Schlumberger releases new CT, MWD, RSS, and PCD bit technology .................... 159

Autonomous subsea fluid injection skid built by OceanWorks for MWCC ............. 160

Clover Tools produces BOP/hydrostatic test units .................................................. 161

Scientific Drilling launches new mud-pulse MWD system ..................................... 161

PDF-based electronic system eases P&ID review ................................................... 162

Falmouth Scientific enhances Bubble Gun family ................................................... 162

COVER: The Anoa Natuna FPSO offshore

Indonesia serves Premier Oil’s Natuna Sea

production in the South China Sea 140 mi

(225 km) offshore of the Natuna Islands in

the Greater Sarawak basin. The FPSO can

process 32,000 b/d of oil and has oil storage

for 550,000 bbl, along with gas processing

capacity of 5.4 MMcf/d and 14,000 b/d of

water. This was MODEC’s first purpose-built

FPSO. Late last year, Premier said it sanc-

tioned a major brownfield project for the

Anoa complex that would extend the field’s

productive life for three years and develop

200 bcf of reserves. The project is scheduled

for completion toward the end of this year.

(Photograph courtesy Premier Oil)

Online .................................................... 8

Comment ............................................. 10

Data ..................................................... 12

Global E&P .......................................... 14

Offshore Europe .................................. 20

Gulf of Mexico ..................................... 22

Subsea Systems ................................. 24

Vessels, Rigs, & Surface Systems ...... 26

Drilling & Production .......................... 28

Geosciences ........................................ 30

Offshore Automation Solutions .......... 32

Business Briefs ................................. 164

Advertisers’ Index ............................. 167

Beyond the Horizon .......................... 168

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For additional information, please

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C O M M E N T %BWJE�1BHBOJF�t�)PVTUPO

New research identifiesprolific deepwater plays

Offshore operators are increasingly seeking new sources of sustainable productionfrom deepwater areas. While capital-intensive and high-risk, the reward from deepwater development can be substantial and new areas of opportunity are emerging. Exclusive analysis by IHS inside this issue identifies the most prolific geological settings in deep-water for significant reserve accumulation. The analysis of more than 5,100 global pe-troleum basins and sub-basins, as well as 57,000 reservoirs, found the vast majority of deepwater discoveries from 2007 to 2012 were made in passive margins. One of the pas-sive margins, overlying a rift system, accounted for 77% of total new reserve additions in deepwater, according to the report. Moreover, two major depositional facies, turbidites and lacustrine, accounted for 47% and 30% respectively of the total new discovery vol-umes in deepwater. These passive margin basins are common not only on both sides of the Atlantic Ocean in West Africa and eastern South America, but also in the Arctic,Australia, New Zealand, India, and eastern Canada.

Meanwhile, a number of new deepwater plays were discovered during the six-year analysis period. IHS suggests that these new plays were not known either onshore or offshore prior to 2007, and represent new concepts of hydrocarbon accumulation in deepwater. For example, in Mozambique and Tanzania, approximately 8 tcf of natural gas was discovered in Eocene and Paleocene stratigraphic plays. Another significant gas discovery of 5.7 tcf was made in a Lower Miocene play in Israel and Cypress (Le-vantine basin). While the discoveries off East Africa await project sanction, Israel, this past March, solidified its position as a deepwater producer with first gas from the Tamarfield.

In Ghana, a significant oil and gas volume of almost 2 Bboe was made in a Turonianstratigraphic and Turonian stratigraphic structural plays in the Cote d’Ivoire basin. Oth-er new, significant deepwater plays, according to IHS, were established offshore FrenchGuiana, the Falkland Islands, Norway, Iran, Mexico, and India.

The deepwater analysis finds another interesting trend, among others, that highlights the success rate of wildcat drilling in deepwater, by company type. Approximately 200 oil and gas companies participated in deepwater exploration during the study period. Those companies spudded about 950 new-field wildcat wells, with the independentsdemonstrating the highest rate of drilling success.

The full analysis by *)4�BVUIPST�,FSSJ�/FMTPO �.JDIBFM�%F+FTVT �"MFY�$IBLINBL-

IDIFW �BOE�.FMJTTB�.BOOJOH, begins on page 34.Also inside is our annual global E&P report, which highlights activity and trends

in the key offshore producing regions. The report begins on page 42 with Offshore

NBOBHJOH�FEJUPS�#SVDF�#FBVCPVFG’s review and outlook for the US Gulf of Mexico.

Developing the next generation

Inside this issue we review the specific actions that academia and industry are taking to prepare the next generation of industry professionals. One example is the launch of a subsea engineering graduate program at the University of Houston, which is believed to be the first of its kind in the US. Established in collaboration with FMC Technologies,Cameron, GE Oil & Gas, and Weatherford, the 10-course master’s program is expected to begin this fall.

Industry expansion in research and development is also helping to bridge the skill gaps, writes +FTTJDB�5JQQFF �Offshore�BTTJTUBOU� FEJUPS. She highlights a number of examples in her report, including Saudi Aramco’s international expansion of researchand development to increase access to talent and technology, and promote closer col-laboration with key research institutions. Tippee’s report begins on page 74.

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Worldwide offshore rig count & utilization rate

April 2011 – March 2013

950

850

750

650

550

450

350

100

90

80

70

60

50

40

No

. o

f ri

gs

Fle

et u

tilizatio

n ra

te %

April 11

July

11

Oct

11

Jan 1

2

April 1

2

July

12

Oct

12

Jan 1

3

Contracted fleet utilization Total fleet Contracted Working

Sourc

e: IH

S

Global reserves onstream (MMbbl) 2008-2017

80,000

60,000

40,000

20,000

0

West Africa

South Asia

North America

Latin America

Australasia

Southern Europe

South & East Africa

North Africa

Eastern Europe

Southeast Asia

NWECS

Middle East

East Asia

Source: Infield Systems Ltd.

2008 2009 2010 2011 2012 2013 2014 2015 2016 2017

Worldwide day rates

Year/Month Minimum Average Maximum

Drillship

2012 Apr $157,000 $443,150 $671,000

2012 May $157,000 $438,961 $671,000

2012 June $50,000 $433,711 $671,000

2012 July $50,000 $437,808 $671,000

2012 Aug $50,000 $442,438 $671,000

2012 Sept $50,000 $429,559 $671,000

2012 Oct $50,000 $429,106 $674,000

2012 Nov $50,000 $429,410 $674,000

2012 Dec $50,000 $441,112 $674,000

2013 Jan $50,000 $447,044 $674,000

2013 Feb $50,000 $454,689 $674,000

2013 Mar $50,000 $454,477 $674,000

Jackup

2012 Apr $36,000 $107,984 $366,000

2012 May $36,000 $108,450 $366,000

2012 June $36,000 $110,695 $366,000

2012 July $30,000 $111,416 $366,000

2012 Aug $40,000 $111,454 $366,000

2012 Sept $40,000 $111,841 $366,000

2012 Oct $30,000 $112,275 $366,000

2012 Nov $30,000 $114,593 $366,000

2012 Dec $30,000 $115,284 $366,000

2013 Jan $30,000 $118,145 $366,000

2013 Feb $30,000 $119,166 $366,000

2013 Mar $30,000 $120,168 $366,000

Semi

2012 Apr $137,000 $361,434 $655,000

2012 May $125,000 $360,402 $655,000

2012 June $125,000 $359,368 $655,000

2012 July $69,825 $353,576 $675,000

2012 Aug $69,825 $360,119 $675,000

2012 Sept $130,000 $357,336 $675,000

2012 Oct $130,000 $357,439 $655,000

2012 Nov $130,000 $362,429 $655,000

2012 Dec $130,000 $363,679 $655,000

2013 Jan $137,000 $365,380 $655,000

2013 Feb $137,000 $366,217 $655,000

2013 Mar $137,000 $369,458 $655,000

Source: Rigzone.com

G L O B A L D ATA


Infield Systems expects 1,546 new fields to enter

production worldwide in the next five years. During

the previous period from 2008 to 2012, 779 fields

came onstream. In unitary terms, the NWECS region

is anticipated to see the largest number of fields enter

production over this period, with 389 fields expected

onstream. The largest number of these, 207, are

expected offshore the UK. However, average field re-

serves offshore the UK during the period equate to just

33 MMbbl, compared to the largest average reserves

per field of 7,453 MMbbl expected offshore Kazakhstan

as a result of the on-going development of Kashagan.

In terms of expected reserve additions onstream over

the next five years, Infield Systems anticipates all of

the top five fields to be in the Middle East. The largest

field, South Pars phases 25-28, is expected to enter

production in 2017.

From an operator perspective, Infield Systems

expects the largest number of fields to come onstream

under Petrobras, with 64 fields planned to enter

production before the end of 2017. All but one of the operator’s fields – Cegonha field offshore Angola

– are expected to come onstream offshore Brazil. Chevron is anticipated to bring onstream 63 fields

during the same period across 14 countries. China’s CNOOC is expected to bring 62 fields into produc-

tion; 59 of which will be located offshore China, with three developments within Indonesia’s production

zone.

In terms of the water depth of new fields onstream, the growth toward deepwater prospects is

also apparent, with 241 fields in water depths of 500 m (1,640 ft) and greater expected to commence

production between 2013 and 2017. The largest growth is expected to be seen in the ultra-deepwater

market, with fields of depths greater than 1,499 m (4,918 ft) driven by the Gulf of Mexico and Brazil.

– Catarina Podevyn, Analyst, Infield Systems Ltd.

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G L O B A L E & P +FSFNZ�#FDLNBO�t�-POEPO

14 0GGTIPSF�May 2013�t�www.offshore-mag.com

The jackup GSP Jupiter is preparing to drill a third well on the Dolginskoye field in the Pechora Sea.

North America/

Gulf of Mexico

ExxonMobil has authorized Kiewit-Kvaerner Contractors to start engineer-ing, procurement, and construction of a gravity-based structure for the new Hebronplatform offshore eastern Canada. Fabrica-tion is in progress at the Bull Arm yard in Newfoundland, and the completed structurewill be installed at the Hebron field in the Grand Banks region, 350 km (217 mi) off-shore Newfoundland and Labrador. First oil should flow from Hebron by end-2017.

tttPemex has contracted Petrofac and Doris

Engineering to jointly assist and superviseconstruction and installation of deepwa-ter wells and related infrastructure for the Lakach structure offshore Mexico. The scope extends to tie-ins to existing onshorefacilities. The program should be completed toward end-2015.

tttA referendum on future field develop-

ment offshore the Bahamas will not be held for the time being. The islands’ governmenthas decided to postpone any popular vote until results of exploration drilling come through, and the scale of any discoveries has been determined. Bahamas PetroleumCo., which has been preparing an offshoredrilling campaign for years, welcomed the decision.

Brazil

Production from Petrobras-operated pre-salt oil fields offshore Brazil has reached a new benchmark of 300,000 b/d. The figurewas achieved seven years after oil was first discovered in the presalt layer in 2006, and with a total of just 17 production wells. All are in ultra-deepwater, with six of the wells in the Santos basin accounting for 43% of the production (129,000 b/d).

This month, Petrobras expects a new FPSO,the Cidade de Paraty, with processing capacityfor up to 120,000 b/d of oil, to go onstream ata location northeast of the presalt Lula field.

Another 11 new platforms should enter service for the company in ultra-deepwater fields in the Santos and Campos basins be-tween 2014 and 2016, pushing its total pre-salt output beyond 1 MMb/d in 2017. Two of the additions will be conversions from twin-hulled vessels, to be handled by a joint ven-ture of SBM Offshore and Queiroz Galvao Oleo e Gas, and deployed on Lula in block BM-S-11 under a 20-year charter.

tttBP has completed a successful drill stem

test of the presalt Itaipu-1 A discovery well in the Campos basin. The DST flowed oil at up to 5,600 b/d for 12 hours, with pressurebuild-up analysis after the main flow sug-

gesting good connectivity with the main res-ervoir. BP is set to drill a further appraisal well, Itaipu-3, later this year on the BM-C-32 concession, 125 km (78 mi) offshore.

West Africa

Business intelligence provider GBI Re-search expects offshore drilling spending to increase across all major nations in the re-gion. Escalating activity in countries new to offshore exploration, such as Sierra Leone and Liberia, may provide increasing compe-tition for the more established nations. But Angola should remain the leading player for the next few years, with drilling expen-diture there reaching $6.67 billion in 2016, GBI predicts, followed by Nigeria with $2.26 billion.

tttCairn Energy is set to become operator

of three contiguous nearshore-deepwaterblocks off Senegal. Current partners in the Rufisque, Sangomar, and Sangomar Deep blocks are Australia’s FAR and Senegalese state oil company Petrosen. Analysis of 3D seismic suggests has identified numer-ous play types. A first well could be drilled around the turn of the year on the 250-MM-boe “L” prospect.

tttAfrican Petroleum has started prepara-

tions for an exploration well later this year on the Alhamdullilah prospect offshoreGambia. The company has a 60% interest in surrounding blocks A1 and A4 in partner-ship with Buried Hill, but a further partnerwill be needed to co-fund the well. Alham-dullilah is a four-way dip-closed structure ex-tending over 24 sq km (9.3 sq mi), with five mapped reservoirs. These will be targeted

by the well, to be drilled in 2,300 m (7,546 ft) water depth.

tttCap Energy hoped to complete acquisi-

tion of majority shares in Sphere Petroleumlast month, gaining access to two explora-tion licenses offshore Guinea-Bissau. These cover blocks 1 (Corvina) and 5b (Becuda).

tttEni has notched a ninth oil discovery in

deepwater block 15/06 offshore Angola. The Vandumbu 1 well encountered net oil pay of 114 m (374 ft) in Lower Miocene sands. The well was drilled in a water depth of 976 m (3,202 ft), 150 km (93 mi) offshore.The result has increased the resource base of the West Hub project, Eni says.

Russia

The jackup GSP Jupiter should start drill-ing operations next month for Gazprom Nefton the Dolginskoye oil field in the PechoraSea off northern Russia. Work scope includesdrilling, logging, completion, and testing ofthe Severo-Dolginskaya No. 3 well. The Dol-ginskoye field was discovered in 1999, 110km (68 mi) offshore, in a water depth of 35-55m (115-180 ft). Two wells have been drilled todate on the north and south of the structure,with recoverable reserves estimated at over200 million metric tons (220 million tons).

tttLukoil has commissioned Schlumberger

to design wells for the V.Filanovsky develop-ment in the northern Caspian Sea. The two companies are also collaborating on inte-grated studies of Lukoil’s prospective assets at the Moscow-based Center of Geologic Exploration Technologies, using equipment supplied by Schlumberger.

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G L O B A L E & P

Mediterranean Sea

UK-based Northern Petroleum believesits Cygnus prospect offshore southern Italycould hold up to 790 MMbbl of oil. The com-pany bases its estimate on a common oil/water contact identified between Cygnus andEni’s producing oil field in an adjacent con-cession. This follows analysis by ERC Equi-poise, derived from previously undisclosedwell data relating to Aquila in a new environ-mental submission by Eni. Northern is seek-ing partners to co-fund a 3D seismic surveyover Cygnus and subsequent drilling.

tttBurullus Gas Co. has handed Saipem an

EPIC contract for new subsea facilities in the West Delta Deep Marine concession off-shore Egypt. Scope includes supply and in-stallation of rigid and flexible flowlines, um-bilicals, and other structures in water depths of up to 850 m (2,789 ft). Offshore work will be performed during 2014.

tttNoble Energy says the Leviathan #4 ap-

praisal well offshore Israel encountered 454 net ft (138 m) of gas pay in multiple inter-vals. Results have led to an upgrade of re-serves recoverable to 18 tcf. The drilling rig Ensco 5006 was due to transfer to the Alon C license to drill the 3-tcf prospect Karish.

Middle East

Saudi Aramco has contracted two new jack-ups from Asia Offshore Drilling (AOD) foroperations offshore Saudi Arabia. Both havebeen under construction at Keppel FELS inSingapore – one was due to be delivered lastmonth, the other in July. Seadrill will managethe drilling program on AOD’s behalf.

tttWintershall and Qatar Petroleum have

discovered new gas reserves offshorenorthern Qatar. The well was drilled in 70 m (229 ft) water depth in exploration block 4, close to the giant offshore North field.

East Africa

Statoil and partner ExxonMobil have proven fresh deepwater gas reserves in block 2 offshore Tanzania. Ocean Rig Posei-

don drilled the Tangawizi-1 well in 2,300 m (7,546 ft) of water, 10 km (6.2 mi) from the previous Lavani and Zafarani finds. It en-countered gas in tertiary sandstones, liftingvolumes found on the block to date to 15-17 tcf. Statoil has booked the drillship Discover-

er Americas to step up its exploration drilling both on block 2 and on block 5 off Mozam-bique to the south.

Another drillship, Deepsea Metro-1, has com-pleted a drillstem test on the Jodari gas dis-

covery in Tanzania block 1 for BG Group andOphir Energy. The DST flowed at rates of up to70 MMcf/d from one of the tertiary reservoirwells. The rig was next due to perform anotherDST to test the Mzia-2 appraisal well, 22 km(13.7 mi) to the north.

tttPetrochina has farmed into 20% of gas-

prolific Area 4 offshore Mozambique previ-ously held by operator Eni. The deal nettedEni $4.21 billion.

India

The Indian Cabinet Committee on Invest-ment has approved award of five new explo-ration blocks offshore eastern India. CairnIndia and Reliance Industries picked up one and three blocks respectively in the Krishna Godavari basin, with ONGC assigned one off the northeast Indian coast.

ONGC has found more gas in the KG off-shore shallow water basin, 25 km (15.5 mi) south of Narsapur.

The Saveri #1 well on block KG-OSN-2004/1flowed gas from one interval and gas-conden-sate from another interval higher up. It boostsprospects for a cluster development with theAlankari and Chandrika South finds on thesame block.

Offshore western India, Reliance hopes to

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G L O B A L E & P

develop the Dhirubhai gas field, after sub-mitting a plan to the authorities last year.This calls for a new unmanned platformwith dry tree wells, a multi-phase exportpipeline to shore, and new onshore pro-cessing/export facilities. The location isin the Gujarat-Saurashtra basin, north-west of the Bombay High oil field, in wa-ter depths of 80-150 m (262-492 ft).

Asia/Pacific

Production has started from two de-velopment wells on the CNOOC-oper-ated WZ 6-12 wellhead platform in the Beibu Gulf, offshore China. Three morewells are due to come online soon after-ward. Thereafter, the jackup HYSY 931

is set to drill three more wells beforetransferring this summer to the WZ12-8 wellhead platform to complete the final development phase.

tttExxonMobil and Petronas Carigali

have produced first gas from the Telokfield in the South China Sea offshoreMalaysia. One four-legged unmanned platform is currently in ser-vice (Telok A), with a second, Telok B, to follow. Eventually 14 wells will be drilled from both facilities. The combined wet gas stream will head through a new 16-mi (26-km) subsea pipeline to the existingGuntong E platform for processing.

tttLundin Petroleum has discovered oil

on block PM308A offshore peninsular Malaysia. The jackup West Courageous

drilled the Ara-1 well in 75 m (246 ft) of water. The results confirmed an exten-sion of a new intra-rift oil play, proven in 2011 by the Junglau-1 well, across a largestructural complex in the northeast of the block. However, Ara-1’s oil pay zones were thinner than expected. Lundin aims to use a recently extended 3D seismic dataset to identify areas where local sand reservoir sources might be better devel-oped.

tttPan Pacific Petroleum has completed

a 15% farm-in to the block 121 produc-tion-sharing contract offshore southern

Vietnam. The semisub Ocean General was due to spud a first well on the large Ca Voi prospect this month, pending its release from a job in Indonesian waters. After Ca Voi, the rig should drill two morewells on Vietnamese block 07/03 for the same operator, Premier Oil, including a remaining commitment exploratory well (Ca Duc-1X). �

Drilling was due to start this month

on the Ca Voi prospect offshore Vietnam.

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Statoil striving to speed up subsea tie-ins

Statoil has brought onstream three of its conveyor belt of fasttrack subseatiebacks. Two are in the North Sea and one in the Norwegian Sea, where thecompany has also started work on a new project in the Åsgard area.

Vigdis North-East is a reservoir on the northern limits of the Vigdisfield in the North Sea, discovered in 2009. Recoverable volumes areestimated at around 37 MMboe. A seabed template with four wells isconnected to the existing facility for Vigdis on the Snorre A platform, 7km (4.3 mi) to the north. The anticipated field life is over 15 years, withoverall development costs around $739 million.

Statoil did not issue a cost estimate for Stjerne, a 13-km (8-mi) four-well tieback to the North Sea Oseberg platform, but did say that thefinal figure was $86 million below the amount forecast at the time ofsanction. Drilling was delayed at the start due to a rig change. The49-MMboe Stjerne field eventually entered production 39 months af-ter its discovery in late 2009. However, Statoil’s goal is to reduce itsfasttrack field development times to an average of 30 months.

Skuld in the Norwegian Sea is the company’s sixth tie-in to the Nornefield production ship. It takes in 90 MMboe (mostly oil and gas) from theFossekall and Dompap discoveries, and should extend Norne’s lifespantill at least 2030. Costs here were around $1.8 billion. Statoil plans furtherexploration and development in the Norne area, and is looking at ways oflifting recovery from the existing satellites.

To the south, Statoil and its partners have committed to the $600-mil-lion Smorbukk South Extension project, which involves adding a newsubsea template to tie in 16.5 MMboe of reserves to the Åsgard A semi-submersible platform. Initial plans call for one multi-lateral well withtwo oil-producing branches, and one gas injection well to maintain res-ervoir pressure as oil is produced. Drilling should start early in 2015followed by start-up later that year.

Lack of available capacity in the Åsgard gas pipeline system had heldup work on other gas discoveries in the area. However, the planned long-distance Polarled pipeline and its various branches in the Norwegian Seahave opened up possibilities. The partners in Zidane in license PL435 areset to take advantage by connecting the field’s gas to Statoil’s Heidrunplatform, 15 km (9.3 mi) to the southeast, via a subsea template with slotsfor four production wells. A new treatment module will be installed on theplatform to prepare Zidane’s gas for export through Polarled.

Wintershall proves oil in Hibonite

Wintershall has maintained its strong run of exploration successesin Scandinavian waters by proving oil in the Hibonite structure in theDanish North Sea, 278 km (172 mi) west of Esbjerg. The location inthe 5/06 license is 7 km (4.3 mi) north of the Ravn oil field, which thecompany successfully appraised in 2009. In both cases the reservoir isformed by upper Jurassic Heno sandstones. The jackup Noble George

Sauvageau, was next due to switch to nearby license 4/06a to drill an-other exploratory well for Wintershall on the Spurv prospect.

At present there appears to be 100 MMbbl of in-place oil, and potential for a joint development of Hibonite with Ravn. All other Danish oil field developments to date have been operated by the es-tablished triumvirate of DONG, Hess, and the DUC consortium. PAResources found commercial oil fairly recently in the Broder Tuckand LilleJohn structures, but the company’s financial difficulties ap-pear to have held back progress there.

In the southern Norwegian Sea, DONG has discovered more oil and gas close to the Trym field. A well drilled by the jackup Maersk

Giant in 65 m (213 ft) of water in license PL 147 intersected a 159-m (521-ft) hydrocarbon column in the Sandnes and Bryne formation.

Statoil’s latest appraisal well on Johan Sverdrup in the NorwegianNorth Sea proved that the giant field extends into a third license, PL502.The well encountered a 13.5-m (44-ft) oil column in the Jurassic, andthe results suggest potential for further upside west of Johan Sverdrup.Later this year Statoil plans to drill the Cliffhanger prospect in PL265.

Elgin/Franklin back in action

Total has restarted operations in the Elgin/Franklin area of the UK central North Sea.

Production had been shut in for almost a year following a gas leak from the G4 well on March 25, 2012. Investigations revealed that the cause was a type of stress corrosion unique to the well, induced froma non-producing chalk layer 1,000 m (3,281 ft) above the reservoir.

The partners have agreed to permanently abandon several Elgin/Franklin wells and to evaluate others for safety risks. In the meantime,present production is only at half the fields’ combined potential at closeto 70,000 boe/d. To restore the level of performance prior to the in-cident, redevelopment will be needed, including drilling of new infillwells. The associated West Franklin Phase II development, involving in-stallation of a new platform, remains on schedule for start-up next year.

At Yme, a planned field redevelopment in the Norwegian NorthSea, the partners have agreed to remove and scrap the MOPUstorproduction platform supplied and installed by SBM Offshore follow-ing continuing delays to start-up caused by structural defects. Thetopsides will be removed, with the Yme license holders taking own-ership of the in-situ subsea structure while they assess developmentalternatives involving a new topsides solution. SBM will receive anupfront settlement payment of $470 million and will manage trans-portation and scrapping of the removed facility.

Statoil has had no known problems with its platform on the Huldrafield in the North Sea, which entered service in 2001. The steel jacketfacility has a design lifetime of 20 years, but Huldra itself faces depletionby 2015. So, Statoil is prepared to listen to offers for re-use of the platformelsewhere. It was built as a high-pressure/high-temperature gas-con-densate production installation but could be adapted to handle light andheavy oils without the need for major investments, the company claims.

BP starts latest review of Clair potential

BP and its partners have sanctioned a new two-year appraisal drill-ing program on the giant Clair oil field 75 km (46.6 mi) west of Shet-land. The first of the five planned wells is drilling ahead and seven more could follow, depending on results. The aims of the $500-mil-lion campaign are to clarify overall reservoir volumes, distributionand fluid characteristics; to evaluate techniques that could improverecovery from the field; and to gain information for potential new developments and links to the current Clair Ridge project, targetingpart of the field north of the existing production facilities.

One new UK project going ahead is TAQA Bratani’s redevelopmentof Pelican, a subsea tieback to the Cormorant Alpha platform. Thiswill involve drilling new development wells. The project qualifies forthe UK’s brownfield tax allowance for older North Sea fields. �

Huldra platform. Photo courtesy Kjetil Alsvik, Statoil ASA.

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BSEE, API issue new rules

and standards

New rules and standards were issued forthe US offshore oil and gas industry in earlyMarch, as the Bureau of Safety and Environ-mental Enforcement (BSEE) released the Safe-ty and Environmental Management Systems(SEMS) II final rule, and the American Petro-leum Institute published two new standards forwell design and drilling operations.

According to the BSEE, the SEMS II final rule“provides greater protection by supplementingoperators’ SEMS programs with greater em-ployee participation, empowering field level per-sonnel with safety management decisions, andstrengthening oversight by requiring audits tobe conducted by accredited third-parties.”

This is an adjunct to the Workplace SafetyRule that became effective Nov. 15, 2010,which required operators to implement aSEMS program by Nov. 15, 2011, and to sub-mit a first complete SEMS audit to BSEE byNov. 15, 2013. The SEMS II Rule becomes ef-fective on June 4, 2013. Operators have untilJune 4, 2014, to comply with the provisions ofthe SEMS II Rule, except for the auditing re-quirements. All SEMS audits must be in com-pliance with the SEMS II Rule by June 4, 2015.

This comes on the heels of BSEE’s Dec. 20,2012, Draft Safety Culture Policy Statement thatoutlines the administration’s approach to estab-lishing a “common definition” for all offshoreworkers and to inform operators of BSEE’s safe-ty expectations. Elements of a final Safety Cul-ture Policy Statement are under consideration.

The SEMS II final rule expands, revises, andadds several new requirements to the existing 30CFR part 250, subpart S, regulations for SEMS.

The additional safety requirements con-tained in this final rule that were not coveredin previous regulations include: t��%FWFMPQJOH�BOE�JNQMFNFOUJOH�B�TUPQ�XPSL�

authority that creates procedures and au-thorizes any and all offshore industry per-sonnel who witness an imminent risk ordangerous activity to stop work.t��%FWFMPQJOH�BOE�JNQMFNFOUJOH�BO�VMUJNBUF�

work authority that requires offshore in-dustry operators to clearly define who hasthe ultimate work authority on a facility foroperational safety and decision-making atany given time.t��3FRVJSJOH�BO�FNQMPZFF�QBSUJDJQBUJPO�QMBO�

that provides an environment that pro-motes participation by offshore industryemployees as well as their managementto eliminate or mitigate safety hazards.t��&TUBCMJTIJOH�HVJEFMJOFT�GPS�SFQPSUJOH�VO-

safe working conditions that enable off-shore industry personnel to report pos-sible violations of safety, environmentalregulations requirements, and threats ofdanger directly to BSEE.t��&TUBCMJTIJOH� BEEJUJPOBM� SFRVJSFNFOUT�

for conducting a job safety analysis. t��3FRVJSJOH�UIBU�UIF�UFBN�MFBE�GPS�BO�BV-

dit be independent and represent an ac-credited audit service provider.

It also makes mandatory elements of the American Petroleum Institute’s (API) Rec-ommended Practice 75 (RP 75).

Meanwhile, the API has published two new industry standards for well design and drilling operations.

One of these is RP 96, “Deepwater Well De-sign and Construction.” It provides a referencefor offshore well design, drilling, and comple-tion operations in deepwater, and covers therange of considerations to include when plan-ning and executing deepwater drilling.

This document does the following: t��*EFOUJåFT� UIF� BQQSPQSJBUF� CBSSJFS� BOE�

load case considerations to maintain wellcontrol during deepwater well operations(drilling, suspension, completion, produc-tion, and abandonment).t��4VQQMFNFOUT� CBSSJFS� EPDVNFOUBUJPO� JO�

API 65-2 with a more detailed descriptionof barriers and discussion of the philoso-phy, number, type, testing, and manage-ment required to maintain well control.This document also supplements the bar-rier documentation in API 90 with regardto annular pressure buildup. Abandon-ment barrier requirements are describedfor use when designing the well.t��%JTDVTTFT�MPBE�BTTVNQUJPOT �SFTJTUBODF�

assumptions, and methodologies com-monly used to achieve well designs with high reliability. The load case dis-cussion includes less obvious events that can arise when unexpected circum-stances are combined.t��%FTDSJCFT�UIF�SJTL�BTTFTTNFOU�BOE�NJUJ-

gation practices commonly implementedduring deepwater casing and equipmentinstallation operations.

The other standard is Technical Report1PER15K-1, “Protocol for Verification andValidation of High-Pressure High-Temper-ature Equipment.” This publication gives aprocess to evaluate equipment for use in HP/HT environments offshore and onshore.

The report focuses on an evaluation pro-cess for HP/HT equipment in the petroleumand natural gas industries and includes de-

sign verification analysis, design validation,material selection considerations, and manu-facturing process controls “necessary to en-sure the equipment is fit-for-service in theapplicable HP/HT environment.”

This follows the November 2012 publica-tion of API Standard 53, “Blowout Preven-tion Equipment Systems for Drilling Wells.”

“We are the global leaders on setting the in-dustry’s standards, which are developed in ac-cordance with ANSI-approved procedures in arigorous and open review process,” said DavidMiller, API director of Standards. “Every oneof our standards is built on expert input fromindustry and the regulatory agencies.”

Ecopetrol increases GoM

presence with lease sale

Ecopetrol S.A. reports that its US affiliate hasplaced the most competitive bids for six blocks inthe recent Central Planning Area Lease Sale 227held in New Orleans, as disclosed by the Bureauof Ocean Energy Management (BOEM).

In this lease sale, Ecopetrol America Inc.partnered with Murphy Exploration and Pro-duction in two blocks; with Anadarko US Off-shore Corp., MCX Gulf of Mexico LLC andJX Nippon Oil Exploration (U.S.A) Ltd. in twoblocks; and in two blocks Ecopetrol Americahas 100% interest.

The official awarding of the blocks will beconducted by BOEM in the coming months af-ter the checking of bids and ascertaining thatthe companies fulfill the conditions requiredfor the round.

The economic bids placed by EcopetrolAmerica and its partners in the six blocks addup to approximately $15.5 million, with Eco-petrol America’s share consisting of approxi-mately $6.2 million.

These blocks allow deepwater hydrocarbonexploration in water depths of over 221 m (725ft) for a five to seven-year period. The newblocks are added to the 47 obtained on theGoM in previous lease sales. With these sixblocks, Ecopetrol America Inc. could increaseits participation in this prolific hydrocarbonbasin to 136 blocks.

The results obtained strengthen Ecopet-rol’s position in the Gulf of Mexico, which itconsiders a focus area in its internationaliza-tion process. �

Chevron discovers Lower

Tertiary oil at Coronado prospect

Chevron Corp. has reported an oil discovery at the Coronado prospect in the deep-water US Gulf of Mexico.Walker Ridge block 98 Well No. 1 encountered more than 400ft (122 m) of net pay.The well is located approximately 190 mi (308 km) off the Louisi-ana coast in 6,127 ft (1,868 m) of water and was drilled to a depth of 31,866 ft (9,713 m).

“The Coronado discovery continues our string of exploration successes in the Lower Tertiary trend, where Chevron is advancing multiple projects,” said GaryLuquette, president, Chevron North America Exploration and Production Co. “It also highlights the importance of the deepwater Gulf of Mexico as a source of domestic energy for the United States.”

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Statoil’s Smørbukk South

to get FMC hardware

FMC Technologies Inc. will supply Statoilwith $96 million in subsea equipment for theSmørbukk South Extension Project. FMC willsupply subsea trees, wellheads, a manifold, con-trol systems, and other associated equipment.

Smørbukk South is part of the Åsgarddevelopment in the Norwegian Sea, and the award is the third order for FMC Technolo-gies from the fasttrack portfolio agreementannounced in 2012. The equipment is sched-uled for delivery in 2014.

Åsgard takes in production from the Smørbukk, Smørbukk South, and Midgardfields, which have been developed throughthe Åsgard A FPSO, the Åsgard B semisub-mersible platform, and the Åsgard C FSO.

Smørbukk South Extension holds esti-mated recoverable reserves of 16.5 MMboe, and will be developed with a new subsea template connected to Åsgard A with spareslots for future wells. Statoil plans to put in one multi-lateral well with two oil-producingbranches and a gas injector well.

Recovered gas will be re-injected into thereservoir to maintain reservoir pressure as oilis drained. Drilling should start in early 2015,followed by first production in September2015. Statoil estimates the productive life spanof Smørbukk South Extension at 12 years.

Other partners are Petoro, Eni Norge, To-tal E&P Norge, and ExxonMobil.

Petrobras, Aker Solutions

sign frame agreement

Petrobras has entered a frame agreementwith Aker Solutions for subsea equipment touse in deepwater presalt field developmentoffshore São Paulo, Santos basin, Brazil. Thenew agreement is valued at $800 million andhas a scope of work for 60 vertical subseatrees, subsea controls, tools, and spares inthe 2014-2018 time period.

Based on the new agreement, Aker says it will expand its facilities in Brazil and that a new subsea equipment manufacturing fa-cility will be established in Curitiba, Parana, 800 km (479 mi) south of Rio de Janeiro, to replace the current facility by 2015.

At the same time, Petrobras issued a sec-ond call-off order to Aker for delivery of sub-sea equipment to Sapinhoá and Lula Nor-deste offshore presalt field developments based on a frame agreement signed in 2010.

The second call-off from the earlier agree-ment includes 20 vertical subsea trees, sub-sea controls, tools, and spares for delivery in the 2013-2015 span.

Total signs for Congo subsea

production system

Total has signed an $850-million letter of award with Aker Solutions for the subsea

production system offshore Republic of the Congo at the Moho Nord project.

Scope of work includes the delivery of 28 vertical subsea trees including wellhead sys-tems, two installation and workover controlsystems, seven manifold structures, subsea control and tie-in systems. The contract also contains options related to Moho Nordwhich Total may exercise. The project will apply Aker Solutions’ new vertical tree tech-nology.

Aker Solutions and Total also will estab-lish a service base in Pointe Noire, Republic of the Congo. Management, engineering, and procurement will be from Aker Solu-tions’ headquarters in Fornebu, Norway.The subsea trees and the workover systems

will be manufactured at the Tranby manu-facturing center, outside Oslo. The produc-tion of the manifolds will be at Aker Solu-tions’ facility in Egersund on the west coastof Norway, while the facility in Aberdeen in the UK will deliver the control systems and the wellheads.

The first deliveries of the Moho subsea production system will be made in the 2Q 2014.

Moho Nord and Moho Bilondo 1bis arepart of the Moho-Bilondo oil field which was commissioned in April 2008 for commercialproduction. It is the first deepwater field offshore the Republic of the Congo at wa-ter depths ranging between 600 to 1,050 m (1,968 to 3,444 ft). �

OSRL shows new well capping equipment

Oil Spill Response Ltd. (OSRL) has unveiled new well capping equipment for de-ployment in the event of a subsea well control incident.

The Subsea Well Intervention Service (SWIS) is available to oil and gas companies across the industry and to any offshore location worldwide.

SWIS includes four capping stacks to shut in an uncontrolled subsea well and two hardware kits to clear debris and apply subsea dispersant at a wellhead, making surface working conditions safer and enhancing bio-degradation.

The equipment is claimed to be suited to most known subsea wells, and can be deployed in water depths up to 3,000 m (9,842 ft) and control flow pressures up to15 kpsi.

It will be stored at four locations in Norway, Brazil, South Africa, and Singapore,and maintained ready for immediate mobilization and transport by sea and/or air in response to an incident.The equipment in Stavanger is already available for interna-tional use, with a further three devices to be delivered this spring and summer.

In 2011, nine international oil and gas companies formed the Subsea Well Re-sponse Project (SWRP), pooling resources to develop equipment to enhance subsea well control capability. OSRL collaborated to construct this equipment, and com-panies can now subscribe to SWIS to incorporate this equipment into their ownincident response plans.

Fugro Chance Inc. and Coda Octopus Group Inc. have entered a two-year agree-ment to develop the Coda Octopus Echoscope, a patented 3D sonar technology.Coda Echoscope Dual Frequency 3D Sonar is a sonar device that uses phased arraytechnology. It generates more than 16,000 beams simultaneously to produce 3D sonar images of both moving and stationary objects.Tony Gray, Fugro Chance data manager, said: “There is a world of possibilities with this 3D technology, be it install-ing platform legs subsea, seabed clearance surveys, or even close-proximity subsea structure point cloud acquisition.”

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Scarborough partners mulling FLNG option

ExxonMobil and BHP Billiton are considering what would be theworld’s largest-capacity floating LNG facility for the Scarborough fieldin Australia’s Carnarvon basin. If given the go-ahead, the 480 m by 75m wide (1,575 ft by 246 ft) FLNG unit would be capable of processingaround 6 MM tons per annum of LNG, an ExxonMobil spokesmantold Offshore.

ExxonMobil communications advisor Aaron Stryk confirmed thatthe company has submitted an environmental plan to Australian author-ities and said a development decision could come in the second half of2013. “A final concept select decision will be made following completionof engineering and design work which will enable a comparison of alloptions for developing Scarborough,” Stryk said.

“FLNG is considered the best development option for Scarboroughbased on a balance of economic, environmental, and social reasons.FLNG reduces capital costs by eliminating the need for infrastructurelike LNG loading jetties, dredging of shipping channels, pipelines, andsite clearance. It can reduce development costs of gas in a remote off-shore field, and enable development of a resource that may otherwiseremain undeveloped. It has a much smaller environmental footprintcompared to an onshore LNG development and would eliminate theneed for dredging.”

The company has not provided a cost estimate for the project, andStryk would not comment on the possible timing of a final invest-ment decision. ExxonMobil operates the Scarborough prospect in a 50/50 joint venture with BHP Billiton.

Shell’s Prelude FLNG project, also offshore Western Australia, is indevelopment with a targeted startup date in 2017, which could makeit the first FLNG project to go onstream. Prelude’s floating productionsystem will be roughly the same size as the Scarborough unit, but willhave a production capacity of around 3.6 MM tons per annum of LNG.

Q5000 lands GoM gig

Helix Energy Solutions Group’s Q5000 deepwater well interventionsemisub will go to work for BP in the US Gulf of Mexico following thenewbuild’s planned 2015 delivery. The five-year contract includes anoption to extend for two successive one-year terms, Helix said.

The Q5000 is modeled after Helix’s Q4000, which was used exten-sively in the Macondo emergency response operations. The new semi,under construction at Sembcorp Marine’s Jurong Shipyard in Singa-pore, will be capable of operating in 10,000 ft (3,048 m) water depths.

Grupo R orders four Keppel jackups

Keppel Offshore & Marine subsidiary KeppelFELS has secured con-tracts worth $820 million to build four jackup rigs for Mexican drillerGrupo R. The jackups will be built to Keppel’s KFELS B Class designand are scheduled for delivery from 2Q 2015 to 4Q 2015. The rigs willoperate in water depths of up to 400 ft (122 m) and drill to depths of30,000 ft (9,144 m).

Mexico’s state oil company, Pemex, has said it plans to invest $25.3billion this year to help counter production declines, with around $20billion dedicated to upstream activities.

“Pemex have indicated their aim to operate the biggest fleet of jackuprigs in the world and Grupo R is well positioned to support them withfour premium jackup rigs,” said Ramiro Garza Vargas, CEO of Grupo R.

Wärtsilä picked for PSV series design

Wärtsilä Corp. has been awarded a contract to design four multi-purpose platform support vessels for Bumi Armada Berhad subsid-iary Armada Offshore MPSV, the Malaysian vessel operator. The fourvessels will be built by a subsidiary of Nam Cheong Ltd. in China’s Fu-jian Mawei Shipbuilding yard. The contract’s value was not disclosed.

The PSVs will be based on the WSD 1000 design and will measure88.8 m (291 ft) in length by 20 m (66 ft) in breadth. Wärtsilä will also

supply main power generation systems, propulsion systems, electri-cal systems, and automation systems.

Ensco orders Keppel FELS jackup

Ensco has placed a $225-million order with Keppel FELS for a new premium jackup to be delivered in early 2015. The ENSCO 110

will be based on the Keppel FELS B Class Bigfoot design, capable of working in 400 ft (122 m) water depths and equipped to drill to a maximum 30,000 ft (9,144 m). The rig will be built in Singapore.

“Customer demand is broad-based for high-specification jackup rigs,and this rig can work in virtually every shallow water basin around theworld,” said Dan Rabun, Ensco chairman, president and CEO.

HHI to build Edda Accommodation monohull

Edda Accommodation has placed an order with Hyundai Heavy Industries for a new monohull accommodation vessel based on the company’s Edda Fides monohull vessel, delivered in early 2011. The contract includes an option for an additional ship.

The 155-m (509-ft) long accommodation vessel will house up to 800 people and is scheduled for delivery in June 2015. �

Dockwise Ltd.’s Mighty Servant 1 has transported the extended tension

leg platform for Chevron’s Big Foot field from Daewoo Shipbuilding &

Marine Engineering’s South Korea shipyard to South Texas, where it

will be readied for deployment in the deepwater Gulf of Mexico.The Big

Foot TLP will be installed in 5,330 ft (1,615 m) water depths, said to be

the deepest TLP installation to date. First oil from the $4-billion project

is scheduled for 2014.The platform will have a production capacity of

75,000 b/d of oil and 25 MMcf/d of gas. (Photo courtesy Dockwise)

A. K. Suda has signed a contract with Triyards Marine Services of Sin-

gapore, a subsidiary of EMAS Offshore, to design a series of 137.25-m

(450-ft) leg liftboats, based on the SUDA-450-L3T design. Two such ves-

sels are currently under construction in Asia.The liftboats are suitable

for North Sea operations and will be certified for offshore wind farm

installation, maintenance, and repair. (Photo courtesy A. K. Suda)

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Back in the day, the ultimate over-simpli-fication of the force motivating oil producers was the phrase, “Drilling for Dollars.” It was a neat way to display the inbred optimism of the wildcatter’s spirit. Back then, with dry hole ra-tios hovering around 90%, the industry needed all the optimism it could muster. Luck played a major role in deciding whether a wildcatter would strike it rich or drill a duster.

In the early part of the 20th century, slick-tongued promoters scoured the country look-ing for investors so they could keep drilling. Many were delighted with a dry hole because that meant they did not have to pay off the people who held fractions of the lease total-ing 200% or 300%. In many cases, the science used in determining where to drill was loosely termed “closeology” – drill as close as possible to a producer and you were likely to bring in a well.

Since subsurface geology was more art than science, drillers employed “scouts” who fre-quented the saloons around the oil patch trying to find out who was drilling and how deep they were. Scouts were even seen to sneak up to a competitor’s rig that was making a trip to try to count the number of stands in the derrick so they could estimate the well’s depth.

The industry has come a long, long way since those days of wooden rigs and iron men. Science and technology has enabled us to con-tinue drilling, and even to reduce the dry hole ratios to 60% or less. At the forefront of this ap-plied science is the ubiquitous drill bit.

In this issue of Offshore, there is a story about bit innovations that, in their effect, truly pay off the phrase “Drilling for Dol-lars.” However, since the bit has nothing to do with whether the well penetrates produc-tive strata, the dollars we are writing about do not come from production, they come from cost reduction.

Traditionally, the highest cost item on an AFE is rig cost. The Independent Petroleum Association of America (IPAA) used to do an annual survey of the cost of drilling and equipping an oil well. Rig costs always led, averaging 35% of the total. Naturally, people reasoned, “If we can reduce drilling time, we can reduce our biggest cost item.” And the race was on.

The conventional wisdom gravitated to-ward increasing rate of penetration (ROP) to save time, and many of the innovations devel-oped by bit providers were aimed at designs that could boost ROP. If you look through oil magazine archives, you will find that al-most all bit advertisements focus on ROP. It is logical. Wells were vertical, for the most part. Most geocolumns were conventional and fairly easy to drill. Few wells were deeper than 15,000 ft (4,572 m), and bits just had to

make it to the next casing point, so ROP was the only parameter that played a major role in cost reduction. Offshore was no exception.

As oil and gas became harder to find, drill-ing became tougher. Well depths increased both offshore and on land. Offshore drillers moved to increasingly deeper waters, where individual wells could not be produced eco-nomically from single jacket platforms. It be-came more economical to drill multiple wells from a single platform, and this called for di-

rectional wells to reach the far limits of the reservoirs. Finally, water depth exceeded the economic limit of fixed platforms and floating production facilities were needed. On land, there was a similar revolution, as plays like the Austin Chalk required long lateral wells.

The upshot of these changes altered bit economics. In many cases, it was not possible to drill to the next casing point with a single bit. Intermediate formations became tougher to drill, with hard streaks and highly abrasive sections. Bits became worn before they could complete drilling a section. Suddenly ROP stopped being the key parameter in rig cost re-duction. It became more important to extend bit life so it could drill a section in one trip, rather than to drill fast.

Deepwater offshore rig rates were steadily climbing, and tripping pipe could consume 12 to 24 hours. If one pipe trip could be elimi-nated by extending bit life, it would save far more rig hours than increasing penetration rate.

As you read the story on bit technology advances, see how many of the latest innova-tions are directed at extending bit life. ROP is still important, but increasing ROP has fallen behind as the number one design goal. For the past couple of years, the bit manufactur-ers’ advertisements now talk about their products’ ability to “Drill the build section and the lateral in a single trip.” Most recently, they are starting to say, “Drill the vertical, build, and lateral sections in one trip!”

Offshore, dual-gradient technology has been introduced to allow safe margin drill-

ing so many casing points can be eliminated. This will save considerable money in casing and cementing costs as well as logging costs. However, to take advantage of this benefit, the drill bits must be able to drill the resulting longer sections without wearing out. Again, the aim is reduction of pipe trips, not increas-ing ROP. When dual-gradient drilling takes off, the bit providers will be ready.

Rigs are truly drilling for dollars these days. Oh sure, they are using every skill they have to steer wells through reservoir “sweet spots” and land long laterals in prolific pay zones to maximize reservoir contact and productivity. But they are also drilling to save dollars by maximizing bit life to minimize the number of necessary bit trips. And if their subsequent designs have to give up a bit of ROP to achieve longer bit life, they are willing to make that sacrifice. �

&EJUPS�T�OPUF� Dick Ghiselin’s article, “Bit technology

continues to advance,” can be found on page 86.

New twist on an old phrase

The IDEAS drill bit design platform enabled engineers to optimize placement of the rolling cutters

on bit blades to ensure efficient cutter rotation, thereby optimizing drill bit durability. Image courtesy

Smith Bits, a Schlumberger company.

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CGG claims new survey

records made in GoM

Using its StagSeis survey configuration, CGG claims the recordfor deploying the longest offsets in the industry for a full-azimuthmulti-vessel survey. For the recent multi-client “IBALT” survey in the Gulf of Mexico, offsets were a record-breaking 18 km (1.2 mi). StagSeis data are acquired using multiple vessels in a staggered con-figuration to provide the ultra-long offsets, full-azimuth, and broadbandwidth (especially low frequencies) required to image complex areas such as the Gulf of Mexico.

Data are acquired in a regular grid, so processing is compatiblewith conventional wide-azimuth techniques, allowing faster turn-around than alternative non-linear methods. The Geo Caribbean,operating in the Gulf of Mexico, used its record-breaking 13.44 sq km (5 sq mi or 3,321 acre) towing configuration. CGG proposed a wide tow of eight streamers with a 160-m separation, 60% wider than a typical survey with a 100-m separation, enabling a greater area of data to be acquired in a single pass and hence greater productionefficiency.

By deploying a streamer length of 12,000 m (39,360 ft), CGG de-livered the long offsets required to achieve the survey’s geological objectives. The end-result is an efficient survey design and the larg-est single-vessel acquisition footprint in the world, CGG says.

Open Geophysical

releases OpenCPS 3.0

Dolphin Group ASA’s Open Geophysical has released its OpenCPS3.0 software platform for land and marine data processing. The newrelease brings processing capabilities spanning from field QC throughPSTM imaging, said Open Geophysical. New marine workflows in-clude 3D SRME and Fourier-domain regularization.

Open Geophysical was acquired by Dolphin Geophysical in 2012. Subsequently, Dolphin has installed OpenCPS 3.0 in its London pro-cessing center and on its four vessels for onboard quality controland fasttrack processing.

OpenCPS 3.0 supports Dolphin’s full workflow from navigationmerge through imaging including the proprietary SHarp broadbandprocessing.

“OpenCPS delivers interactivity, high-end visualization, and ex-tensibility. With the 3.0 release, OpenCPS is now a full productionseismic processing system ready to handle the largest and mostcomplex datasets,” said Roland Gunther, VP of Open Geophysical. “Now part of Dolphin Geophysical, we are continuing to focus onsoftware and services for all of our customers and continue to de-velop new tools for both land and marine processing.”

Dolphin sets

South Africa survey record

Dolphin Geophysical has used a seismic survey spread of eight streamers were 8 km (5 mi) long and separated by 200 m (656 ft), giving a total area covered under tow of 11.2 sq km (4.3 sq mi).

The equipment was used offshore South Africa under contract with Shell and using the Polar Duchess seismic vessel.

The big spread was used to get 8,000 sq km (3,089 sq mi) sur-veyed during a limited weather window of four months.

“Despite the remote nature of the area and the challenging met-ocean conditions, the survey has been executed safely, efficientlyand with a low down time,” said Stuart McGeoch, Shell regionalventures exploration manager for sub-Sahara Africa. “We have beenimpressed with the quality of acquisition data.”

Shell’s processing center in Houston validated the initial returnsand is processing the data. �

CGG has started its first-ever 3D multi-client survey in the Norwegian North Sea. Phase 1 of the Steppingstone broadband marine project will cover

2,260 sq km (873 sq mi or 558,455 acres) over Halten Terrace.The survey is being acquired by the Oceanic Champion and the operation is expected to

last three months. CGG said it is optimizing its BroadSeis acquisition and processing to focus on Jurassic rotated fault blocks, inversion anticlines,

and shallow targets.

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O F F S H O R E A U T O M AT I O N S O L U T I O N S


Paul Miller

ARC Advisory Group

Since many brownfield offshore produc-tion assets lack accurate “as-built” documen-tation, it is often problematic for engineers to plan, design, and implement needed re-configurations. Modern laser scanning tech-nology helps to a certain degree, but still re-quires the engineering group to transform the laser scan data into 3D models of the asset that can be used within their familiar plant design management software (PDMS) environment, a relatively costly and time-consuming process.

Several years ago, the owner-operator of a 25-year-old offshore wellhead platform locat-ed in North West Java in Indonesia observed increasing subsidence. This was reducing the distance between the platform’s cellar deck and the maximum wave height on this normally unmanned platform, threatening vital equipment and posing a safety threat for operators when on the platform.

As part of a 13-year life extension proj-ect, the owner-operator commissioned PT Synergy Engineering to reconfigure the platform, relocate equipment to compen-sate for the subsidence, and perform addi-tional structural and other modifications as needed to ensure safe operation over the projected lifespan. These extensive brown-field modifications ultimately included rein-forcing the existing decks and constructing a new mezzanine deck to house some of the equipment relocated from the cellar deck.

According to Arief Susanto, director at PT Synergy Engineering, the company faced many engineering challenges on this proj-ect. First, the only available as-built draw-ings providing the only documentation basis for the existing facilities had been created 25 years ago when the platform was origi-nally commissioned. These had never been updated. In addition, no drawings existed for either the piping plans/layouts or the electrical and instrument layouts and no datasheets were available for the instru-mentation. To make matters worse, the old equipment had no tags, which made it dif-ficult to identify during the survey, and the wellhead control panel had been modified significantly, so it had to be retraced to iden-tify the control logic.

Since the platform was sinking (with the existing boat landing already under water), it had also become very difficult to gain access to the lower sections, making it extremely dif-ficult to take physical measurements.

Previously, Synergy had used laser scan-ning on a number of projects to produce as-built models as the basis for redesigns. Typically in these projects, the company’s laser scanning partner, PT SurtechUtama, would perform the laser scanning to obtain the point cloud data and then convert it to a non-intelligent model for use in the AVE-VA PDMS engineering software. Synergy would then use conventional techniques to build in the needed intelligence, such as to import and export PDMS piping, structural elements, and equipment nozzle specifica-tions. This all involved time and cost.

In mid-2011, global engineering software provider AVEVA contacted Synergy’s part-ner, Surtech, seeking its assistance with the beta testing of its new Laser Modeller, designed to transform laser scan data into an intelligent 3D model for use in its own or most other leading suppliers’ PDMS soft-ware.

Together, Synergy and Surtech decided that the challenging wellhead revamp proj-ect would represent an excellent opportuni-ty to test the capability of the new software. For this engagement, Surtech assumed re-sponsibility for performing the actual laser scanning and Synergy for all subsequent en-gineering work, including applying the laser modeling software to transform the laser-scanned point cloud data into an intelligent 3D model for use within Synergy’s software.

Since Synergy had no experience apply-ing either laser modeling or the new soft-ware, used to read the cloud point data from the laser scan photos, it would have to learn how to use these solutions from scratch, which is typically a time-consuming process. It would also be necessary to export the company’s engineering specifications from its PDMS database into the laser modeling software prior to use.

However, according to Susanto, even though engineering firms such as his own do not typically involve themselves with the “nuts and bolts” of specialized laser scan-ning-related software, with some assistance from the laser scanning experts at Surtech, Synergy’s designers became proficient with the software relatively quickly.

The designers were able to identify the relevant shapes and configurations from Surtech’s high-quality point cloud data, use the laser modeling software to generate in-telligent 3D models of the structural com-ponents and assets, and then import these models into the familiar PDMS software us-ing the interface software.

For any engineering engagement, it is im-portant to distinguish between what could be done using the available tools and re-sources, and what needs to be done to fulfill the project requirements within the given time and cost constraints.

For this challenging project, Synergy not only used a common-sense, hybrid approach that employed the laser modeling software for the bulk of the modeling requirements, but also used the conventional PDMS envi-ronment to provide additional model detail or fine tuning, as required. For example, the main piping lines were modeled directly us-ing the laser modeler, while smaller compo-nents such as supports and cable trays were modeled in the conventional design environ-ment.

In addition to modeling compatible, intel-ligent components, the intelligent PDMS specifications within the laser modeling environment enabled Synergy’s designers to calculate weights, centers of gravity and surface areas, as well as generate drawings and isometric projections (using Standard Draft and ISO Draft modules).

Susanto said: “The bubble view software provided a dynamic, high-resolution field of view of the laser-scanned data that reduced perspective distortion and enabled Syn-ergy’s designers to place themselves at any scan location and perform zoom, pan, and measure operations within the laser scan environment.”

Finally, since the interface software en-abled the laser scanned data to be made available within the PDMS environment, it provided a useful tool for performing in-house design and clash reviews, verifying model completeness, and supporting client presentations.

According to Susanto, this new approach enabled PT Synergy Engineering to turn what is traditionally a five-step process into a more efficient four-step process that elimi-nated the time and effort typically required to remodel the non-intelligent model in the intelligent PDMS environment.

“Once our designers became proficient with the associated laser scanning-related tools, we found that the laser modeling soft-ware could save up to 30 or 40% of the time and effort normally required to generate an intelligent model from laser scan surveys,” Susanto said. “We particularly saved time on jobs such as 2D drawing production, and in the remodeling of intelligent shapes and objects over laser scanned, non-intelligent ones.” �

Laser modeling technology supports

platform upgrade offshore Indonesia

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34 Offshore May 2013�r�www.offshore-mag.com

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look to new frontiers

Passive-margin basins emerging as new source

of reserve additions and new plays

Oil and gas producers frequently ask “where do we go next to find new hydrocarbon reserves?” As research-ers, to help answer this question, we began by analyzing available histori-

cal discovery data. As a first step to help un-derstand trends as well as to identify priority geographical areas, we analyzed the history of existing discoveries found in the IHS In-ternational Field database. This database contains detailed information for more than 28,000 oil and gas fields globally, including 481 deepwater discoveries made during the study period, 2007 to 2012.

Calculating total new discovery volumes and average new discovery size by the type of terrain and by country quickly led us to several important conclusions. First, deep-water has become the predominant source of new oil and gas discoveries worldwide, accounting for more than 50% of all conven-tional new reserves of 170 Bboe.

Second, six-year trend data shows that av-erage hydrocarbon discovery size is consid-erably larger offshore, and is especially so in deepwater, where discovery sizes reached a healthy 230 MMboe. This is about a magni-tude larger than the onshore average new discovery size for the same period, which is approximately 20 MMboe. Since deep-water operations are extremely costly, the economic threshold is forcing operators to focus their efforts on larger prospects ini-tially. Fortunately, according to our analysis at IHS, they have been able to find signifi-cant hydrocarbon accumulations in many frontier provinces.

Deepwater accounts for approximately 7% of total conventional production, in com-parison with onshore and shallow water, with 60% and 33%, respectively. However,

only 38% of discovered deepwater reserves are currently producing. More than 60% of deepwater reserves currently have apprais-al, developing, or discovery status. How-ever, once they are brought into production, these non-producing fields could potentially double production volumes to approximate-ly 6 Bboe by 2020.

Even though recent challenges such as the global economic downturn, credit crises, increased capital costs, and environmental concerns affect deepwater operations, the strong positive growth in offshore E&P trends will likely continue, making deepwa-ter a key contributor to conventional reserve replacement with rapidly increasing share in global hydrocarbon production.

Assessing the geographical locations and geologic targets of recent deepwater discov-eries, we find that Brazil continues to deliver by adding primarily oil reserves (26 Bboe) in subsalt deposits of the Santos basin. In-terestingly, an analogous subsalt play is an exploration target in the Kwanza basin of Angola, which is located on the other side of Atlantic Ocean.

Substantial oil additions were made in the deepwater Gulf of Mexico, Angola, and Ghana. And an important oil discovery was made in the Fox do Amazonas basin of

French Guiana in 2011. For many years, this basin was famous for unsuccessful explora-tion drilling offshore. However, an attempt that targeted a different stratigraphic play of Turonian age was successful, and resulted in a significant oil and gas discovery esti-mated at 957 MMboe (proven and probable) recoverable.

This discovery may indicate even greater exploration potential in French Guiana and possibly neighboring countries including Suriname, Guyana, and Brazil. IHS’s six-year deepwater discovery outlook indicates that operators searching for oil reserves are most likely to find success searching either in the deepwater Gulf of Mexico, or the Atlantic margin of South America or West Africa.

To the east, new, giant gas discoveries were made during 2007 to 2012 in East Af-rica (Mozambique and Tanzania), and in the Mediterranean (Israel and Cyprus). As a result, both developments are going to change the energy balance in the region and will provide significant, long-term gas supplies to energy-hungry countries. Dur-ing the period, several new countries joined the deepwater club, having achieved their first deepwater discoveries. Deepwater drilling rigs finally made their way to inner seas such as the Black Sea and Caspian Sea, which led to discoveries in Russian, Iranian, and Romanian sectors. Other new deepwa-ter countries include Ghana, Libya, China, Cyprus, and French Guiana.

To assess basin and country potential for deepwater discoveries, we analyzed the de-tailed geologic data stored in the IHS Global E&P Basins database, which contains infor-mation on more than 5,100 global petroleum basins and sub-basins, as well as 57,000 field reservoirs containing hydrocarbons. Trend

Kerri Nelson

Michael DeJesus

Alex Chakhmakhchev, Ph.D.

Melissa Manning

IHS

Photo by Dag Myrestrand,

courtesy Statoil

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Passive margin

Passive/backarc

Passive/rift

Passive/transform

Basins

Bally Snelson

Passive/rift77%

Passive/backarc

7%

Passive/margin5%

Passive/transform

4% Others7%

Source: IHS

Global Passive Margin basin location map.

analysis identified the most prolific geologi-cal settings favorable for significant reserve accumulation. Our analysis of deepwater discoveries for 2007 to 2012 reveals several trends that can help operators strategize their global exploration efforts.

First, the vast majority of deepwater dis-coveries were made in passive margins, which are continental margins with very little or no seismic or volcanic activity. Based on Bally and Snelson classification, there are four examples of Atlantic-type passive mar-gins, which straddle continental and oce-anic crusts. One of them, the passive margin overlying a rift system, accounts for 77% of total new reserve additions in deepwater.

In passive margins, substantial volumes of deepwater reserves occur in stratigraphic traps or in a combination of stratigraphic and structural traps, which requires more sophisticated techniques to uncover. Fur-ther analysis of these reservoirs shows that two major depositional facies, turbidites and lacustrine, account for 47% and 30%, respec-tively, of total new discovery volumes in deepwater.

A passive margin basin type is common not only on both sides of the Atlantic Ocean in West Africa and eastern South America, but also is widespread in the Arctic, Austra-lia, New Zealand, India, and Eastern Canada. Widespread passive margin basins around the globe offer explorationists many oppor-tunities for new hydrocarbon discoveries.

From 2007 to 2012, a number of new plays were discovered in deepwater settings worldwide. These new plays were not known either onshore or offshore prior to 2007, and represent new concepts of hydrocarbon ac-cumulation in deepwater. For example, in Mozambique and Tanzania, approximately 8 tcf of gas was reported discovered in Eocene and Paleocene stratigraphic plays. Another

significant gas discovery of 5.7 tcf was made in a Lower Miocene play in Israel and Cy-press (Levantine basin).

In Ghana, a significant oil and gas volume of almost 2 Bboe was made in a Turonian stratigraphic and Turonian stratigraphic-structural plays in the Cote d’Ivoire basin. Other new, significant deepwater plays were established in the deepwater off French Guiana, the Falkland Islands, Norway, Iran, Mexico, India and others.

Deepwater challenges

Exploration is risky in many deepwater frontier provinces, with drilling success rates averaging only 10 to 15%. With that in mind, operators carefully select their drilling prospects and make every effort to minimize the risk. Still, only 38% of deepwa-ter newfield wildcats drilled in 2007 to 2012 were technically successful. If an economic threshold for minimum reserve size is ap-plied, then the drilling success rate would drop to 25% globally.

Another big challenge of deepwater proj-ects is their capital intensive nature and technological complexity, which combined, resulted in longer payout periods and lower returns on investment. A typical deepwater discovery requires a development period of five to eight years prior to starting produc-tion. When it comes to bringing fields into production, operators in North America are more efficient – averaging five years to production after discovery. The exploration period preceding an official discovery date adds to the total time needed to start pro-duction and generate revenue.

The 2008 global recession had a strong impact on offshore drilling activity, which included slowing drilling rates in shallow water. However, this decline in shallow-water drilling started before the recession,

and was caused by various factors, includ-ing the utilization of new technology, higher drilling success rates, and higher flowrates in deviated wells. Also, shallow-water/shelf production in some countries approached an advanced stage of development during the period, and once in production, these projects do not require extensive drilling programs.

Deepwater and ultra-deepwater diverged considerably during the study period of 2007 to 2012, and exploration and development drilling trends do not show any indication of a slowdown. In fact, 2011 was a record year for ultra-deepwater drilling, totaling 177 wells. The 2011 well count showed indi-cations of recovery, with strong deepwater and ultra-deepwater drilling rates of approxi-mately 500 wells globally, with additional growth in the number of shallow-water wells.

With expanding activities in deepwa-ter, the global supply and demand balance for drilling rigs is very tight. Even though the number of available deepwater drilling rigs is increasing every year and reached a record number of 283 in 2012, utilization rate is close to 98%, which, not surprisingly, caused ultra-deepwater drilling rig day rates to escalate. From 2007 to 2012, ultra-deep-water rig day rates grew from $250,000/day to more than $400,000/day. At present, the global industry needs more drilling rigs capable of operating in deep- and ultra-deep water depths to test numerous exploration targets and to bring the discovered reserves to production.

Political risks

Because deepwater projects are so capex intensive, operators are very sensitive to their levels of risk exposure in the countries in which they operate. To aid in risk assess-

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Drilling rig day rates by water depth.

Source: IHS

ment, IHS identifies and analyzes the political and commercial risksaffecting the E&P climates in more than 120 producing and prospec-tive countries. The IHS political risk analysis service is designed specifically for the international oil and gas industry, and as such, fo-cuses its analysis on factors that directly influence the investment or operational climates of upstream exploration plays, and is weighted for the following criteria:t��1PMJUJDBM�SJTLT��8BS�BOE�FYUFSOBM�UISFBUT �DJWJM�BOE�MBCPS�VOSFTU �JOUFSOBM�WJPMFODF�BOE�SFHJNF�JOTUBCJMJUZt��4PDJP�FDPOPNJD�SJTLT��&DPOPNJD� JOTUBCJMJUZ �FOFSHZ�WVMOFSBCJM-

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"T�B�SFTVMU �UIF�åOBM�SBOLJOH�SFTVMUT�DBO�CF�RVJUF�TVSQSJTJOH �QBS-ticularly if you weigh heavily the impacts of environmental activism JO� UIF�64 �#SB[JM �$BOBEB �BOE�"VTUSBMJB�� *O� UIFTF�DPVOUSJFT �XIJMF�political risk is low, regulatory risk is high, and strict environmen-tal requirements result in higher costs, project delays, and financial losses.

Winning strategy

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dependent companies. Moreover, these companies, especially the small and medium independents, demonstrated high exploration efficiencies in terms of drilling success rates and reserves-additionsper well.

The key to their success is a clear exploration strategy that fo-DVTFT�PO�TQFDJåD�CBTJOT�BOE�QMBZ� UZQFT��5IFJS�EJWFSTJåFE�FYQMPSB-UJPO�QPSUGPMJPT�JO�QBTTJWF�NBSHJOT�BMTP�JODMVEF�MJDFOTF�BSFBT�JO�CPUI�NBUVSF�BOE�GSPOUJFS�CBTJOT �XIJDI�BMMPXT�UIFN�UP�TVDDFTTGVMMZ�BQQMZ�accumulated knowledge and expertise in less explored territories.5IFTF� DPNQBOJFT� IBWF� TUSPOH� BCJMJUJFT� UP� DSFBUF� BOBMPHVFT� PG�

proven plays for evaluation purposes, and to apply new geological DPODFQUT� JO� PME� FYQMPSBUJPO� BSFBT�� 5IFJS� ýFYJCJMJUZ� BOE� BCJMJUZ� UP�make moves fast gives independents additional competitive advan-tage in exploration wars.

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2007-2012 newfield wildcat wells drilling success rate in deepwater.

Source: IHS

Conclusion

Analysis of variable data sets, including global E&P, petroleum basin geology, political risk, costs and fiscal terms reveals remark-able new reserve-growth trends in global deepwater domains, and identifies critical success factors for deepwater operators.

Recent exploration success in deepwater continues to encourage operators to drill in deeper water depths and to explore frontier ar-eas, despite economic, technical, and political challenges.

Global, passive margin basins provide explorationists with many opportunities for reserve additions in new plays. Significant supplies of newly discovered reserves have been found by NOCs in deepwa-ter, who have unrestricted access to first-class resources; as well as by small and medium independent companies who have niche tech-nical or geological expertise, and can move quickly to leverage com-

petitive opportunities. As a result, these independents demonstrate high exploration efficiencies in terms of drilling success rates and reserve additions per well. The key to their success is having clear exploration strategies that focus on specific basins and play types.

However, the prices of new discoveries remain extremely high because of relatively low drilling success rates on a global level, and escalating capital costs. Operators are facing certain challenges such as tight demand/supply balance for deepwater drilling rigs, elevated political risks, and new, strict environmental regulations and require-ments in leading deepwater countries. Gas is becoming the dominant hydrocarbon type in new deepwater discoveries, especially in the Eastern Hemisphere. Available favorable fiscal terms or/and local markets able to consume significant gas volumes are essential condi-tions for monetizing new gas reserves from deepwater discoveries. �

Author’s noteIn this article, the authors used the IHS “Big Data” approach to understand global

exploration trends focusing on deepwater activities. This approach integrates and

analyzes various, big-volume data sets to understand global trends and assess risks

in a 360-degree fashion, with a goal of helping operators develop a comprehensive,

deepwater global exploration strategy that balances risk, prospectivity, cost and other

business success factors. Based on an analytical approach, the authors sought to rank

and prioritize countries, petroleum provinces and plays. This analysis is also used to

identify marketing options for stranded gas or to help operators identify candidates

for acquisition by displaying the results spatially. The analysis presented here is based

on the IHS International E&P databases, the IHS PEPS (Political Economic and

Policy Solutions Service) and the IHS Petrodata services. For this analysis, we used

the following definitions for dividing and analyzing trends by water depth: shallow

water <= 400 m (1,312 ft), 400 m < deepwater, 1,500 m<ultra deepwater; which

are all related to bathymetric depth. Recoverable reserves are reported using proven

plus probable category (P+P).

Editor’s Note: Some of the art was cut due to space restrictions. For the full manu-

script, please visit www.offshore-mag.com.

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North America offshore summary of projected field developments 2013-2017 DATA COURTESY OF INFIELD SYSTEMS LTD. 2013. VISIT OTC BOOTH # 8851.

North America 53 68 6,098 5,842 369 2 15 0 3 6 0 12 39 0 0 4 4,092 88

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Bruce Beaubouef

Managing Editor

Gulf of Mexico E&P activity

maintains momentum

Oil and gas development in the Gulf of Mexico continues to re-bound after the nadir of 2010, and activities are ramping up inall phases – leasing, exploration, drilling, field development andproduction.

Operators and E&P firms exhibited a strong interest in Gulfdevelopment with the Central GoM lease sale, held in mid-March. Thepositive results, described below, are expected to maintain the momen-tum that has been slowly but surely growing in the past two years.

And, along with the growing number of high-profile deepwater proj-ects, operators are also reviewing opportunities for development alongthe continental shelf and in shallow-water areas.

Lease sale results

The recent Central Gulf of Mexico Lease Sale 227 covered about 38.6million acres, located from three to about 230 nautical miles off the coastof Louisiana, Mississippi, and Alabama. The sale resulted in 52 companiessubmitting 407 bids on 320 tracts, with more than $1.2 billion in high bids.

Conducted by the Department of Interior’s Bureau of Ocean EnergyManagement (BOEM), the lease sale included 7,299 blocks in waterdepths ranging from nine to more than 11,115 ft (three to 3,400 m).BOEM estimates the areas available for sale could result in the produc-tion of up to 890 MMbbl of oil, and 3.9 tcf of natural gas. Each high bidon a tract will now be evaluated by BOEM to ensure fair market valuebefore a lease is awarded.

The sale builds on a number of recent offshore lease sales, includinga November 2012 sale that made more than 20 million acres available,and a sale last June that made more than 39 million acres available.

The administration’s Outer Continental Shelf Oil and Gas LeasingProgram for 2012–2017 (Five Year Program) makes available for ex-ploration and development all offshore areas it defines as having thehighest conventional resource potential, including areas that are esti-mated to hold more than 75% of the nation’s undiscovered, technicallyrecoverable offshore oil and gas resources.

The March lease sale is the second under the new Five Year Program,and the first of its five scheduled Central Gulf of Mexico lease sales.

The lease sale promises to enable operators – including a numberof international state-owned companies – to increase their presence inthe Gulf of Mexico. For example, Colombia’s Ecopetrol says that itsUS affiliate has placed the most competitive bids for six blocks in therecent lease sale.

Ecopetrol America Inc. partnered with Murphy Exploration andProduction in two blocks; with Anadarko US Offshore Corp., MCXGulf of Mexico LLC, and JX Nippon Oil Exploration (U.S.A) Ltd. in two

blocks; and in two blocks Ecopetrol America has 100% interest. The bids placed by Ecopetrol and its partners in the six blocks add up toapproximately $15.5 million.

Statoil was the highest bidder on 15 leases in the lease sale. ErikFinnstrom, senior vice president of Exploration for Statoil in North Amer-ica, said: “Walker Ridge 271 was our number one priority lease, and weare very pleased to have placed the highest bid on this impact prospectthat we call Monument.”

A number of domestic E&P firms also hope to increase their Gulfpresence through the lease sale as well. New Orleans and Houston-based independent EPL Oil & Gas Inc. reports that it was the high bid-der on five leases. The five high bid lease blocks cover a total of 13,892acres on a net and gross basis, and are all located in the shallow Gulfof Mexico shelf, within the company’s core area of operations. EPL’sshare of the high bids totals $2.1 million.

Exploration

Meanwhile, Gulf operators are showing renewed interest in develop-ment opportunities along the OCS. Energy XXI says it has entered intoan agreement with Apache Corp. to explore for oil and gas pay sands as-sociated with salt dome structures on the central GoM shelf. The areaof mutual interest includes several salt domes within a 135-block area.

In addition, Energy XXI has acquired a 25% working interest in 21non-producing primary-term leases with Apache. A new wide-azimuthseismic program is under way to define the potential of the AMI, cover-ing approximately 633,000 acres.

“This joint venture exemplifies our interest in exploring salt struc-

Statoil was the highest bidder on 15 leases in the Central Gulf of Mexico

Lease Sale 227, including Walker Ridge 271, the company’s number one

priority lease.

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tures where new seismic data, remapping, andremodeling could uncover significant hiddenhydrocarbons,” said John Schiller, Energy XXIchairman and CEO.

Drilling and completion

Drilling activities are under way on severalfronts, and many of these are showing positivesigns. Chevron Corp. has an oil discovery atthe Coronado prospect in the deepwater GoM.The Walker Ridge block 98 Well No. 1 encoun-tered more than 400 ft (122 m) of net pay. Thewell is located approximately 190 mi (308 km)off the Louisiana coast in 6,127 ft (1,868 m) of

water and was drilled to a depth of 31,866 ft(9,713 m).

“The Coronado discovery continues ourstring of exploration successes in the LowerTertiary trend, where Chevron is advancingmultiple projects,” said Gary Luquette, presi-dent, Chevron North America Exploration andProduction Co.

Elsewhere, Anadarko Petroleum Corp. hasannounced that its Shenandoah-2 well in thedeepwater Gulf has encountered more than1,000 net ft of oil pay in multiple high-qualityLower Tertiary-aged reservoirs.

The Shenandoah-2 well, located in WalkerRidge block 51, was drilled to a total depth of31,405 ft in approximately 5,800 ft of water,more than 1 mi southwest and approximately1,700 ft structurally down-dip from the Shenan-doah-1 discovery. The Shenandoah-1 discov-ery well was drilled in early 2009 on WalkerRidge block 52 and encountered more than300 net ft of Inboard Lower Tertiary oil pay.

Similar to the initial Shenandoah discoverywell, log and pressure data from the Shenan-doah-2 well indicate excellent-quality reservoirand fluid properties. The well was drilled totest the down-dip extent of the accumulation,and the targeted sands were full to base withno oil/water contact.

“The successful Shenandoah-2 well marksone of Anadarko’s largest oil discoveries inthe Gulf of Mexico, with more than 1,000 netft of oil pay and reservoir rock and fluid prop-erties of much higher quality than previouslyencountered by industry in Lower Tertiarydiscoveries,” said Bob Daniels, Anadarko sr.vice president Deepwater and InternationalExploration. “With ownership in the success-ful Shenandoah wells, the adjacent Yucatanprospect, and the very encouraging resultsfrom the nearby Coronado well, Anadarko isstrategically positioned in the Shenandoah ba-sin, which has the potential to become one ofthe most prolific new areas in the deepwaterGulf of Mexico.”

“We are incorporating the information ob-tained from Shenandoah-2 into our planning andanticipate further appraisal drilling to advancethis potentially giant project,” Daniels added.

Anadarko is the operator of the Shenan-doah-2 well and the previously announcedShenandoah-1 discovery well, with a 30% work-ing interest. Other co-owners in Shenandoah

Independent EPL Oil

& Gas Inc. reports that

its five high bid lease

blocks are all located

in the shallow Gulf of

Mexico shelf, within the

company’s core area of

operations.

AR12-14 © The Lincoln Electric Co. All Rights Reserved.www.lincolnelectric.com/offshore

Out here isn’t the place to find out ifyou chose the right welding products.

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Field development

Field development is also moving forwardon several GoM projects. Hess Corp. recentlyreported that development of the Tubular Bellsfield is proceeding on schedule, with drillingcampaigns under way and construction of thespar platform ongoing.

Since last April, the Stena Forth has drillednine topholes and is currently drilling the sec-ond well. When the drilling program concludes,the project will have three to five producers,

and two to three water injection wells.Construction of the spar platform is under

way in Texas and Louisiana. The engineeringand construction of the project is being con-ducted almost entirely within the United States.

The initial subsea development will comprisetwo drill centers connected to three productionwells and two water injection wells. There is apossibility that two additional production wellsand one additional water injection well may beadded to the field development.

The subsea facilities will be tied back to aWilliams Partners-owned floating productionspar (FPS) with a 50-person accommodationcapacity. Hess will initially operate the produc-

tion facility.The spar platform is designed to handle:t�� C�E�PG�PJMt��..DG�E�PG�HBT�QSPEVDUJPOt�� CCMT� PG� QSPEVDFE� XBUFS� USFBUJOH�

capacityt�� C�E�PG�XBUFS�JOKFDUJPO�Export from the FPS will be through Wil-

liams’ existing pipeline systems, including its12-in. oil line and its 12-in. natural gas line.

'JSTU�QSPEVDUJPO�JT�QMBOOFE�GPS��2��5IF�QSJNBSZ� UBSHFU� MJFT�BU�BQQSPYJNBUFMZ� �� GU�(7,315 m) reservoir depth below approximately�� GU�� N�PG�TBMU�

The Tubular Bells project was sanctionedJO��XJUI�)FTT�IBWJOH�B��XPSLJOH�JO-terest as operator. Chevron has the remaining��JOUFSFTU�

Elsewhere, the semisubmersible hull for$IFWSPO�T� +BDL�4U��.BMP� EFFQXBUFS� (VMG� PG�Mexico project has sailed out of the SamsungHeavy Industries yard in Geoje, South Korea,bound for the Kiewit yard in south Texas.

"U�� NFUSJD�UPOT�� UPOT �UIF�IVMM�JT�the world’s largest to date, said marine contrac-tor Dockwise. The successful float-on operationwas the first for the company’s new Dockwise

Vanguard heavy transport vessel. The hull was scheduled to arrive at the Kiewit yard mid-April.

The Jack and St. Malo floating production unitwill be installed in 7,000 ft (2,100 m) water depths.The $7.5-billion development will comprise threesubsea centers tied back to the FPU with a ca-QBDJUZ�PG�� C�E�PG�PJM�BOE��..DG�E�PG�OBUVSBM�HBT��4UBSUVQ�JT�QMBOOFE�GPS��

Production

With exploration and drilling activities onthe rise, production has also been increasingover the past few years. Oil production in theGFEFSBM�(VMG� PG�.FYJDP�XBUFST� HSFX� �� MBTU�year, according to a recent report issued bythe US Energy Information Administration.

The report, “Short‐Term Energy OutlookSupplement: Key drivers for EIA’s short‐termU.S. crude oil production outlook,” says that oilproduction in the federal GoM is projected toIBWF�JODSFBTFE�GSPN�BCPVU��..C�E�JO�+BO-VBSZ�UP�BCPVU��..�C�E�JO�%FDFNCFS��

The increase was driven by the initiation ofproduction at 13 new deepwater fields with acombined peak production of about 195,000C�E � BT�XFMM� BT� UIF� SFTUBSU� PG� UIF�.BE�%PH�field, which had been offline since April 2011.

Also contributing to the increase was thestart‐up of the Tahiti Phase 2 redevelopmentproject, as well as those deepwater fields thatbegan production in 2011 but continued to in-crease production during 2012.

EIA says it expects federal GoM productionUP� JODSFBTF� GSPN�BO�BWFSBHF� ��..C�E� JO��UP�BO�BWFSBHF��..C�E�JO��"EE-ing to federal GoM production in 2013 will bea combination of six new field start‐ups withB�DPNCJOFE�QFBL�QSPEVDUJPO�PG�BCPVU�� CCM�E � BOE� UIF�/B�,JLB� 1IBTF� �� SFEFWFMPQ-ment project. �

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Europe offshore summary of projected field developments 2013-2017 DATA COURTESY OF INFIELD SYSTEMS LTD. 2013. VISIT OTC BOOTH # 8851.

Eastern Europe 15 1 1,427 353 3 0 2 0 0 0 0 5 0 0 0 0 3,819 0

Southern Europe 32 5 269 1,002 18 1 2 1 0 0 0 13 0 0 0 0 743 13

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Jeremy Beckman

Editor, Europe

Britain’s dwindling reserves of offshoregas have been further drained by anunusually prolonged winter. But BPprovided a gleam of light last monthwith its North Uist gas/condensate

discovery west of Shetland.According to partner Faroe Petroleum this is

in a previously unexplored area, although thelocation is not far from Chevron’s undevelopedRosebank oil and gas field. Chevron expects totake a final decision on Rosebank in late 2013. Ifit goes ahead, it would be Britain’s deepest wa-ter field development to date at 1,100 m (3,609ft). WorleyParsons and INTECSEA have beenworking on studies for a ship-shaped FPSO tohandle producing up to 75,000 b/d of oil and100 MMcf/d of gas.

Analysts BritBoss report that the processedgas would head through a new 130-km (81-mi) subsea pipeline to Sullom Voe, Shetland,where it would connect directly to the newShetland Islands Regional Gas Export line toeastern Scotland. Total has commissioned thissystem to transfer gas that will flow from itsLaggan/Tormore fields west of Shetland, dueonstream next year.

Rosebank’s economics should benefit fromthe UK government’s new allowance for fieldsin water depths exceeding 1,000 m (3,281 ft).Other new initiatives over the past year includetax breaks on heavy oil field developments,which prompted Statoil and its partners tolaunch the giant Mariner project in the north-ern UK North Sea in December, and furtherassistance for mature field projects. That onelit the fuse for Talisman/Sinopec’s Montrosearea redevelopment in the central North Sea,involving construction of a new processing/production platform (Montrose BLP) linkedto the existing Montrose A platform, and han-dling output from the Cayley and Shaw fields.

The improved climate for investors on the UKcontinental shelf has also had a positive impacton exploration drilling. Activity has recoveredstrongly after last year’s slump, although, aside

from North Uist, results to date are modest.The potentially highest-impact well throughoutthe northwest Europe region got under wayin March, targeting the ExxonMobil-operatedDunquin prospect in the deepwater Porcupinebasin offshore southwest Ireland.

Irish E&P company Providence Resourcesplans to drill shallower water Irish plays in thecoming year in the St George’s Channel, theKish basin east of Dublin, and the Rathlin basinoffshore northern Ireland. Additionally Provi-dence is trying to attract partners to developthe Barryroe oil and gas field offshore south-ern Ireland which it successfully appraised lastyear. Latest analysis suggests Barryroe couldhold over 300 MMbbl of recoverable oil.

Among the contingent drilling offshoreNorway, Wintershall has probably deliveredthe strongest results, with new finds overthe past year in the Skarfjell and Asha Noorprospects. Lundin Petroleum, which achievedbreakthrough discoveries on the Utsira Highregion of the North Sea with Edvard Grieg

(ex-Luno) and Avaldsnes (part of Johan Sver-drup), continues to drill the play. Last monththe company proved oil in a new accumu-lation, Luno II. Statoil’s recent explorationachievements have been to prove extensionsof Johan Sverdrup, and to confirm a new HP/HT gas province in the southern NorwegianNorth Sea with King Lear, a re-drill of a wellthat Saga Petroleum had to abandon for tech-nical reasons.

As in the UK, numerous large-scale Norwe-gian field developments are going forward inthe North Sea, such as Total’s Martin Linge,Statoil’s Gina Krog, and DNO’s Ivar Aasen field,with the main construction work split betweenFar East and Norwegian yards, and HeeremaFabrication Group in the Netherlands.

Later in the decade, construction of thelong-distance Polarled gas export pipelinefrom Statoil’s Aasta Hansteen field spar shouldopen prospects for further small to mid-sizedevelopments in the Norwegian Sea currentlyheld up by capacity constraints in the region’sÅsgard trunkline system. One such project setto go forward is RWE’s Zidane, as a tieback tothe Heidrun field platform.

Offshore Denmark DONG is pushing aheadwith the platform-based Hejre oil and gas fielddevelopment. The DUC consortium led byMaersk Oil has sanctioned an $800-millionextension to the Tyra Southeast production fa-cilities, involving construction of a new platformwith horizontal subsea development wells. Fur-ther oil development could follow if Wintershallproves that its recent Hibonite oil discovery iscommercial.

Early this year, Iceland’s National EnergyAuthority (Orkustofnun) issued the country’sfirst offshore exploration licenses. They wentto Faroe Petroleum, Íslenskt Kolvetni (IcelandPetroleum), Petoro Iceland, and Valiant Petro-leum. All are in the Dreki area. Additionally,the country is cooperating with the Norwe-gian authorities on studies to open the JanMayen area to exploration. �

Exploration and development resurgent

throughout main NW Europe regions

Artist’s impression of the new Montrose BLP

platform in the UK central North Sea (copyright

Talisman).

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Middle East offshore summary of projected field developments 2013-2017 DATA COURTESY OF INFIELD SYSTEMS LTD. 2013. VISIT OTC BOOTH # 8851.

Middle East 65 5 126,852 2,441 27 1 6 1 0 0 6 222 0 1 1 14 6,683 43

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Jeremy Beckman

Editor, Europe

Gas production started from the 10-tcf Tamar field offshore Israel on March31. Aside from being the country’sfirst deepwater development—and at over 90 mi (145 km), the world’s lon-

gest subsea tieback to a platform—the proj-ect has lain the foundations for a new gas province in the Middle East region. Once exports start from the next wave of offshoreprojects, the region could rival Qatar as a source of gas for Europe.

Operator Noble Energy brought Tam-ar onstream just over four years after theinitial discovery well in the deepwaterLevantine basin. Five subsea wells areconnected via a long-distance pipeline tothe near-shore Tamar platform, which ex-ports the gas through an existing pipelineto the onshore terminal at Ashdod. Out-put could build to a peak this summer of1 bcf/d.

All production has been assigned to various Israeli utilities for domestic use, but the next deepwater Israeli projectplanned by Noble and its partners will be wider-ranging in scope. Appraisal drilling continues on the much largerLeviathan gas discovery, with the aim of confirming sufficient reserves for an LNG export scheme. Studies continue for a floating LNG facility for the first-phase development delivering up to 1.6 bcf/d of gas, of which over half would be ex-ported. Phase 2 could involve constructionof a second deepwater hub on the field.

The same partnership was responsiblefor Aphrodite, the sole gas discovery to date offshore neighboring Cyprus. Noble will reportedly resume exploratory and ap-praisal drilling on the surrounding block 12 this summer. Eni and Total are set to join thepursuit of gas after being awarded blocks last year off the southern part of the island.

Despite Cyprus’ chronic financial diffi-culties and the threat of Syria’s conflict ex-tending deeper into Lebanon, 52 companies

applied recently to pre-qualify for the first Lebanese licensing round, which was due to open on May 2. They included from the US Anadarko, Chevron, ExxonMobil, and Marathon; Petrobras, Petronas, PTTEP and Lukoil; and a wide range of European and Middle Eastern companies.

In the Turkish part of the Black Sea to the north, Turkish Petroleum discoveredgas last year in Middle Miocene sandstones in the Istranca structure, in 85 m (279 ft) of

water. This region too is emerging as a gas theater, with ExxonMobil and OMV Petromplanning more deepwater drilling offshoreRomania to build on their earlier Neptun dis-covery, and Gazprom starting constructionof the South Stream pipeline that will take gas to Europe through the Bulgarian sector of the Black Sea.

More gas will eventually head Europe’sway from the Shah Deniz field in the Azerizone of the Caspian Sea. Operator BP andits partners are evaluating bids from the Na-bucco and Trans Adriatic Pipeline consortiato construct new onshore/offshore gas trans-

port pipelines in southeast Europe as part ofShah Deniz Stage 2. This is designed to stepup production from the field by 16 bcm/yr through the addition of two new bridge-linked production platforms, 26 subsea wellsdrilled by two semisubmersible rigs, and500 km (310 mi) of subsea pipelines in waterdepths of up to 550 m (1,804 ft).

In the Turkmen offshore sector of the Caspian, Dragon Oil is preparing to startoperations later this year from two new drill-

ing platforms on its CCA contract areafields. The aim is to continue the com-pany’s steady ramp-up of oil produc-tion. Additionally, Dragon is starting a pilot water injection program, following conversion of a production well on the targeted Dzheitune (Lam) 75 area to an injector.

Last October, Saudi Aramco took delivery of the first jackup purpose-built for drilling on its fields offshoreSaudi Arabia. The rig, built by Keppel FELS in Singapore, began operations in January. Its legs are over 400 ft (122 m) long, allowing it to operate on Aramco’s deepest offshore fields. Other featuresinclude a 54-motor jacking system, al-lowing it to carry a greater load than normal 36-motor rigs, and a water cool-ing system that speeds up heat removal.

Maersk Oil has contracted Gulf Drill-ing International’s new jackup Al Jassra for anew phase of development drilling and work-overs on the Al Shaheen oil field offshore Qa-tar. These will include extended reach wellsinto the field’s thin reservoirs. Maersk hasdrilled over 300 wells to date on Al Shaheenand plans a further 51 under the latest phase.

In Qatar’s offshore block 4 North, Winter-shall and partner Qatar Petroleum recentlydiscovered a new gas field, unrelated to the giant North Field. Neighbor Iran continues its widespread mopping up of remainingdevelopment phases of the adjoining South Pars gas-condensate field. �

Map shows location of the Noble-operated partnership’s

discoveries offshore Israel.

Eastern Mediterranean gas draws

international investors

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Latin America offshore summary of projected field developments 2013-2017 DATA COURTESY OF INFIELD SYSTEMS LTD. 2013. VISIT OTC BOOTH # 8851.

Latin America 99 58 18,235 18,768 468 41 15 6 1 0 1 75 3 0 0 0 3,306 2,257

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Eleventh round of bidding scheduled for this month

Brazil gears up for new wave of offshore activity

Brazil’s National Petroleum Agency has finally outlined the process for the 11th round of bidding for 166 of the coun-try’s offshore oil blocks to be held in May 2013, five yearsafter the previous round went under the hammer. Beset by delays and uncertainty, chief amongst which being the on-

going debate surrounding the destination of royalties from the oil production, the auction will provide a timely boost for the industryjust ahead of the presalt blocks, set for a first auction in November pending governmental approval.

Of the total 289 blocks comprising the 11th round, 166 are off-shore and 81 lie in deepwater locations. The agency’s seismic data suggests there are up to 7.5 Bbbl of oil to be tapped in the round, and 71 companies from 18 countries had registered to take part by the ANP’s deadline at the start of April.

Difficult times

The latest figures for Brazilian oil and gas production underlinewhat has been a difficult 12 months for the industry, with Petrobrasannouncing a 36% drop in profits in 2012 compared with the year before and production down 2%. Company President Maria de Gra-ças Foster told investors that 2013 would “also be a difficult year for oil production” and that “it will only begin to increase in the second semester of 2013 with the six new platforms which will begin work-ing through the year.”

The company continues to be responsible for 94% of all oil pro-duced in Brazil, of which 91% comes from its offshore wells. Foster announced a 2013-2017 investment plan that maintains spending levels rather than offering any sign of industry-boosting increases,promising $237 billion over the next five years, two-thirds of whichwill be dedicated to exploration and production.

Meeting high production targets remains one of her biggest chal-lenges, and getting the state oil giant’s 11 new units onstream by 2015 is the priority, from which point the company is confident it will start generating more cash than spending. The plans prompted an optimistic appraisal of the presalt prospects from Foster, who pre-dicted that production levels in the Santos and Campos basins would reach 1 MMboe/d by as early as 2017.

Presalt potential

Petrobras broke the 300,000 boe/d mark in the presalt layersof the Santos and Campos basins on Feb. 20, seven years after the huge reserves were first discovered. While average daily produc-tion remains nearer the 281,000 boe/d mark, the achievement un-derlines the potential over the coming years. Drawn from just 17 wells, production will receive another boost when FPSO Cidade de

Paraty, with a capacaity of 120,000 boe/d and currently undergoinga refit in Angra dos Reis, is installed in the Lula field of the Santosbasin later this month. The FPSOs Cidade de Ilhabela and Cidade da

Mangaritba are undergoing conversion in China and are expected to hit production of first oil in the last trimester of 2014, the former in Sapinhoá field, the latter in Iracema Sul.

Upcoming campaigns

The Dutch company SBM Offshore reached agreement with Petro-bras for the 20-year charter and operation of two further FPSOs ina contract worth around $3.5 billion. The Lula field, where they aredestined to go into production in 2015, is 186 mi (300 km) offshore Riode Janeiro, and has some of the largest reserves of oil in the world.

Doug Gray

Contributing Editor

The P-55 platform is Petrobras’ largest semi-submersible and the third

largest in the world, capable of producing 180,000 boe/d.The company

expects it to go into operation at the end of September.

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Following the signing of a $700-million deal with Ocean Rig for the Mylos drillship at the end of 2012, Repsol are expecting delivery in the second half of the year as its construction nears completion in South Korea. Mylos’s destination is the Pão de Açucar field, part of the BM-C-33 block Repsol operates on behalf of Statoil (35%) and Petrobras (30%), drilled in 2,800 m (9,186 ft) of water, 195 km (121 mi) off the Brazil coast with estimated resources of 700 MMbbl of light crude.

BP has completed flow tests at the Itaipu-1A well in the Campos basin, 125 km (77.6 mi) off the coast of Rio de Janeiro. The re-sulting flow of up to 5,600 boe/d was, ac-cording to BP Brazil’s Vice President for Exploration Neil Piggot, “a good result…in-dicating that commercially viable flow rates can be achieved.” BP is the operator of the block with 40%, while Anadarko Petroleum holds a 33.3% stake and Maersk Energia has a 26.7% share. A new appraisal well, Itaipu-3, has been agreed with the ANP and BP will begin operations there later this year.

Following the ANP announcement on March 12 to hold the bid round on May 14-15, the president of BG Brazil, Nelson Silva, con-firmed the company will be looking at operat-ing in new blocks, rather than acting as part-ners. The company was buoyed by positive results from the company’s BMS-9 and BMS-11 blocks in the Santos basin that were, Silva noted, “better than had been anticipated.”

Brazil’s second biggest operator, OGX, was confirmed as one of the first companies to qualify for the 11th round. After disap-pointing results in the Tubarão Azul field, better news came with the declaration that

three fields, the newly named Tubarão Ti-gre, Tubarão Gato and Tubarão Areia, were commercially viable for development.

Further north, Norwegian electromag-netic specialists EMGS announced a coop-eration agreement with Spectrum covering the Foz de Amazonas basin, giving EMGS access to the 21,000 km (13,051 mi) of 2D seismic data in order to improve imaging. With the prospect of high-quality 2D and 3D data being made available for 65 of the blocks included in the 11th licensing round, this could prove crucial for the predicted in-flux of smaller and medium-sized companies involved in the auction.

Norwegian data specialist PGS has re-cently completed the deployment of and seismic data acquisition on the world’s first full-solution, deepwater, permanent seismic reservoir monitoring (PRM) installation in the Petrobras-operated Jubarte field, 70 km (43.5 mi) off the coast of Espírito Santo.

The project includes provision of the OptoSeis system, developed and operated by PGS. Made up of a fully fiber-optic sen-sor array installed on the seabed with opto-electronics on the topside of the FPSO P-57,PGS will acquire active seismic data once a year using a source vessel, and passive data twice a year, that they will also process. This is expected to provide crucial 4D seismic and PRM information as assets become scarce in existing production facilities.

The FPSO Cidade de Paraty is undergoing final

integration of the vessel’s modules in Angra dos

Reis, Rio de Janeiro, and due to go into opera-

tion in the Lula NE prospect in BM-S-11 at the

end of May.

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Local content

One aspect of the new licensing round un-der close scrutiny will be the local content requirements written into the contracts. Sev-eral companies have suggested that these requirements are slowing down progress.Director General Magda Chambriard de-nied there would be any flexibility offered to the matter, however.

Alex Tischdorf, director of operations forTeekay in Brazil, who have 10 shuttle tankersand three FPSOs operated by Petrobras, saysthat the quality and quantity of trained Brazil-

ians has been on the increase, however, andthat there is plenty of time for that processto continue before production is stepped up.

“There is unlikely to be much develop-ment in the industry in the next 12 months,” he said, “and Petrobras production will re-main flat. Their five-year plan is more prom-ising, though, and the vast majority of their increase will be offshore and dependent on shuttle tankers. Plus the amount of oil being exported will increase, all of which can only be good for the shipping industry.”

With regards to the rest of Latin America,

Tischdorf is happy to sit tight. “We will have to see what happens with the royalties as to how international oil companies and Petro-bras react in the bid round. Our Latin Ameri-can focus remains on Brazil, but we will keep an eye on what happens in Argentina too.”

June will see the first of four Teekay tank-ers being delivered to BG under a long-termagreement signed in 2011. The Suezmax-size DP-2 shuttle tankers are being built in South Korea, with delivery throughout 2013 to commence 10-year time-charters. The agreement includes certain extension op-tions and vessel purchase options.

Presalt bid round

The first presalt bid round remains slated for November. Brazil’s Ministry of Mines and Energy has stated that, as a result of recent discoveries by Petrobras and its partners Galp, Barra Energia and QueirozGalvão in the BM-S-8 block, estimates for the presalt reserves are now in excess of the previous 35 Bboe, with the Santos block alone potentially holding 1 Bboe. �

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Asia-Pacific offshore summary of projected field developments 2013-2017 DATA COURTESY OF INFIELD SYSTEMS LTD. 2013. VISIT OTC BOOTH # 8851.

Australasia 73 10 10,368 4,504 183 4 5 0 2 0 0 12 1 1 0 1 5,143 134

East Asia 76 7 5,383 1,489 55 2 3 1 1 0 0 87 0 0 0 1 2,444 13

Australasia 73 10 10,368 4,504 183 4 5 0 2 0 0 12 1 1 0 1 5,143 134

East Asia 76 7 5,383 1,489 55 2 3 1 1 0 0 87 0 0 0 1 2,444 13

Reg

ion

No.

sha

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No.

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Dee

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(MM

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PS

Os

No.

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sN

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pars

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No.

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With growing energy demands in China and India, and hugeLNG export projects under way off Australia, the Asia/Pa-cific region is a tale of two complementary ends of oil andgas exploration and development continuum. Add to thatthe continuing work offshore Indonesia, Vietnam, Myan-

mar, and others, and you have a region of extreme contrasts.Looking at the Asia and Australia region, offshore exploration and

production capex spending is forecast by Douglas-Westwood to to-tal $56.3 billion over the next five years. The long-term nature of theprojects and the high capex for each one suggests that operators withdeep pockets will make up most of the list of players. Also, spend-ing is going toward subsea and deepwater developments rather thanshallow-water infrastructure, further raising the costs of the projects.

Infield Systems says seven of the top 10 field developments ex-pected onstream over 2013-2017 are offshore Australia. The threelargest developments, Jansz, Gorgon North, and Gorgon Central,are expected on production before the end of 2014

The two largest developments outside Australia are expected to enter production during 2013. China’s Liwan 3-1 deepwater gas de-velopment, jointly operated by Husky and CNOOC, holds potential reserves of 5 tcf. The second largest development is expected to be the Shwe field offshore Myanmar. The Shwe development, whichincludes the Shwe, Shwe Phyu, and Mya discoveries, is estimated to hold combined gas reserves between 4.79 and 8.63 tcf.

Malaysia is expected to bring onstream the second largest pro-portion of reserves in the region with development led by Cono-coPhillips’ Gumusut-Kakap project. The development saw early start up in January, ahead of the completion of the FPS. Currentlytied-back to the Kikeh production facility offshore Sabah, the field’s FPS is expected to be installed toward the end of 2013.

Offshore Indonesia, the Gendalo Gehem joint project is at the forefront of the country’s offshore development and is globally ac-knowledged as one of the key deepwater fields expected to comeonstream during the period. Operator Chevron awarded the FEEDpackage for the development to Technip and Worley Parsons.

Australia

Offshore Australia is the world’s hotbed of gas export projects.Gorgon, Wheatstone, and Prelude all are progressing toward first

Gene Kliewer

Technology Editor, Subsea & Seismic

Supply and demand in the Asia/Pacific

region try to reach equilibrium

Exxon proposes FLNG development

for Scarborough

Exxon Mobil Corp.’s Esso Australia Resources Pty Ltd, asoperator, and partner BHP Billiton Ltd. have filed a public noticewith the Australian Department of Sustainability, Environment,Water, Population and Communities regarding a plan to developthe Scarborough LNG project offshore Western Australia.

At the heart of the pro-posed action is an FLNGfacility fed by 12 subseaproduction wells drilledin two phases. Phase 1drilling would start in2018 with seven wells tobe followed by five wellsin Phase 2 within 15 yearsof production start-up.Production through theFLNG is proposed to startin the 2020-2021 range.

Offshore installation and commissioning of the umbilical, risers, and flowlines as well as tieback to the FLNG would come in the 2019-2020 timeframe. Preliminaryestimates are for 125 km (78 mi) of infield flowlines and um-bilicals.Three to six umbilical riser bundles would connect the flowlines to the FLNG turret.The mooring is expected to haveabout 24 steel chain mooring lines in a four by six pattern an-chored to piles in the seabed. The mooring design would be for up to 10,000-year return period weather, and thus expectedto stay on location permanently.

The project currently is in the pre-front-end engineering and design phase and is expected to move into the FEED phasethis year with a final investment decision in 2014-2015.

General plans now call for the FLNG vessel to be 495 m (1,624 ft) long, 75 m (246 ft) wide with a capacity to process1,100 MMcf/d. It will have gas treatment, liquefaction, storage,and transfer capability with a 25-35 year lifespan.

The FLNG unit and subsea infrastructure would be in WA-1-R in the Carnarvon basin 220 km (137 mi) northwest of Exmouth in waters 900-970 m (2,952-3,182 ft) deep.

Exxon’s filing does point out that these are preliminaryplans subject to change as drilling progresses.

Exxon Mobil FLNG development schematic.

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A12

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production and additional exploration suc-cesses support these long-term investments.

Eni Australia Ltd. says it will drill a well in the Blackwood area of NT/P68 to evaluate a discovery made in 2008. This comes after a 3D seismic survey of the Blackwood East area by CGG’s Veritas Viking.

The PMP 38158 (Tui) Joint Venture plansto drill two wells in the second half of thisyear using the Kan Tan 4 semisubmersible.One well will be an infill in the Pateke field.The other is an exploration well targeting afour-way dip closure created by a compactiondrape over an underlying basement high.

Santos says its Crown 1 wildcat in the Browsebasin permit WA-274-P in 440 m (1,443 ft) waterdepth confirmed 61 m (200 ft) of net gas pay inJurassic Montara, Plover, and Malita reservoirs.

Another big offshore LNG development see-ing significant progress the Inpex/Total Ichthysproject. The project calls for gas to get prelimi-nary processing offshore to remove water andcondensate before piping to shore 889 km (552mi) via a subsea pipeline.

China

China is the world’s largest consumer ofenergy and the second largest oil consumer.With this as a starting point, any increase indemand is going to have a significant impact.And, with its older fields in decline, explorationand production offshore in Bohai Bay and theSouth China Sea take on rising importance.

Bohai Bay holds most of the proven oil re-serves offshore China. The South China Sea is predominately a gas play, although some small oil reserves are on the books. Furtherexploration of South China Sea’s deepwater Pearl River Mouth basin could hinge on ad-ditional leasing. CNOOC opened a licensing round for nine blocks in mid-2012, and the close of bidding is scheduled for this June.

Ownership disputes have clouded de-velopments in the South China Sea, with boundary differences between China and Ja-pan, and China and Vietnam. The nine-block lease round includes some territories in the disputed area between China and Vietnam.

The South China Sea may have hydrocarbonsin underexplored areas. The U.S. GeologicalSurvey estimates that about 12 Bbbl of oil and160 tcf of natural gas might exist as undiscov-ered in the South China Sea, excluding the Gulfof Thailand and other adjacent areas. About one-fifth of these resources may touch contestedareas, particularly in the Reed Bank at the north-east end of the Spratly Islands, which is claimedby China, Taiwan, and Vietnam.

CNOOC says its long-term domestic de-velopment plans include exploration and production from deepwater fields in the Pearl River Mouth and Qiongdongnan ba-sins. Development of other deepwater fields in the area, Panyu 34-1, for instance, may benefit from the Liwan infrastructure with tiebacks possible to the processing platform.

China is on schedule to complete the Myanmar-China Oil and Gas Pipeline in 2013, two parallel oil and gas pipelines that stretch from Myanmar’s ports in the Bay of Bengal to the Yunnan province of China. The oil pipeline will be an alternative trans-port route for crude oil imports from the Middle East to potentially bypass the Strait of Malacca. The oil pipeline capacity is ex-pected to reach about 440,000 b/d.

Myanmar

Myanmar’s Ministry of Energy was sched-uled to put 25 offshore exploration blocks upfor auction this past April. There is no newsof any results as of this writing. This would bethe most recent move on behalf of the govern-ment to attract foreign capital and technologyinto the country’s oil and gas business, and ithas been signing directly negotiated produc-tion-sharing contracts and licensing roundssince 2011. A revision to the foreign invest-ments regulations last year aims to improveincentives to bidders.

In field activity since the first of this year,Mitsui Oil Exploration Ltd. has agreed to ac-quire from PTTEP Indonesia a 20% operat-ing interest in offshore block M-3 in the Gulf of Martaban. Gas was discovered on the tract by the Aung Sinkha-2 exploration well that flow tested two zones at a maximum flow rate of approximately 25 MMcf/d with a condensate flow of approximately 150 b/d.

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On the field development front, KvaernerASA won a job from Premier PetroleumMyanmar Ltd. to upgrade the existing Yeta-gun platform in the Gulf of Martraban. The plan is to increase the production capacity to 300 MMcf/d of gas starting in 4Q 2013. Kvaerner did the front-end engineering de-sign earlier this year and now will provideengineering, procurement, and constructionmanagement services for the $30-million up-grade.

In Yetagun North, Petronas Carigali hascontracted a new wellhead platform fromLarsen and Toubro for about $100 million.L&T will provide engineering, procurement,construction, installation, and commissioningof the platform and related subsea pipelinefor the project in 108 m (354 ft) water depth.

Scheduled to come onstream this year is the $2-billion Zawtika natural gas project.The development includes Szwtika, Ka-konna, and Gawthaka fields in blocks M9 and M11 in the Gulf of Martaban spreadacross 11,746 sq km (4,535 sq mi) of area,says operator PTTEP International. Initial production is expected to be 300 MMcm/d, or about 1 bcf/d. Most of this production is scheduled to go to Thailand. This is the first phase of development in what eventually could encompass three wellhead platforms,a processing and living platform, and 21 km (13 mi) of subsea pipeline.

Malaysia

The final investment decision by ShellMalaysia, Petronas, and ConocoPhillips togo forward with the Malikai oil field devel-opment is the big news from Malaysia. Theplanned installation of a TLP for developmenthas drawn even more attention to the project.

The field is in waters up to 500 m (1,640 ft)deep in part of the block G production-sharingcontract awarded by Petronas in 1995. Oper-ated by Sabah Shell Petroleum Co., it is thecountry’s third deepwater project. The Ma-likai development will require 17 wells drilledfrom the TLP.

Dril-Quip Inc. has the contract to supply drill-ing and production equipment and services toSabah Shell for Malikai. Dril-Quip will supplysubsea wellheads, tensioner systems, risers,production trees, injection trees, and tiebackconnectors. Delivery is expected to start in 2014.

A joint venture of Technip and Malaysia Ma-rine and Heavy Engineering Sdn Bhd has wonthe contract to engineer, procure, and constructthe TLP. It will be 110 km (68 mi) offshore Sabah,Malaysia. The TLP will weigh approximately26,000 metric tons (28,660 tons) and will includetopsides with facilities to process 60,000 b/d ofoil and 1.4 MMcm/d (49.4 MMcf/d) of gas.

Sabah Shell Petroleum Co. also has com-missioned Technip for pipelay at Malikai. The scope covers transportation, installa-tion, and pre-commissioning of one 50-km

(31-m), 8-in. gas line and one 55-km (34-mi), 10-in. liquid pipeline, plus steel catenary ris-ers. The pipelines will extend from the Ma-likai TLP to the Kebabangan platform.

Indonesia

While most of the talk about energy de-mand in Asia centers on China and India,Indonesia increased its consumption by 50%from 2001 to 2010. To meet the demand,state-owned PT Pertamina and a numberof international oil companies are workingIndonesia’s upstream. Among the IOCs inIndonesia are Chevron, Total, ConocoPhil-lips, Exxon, and BP. In addition to Pertamina,NOCs in Indonesia include China NationalOffshore Oil Corp. and South Korea’s KNOC.

Indonesia’s government is trying to in-crease interest in the country with incen-tives for such things as 3D seismic surveysfocused on developing oil reserves in Indo-nesia’s frontier and deepwater areas. Further,Indonesia plans to offer 23 oil and gas blocksbefore year end. These blocks include off-shore Timor Sea and offshore Java island.

With operators and national oil compa-nies embarking on their exploration plans, there is also significant field development already under way offshore Indonesia. Thispast August, BP Migas reportedly approveda dozen development plans with $830 million in total investments. �

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Africa offshore summary of projected field developments 2013-2017 DATA COURTESY OF INFIELD SYSTEMS LTD. 2013. VISIT OTC BOOTH # 8851.

North Africa 38 18 2,201 2,916 72 1 1 2 0 0 0 42 0 1 0 0 1,703 43

South & East Africa 6 0 288 0 8 0 1 0 0 0 0 1 0 0 0 0 392 23

West Africa 139 59 5,531 9,906 595 18 3 2 1 0 0 118 3 3 4 0 5,597 750

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From huge gas discoveries off its undeveloped eastern coast to presalt exploration in the west’s mature markets, Africa isthe focus of intense activity among major operators and inde-pendents alike. According to energy analysts Infield Systems, 139 shallow water fields and 59 deepwater fields are currently

onstream in West Africa, and six shallow-water projects are produc-ing offshore South and East Africa. Those numbers are expected to grow as new discoveries come onstream over the next several years.

One major driver over the past year has been the quest to tap reservoirs off West Africa that share analogous characteristics with recent discoveries offshore Brazil (see Offshore, January 2013).

“Since big discoveries were made in Brazil, major IOCs have movedto West Africa deep offshore targeting similar structures,” says Mo-hamed Zine, regional director, Africa, for IHS. Cobalt International En-ergy’s Cameia 1 presalt discovery in the Kwanza basin offshore Angola,in particular, helped boost interest in the presalt play that extends northto Gabon. “Total is planning to drill a wildcat in 2013 targeting the pre-salt structures in Gabon, and Shell will drill later,” he says.

Other notable recent developments offshore Africa, Zine says, in-clude the gas discoveries off Mozambique and Tanzania, where opera-tors are still hoping to find oil (see Offshore, April 2013); new discover-ies in Kenya that indicate a possible extension of Uganda’s onshore oilplay; exploration in Upper and Lower Cretaceous formations in the Gulfof Guinea from Sierra Leone to Benin, where “companies are lookingto replicate Ghana’s success story”; a second phase of drilling offshoreNamibia; and keen interest in the underexplored waters off the north-western nations of Morocco, Mauritania and Senegal.

Northwest frontier

Kosmos Energy, buoyed by the success of Ghana’s Jubilee field,has become what president and CEO Brian Maxted recently de-scribed as one of the largest stakeholders offshore northwest Af-rica, including substantial positions in Morocco’s Aaiun and Agadirbasins. This year the company plans to drill up to three wells in bothpre- and post-salt prospects offshore Morocco. “We have receivedthe final volumes of seismic data and we are very excited by the early interpretation, which provides a diverse set of opportunitieswith multi-billion barrel potential,” Maxted said.

Kosmos also has leased nearly 27,000 sq km (10,425 sq mi) in deepwater off Mauritania and has launched seismic surveys explor-ing Upper Cretaceous plays that the company believes could contain “a deeper source kitchen” for proven oil fields up dip, Maxted said.

In Senegal, Dolphin Geophysical recently signed an agreement with

the Senegalese government to acquire, process, and market a 3D multi-client deepwater survey targeting a potential turbidite fan play. Mean-while, Cairn Energy has agreed to assume operatorship of the contigu-ous Rufisque, Sangomar, and Sangomar Deep blocks offshore Senegal,currently operated by Australia’s FAR, which will retain a 25% stake. The2,050-sq km (791-sq mi) acreage has been covered by a 3D seismic sur-vey and is said to hold up to 1.5 Bboe. An exploration well is scheduledfor early 2014.

Also in Senegal, Elenilto and partner Petrosen plan to invest $10 mil-lion on a 3D seismic and drilling program in the Offshore Sud ShallowOil block, which the companies say could contain 500-800 MMbbl of oil.

In Gambia, Australia’s African Petroleum announced plans to drillthe Alhamdullilah prospect in blocks A1 and A4 later this year. Afri-can Petroleum (60% interest) and partner Buried Hill (40%) said morethan 30 exploration prospects have been identified in the blocks.

West Africa extends reach

African Petroleum and Kosmos last year won rights to exploreblock SL-4A-10 offshore Sierra Leone. African Petroleum also pickedup two deepwater blocks, CI-509 and CI-513, off Cote d’Ivoire, andholds 100% interest in blocks LB-08 and LB-09 offshore Liberia. In

At Jubilee,Tullow Oil and partners Kosmos and Anadarko finished 2012

with a production rate of 110,000 b/d of oil, up 70% from the beginning of

the year. Pictured is the Kwame Nkrumah FPSO. (Photo courtesy Anadarko)

Exploration continues to spread

offshore AfricaRussell McCulley

Senior Technical Editor

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February, the company announced results of the Bee Eater-1 well in LB-09, drilled as a step-out west of the 2012 Narina-1 discovery. The well encountered 48 m (157 ft) of oil-bearing sandstone indicating an extension of the Turonian oil play from the Narina-1 find.

Liberian lawmakers in March voted to ratify an amended production-sharing contract allow-ing Canadian Overseas Petroleum Ltd. (COPL) to bring in ExxonMobil as a partner in block LB-13. ExxonMobil will operate the block with 80% interest. Norway’s TGS launched a 3D multi-client survey covering 7,800 sq km (3,012 sq mi) of the Harper basin, with data to be avail-able for an expected Liberian bid round later this year.

In Ghana, Hess Corp. reported a seventh successful exploratory well on the Deepwater Tano/Cape Three Points block. The Pecan North-1 well encountered 40 ft (12.2 m) of oil pay in a Turonian reservoir. Hess, which holds 90% operated interest in the block, said it plans to submit appraisal plans for the deep-water discoveries, which are in water depths of 5,623 ft to 8,245 ft (1,714 m to 2,513 m).

At Jubilee, Tullow Oil and partners Kosmos and Anadarko finished 2012 with a production rate of 110,000 b/d of oil, up 70% from the be-ginning of the year. Kosmos’ Maxted said the partners would seek to maximize production in 2013 “by identifying ways to debottleneck the (Kwame Nkrumah) FPSO and increase production even further.” The companies

plan to complete five Jubilee Phase 1A produc-tion wells by the middle of 2013.

The companies submitted development plans for the Tweneboa, Enyenra, and Ntom-me (TEN) project to Ghana’s energy minis-try in November 2012.

In Nigeria, Total reportedly has awarded Samsung Heavy industries a $3.1-billion con-tract for an FPSO for the Egina project in the OML-30 license. The field is scheduled to be onstream in 2015. Meanwhile, ExxonMobil is awarding contracts for the Erha North Phase 2 development, also scheduled for a 2015 start-up. The subsea extension of the Erha system is in water depths of 1,000 m to 1,200 m (3,281 ft to 3,937 ft). Aker Solutions will deliver two dynamic and two static steel tube umbilicals in 2014. Subsea 7 has been enlisted for instal-lation of the subsea equipment and modifica-tions to the Ehra FPSO. The Seven Borealis

and Seven Pacific vessels will carry out instal-lation in 2015.

In March, UK explorer Afren said it plans to drill two wildcat wells in the OML-115 lease. The first will target the Ufon structure, which is structurally and geologically analogous to the nearby Ebok and Okwok fields.

In Equatorial Guinea, Noble Energy spud-ded the I-7 exploration well on the Carla South prospect. The prospect is said to be on trend with the Carla North discovery in block O. Noble could drill an additional appraisal well later this year at the Diega discovery in

block I. Meanwhile, Ophir Energy said it is in discussions with Equatorial Guinea authori-ties about possible LNG exports from block R, where in 2012 the company drilled three successful exploration wells at the Tonel, Fortuna East, and Fortuna West prospects.

In Gabon, Total plans to drill the Diaman-1 well in the Diaba license in 2Q 2013. The op-eration was postponed because of delayed availability of the Ocean Rig Olympia drill-ship. The company has applied for a license to develop the Mutamba prospect, where the Ngongui-2 well discovered a small oil and gas accumulation in 2012. Total has drilled four wells at the Anguille field as part of a third-phase redevelopment program. The wells tieback to the AGMN platform and first oil is expected soon, Total said.

Harvest Natural Resources last year launched the third exploration phase of the Dussafu PSC, drilling the DTM-1 well and a subsequent appraisal side track. The well was drilled to test the presalt Gamba and Dentale formations of the Tortue prospect, and dis-covered pay in both formations. Tortue is the fourth discovery on the block along with the Ruche, Walt Whitman, and Moubenga finds.

In the Republic of Congo, Total and partner Chevron in March announced a final invest-ment decision for the $10-billion Moho Nord development, which includes the the Moho-Bi-londo Phase 1bis and Moho Nord projects. Wa-ter depths range from 450 m to 1,200 m (1,312 ft to 3,937 ft). First oil is expected in 2015, with output to reach 140,000 boe/d in 2017.

For Phase 1bis, a total of 11 subsea wells in the Miocene will be tied back to the existing FPU on Moho-Bilondo. For Moho Nord, 17 subsea wells targeting Miocene reservoirs will be drilled and tied back to a new floating pro-duction unit (FPU), and 17 more subsea wells targeting Albian reservoirs will be developed from a newbuild TLP, Total said. The partners awarded Aker Solutions a contract worth $850 million for the subsea production system.

Chevron announced plans to develop the deepwater Lianzi field offshore Congo and An-gola at a cost of $2 billion. The development will include a subsea production system and a 27-mi (43-km) electrically heated flowline, which the company says will be the first of its kind in 3,000-ft (900-m) water depths. Lianzi will tieback to the existing Benguela Belize Lobito Tomboco (BBLT) platform in Angola block 14 and is expected onstream in 2015.

Chevron also said it will proceed with the $5.6-billion Mafumeira Sul development off-shore Angola, the second stage of development of the Mafumeira field in block 0. In water depths of 200 ft (60 m), the project is scheduled for a 2015 startup. Fifty wells will connect to two wellhead platforms and a central processing and compression facility.

Cobalt International Energy, meanwhile, plans a four-well presalt drilling program this year in Angola block 21, site of the Cam-eia discovery. The company has a three-year

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contract for the deepwater semi SSV Cata-

rina, which will be augmented by Diamond Offshore’s Ocean Confidence rig.

BP in January started production at the PSVM project with three wells in the Plutao field. Wells in the Saturno and Venus fields are scheduled to go onstream this year, fol-lowed by the Marte field in 2014. PSVM, in the northeast section of block 31, is in wa-ter depths of up to 2,000 m (6,562 ft). When complete, it will include a total of 40 produc-tion, gas, and water injection wells connect-ed to a 1.6 MMbbl storage capacity FPSO.

South and East

In Namibia, Brazil’s HRT announced earlythis year that it had spudded the first of threeplanned wells in the Walvis basin. The Wing-at-1 well is in license 23 in water depths of1,034 m (3,392 ft).

ExxonMobil announced plans to explorethe Tugela South prospect off the east coastof South Africa following an agreement withImpact Oil & Gas that gave the company a 75%operated interest in the license. The agreementincludes a provision allowing ExxonMobil toacquire 75% participating interests in future ex-ploration rights in three offshore areas coveredby technical cooperation permits currently heldby Impact. The company also has a technicalcooperation permit from the South African gov-ernment to study the deepwater Durban basin.

In Mozambique, Anadarko, which operatesOffshore Area 1, has signed a heads of agree-ment with Eni, operator of Offshore Area 4, forthe coordinated development of the reservoirsthat span the two blocks. The gas fields willconnect to an initial four-train onshore gasprocessing facility. Anadarko’s discoveries todate in the Prosperidade and Golfinho/Atumcomplexes have pushed resource estimatesin Area 1 to 35-65 tcf of recoverable gas andnearly 100 tcf of original gas in place.

In late February, Eni reported a gas dis-covery in Area 4’s Mamba complex. TheCoral 3 well, drilled in 2,035 m (6,675 ft) ofwater, confirmed a resource estimate of 27 tcfof gas in the block, Eni said. In blocks 2 and5, Statoil farmed down a 25% working inter-est to Japan’s Inpex Corp. Statoil will retain a40% interest and operatorship of the blocks;Tullow holds 25% interest, and Mozambiquehas the remaining 10%.

North to Tanzania, Statoil and ExxonMo-bil announced a gas discovery in the block2 license. Results from the Tangawizi-1 wellupped resource estimates in the block to 15-17 tcf of gas, Statoil said. The companies planadditional drilling offshore Tanzania this yearand are eyeing a potential LNG project.

In Kenya, Apache Corp. in September 2012announced a gas find with the Mbawa-1 well,drilled in the Lamu basin’s block 8. Anadarkothis year spudded two wells offshore Kenya: Ki-boko-1, in block 11A, and Kubwa-1, in block 7. �

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Arctic offshore summary of projected field developments 2013-2017 DATA COURTESY OF INFIELD SYSTEMS LTD. 2013. VISIT OTC BOOTH # 8851.

Arctic/Cold water 14 3 4,815 306 73 1 0 0 0 0 0 1 5 0 0 4 185 53

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Jessica Tippee

Assistant Editor

Despite the challenges that the Arctic and sub-arctic regionspresent – ice, low temperatures, darkness and remoteness –the substantial amount of oil and gas reserves are propelling industry interest and exploration and development activity.

A recent report from Infield Systems estimates the Arcticregion holds 116 Bboe of natural gas and 17 Bboe of oil – in discov-ered offshore reserves. According to the energy analyst, 33 of the 174 discovered fields have been successfully developed. However,the average field development time exceeds 13 years, the second longest timeframe in the world. “The Offshore Arctic Oil and Gas Market Report to 2018” identified 38 fields with production potential between 2012 and 2018, with seven currently under development or having a “firm plan.”

Atlantic Canada and Greenland

ExxonMobil and its partners have sanctioned the $14-billion He-bron development project offshore Newfoundland and Labrador,Canada. The project, 350 km (217 mi) offshore in the Grand Banks, takes in the Hebron, West Ben Nevis, and Ben Nevis fields.

The centerpiece will be a stand-alone concrete gravity-based struc-ture (GBS) platform in 95 m (311 ft) water depth, designed to withstandsea ice, icebergs, and severe local meteorological and oceanographicconditions. It will have production capacity for up to 150,000 b/d of oil,and storage for 1.2 MMbbl of crude.

ExxonMobil Canada Properties has con-tracted Kiewit-Kvaerner Contractors to provideengineering, procurement, and constructionservices for the GBS. The contract value is $1.5billion and includes work done to date. Construc-tion of the GBS has begun at the Bull Arm fabri-cation yard in Newfoundland and Labrador. Thesteel skirts have been installed, which allowsbase slab construction to progress. Work on thetopsides is expected to start later this year. Front-end engineering and design was completed lastyear and detailed engineering continues. Firstoil is scheduled for late 2017. The aim is to ex-tract more than 700 MMbbl during the field’s 40-year lifespan.

The co-venturers are: ExxonMobil Canada Properties (operator,36%), Chevron Canada Resources (26.6%), Suncor Energy (22.7%), Statoil Canada (9.7%), and Nalcor Energy Oil and Gas (4.9%).

Cairn Energy remains confident that all the elements are in placefor drilling successes offshore Greenland, despite its unproductivecampaign in 2011. The company has interests in licenses that cover 11offshore blocks with a combined area of 102,000 sq km (39,382 sq mi).The current focus is on the Pitu license block, 100 km (62 mi) offshorenorthwest Greenland in water depths of 400-800 m (1,312-2,624 ft).

Studies by Cairn and partners Statoil and Nunaoil, based on map-ping and evaluation of 3D seismic, indicate potential resources of up to 5 Bboe. A first well could be drilled next year on the main struc-tural high, subject to approvals and rig availability.

Elsewhere in the region, Cairn may seek to pre-qualify for the second East Greenland bid round later this year. In 2012, various op-erators acquired 2D and 3D seismic in Baffin Bay. Cairn participatedin a joint shallow borehole program operated by Shell on behalf ofa consortium including Conoco Phillips, GDF, Nunaoil, Maersk, Tullow, and Statoil. The 11 completed boreholes have providedinformation to help stratigraphic correlations across the undrilled Melville basin.

United States

After marking the industry’s return to offshore drilling in the AlaskanArctic after more than a decade, Royal Dutch Shell suspended its explor-atory drilling campaign in the Beaufort and Chukchi seas for 2013. In2012, Shell completed top-hole drilling on two wells at the Burger pros-

pect in the Chukchi Sea with the drillship Noble

Discoverer. After the drilling season ended, a smallfire broke out on the drillship while in port, but noinjuries were reported.

Another Shell drilling rig, the Kulluk, was damaged in a maritime incident related to strong weather conditions. The conical drilling rig broke free and ran aground offshore Sitka-lidak Island, Alaska, while on its way to Seattle, Washington. Both drilling rigs will be towed to Asia for maintenance and repairs.

“We’ve made progress in Alaska, but this is along-term program that we are pursuing in a safeand measured way,” said Marvin Odum, direc-tor, Upstream Americas. “Our decision to pausein 2013 will give us time to ensure the readinessof all our equipment and people following thedrilling season in 2012.”

The jackup drilling rig Endeavour – Spirit of In-

E&P activity rises in Arctic, sub-arctic regions

Shell’s Kulluk drilling rig broke free during tow

and ran aground offshore Alaska.

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dependence has received its ABS Certification. Once the US Coast Guard and the Alaskan Oil & Gas Conservation Commission have added their approval, Buccaneer Energy Ltd. can begin drilling on the Cosmopolitan prospect, which is in 50 ft (15 m) of water and 30 mi (48 km) northwest of Homer, Alaska. Spartan Drilling LLC will assume the role of drilling con-tractor for the project.

Russia

Rosneft and ExxonMobil have agreed to expand their cooperation to include an additional 600,000 sq km (231,661 sq mi) of exploration acreage in the Russian Arctic. The two companies signed accords to explore seven new blocks, comprising Severo-Vrangelevsky-1, Severo-Vrangelevsky-2, and Yuzhno-Chukotsky blocks in the Chukchi Sea; Ust’ Oleneksky, Ust’ Lensky and Anisinsko-Novosibirsky blocks in the Laptev Sea; and the Severo-Karsky block in the Kara Sea. Rosneft says these are among the world’s most promising and least explored offshore areas.

Additionally, the two companies will jointly study the economic vi-ability of an LNG development in the Russian Far East, which could involve the construction of an LNG facility.

Rosneft and ExxonMobil have commissioned Vostochniy Off-shore Structures Construction Yard (VOSTCO) to conduct a study for a drilling platform in the Kara Sea offshore northern Russia.

The concept will be evaluated for use in the shallow waters of East Prinovozemelsky license blocks 1, 2 and 3, which cover a total area of 126,000 sq km (48,600 sq mi) in waters depths ranging from 20-200 m (65-650 ft).

According to Rosneft, the platform would need to incorporate safety and environmental protection measures for operating in arc-tic conditions, including the ability to withstand extreme ice, wind, wave, and temperature conditions. The study will evaluate the feasi-bility of using a gravity-based structure that could extend the drill-ing season by several months. This would be designed to operate in up to 60 m (200 ft) of water, with the drilling equipment installed on the seabed to drill a well, before being refloated and transferred to other drilling sites. Kvaerner will provide design services for the project in collaboration with VOSTCO.

Gazprom Neft has contracted GSP Offshore’s jackup GSP Jupiter

to drill in the Pechora Sea offshore northern Russia. The rig will start operations on the Dolginskoye oil field in early June. The loca-tion is in the southeastern part of the Russian sector of the Barents Sea. Scope of work includes drilling, logging, completion, and test-ing of the North-Dolginskaya No. 3 well. GSP additionally will pro-vide two of the four offshore support vessels to assist the rig during drilling. This will be GSP’s first experience in Arctic drilling.

The Dolginskoye field, discovered in 1999, is 120 km (74 mi) south of the Novaya Zemlya archipelago and 110 km (68 mi) north of mainland Russia. Water depth is about 35-55 m (115-180 ft). To date three exploratory wells have been drilled on the license – two wells on the North-Dolghinskoye field and one on South-Dolghin-skoye. Recoverable reserves are estimated at more than 200 MM metric tons.

Gazprom has started construction of production wells on the Kirinskoye gas and condensate field offshore Sakhalin Island. The Polyarnaya Zvezda (Polar Star) semisubmerged drilling rig is per-forming the program, 28 km (17.4 mi) offshore in 90 m (295 ft) water depth in the Sea of Okhotsk. Gazprom says Kirinskoye, part of the Sakhalin II project, is its top development priority offshore Sakhalin and will also be the first-ever instance of gas production on the Russian continental shelf via a subsea production system.

A manifold to receive the gas mix from the wells has been installed at the field and a pipeline has been laid to the coast to transport pro-duction. Another pipeline has been laid which will take MEG from the coast to the field for use in preventing hydrate formation in the wells and the gas gathering system. Gas flowlines and control cables are currently being trenched and process equipment is being installed.

Preparations continue for the Shtokman gas/condensate project in the Barents Sea, according to Gazprom. Phases 2 and 3 design and ex-

ploration programs are under way. Front-end engineering and design documents have been compiled for the offshore facilities in line with international standards, and engineering surveys are in the final stage. Preparation of the project documents in compliance with Russian stan-dards is close to completion and will be submitted for review in 2013.

The Shtokman field is in the Russian sector of the Barents Sea, with C1 reserves of 3.9 tcm (138 tcf) of gas and 56.1 MMtons of gas/condensate. Gazprom Neft Shelf holds the gas and gas/condensate exploration and production license.

Technip has signed two agreements with State Corp. Russian Technologies (Rostec) that pave the way for the manufacture of flex-ible pipes and umbilicals for the Arctic region and Black Sea fields. The company signed a memorandum of understanding with Rostec subsidiary RT-Chemcomposite Holding Co. to establish a joint ven-ture company for subsea activities in Russia. The other agreement was with Rustechexport, which could lead to a jointly owned com-pany providing engineering, design, and turnkey construction for oil refinery, petrochemical, and gas chemical production projects in Russia, plus facilities for offshore oil field operations.

Norway

Statoil and partners Eni and Petoro have selected a development con-cept for the Skrugard oil field in the Barents Sea. This calls for a semisub-mersible platform exporting the oil through a 280-km (174-mi) subsea pipeline to a terminal at Veidnes outside Honningsvåg in the Finnmark region of northern Norway. The oil will be stored in two mountain cav-erns and piped from there to the quay for transportation by tankers.

Skrugard and the nearby Havis oil find will share the same infra-structure – together they hold recoverable reserves in the 400-600 MMboe range. Output from both fields will be tied into the platform via a subsea production system in 380 m (1,247 ft) of water. Statoil aims to submit a plan for development and operation next year, and to bring Skrugard into production in 2018. It is targeting output close to 200,000 boe/d.

The company has drawn up nine new prospects in the Barents Sea for drilling during 2013-2014. The campaign will start in the Sk-rugard area, where four new prospects will be drilled. Skrugard and Havis are in license PL532, covering blocks 7219/9 and 7220/4, 5, and 7.

Production drilling has started on the Eni-operated Goliat oil field development in the Barents Sea. A total of 22 wells will be drilled from eight templates already installed on the seafloor. Drilling is ex-pected to last at least three years and will continue after the sched-uled start of production in summer 2014.

Development calls for 11 production wells, nine water injectors, and two gas injectors. Goliat’s reservoir zones are relatively shal-low and characterized by low pressure and low temperature. Water depths in the area range from 350-400 m (1,148-1,312 ft). Eni esti-mates recoverable reserves at 174 MMbbl of oil and 8 bcm (283 bcf) of gas. Its partner in the project is Statoil. �

Statoil’s Skrugard and Havis development concept in the Barents Sea.

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R E C R U I T M E N T T R E N D S

Industry steps up recruitment

in response to ‘great crew change’Jessica Tippee

Assistant Editor

The Fabricom Offshore Services Academy offers

apprenticeships, training programs, and devel-

opment schemes.

As the offshore oil and gas market con-tinues to heat up due to global demandand high prices, so does the competi-tion for talent. Oil and gas professionalssaw an 8.5% rate of growth in salaries

in 2012, according to a new report from HaysOil & Gas and Oil and Gas Job Search. The re-port, “Oil and Gas Global Salary Guide 2013,”says the industry’s global average salary is$87,300. The top five average local salaries arelocated in Australia, Norway, New Zealand,the Netherlands, and Canada.

Duncan Freer, managing director of Oil andGas Job Search, said: “Despite the concernsin Europe and a slowdown in China’s growth,the sentiment in the industry remains posi-tive. Current employees and new entrants tothe industry can look forward to working in adynamic and highly rewarding sector.”

Even with a buoyant job market, many re-cent surveys of oil and gas professionals havefound that the industry’s greatest concern isthe skills shortages presented as many babyboomers prepare to retire over the next de-cade.

The inaugural “Global Oil and Gas Trainingand Development Report” – produced by theSociety of Petroleum Engineers and sponsoredby BP – found that when it comes to technicaltraining, most age groups prefer on-the-jobtraining and combined structured training.While older professionals prefer traditionalacademics, younger professionals prefer onlinetraining and mentoring programs.

Don Shoultz, head of Learning and Devel-opment at BP, said: “The industry’s more ex-perienced talent needs continually to transferthe knowledge and skills they have built upthrough mentoring programs. Separately, oiland gas companies, of all sizes, need to ensurethey are consistently increasing their invest-ment in formal training and development pro-grams.”

Academia and the industry

As the industry moves into deeper waters, the development of geosciences, subsea, and deepwater talent increases.

The University of Houston has receivedthe Texas Higher Education CoordinatingBoard’s approval to offer the first subsea en-gineering graduate program in the UnitedStates. Established in collaboration with FMCTechnologies, Cameron, GE Oil & Gas, andWeatherford, the 10-course master’s program,

which is expected to begin in the fall 2013, willinclude classroom lectures and hands-on soft-ware education for subsea systems design.

Students will be assigned a major design project and each course will require a writ-ten project report, a technical presentation,and the use of state-of-the-art subsea engi-neering software. The courses will cover flow assurance, pipeline design, riser design, materials and corrosion, subsea processingand artificial lift, and subsea controls and systems engineering. Since the program is designed for working engineers and recentBachelor of Science recipients, classes will be taught in the evening by industry profes-sionals and full-time college faculty mem-bers. The university currently has a subsea engineering certification program.

In August 2012, FMC Technologies Mea-surement Solutions, based in Erie, Pennsyl-vania, opened a 2,000-sq ft (186-sq m) engi-neering design center to provide hands-onjob training – and job offers – to engineeringstudents at Penn State Erie, The Behrend Col-lege. The company says the center builds on a10-year partnership between FMC Technolo-gies and Penn State Behrend. The college hasprovided 30 interns to the FMC Technologiesengineering department during that period.Seventeen went on to accept full-time positionsat the company after graduation.

Fabricom Offshore Services Academy in

Newcastle, UK, has been developed by en-gineers for engineers to provide a fully-inte-grated training, learning, and development set of programs aimed at graduates, appren-tices, and people looking to upgrade or di-versify their skills. More than 30 people arealready undergoing apprenticeships, gradu-ate training programs, and professional de-velopment schemes at the academy.

The Academy includes:t��.POJUPSFE� QSPGFTTJPOBM� EFWFMPQNFOU�

schemes for graduates, trainees, and apprenticest��.FOUPSTIJQ�BOE�NFOUPSJOH�QSPHSBNTt��'VMMZ�BMJHOFE� TUBGG� EFWFMPQNFOU� QIJ-

losophy via a staff development reviewprocesst��"� GVMM� �� USBJOJOH� BOE� EFWFMPQNFOU�

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ing and development programs.The company’s four-year modern appren-

ticeship scheme offers classroom-based train-ing at Tyne Metropolitan College, three yearson site at the Newcastle head office, practicaltraining in various engineering disciplines,NVQ Level 3, HNC qualifications, and indus-try experience. Fabricom CEO Allan Cairnssaid: “The Fabricom Offshore Services Acad-emy provides a solid platform to develop engi-neers from the start of their careers throughto Chartership in eight to 10 years, which bol-sters our internal supply chain. I am alreadyconfident that we are helping to address theskills shortage by delivering the engineersand industry leaders of the future.”

As part of Britain’s government strategyto continue investing in the offshore oil andgas sector, $10.6 million went to NewcastleUniversity through the Higher EducationFunding Council for England to establishthe Neptune Centre for subsea and offshoreengineering. This facility will promote inter-action of industry and academia, provide in-frastructure for emerging research opportu-nities, and help develop skilled graduates toaddress critical skills shortages.

In September 2012, Aker Solutions signed a two-year agreement with Institut Teknolo-gi Bandung, Universitas Gadjah Mada, and Politeknik Batam to provide six-month in-ternships to students in Indonesia. The in-ternship program will be carried out at Aker Solutions’ manufacturing center in Batam, Indonesia. Under the agreement, the com-

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Saudi Aramco is looking for drilling and workover engineers to plan and design some of the most technically advanced multilateral and extended reach horizontal wells in the industry, along with high pressure, high temperature (HPHT) gas and deepwater exploration wells. Saudi Aramcooffers a stable and rewarding career and an international lifestyle, withgreat travel opportunities, a competitive salary and some of the industry’sbest savings and retirement plans.

��

Hiring managers will be conducting prescheduled interviews in May with drilling professionals.

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The mode and method of delivery also varied by age and experience

A few of the noteworthy differences exist in preferences for the mode of training, with younger respondents expecting their employer to be the primary facilitator, providing almost all training, whereas older, more experienced professionals were more self-reliant in procuring their training. Their preferences couldinfluence the types of training companies provide in the future, and how they deliver content.

Technical training: Most age groups prefer combined structured and on-the-job training, but older professionalsstill prefer traditional academics over mentoring and online training, which younger professionals prefer.

Te

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56-65

46-55

36-45

26-35

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Online training

University or technical college training

Mentoring programs

Internal training program (like corporate university)

On-the-job training (formal program)

Outside companies that provide industry training

Training workshops and training courses providedby professional industry associations (like SPE)

Other


R E C R U I T M E N T T R E N D S

pany will provide on-the-job training oppor-tunities to 12 students every year.

R&D creating global

employment opportunities

One way the industry is bridging the skills gap is by investing in technological in-novation and expanding research and devel-opment operations.

Saudi Aramco’s EXPEC Advanced Research Center (EXPEC ARC) and the Research and Development Center (R&DC) are expanding internationally by establishing satellite research centers to increase access to talent and technol-ogy and to promote closer collaboration with key research institutions. In September 2012, the company’s first research office opened at Delft University of Technology in the Nether-lands. The center concentrates on geophysics research in near surface characterization and data-driven seismic processing.

Five additional stand-alone research cen-ters are expected to be fully operational in 2013. The second technology office, located in Aberdeen, Scotland, will handle partner-ships, collaboration, and other business functions largely related to production and drilling technologies. The center in Beijing will emphasize research in reservoir and production chemistry, as well as geophysics.

Aramco Services Co., the United States subsidiary of Saudi Aramco, is opening a re-search center in Houston that will focus on the recruitment of research and development professionals. In Cambridge, Massachusetts, adjacent to the Massachusetts Institute of Technology, a research center will support computational reservoir modeling, nanotech-nology, and advanced gas membrane sys-

tems, and will host EXPEC ARC and R&DC teams. A research center in Novi, Michigan, will focus on carbon capture from mobile sources and fuel technology research.

GE says that it will build an oil and gas technology center in Oklahoma City that will initially create 125 high-tech engineer-ing jobs in disciplines ranging from geology to mechanical and electrical to systems and software engineering.

FMC Technologies is constructing its Brazil Technology Center at the Federal University of Rio de Janeiro, an area that has been designat-ed as the hub of the country’s future oil and gas technology development. The building will con-tain engineering offices, technical training and design areas, research and development labo-ratories, and the capability for full-scale proto-type integration and testing of subsea systems. The center will support three main disciplines: engineering and research and development; product qualification laboratories; and assem-bly, tests, and system integration testing.

Emerging markets

As the offshore oil and gas market and confidence continue to grow, companies continue to expand around the world.

Halliburton has opened its new Comple-tion Technology and Manufacturing Center in Singapore. The state-of-the-art facility is located on about 43 acres in Jurong Industrial Park and includes more than 500,000 sq ft (46,451 sq m) of manufacturing and adminis-trative space. The facility includes technology laboratories and test facilities, which house complex processes such as high-alloy mate-rial precision machining, electrode discharge machines, small deep-hole gun drilling, and

fully automated high-pressure testing.A second phase of development is under

way, which includes construction of the tech-nology administration building, workshops, deep well simulators, high-pressure/high-temperature testing facilities, and the com-pletion of a deep horizontal well, enabling all aspects of engineering testing and simulated systems integration testing.

GE’s Oil & Gas Subsea Systems business, headquartered in Aberdeen, plans to build a new subsea center in Bristol at the city’s Aztec West Business Park. By establishing this facility, the company will create 200 new jobs in 2013.

Rod Christie, vice president for Subsea Sys-tems at GE Oil & Gas, said: “The area has a strong pool of high integrity industries, such as aerospace, defense, nuclear and automotive, that we can tap into, allowing us to realize our growth goals more readily.”

In January, the company established a new technology and service center near Basra, Iraq. The facility will help boost pro-duction in the Rumaila oil field offshore southern Iraq. In addition to being a base for the supply of pressure control equip-ment to Iraq’s drilling and production sector, the new center provides a range of services including installation and maintenance, test-ing, inspections, repair and storage. Future services will include complete non-destruc-tive testing capabilities, machine, welding and heat treatment, blasting and painting, and API certification and recertification.

Rami Qasem, president and CEO for the Middle East, North Africa and Turkey of GE Oil & Gas, said: “The center not only builds on our long-term commitment to the coun-try but also complements the government’s focus on promoting job creation and nurtur-ing the technical skills of the Iraqi profes-sionals.” The company also has offices in Baghdad and Erbil, Iraq.

GE Oil & Gas and the Angolan group GLS Holding S.A. have entered into a new joint venture, GE-GLS Oil & Gas Angola Ltd., to better support Angola’s rapidly growing oil and gas sector. As part of the agreement, which received the approval of Angola’s Na-tional Agency for Private Investment (ANIP), the companies are planning a proposed initial investment of $175 million to build a new manufacturing facility in Soyo, in the prov-ince of Zaire, that will supply subsea equip-ment to the country’s oil and gas industry.

The new manufacturing facility will start operating in two years. Armindo Costa, pres-ident of GE Oil & Gas Angola and the new joint venture, said: “An investment of this size will require a large workforce. While there are difficulties in finding staff locally, we are committed to recruiting and training Angolans for the project.” �

Courtesy SPE and BP.

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G E O L O G Y & G E O P H Y S I C S

Dolphin responding to demand for wider

seismic arrays, more in-depth processing

One of the fastest-growing contractors in the offshore services sector is Dol-phin Geophysical. Since its forma-tion in 2010, the Norwegian-ownedseismic acquisition company has

grown from zero turnover to $220 million in 2012, with sales revenue heading potentially for $500 million in the next two years. It has already worked in most of the major explora-tion provinces and is pre-qualified to work for nearly all the leading E&P companies.

In response to the currently insatiableneed for new exploration data, the companyhas committed to adding eight seismic acqui-sition vessels to its fleet over the next threeyears, targeting in particular the high-end 3Dand 4D market. It has further plans to expandits multi-client services and data processingcapabilities, and to speed up development ofits in-house processing software.

CEO Atle Jacobsen, speaking at a presen-tation earlier this year in London, said that when the company was formed, the seismic sector was emerging from a slump. “At the end of 2009, day rates for seismic acquisition vessels were down to $170,000. E&P spend-ing that year was low, and there was vessel overcapacity, with rates having declined since the global financial crisis of 2008. But coming into the market at the low end meant that we could secure good deals, and we managed to secure risk capital from UK, US, and Far East investors.”

Dolphin’s current three-strong fleet com-prises sister ships Polar Duchess and Polar

Duke, both capable of towing up to 14 stream-ers at 100-m (328-ft) separation; and the Arte-

mis Arctic, upgraded to eight streamers. Overthe next four years the company plans to addeight further vessels, with the first three dueto be delivered by mid-2014.

First to arrive should be the Polar Swift in July, a 3,250-ton newbuilding commissioned from Sanco Shipping, designed to accom-modate 14-16 streamers and with a bollardpull capacity of around 200 ton, allowing it to tow giant spreads. The 2D ice-class Artemis

Atlantic should follow around year-end. This vessel, built in 2002 and presently known as Geo Atlantic, will be upgraded in Singaporeby owner GC Rieber to handle 14 streamers.

Dolphin has agreed to a fixed-term contract of 42 months, with possible extensions for up to four more years. And Sanco’s newbuild Sword, a sister ship to Polar Swift, should be available early next year. In addition, the company has a charter agreement with GC Rieber for a new 22-streamer 3D vessel Su-

per Duke, with the highest ice-class notation, to be built at the Kleven yard in Norway. De-livery is scheduled for March 2015.

At present Dolphin has a 5% share of the global marine seismic acquisition market, Jacobsen said. “We expect that to grow to 9% within two years, or maybe 10% following the addition of the Super Duke…The threebig players of CGG, WesternGeco, and PGS still dominate the sector, but the industry

is set for further growth. Early in 2012 we were still trying to find work for our vessels – now we have $150 million of contracts in our backlog. Rates for big boats went from$200-220,000 per day in 2011 to $250-280,000 per day in 2012. This year we are booking capacity upward of $300,000 per day, and we expect to see growth of 8-10% on 2014. But all this is fuelled by high oil prices. The main uncertainty is, will we maintain a healthy oil price going forward?”

South Africa spread

Dolphin vessels have been active in fron-tier plays including offshore East Green-land, the Caribbean Sea offshore Colombia, India, and East Africa. Earlier this year the

Jeremy Beckman

Editor, Europe

(Above) Polar Duke is one of two Dolphin vessels capable of towing 14 streamers at 100-m (328-ft)

separation. (Below) Polar Duchess performed Shell’s first large-scale survey last year in the Orange

basin offshore South Africa.

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company was shooting seismic offshore Mo-rocco for Britain’s Genel Energy. Another vessel was mobilizing to work for Cairn En-ergy on a concession offshore South Africa.

Last summer, Shell commissioned Dol-phin to perform an 8,000-sq km (3,088-sq mi) 3D survey over deepwater acreage in the Orange basin, 150-250 km (93-155 mi) offshore western South Africa. This is an area prone to bad weather and surface wave disturbances that can disrupt vessel stream-er operations and impact data quality.

Polar Duchess mobilized to the location inlate October, configured with eight x 8-km (5-mi) streamers, each separated by a distanceof 200 m (656 ft). According to Phil Suter, VPmarketing and sales, the company devisedthe widest tow possible so that the vesselcould complete its work during the limitedfour-month weather window. This would havebeen virtually impossible with a standard pat-tern of 100-m (328-ft) separation, he claimed.The vessel’s high engine shaft power and its210-metric ton (231-ton) bollard pull capacityallowed it to navigate the choppy waters withthe giant spread. The work was completedin February a week ahead of schedule. “Itended up as probably the most efficient seis-mic survey Shell had shot in the last 20 years,with very few interruptions,” Suter said.

Last year Dolphin invested $60 million inmulti-client (MC) services, and could commita further $70 million to this activity in 2013.Its MC library currently holds over 10,000sq km (3,861 sq mi) of 3D and 43,000 km(26,719 mi) of 2D data. “We will invest wherethe returns are best,” Jacobsen said. “Thereis a lot of interest at present in the NorwegianBarents Sea, and the UK central North Sea,following recent license round awards.”

In February the company committed to Phase 2 of a 3D MC survey in the UK cen-tral North Sea, which started last summer.This takes in a region on the west flank of an emerging oil province that had been over-looked prior to EnCore’s Catcher discovery.It is also the first project to apply Dolphin’s SHarp broadband seismic method.

SHarp’s deep, flat cable makes it easier to conduct amplitude analysis (AVO), pre-stackinversion and reservoir characterization, the company claims. Through increasingthe seismic bandwidth, SHarp can provide a higher-definition image and a more accurate description of rock properties, sandstone or shale, the likelihood of finding gas or oil, and flow potential. According to chief geo-physicist Dr. Gareth Williams, this range of information is particularly beneficial to com-panies looking to drill and develop smaller

fields in mature areas where facilities might otherwise face decommissioning.

The technique could also provide a break-through in seismic imaging of the basalt-cov-ered areas between the Shetland and FaroeIslands which are thought to hold strong hy-drocarbon potential. SHarp’s enhanced lowand extended high frequencies, in the range2-100 Hz, should improve penetration andhigher resolution, the company says, addingthat the extra octave at low frequency is bet-ter suited to imaging of sub-basalt, subsalt anddeep targets than conventional seismic meth-ods. The technique is also said to be compat-ible with 4D, enhancing reservoir manage-ment during a field’s lifetime. All of Dolphin’svessels are equipped to use SHarp. Followinginitial onboard processing, the task is complet-ed at the company’s UK processing center inTunbridge Wells using its OpenCP5 software.

The company acquired this softwarethrough purchasing the US-based processingspecialist Open Geophysical, which is responsi-ble for the sole new processing software devel-oped and designed so far this century, Williamsclaimed. “All other competitors are still workingon development of 1970s products. We are incontrol of our development, and we are puttingmoney into that company to develop new algo-rithms.”�

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Isometric marine seismic

technology delivers true 3DNew system captures the full wavefield using towed streamers

It has been nearly 100 years since the reflection seismic method was first used to image the subsurface, and since thenit has evolved to deliver increasingly ac-curate 3D geological models and more

reliable inversion to reveal indicators of rockproperties. While developments in seismic sources and sensors have improved the fre-quency bandwidth that can be input to the subsurface and subsequently recorded back at the surface, achieving truly 3D high-res-olution images of complex structures also requires adequate spatial sampling in both the inline and crossline directions.

Despite a century of improvement in marineseismic acquisition and data processing tech-nology, the method has, until recently, not deliv-ered adequate spatial sampling. This limitationwas overcome by the launch in June 2012 ofthe WesternGeco IsoMetrix marine isometricseismic service which, for the first time, fullycaptures the 3D wavefield using towed stream-ers, enabling reliable high-resolution imagingof complex subsurface structures.

Towed-streamer

seismic surveys

Hydrocarbon reservoirs require trap closurein all directions, so are intrinsically 3D struc-tures. Achieving truly 3D high-resolutionimages of complex subsurface structuresrequires adequate spatial sampling in boththe inline and crossline directions. Onshore,subject to limitations caused by surface ob-structions, seismic sensors can be deployedin a square grid, resulting in equal samplingin both directions.

Offshore, this recording geometry canonly be achieved using sensor nodes de-ployed on the seabed, which is time-con-suming, costly, and currently not possiblein very deep water. In deepwater, towed-streamer geometries are currently the onlyeconomically viable solutions for acquisi-tion of large 3D seismic surveys.

Until the 1980s, marine seismic sur-veys were typically acquired with a singlestreamer to provide grids of 2D lines severalkilometers apart. This required geologicalinterpretations to be interpolated over longdistances. Before the advent of multi-stream-er operations, some seismic companies

experimented with reducing 2D line-spacingto hundreds of meters and interpolating to afiner grid during data processing; however, themethod, achieved limited success in creatingreliable 3D data volumes.

During the 1980s, technologies used by fishing and other industries to spread in-sea equipment laterally from the vessel path were developed into systems to deploy mul-tiple streamers from a single vessel for ma-rine seismic surveys. Today, these surveysare typically acquired by a vessel equipped

with between 8 and 16 streamers towed 50 to 100 m (164 to 328 ft) apart, each 3 to 8 km (1.8 to 5 mi) long. Each streamer contains hydrophone sensors, and spatial sampling of the data recorded along each streamer(inline) can be as fine as 3.125 m (10.25 ft).

However, the distance between adjacentstreamers means that sampling in the crosslinedirection can be 16–32 times sparser than inthe inline direction. The method acquires suchcoarsely spaced data in the crossline directionthat it cannot capture the whole 3D wavefield,and thus is limited in its ability to accurately im-age the subsurface.

New towed-streamer

technology

Isometric 3D sampling is enabled by a towedstreamer design that combines measurementsof wavefield pressure and gradient—verticallyand crossline. Called Nessie-6, this new genera-tion streamer system uses point-receiver tech-nology that combines hydrophones to measurepressure, with calibrated point-receiver micro-electromechanical system (MEMS) accelerom-eters to measure the full particle acceleration atthe streamer location due to both the upgoingand downgoing seismic wavefield.

Delivering the full

3D wavefield

The spatial gradient of the seismic pres-sure wavefield is directly related to theparticle velocity vector, and can be derivedfrom measurements made independentlyby different sensors in the Nessie-6 stream-er. This knowledge enables multi-channelreconstruction of the pressure wavefield inthe crossline direction far beyond the alias-ing limits possible with hydrophone-only orhydrophone plus vertical gradient data.

A new computer algorithm called the gen-eralized matching pursuit (GMP) methoduses crossline (Vy) and vertical (Vz) particlevelocity components of both the upgoingand reflected downgoing wavefronts de-rived from the Nessie-6 multi-sensor stream-er data to achieve simultaneous reconstruc-tion and deghosting of the seismic pressurewavefield in a 3D sense. It can compute theupgoing and downgoing separated wave-field at any desired position within a spread

Stuart Papworth

WesternGeco

The Nessie-6 streamer delivers point-receiver

sampling of pressure (hydrophone) and

MEMS-based measurements of acceleration

that provide Vy and Vz datasets for wavefield

reconstruction.

Measurement of crossline gradients enables unaliased re-

construction of the seismic wavefield between streamers.

The blue waveform represents the actual signal, and the

red waveform the reconstructed signal.The figures con-

trast reconstructed signal with pressure-only measure-

ments as recorded in conventional surveys (top) versus

pressure + gradients as recorded in IsoMetrix surveys

(bottom).

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of streamers, and has been shown to be extremely robust in dealing with highly aliased data.

Isometrically sampled

towed-streamer data

The result of multi-sensor record-ing and multi-channel reconstruction is a reliable, continuous measurement of the full upgoing and downgoing seismic wavefield sampled at a 6.25-m x 6.25-m (20.5-ft x 20.5-ft) point-receiv-er surface grid. This fine isometric sampling in both crossline and inline directions makes the data suitable for use in a wide variety of interpretation and modeling applications, such as high-resolution near-surface imaging, deep reservoir characterization, and 4D reservoir monitoring.

Full bandwidth

deghosting

Conventional towed-streamer ma-rine seismic acquisition systems de-ploy sources and streamers at shallow depths, typically between 6 and 10 m (20 and 33 ft). This configuration en-ables recording of the high frequen-cies needed for resolution, but attenuates the low frequencies needed for stratigraphic and structural inversion. Shallow towing also makes the data more susceptible to environ-mental noise such as that caused by waves, swell, and wind.

Towing sources and streamers at deeper depths enhances the low-frequency content and can increase the signal-to-ambient-noise ratio (S/N); however, it attenuates the high frequencies. The attenuation is due to inter-ference of the upgoing seismic wavefield recorded by the pressure sensors by the re-flection of the wavefield after bouncing back from the sea surface above the streamer—referred to as its “ghost.”

In addition to the receiver ghost there is a source ghost—the result of interference to the downgoing seismic wavefield with its re-flection from the sea surface above the source. These ghost reflections result in “ghost notch-es” in the frequency spectrum, which are low amplitudes in particular frequency bands de-pendent on the source and streamer depth. Ghost notches in the seismic wavelet lead to loss of resolution in the seismic image.

The new system overcomes the need for compromise when deciding tow-depth. For each Nessie-6 streamer, high-quality mea-surement of the vertical particle accelera-tion—with good S/N down to 3 Hz—enables separation of the pressure wavefield into its upgoing and downgoing components, fa-cilitating removal of the receiver ghost. The source ghost is addressed by use of the Delta

calibrated marine broadband seismic source.In combination with a solid streamer design,

the ability to deghost deep-tow data allows ex-tension of the seismic acquisition window by reducing the impact of adverse weather. In addition, adequate sampling of coherent noise from external sources such as rigs and other seismic vessels enables further S/N improve-ments during early stages of processing.

Time-lapse (4D) repeatability

Time-lapse (4D) projects acquire 3D seis-mic surveys at intervals from before the start and during production of a reservoir. Differences between the data recorded from one survey to the next can indicate changes in pressure or fluid content. The method can guide reservoir management decisions, iden-tify flow barriers, and locate untapped com-partments suitable for infill drilling.

Changes in the seismic response of a reser-

voir are often very subtle, and can eas-ily be masked by differences in the way data has been acquired from one survey to the next. The new technology incor-porates several field-proven elements of the WesternGeco Q-Marine point-re-ceiver marine seismic system, including its proprietary marine seismic streamer steering system and intrinsic ranging by modulated acoustics (IRMA) system to control the positions of the entire seis-mic spread. Furthermore, the ability to reconstruct the wavefield at any desired grid offers improved 4D repeatability to better reveal the subtle variations in seis-mic responses related to changes in the reservoir.

Worldwide deployment

The new marine seismic system is the result of 10 years of research and engineering, the largest single engineer-ing project ever undertaken by Schlum-berger. The program not only delivered the new seismic acquisition technology, but also the algorithms and workflows needed to manage the unprecedented amount of data it produces.

Field trials in 2011 proved the capa-bilities of the new technology, achieving a 12:1 crossline reconstruction ratio and producing a 6.25-m surface data grid from streamers 75 m (246 ft) apart.

The new technology is attracting inter-est from oil and gas exploration and produc-tion companies of all sizes around the world. Manufacturing of the new system is running at full-speed, and the company has developed a rollout schedule for the introduction of the new technology among its worldwide fleet of 3D vessels.

Starting in August 2012 the seismic vessel Western Pride, operating in the North Sea for several operators, completed acquisition of the first commercial IsoMetrix projects. In Feb-ruary 2013, the seismic vessel WG Vespucci,equipped with 10 full length streamers, com-pleted acquisition using the new technology of a 3D survey for Thombo Petroleum Ltd. The survey covered a full fold area of 686 sq km (265 sq mi) extending over the A‐J1 graben of block 2B off the west coast of South Africa. This graben contains the A‐J1 oil discovery drilled and tested by Soekor in 1988.

In April 2013, WG Vespucci began acquiring a 3D survey in the western Barents Sea using the isometric seismic technology. The survey, being acquired on a multi-client basis, lies to the north of the WesternGeco Bjørnøya Ice Bear and West Loppa 3D seismic survey areas where the Havis and Skrugard discoveries were made. WG Ves-

pucci has a busy schedule of IsoMetrix projects around the world and other vessels will soon be fitted with the new equipment. �

WG Vespucci is one of the first vessels acquir-

ing commercial 3D surveys using IsoMetrix

technology.

Top: Pressure (P) wavefield reconstructed using a method based

on P-wave data alone as recorded in conventional surveys.

Bottom: P wavefield reconstructed using particle velocity vector

data recorded in IsoMetrix surveys. Accurate reconstruction in

the crossline direction reveals details of subsurface structures

that cannot be properly imaged by P-wave data alone.

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Towed streamer CSEM coming of age

Testing in North Sea shows positive results

The past 10 years have seen the develop-ment of the marine controlled sourceelectromagnetic (CSEM) method forhydrocarbon exploration. The surveymethod exploits the increased electri-

cal resistivity of hydrocarbon-saturated rocksto detect likely accumulations of gas or oil inthe subsurface. Subsurface resistivity is mea-sured by creating a strong EM field from anelectric dipole source, and placing receiverelectrodes at a distance. The EM field propa-gates through the water column and into thesubsurface, and the measurements at the re-ceivers can be used to determine the resistiv-ity at various locations and depths.

The most common technique is to place receiver equipment into individual remotelypowered units called “nodes.” An array of nodes is placed on the seabed and the dipole source is then towed in a regular grid or along specific survey lines. During the sur-vey the node units record the received data, which is recovered after the nodes are re-leased back to the surface once data acquisi-tion is complete. The most favorable targetfor node based systems is deepwater, wherenoise levels are low and the economic incen-tive of very expensive wells make CSEM an attractive option to de-risk investment.

Node deployment and retrieval is time consuming, and just as there is an economic driver to acquire seismic data efficiently with

a towed array encapsulated in a streamer,there are economic advantages to be gained if a similar approach could be adopted in the development of CSEM. The main obstacle to towed streamer electromagnetic surveyingis the presence of EM noise. Towing EM re-ceivers means they move within the Earth’sEM field and are subject to induced noise. Also, efficient towing means that the receiv-ers are currently within 100 m (328 ft) of the sea surface which means they are subject to the natural fluctuations in the earth’s mag-netic field known as magnetotelluric (MT) noise. In spite of these fundamental issues, the cost advantages of a towed streamerelectromagnetic system make it economical-ly viable for use in shallower waters on the continental shelf where budgets may be less likely to support a node-based approach.

Seismic shift

Can a towed streamer EM system reallydeliver valuable information? PGS has de-signed a system with several key featuresto overcome noise and to achieve the nec-essary signal-to-noise ratio for effective sur-veying. Based on survey results collected

late last year, PGS is confident that proof of concept already has been achieved.

Experience from marine seismic shows that a towed streamer electromagnetic sys-tem can be more efficient than placing and retrieving seabed nodes. But is the data fit for purpose?

Preliminary data examples from the 2012 PGS EM survey, suggest that the towed streamer electromagnetic system can be an effective solution to EM surveying based on results from several known continen-tal shelf fields offshore Norway. Data was acquired by the PGS seismic vessel Nordic

Explorer which is enabled for EM operations. A single 8-km (5-mi) long EM streamer was towed behind an 800 m (2,624 ft) bi-pole source at ± 1,500 A. Data was acquired over several targets in the North Viking graben.

Several oil companies are evaluating the technology for use in 2013 EM surveys.

PGS has worked on a towed EM system since 2004. In 2010, towed surveys wereconducted in the North Sea over Statoil’s Peon discovery (PL 318). The system was further tested on a deeper target over the Troll gas field (PL 054 and 085). In each case, data clearly indicated the presence of the gas reservoirs by detection of their re-sistive anomalies. These were compared to detailed resistivity models created from well data, seismic data, and iterative 3D forwardEM modeling.

Robustness and equipment handling was tested in heavy seas. Data was acquired ata speed of around 4- 5 knots, similar to therate at which seismic data is acquired.

During 2013, the Nordic Explorer will also be available for 2D seismic surveys between EM projects, avoiding the down-time that has traditionally been a challenge for EM operators. By offering a common platformfor both seismic and EM operations towed streamer EM could provide additional com-mercial benefits for both the customer and the supplier. �

Jonathan Midgley

Petroleum Geo-Services

Preliminary inversion showing resistive

anomalies that coincide with the Bentley,

Kraken, and Bressay reservoirs.

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D R I L L I N G & C O M P L E T I O N

Bit technology continues to advanceIntense competition spurs innovation

Progress in drill bit design is being made on all fronts. Improvementsrange from major design changes to better manufacturing techniques. Some target niche markets seek-

ing to solve specific problems, others have broader objectives. Some aim to improvepenetration rates; others seek to improvelongevity. Operators are the ultimate benefi-ciaries, because they get better quality bore-holes drilled in less time, reducing rig time costs while improving time-to-market.

Major innovations

With a new hybrid design, Baker Hughes’Kymera drill bit seeks to merge the benefits ofpolycrystalline diamond compact (PDC) bitswith those of roller cone technology. Target-ing transition zones where hard streaks areinterbedded with those of normal compressivestrength, the dual-action cutting structures ofthe Kymera bits increase penetration rate (ROP)while reducing weight-on-bit requirements. Ac-cording to the company, this gives better direc-tional control and steerability. Most importantly,the new design drills with less axial and torsional(stick-slip) vibration, which enhances stability,bit life, and drilling efficiency.

Results to date have exceeded expectations,with longer single bit runs in hard and inter-bedded applications. In Bolivia, ROP increasedby 460% while drilling an extra 270% of footageover previous performance in the area, savingmore than $3 million. A significant benefit ofincreased bit life is the elimination of trips andreduced vibrations. When nonproductive time(NPT) is reduced in big chunks by fewer trips,this transcends ROP as the major contributor todrilling efficiency and cost reduction.

Smith Bits, a Schlumberger company,has introduced its new Stinger conical dia-mond technology. This feature consists of avery hard, conical diamond element pointedstraight down at the rock and located at thecenter of the bit. Because the rotational ve-locity of conventional PDC cutters decreaseswith their proximity to the center of the cut-ting structure, they are least effective at re-moving rock from the center of the borehole,especially in hard formations. The Stingersolves this problem by crushing the rock atthe bit center rather than trying to scrape it.Bit designers shorten the blades that holdthe PDC bit’s low-velocity center cutters.The absence of these cutters allows a stress-

relieved column of rock to develop while drill-ing, which the center-placed Stinger elementcontinuously crushes and fractures, therebyimproving drilling efficiency. Additionally,the Stinger helps to minimize bit instability.This improves borehole quality and reducesstress on drillstring components, increasingBHA reliability. In laboratory testing, a 70%increase in cutting efficiency was obtainedcompared with conventional bit designs.

Stinger technology can be applied to any

fixed cutter bit design. Recently, a Smith BitsSHARC bit with Stinger technology delivered46% improved ROP over that experienced inoffset wells drilling extremely hard, abrasivestrata. The stinger element created a stress-relieved rock column immediately in front ofthe bit’s epicenter, improving the cutting effi-ciency of center cutters. In a tough transitionalformation with hard sandstone stringers whoseunconfined compressive strength rangedbetween 25,000 psi and 30,000 psi, a Stinger-equipped PDC bit increased ROP 14% in a wellbeing drilled with a positive displacement mudmotor and 1.5° bent sub. Even though in rota-tion mode the stinger element was describinga circular path, its tough diamond exterior al-lowed it to crush the rock ahead of the centercutters without problems. Weight-on-bit rangedfrom 30,000 lbf to 50,000 lbf in the drillingprocess, which would ordinarily cause exces-sive wear on center cutters, but the Stinger-equipped bit was able to mitigate the wear bypre-crushing the rock.

Combined benefits

Baker Hughes has introduced the HughesChristensen Talon platform of high-efficiencyPDC bits. Designed using the DART drill-ing application review process, the new of-fering features StaySharp patented polisheddiamond cutter technology that the companysays improves run life by reducing friction andassociated temperature build-up on the cutterface. This reduces cutter balling by producingsmaller cuttings, maximizing cutting evacua-tion from the toolface. StaySharp cutters alsoincorporate improved diamond materials andmanufacturing processes, and new interfacedesigns to deliver overall improved ROP andfootage by reducing chipping as the cutterwears. Talon PDC bits incorporate the useof fully mapped and diverging junk slots forincreased hydraulic efficiency, especially ef-fective in situations with low hydraulic horse-power. A steel-body version is available. TheTalon 3D PDC bit includes StayTough hard-facing that reduces bit body erosion and en-hances durability. This involves applicationof advanced metallurgy coating that deliversthree times the wear resistance of non-propri-etary hardfacing, and is repairable to extendbit life. The StayTough treatment enables thecompany’s steel-body bits to successfully per-form in the same drilling environments as itsmatrix-body bits.

Dick Ghiselin

Contributing Editor

(Above) Unique hybrid design of the Kymera bit

combines the best qualities of roller cone insert

designs with fixed blade PDC designs. (Illustra-

tion courtesy Baker Hughes)

(Below) Axially-pointing Stinger innovation

fractures rock where rotational speed is lowest,

boosting performance of center cutters. (Illus-

tration courtesy of Schlumberger)

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Every time a customer turns to Varel

International, our reputation as the source

for ways to get to TD quicker and more

accurately solidifies. Each Varel bit is

an evolution, born of decades of field

experience, leading technology and the

drive to provide the best. So when the time

comes to write a success story of your own,

we know how to help get you there.

VARELINTL.COM

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New software improves

design effectiveness

A new application for hardened elements is found in Varel’s EdgeGuard treatment of its roller cone bits. Applicable to all of the company’s roller cone line, the treatment adds hardened elements to shirttail bits that protect both the bottom and leading edges of the shirttail. This significantly adds to bit life while protecting bearing and seal ar-eas. Varel has added consistency and speed to its custom design capability with its new SPOT-DN software platform. Making a ma-jor improvement in its previously successful SPOT program, the company says that the SPOT-DN program can integrate wireline log data to produce simulated performance models of proposed bit designs. By focusing on specific well objectives, applications, and drilling systems, Varel engineers can connect specific design changes with their implica-tion on drilling efficiency deliverables. Virtu-ally any condition can be simulated using the new platform, saving time and producing bit designs tailor-made for a specific application. According to the company, the new software has already paid off in improved designs of its steel-body bit line with better torque manage-ment, improved directional control and faster ROP. Bit stability has been improved leading to reductions in destructive vibration that robs the bit of efficiency.

Heart of the market

Halliburton’s MegaForce drill bit is built around a premium matrix-body PDC platform. Using application-specific designs, the bit

aims to provide highest ROP, the most robust cutting structure, and lowest cost per foot. The new line features the company’s SelectCutter PDC technology for maximum abrasion re-sistance with minimal loss of diamond. Select cutters achieve their objectives through high impact resistance that dissipates dynamic forces across the entire cutter, and thermal mechanical integrity that allows the cutters to endure the frictional heat they generate dur-ing the drilling process. Both attributes help them stay sharper longer.

Halliburton has used field-proven force-balancing in its drill bit designs for several years. With multi-level force balancing, cut-ter placement is optimized, increasing bit stability and cutting structure efficiency. By analyzing forces on adjacent cutters during transition zone drilling, engineers have de-termined the optimal position of cutters on all arms to minimize any imbalances. This technique results in reduced vibration and ef-ficient penetration.

MegaForce bits feature advanced hy-draulics that use targeted, directional mi-cronozzles to optimize fluid flow across the bit face. The micronozzles reduce bit balling through fluid movement while providing a boost to cuttings removal and transport. The new bits use an advanced tungsten carbide matrix to minimize erosion and provide im-proved cutter support. An optimized shank length gives better directional control, re-duces bit-to-bend distance, and offers con-sistent make-up torque.

Innovative cutter design

adds to run life

Smith Bits’ new ONYX 360 rolling PDC cut-ters rotate as they drill to expose the entire circumference of the cutter to the formation.

Traditional fixed cutters use 10% to 40% of the cutting edge to destroy rock, whereas rolling cutters use 100% of the cutting edge. The abra-sive wear is more evenly distributed, and the cutter improves thermal dissipation to protect the integrity of the diamond structure.

Not all cutters have to rotate. Smith Bits engineers identify which fixed cutters need to be replaced and optimize the orientation and placement of the rolling cutters within each bit blade. Criteria include first identifying those cutters that experience highest wear, then analyzing the cutting forces that gener-ate rotation. The IDEAS simulation identifies the number of rolling cutters needed and their placement to ensure best results in a variety of drilling scenarios and formation types.

In lab testing using granite test forma-tions of 30,000 psi unconfined compressive strength, premium fixed cutters required dramatic increases of weight-on-bit (WOB) to maintain constant ROP and experienced ter-minal failure in fewer than 100 passes. ONYX 360 cutters required half the amount of WOB and were still cutting after 600 passes.

Lab performance has been replicated in the field, drilling highly abrasive formations while delivering significantly higher ROP and dura-bility. A PDC bit equipped with ONYX 360 roll-ing cutters was run in a Granite Wash well in Oklahoma to test the rolling cutters’ potential to reduce drilling costs. The bit drilled out the casing shoe and then made 1,562 ft (476 m) of horizontal hole through the abrasive reservoir section at 24.8 ft/hr (7.6 m/hr). The lateral required seven additional conventional fixed cutter PDC bits with various blade counts. The ONYX 360 bit drilled 57% more footage than the longest subsequent run of 996 ft (304 m) and achieved 44% higher ROP compared to the fast-est standard PDC bit. �

Varel’s EdgeGuard feature hardens and protects

shirttail on roller-cone bits. (Illustration courtesy

Varel)

Baker Hughes’ StayTough hardfacing protects

PDC bit blades. (Illustration courtesy Baker

Hughes)

ONYX 360 rolling cutter maximizes bit life by ex-

posing full circumference of cutting edge to the

drilling task. (Illustration courtesy Schlumberger)

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Advances in MPD enhance

deepwater opportunities

Closed-loop circulating systems are proving to be the water-shed technology for a new and quickly expanding set of deep-water wellbore construction capabilities. By enabling the precise, real-time monitoring and management of wellborepressure, these fluid circulating systems provide the basis

for new ways of understanding and affecting wellbore pressures.They are the basis for a palate of managed pressure drilling

(MPD) method s that are solving complex drilling challenges. And they open the door for new technologies that are further enhancingdeepwater drilling capabilities where conventional drilling methods have proven risky, costly, or simply inadequate.

Opening the door

“Closing the loop” refers to a process that circulates drilling fluid within a contained, pressurizable system. This closed-loop contrasts with conventional drilling circulating systems that are open to theatmosphere.

The loop is closed by a rotating circulation device (RCD) placedatop the BOP on a land application and, in a recent advance, inte-grated below the tension ring as part of the marine riser system. The RCD contains and redirects the annular flow away from the rig floor to an automated MPD choke manifold.

Within this closed loop, changes in pressure are easily detected and effected. Pressure and mass flow measurements provide real-time data that informs changes in choke settings to manipulate an-nular backpressure at the surface, which immediately increases or decreases downhole wellbore pressure. The result is an ability to understand and manage downhole pressure.

The various MPD methodologies that have evolved from this abil-ity have been further enabled and enhanced by the development of specialized software to monitor, analyze and control wellborepressure. One of these, the constant bottomhole pressure (CBHP) method, is a particular advantage in deepwater wells where precisewellbore pressure control is required to drill narrow windows be-tween pore pressure and fracture gradient.

The ability of CBHP methods to dial-in and hold a specific down-hole pressure without changing mud weight provides a high degreeof control and a new first-response to an influx or kick. The mud option is still there, but backpressure can be applied very preciselyand long before a mud response can be implemented.

While conventional well control capabilities remain fully function-al, MPD enables a response that may preclude their use, and cer-tainly provides the data for a more informed well control response.This improves safety and reduces the risks and costs associated with fighting kick/loss cycles, wellbore instability, stuck pipe, and other pressure-related problems.

Precise detection and management of pressure also provides the means to mitigate riser gas, a problem unique to deepwater drilling. Riser gas occurs when a gas influx entrained in an oil-based mudbreaks out of solution as it is circulated to the surface. This typically occurs about 2,000 to 3,000 ft (610 to 914 m) below the drill floor. At this point, the gas is above the BOP in the riser and beyond conven-tional containment.

The standard mitigation practice is to vent the gas using the rig divert-

er system. However, this affords minimal control and presents consider-able risk. With an MPD system, the expanding gas is quickly detected,SBP is applied, and the gas is circulated out to the mud gas separater(MGS). Continuous containment is maintained.

Closed-loop systems also provide a basis for developing and ap-plying new technologies that further enhance the well constructionprocess. For example, the addition of a special circulating device to allow for continuous circulation made up in the drillstring is help-ing manage pressure by mitigating swabbing effects. Advanced gas detection systems used in MPD operations are being used identify kicks and control the breakout of dissolved gas from the mud.

Drilling offshore Ghana

MPD is achieving remarkable successes in well construction ap-plications that have been impossible using conventional methods. In less extreme applications, the technology greatly reduces risk and improves efficiency. In both cases, it helps extend the scope of deep-water prospects around the world.

An example of drilling “the impossible” is a pair of wells in the deepwater offshore Ghana, West Africa. Where conventional drilling failed in two attempts due to pressure-related wellbore problems,MPD operations successfully mitigated the instability and kicks. The well was not only drilled successfully, it was drilled deeper than planned and without incident.

The first of the two wells encountered an inherently unstable rub-ble zone, and sharp pore pressure and fracture gradient changes. The wellbore was side tracked, and ultimately plugged and aban-doned in the 12¼-in. section.

There were no indications of high pore pressure while drilling the main wellbore, but blocky cuttings at the surface suggested chang-es in mechanical stress and stability. A rubble zone was identified as the source of the cuttings.

In the rubble zone, the well packed off several times due to slough-ing shale and no progress was made in drilling the main wellbore.A side track attempted to penetrate the rubble zone using a higher mud weight to prevent sloughing. It encountered less resistance and formation sloughing until a drilling break was encountered and an influx of 16 to 20 bbl led to shutting in the wellbore.

Brian Grayson

Essam Sammat

Weatherford

MPD monitoring and control capabilities are successfully mitigating well

control risk and improving drilling economics in deepwater wells across

the globe.

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About four years later, drillers returned for another attempt in the rubble. The pri-or experience had led to the selection of a MPD system to control wellbore pressures and stability at a new level of precision.

The change led to successful drilling of the well. The 14¾-in. section was vertically drilled to roughly 12,000 ft (3,657m), which was 532 ft (162 m) deeper than the planned objective. The additional hole allowed the 133⁄8-in casing shoe to be set deeper, elimi-nating the need for the 105⁄8-in. section and reducing non-productive time.

In drilling the MPD well, operations were enhanced by the operator’s proprietary cir-culating technology, a dual valve sub made up in the drillstring to allow continuous cir-culation. This has several benefits, includ-ing simplifying pressure management when making connections, cooling the hole, and continuous monitoring of drilling gas during connections.

MPD application

The MPD application was preceded by engi-neering studies that included kick simulations to identify the pressure limits of the drilling equipment. Establishing the limits ensures the pressure capability needed to safely circulate an influx. Key considerations include loads on the casing shoe, choke line, RCD, riser, and mud-gas systems (MGS). One response was to increase the slip-joint/riser pressure limit to 1,000 psi to ensure that the MPD operations could circulate gas out of the riser.

These pressure considerations benefited from the inclusion of an innovative marine RCD. The device achieves two key results: the rig retains use of its existing telescopic riser joint (slip joint) to achieve maximum stroke

and compensate for rig movement in harsh sea conditions; and the maximum pressure rating of the riser can be used in managing wellbore pressure.

In drilling the well, the application of SBP was effective in controlling the annular pressure profile and managing bottomhole pressure fluc-tuations. Applying 170 psi of annular pressure to the wellbore while pulling out of the hole main-tained stability and helped prevent swabbing effects from causing an influx. In addition, real-time pore pressure/fracture pressure data was acquired by testing upper and lower limits while drilling, saving time and costs.

The well was drilled without borehole stabil-ity issues, underreaming or contingency liners. Riser gas breaking out of the oil-based mud was routinely identified and handled. The success of the drilling operation proved that MPD is an ef-fective solution to the rubble zone challenge.

Gas detection

Accurate understanding of the gas com-ing out of the formation is critical; when combined with the precise flow metering capability of a MPD system, advanced gas extraction and analysis technology provides insights that improve safety and efficiency.

The Weatherford gas extraction and analy-sis system uses membrane technology and a high-speed gas chromatograph to monitor gases as they arrive at the surface. The small unit is placed downstream of the choke but upstream of the degasser to acquire a gas sample that is representative of downhole conditions. Most in-field gas measurement solutions extract a gas sample from drilling mud after it has passed through the degasser, which limits the accuracy of the analysis.

Tests were conducted to validate the system’s

ability to detect and analyze gas in the mud in conjunction with MPD operations. During cir-culation of an influx, data from the gas detection system helped to plan the strategy for handling the gas at the surface. System data was also used to control the breakout of dissolved gas from oil-based mud by varying SBP through the au-tomated chokes. This critical capability ensures that gases containing hydrocarbons are handled safely on the surface.

The gas system also provided quantitative analysis of the lighter and hence more volatile hydrocarbon components, so that circulation rates and SBP can be used to mitigate hazards.

Early kick detection using MPD is also enhanced with the addition of gas detection and analysis. An operator in the North Sea is successfully applying the surface gas detector with MPD to drill a complex field consisting of mature, depleted sections of the reser-voir commingled with sections that are still charged with geopressure.

The method leverages real-time gas analy-sis with the MPD system’s capability to con-trol kicks or losses to improve drilling safety and efficiency. If an influx is detected, the driller is notified and makes appropriate cor-rections. The gas analysis is so sensitive that it can help the driller ensure that they are apply-ing the optimal downhole pressure at all times.

The gas detection tool does not operate in isolation, but rather complements the data obtained from other surface logging tools that measure flow, fluid density and pres-sure. Any change observed in one instru-ment is verified by another instrument.

The fact that these readings compliment and effectively crosscheck each other pro-vides confidence in the data for better-in-formed decision-making. �

Pressure-versus-depth illustration of conventional drilling compared to CBHP MPD. Applied annulus backpressure is controlled by an RCD that allows

maintaining BHP at a constant value that does not exceed formation fracture gradient, even when circulating.

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Tender-assist TLP with coiled tubing

optimizes Moho Nord Albian wellsComplex offshore Congo development to boost oil recovery

Total and partners Chevron and SNPC have committed to the complex Moho Nord development offshore Republic of Congo. The project is targeting oil and gas reservoirs at Miocene and Al-

bian level in the north of the Moho-Bilondo permit.

At the same time, 11 new Miocene wells will be drilled in the permit’s southern areaas subsea tiebacks to the floating produc-tion unit (FPU) Alima, which has operated on the Moho-Bilondo field since start-up in 2008. This scheme, known as Moho-Bilondo Phase 1bis, and Moho Nord, will collec-tively extract an additional 485 MMboe of reserves at an estimated cost of $10 billion. First oil is scheduled for 2015, with output from the two new developments building to 140,000 boe/d in 2017.

Moho Nord will involve processing both light Albian and heavier Miocene crude on a second new FPU. Total has refined various solutions for dealing with mixed crude com-positions on its multi-field deepwater proj-ects in block 17 off Angola. One of these, the use of wash tanks to ease separation of in-coming heavy oil, will be adapted for use on the new FPU. What is more novel on Moho Nord is the selection of an unmanned well-head TLP designed for simultaneous tender-assist drilling of dry-tree wells and coiled tubing intervention, with the latter likely to be needed from the outset in the more prob-lematic Albian reservoir.

Hyundai Heavy Engineering (HHI) is building both the TLP and the new FPU. Doris Engineering, which was involved in engineering for the first-phase Moho-Bilon-do development in 2004-06 and the earlier Nkossa project in the same region, worked with HHI on detailed engineering for both new Moho Nord facilities. The 14,600-metric ton (16,093-ton) TLP will export productionfrom 17 first-phase Albian wells to the new FPU. A further 11 Miocene wells will be

drilled from four subsea manifolds as directtiebacks to the FPU.

Reservoir issues

Total E&P Congo discovered the Moho-Bilondo field 80 km (50 mi) offshore in 1995, bringing it onstream in April 2005. This was Republic of Congo’s first deepwater develop-ment, in water depths ranging from 540-730 m (1,771-2,395 ft), and involved drilling nine production wells and five water injectors in two subsea clusters on the Bilondo and Mobim reservoirs, both connected to the

Alima. Oil is exported through a 16-in. pipe-line to the Total-operated onshore terminalat Djéno, with associated gas piped to the Nkossa barge.

One year prior to start-up, the partnersdrilled the Moho Nord Marine 1 and 2 dis-covery wells, proving fresh reserves of Ter-tiary Miocene oil in the north of the permit.Two more successful wells followed in 2008-09, with Moho Nord Marine-4 encountering oil for the first time at Albian level, 4.4 km (2.7 mi) northwest of the Tertiary structure.

“The Albian section is very deep, at 3,400

Jeremy Beckman

Editor, Europe

Schematic of the Moho Nord TLP.

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m [11,155 ft] below the mudline,” said Jérôme Iacovella, departmental head of naval architecture and marine operations at Doris Engineering. “This is much deeper than Moho-Bilondo and the reservoir will therefore be moredifficult to produce, with 70˚ C [58˚ F] and 20 bar [290 psi] operating con-ditions. Due to the reservoir complexity, and the likely need for interven-tion from the outset, the partners decided that surface wellheads would be the best option for the Albian drilling campaign, with subsea wells on theMiocene part of the field. After evaluating potential concepts for the Albian wells, they went for a TLP.

“A spar platform was in contention, but the behavior of spars offshoreWest Africa is not so good because of the long-period swells, typically 15-22 seconds. In that range, the spar must be very, very deep. The swells also make installation of the spar difficult, because it has to be upended from a horizontal position. Also, the relative motions between the christmas treesand the spar are higher in these conditions than with a TLP. The TLP’stendon supports induce less motion, and the size of the platform is morecompact, and therefore cheaper to build, and easier to operate for drilling with a tender-assist rig alongside.”

Doris had performed numerous studies since the mid-1990s, first on TLPs and later a mini-TLP for tender-assist drilling off West Africa. Totalalso considered a tender-assist wellhead TLP for Moho-Bilondo during the conceptual phase.

At peak, Moho Nord’s platform will produce 40,000 b/d of light oil fromthe Albian reservoir, which will head to the new FPU through convention-

Map shows location of the Moho Nord and

Moho-Bilondo Phase 1bis developments.

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Elevatorsfor tough environments

al flexible transfer lines flowlines and risers suspended at a water depth of 200 m (656 ft). The TLP itself will be located in 780 m (2,559 ft) water depth, with the FPU moored in 800 m (2,624 ft) of water.

Moho-Nord’s platform, to be built by Hyundai in Ulsan, South Ko-rea under a $1.3-billion contract, will be 60 m (197 ft) wide, 56 m (184 ft) high at the upper deck, 119.5 m (392 ft) at the top of the drill-ing set, and with a displacement of 35,000 metric tons (38,581 tons). There will be no facilities onboard for processing aside from test-ing equipment, and no accommodation either, a first for a TLP any-where, according to Iacovella, although personnel will come aboard from the FPU for drilling and coiled tubing operations. The facility will have 27 well slots. It should be delivered during the first half of 2015, with drilling scheduled to start in 3Q 2015. Twelve production wells and five water injector wells will be drilled, with seven more producers and three more water injectors to follow in a future phase.

The TLP’s modular drilling package will be supported and con-trolled by a newbuild tender-assist semisubmersible rig, both to be supplied by Houston-based Bassdrill. The TLP’s drill floor will be higher than normal, at 17.5 m (57 ft) above upper deck to accom-modate the coiled tubing equipment housed below, which will be de-ployed via an overhead crane. Another innovation, designed to save space, is the location of the BOP within a cage between the TLP’s upper and lower decks.

“Unocal was the first company to deploy a wellhead TLP with a BOP, on the Seno field offshore Indonesia,” Iacovella said, “but this is the first instance of a TLP with both a BOP and coiled tubing. Both normally take up a lot of room. We performed tank tests to prove the stability of our concept, including vortex-induced vibration issues, at Marin in the Netherlands. Further tests will follow at Océanide in southern France on the impact on the TLP of a dry transportation.”

As stated earlier, the facilities are designed to provide constant access to the wells for intervention, simultaneous with drilling opera-tions. “The TLP will have an open wellbay with five center slots,” said Iacovella. “This will allow the drilling riser to be skidded seamlessly from one slot to another to drill all the wells without having to be dismantled. That saves a lot of time for the drilling contractor, which is important because the duration of the drilling campaign will be longer than normal. Otherwise, the rest of the drill floor equipment is standard.”

Operations on the TLP will be controlled from the new FPU via a flexible umbilical, again suspended in midwater. Aside from an onboard emergency generator, all the TLP’s power will also be sup-plied from the FPU. “The idea is to save as much weight as possible,” Iacovella explained.

Additionally, Doris will perform detailed engineering of the FPU and its mooring system. The 250-m (820-ft) long, 44-m (144-ft) wide FPU, due to arrive at the field in April 2016, will be bigger than the existing unit on Moho-Bilondo, said Doris CEO Loïc des Déserts, with a weight of 62,000 metric tons (68,343 tons), including a 19,500-metric ton (21,495-ton) topsides, and accommodation for 150 personnel. It will have capacity to produce up to 100,000 b/d of oil and 2.5 MMcm/d of gas, with the oil exported to Djeno and the gas sent to Nkossa via subsea pipelines.

“Otherwise,” said des Déserts, “it will be fairly conventional, al-though it will include equipment for two types of separation, one for the fluids from the TLP, and one for production from the subsea wells. For crude stabilization Total plans to incorporate wash tanks, which it has deployed previously on the Pazflor FPSO offshore An-gola and on Usan and Egina offshore Nigeria.

“The intermediate tank will serve as a very large separator. There is an issue of emulsion to deal with in the heavy Miocene oil arriving from the subsea wells. Washing out the continuous layer of water from the crude will ease separation.” �

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Simulation and sensors

advance the digital oilfieldAssessing expected downhole conditions by computation can help tools perform

As the oil and gas industry looks to increase production fromold fields and deepwater reservoirs, the vision of the digital oilfield is highlighted as a potential solution to many of the challenges presented by higher temperatures, higher pres-sures, longer tiebacks, and more expensive operations.

In fact, digital oilfields have been estimated to tap an additional 125 Bbbl of oil by 2015. Currently, control rooms can and are moni-toring and optimizing operations of sites thousands of miles away.

This creates opportunities to improve processes, have advancedwarning about product performance, and manage assets with realtime field information. The hundreds of terabytes of informationcollected and analyzed in these control rooms everyday provide op-erations with intelligent data that ultimately will improve drilling, production, and operation across the supply chain. The digital oilfield is taking root.

It is no surprise that electronic devices, sensors, controllers, and wireless connections are changing the industry’s drilling practices and technologies. One example is the integration of advanced elec-tronic sensor technology into downhole and drilling operations. Data generated by sensors provides invaluable insight to engineers and operators to determine how to best drill as well as how best to operate subsea facilities for maximum return.

Deploying sensors and developing products that respond and op-erate with embedded sensors lead to products that could have ad-ditional components, smaller sizes, and novel materials. Therefore,many factors must be addressed to ensure seamless, successful op-eration before the sensors can be placed in the well and drilling can begin. Factors include accurate sensor positioning, the signal and product integrity of the sensors, and the response of the equipmentto control and operating conditions.

These are new challenges, so product development practices in many engineering and R&D departments must evolve to keep pace. Leading oil companies are extending capabilities and refocusingproduct development processes to take advantage of three enablingactivities to meet these new challenges within their engineering and R&D divisions:t��%FUBJMFE�JOUFHSBUFE�NVMUJ�QIZTJDT�FOHJOFFSJOH�TJNVMBUJPO�FBSMZ�JO�

the design process)t��4ZTUFN�EFTJHOt��4NBSU� QSPEVDU� EFWFMPQNFOUT� UIBU� JODPSQPSBUF� FNCFEEFE� TPGU-

ware.

Engineering simulation

The growing development of drilling and evaluation and comple-tion technologies influences the way engineers drill wells. They now have access to informative intelligence and data that help with moreefficient and smarter drilling. These sources include electronics and

sensors which help accurately direct and control drill bit positionwhile logging and measuring. This not only reduces nonproductivetime, but also leads to faster drilling rates and helps reduce damage and drill wear. These electronic sensors need to withstand thermal,vibration, and impact damage.

New design practices must account for product performance overthe life of the equipment. For instance, the sensors and drill tools need to be subjected to real-life conditions of vibration, fatigue, hightemperatures, and interferences from other equipment and electron-ic signals before reaching the field for commercial application. Todo so, engineering teams are shifting from a component, or subsys-tem view, to a higher-level perspective that considers performanceat the complete systems-level – applying multiple physics, multiple scales, and a collaborative, cross-functional engineering approachearly in the design stage. By modeling systems-level interactions and product responses to multiple forces, engineering teams areable to rapidly and continually fine-tune the entire product systemand to predict systems-level performance in a virtual environmentwell before physical assembly and testing.

Today, advanced engineering simulation tools can evaluate both single components as well as the interactions among components and subsystems of the entire design using single and multi-physics simulations. These science-based engineering tools include electron-ics, electromagnetics, fluids, and thermal and structural mechanicssimulation technology. With these tools, oil and gas companies can

Ahmad Haidari

ANSYS

Sample results from a computational fluid mechanics simulation illus-

trate velocity vectors of drilling mud flow at the surface of a drill bit. Color

ranges are red for maximum and blue for minimum.

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model well, drilling, and sensor designs with a high degree of detail and fidelity even with complex geometries and complex physics.

Flow assurance

and vibration

For example, post-processing results from a fluid mechanics simulation of drilling mud flow at the surface of a drill bit can give insight into its cooling and cuttings removal performance. This performance can be opti-mized when there is a better understanding of the flow pattern and the velocity magni-tude for a given drill bit and cutting speed. While the drill bit simulation is a static, single physics simulation, it can also include additional components such as transient and dynamic response. Dynamic vibration forces on a downhole tool and/or sensor are another factor that must be modeled to en-sure the durability of electronics such as a printed circuit board assembly.

Electromagnetic analysis

Understanding the formation properties and environment of the oil wells is critical to successful drilling. An oil company must fac-tor in the depth of a well and design appro-priate downhole tools and sensors that can handle the expected environment. One area where sensors play a crucial role in drilling is logging while drilling (LWD). There are

three important LWD engineering tasks that require electromagnetic simulation analysis:t��-8%�BOUFOOB�EFTJHO�UP�NBYJNJ[F�TFOTJUJW-

ity for complex three-dimensional drill bit trajectories into complex formation layers while accounting for realistic environmen-tal conditions such as antenna shape, man-drel affect, borehole effect, mud invasion zones, anisotropic formation properties, and mandrel eccentricity.t��1BSBNFUSJD�TUVEZ�PG�UPPM�BOE�FOWJSPONFO-

tal variables to enable rapid interpretation of complex logs, allowing operators to quickly interpret operating conditions and adjust equipment as needed.t��-8%�BOUFOOB�FMFDUSPNBHOFUJD�DIBSBDUFS-

ization for compatibility with receiver/transmitter electronics to maximize signal integrity and to ensure the tool never op-erates “blind” in the field.These engineering design issues require

3D electromagnetic field solutions together with electronics system simulation to pro-vide design capability and system validation. The 3D tool can be optimized electromag-netically in a virtual environmental forma-tion to look at the antenna design and ex-pected effects on measured logs.

While new to the oil and gas industry, the underlying computational technology used to perform these examples shown are de-ployed widely in other industries. For exam-

ple, the electromagnetic field calculations for low-frequency are used in the design of electric machines, alternators, transform-ers, and other high-frequency electromag-netic applications may include simulation of antennas, cell phones and tablets, biomedi-cal devices, radar systems, and many others.

Embedded software

It is clear that the oil and gas industry is using more advanced electronics and is op-erating more equipment and plants remote-ly. The underlying power controlling the behavior of the electrical, mechanical, and fluidic systems driving the digital oil fields is embedded software. The embedded software manages the complex interaction between software, hardware, and human/machine interfaces.

For a new design, a system-level simu-lation approach combined with verifiable methods to help model the behavior of the hardware and the software before it is im-plemented enables engineers to gain insight into the performance of the well, downhole tools and sensors, and their controllers be-fore they are implemented. For existing systems, and with sensors already in place, the real-time field data can be combined and even help drive detailed 3D simulation to perform root cause analysis, identify im-provement opportunities, and to enhance the controllers and reliability of product and processes.

Technology is changing operation and processes in many oil and gas fields. There are substantial investments in R&D and en-gineering behind every safe, reliable, and cost-effective innovation implemented in the field. Increased product complexity and the remote operation and control of oil and gas equipment and processes create new drill-ing challenges. Detailed engineering simu-lation, coupled with system-level modeling, is empowering engineers to effectively de-sign and deploy next generation sensors and smart products to gain additional efficiency and reliability in oil and gas drilling, produc-tion, and processing. �

About the AuthorDr. Ahmad H. Haidari has more than 20 years of

experience in the application of engineering simulation

and modeling technology to address industrial-process-

equipment design, equipment troubleshooting, analysis,

and scale up. He obtained his Ph.D. from Lehigh

University and has made numerous presentations and

written publications on modeling chemical and hydro-

carbon process equipment and oil and gas machinery.

At ANSYS he is the global director of the energy and

process industries, where he ensures full portfolio of

ANSYS engineering simulation software provides

appropriate capabilities to meet the modeling require-

ment of energy and process industry companies.

Sample results from structural mechanics simulation shows

contours of total deformation of harmonic response of a

downhole tool. (Courtesy of Baker Hughes)

Sample results

from an elec-

tromagnetic

simulation of

a drilling sen-

sor. Optimized

geometry of the

sensor is on the

left, and mapping

of the sensors

electromagnetic

field on forma-

tion properties is

on the right.

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Flare-less requirements drive

innovation on the Okha FPSOAs regulations tighten, production unit designs

will include more flare-free systems

Marten Akesson

Nicolas Bigle

Arjan Gerritse

SBM Offshore

The Okha FPSO serves Woodside’s CWLH complex off Western Australia.

Okha process overview.

In 2009, Australia’s Woodside Energyawarded SBM Offshore an engineering, procurement, and construction con-tract to deliver a disconnectable FPSO to serve the Cossack, Wanaea, Lam-

bert, and Hermes fields offshore WesternAustralia. Dubbed the Okha and moored in 80-m (262-ft) water depths, the FPSO went onstream in September 2011, as part of the AU1.8-billion ($1.88-billion) CWLH Redevel-opment Project.

Initially considered to reduce corrosionrates in the cargo tanks of the convertedvessel, hydrocarbon tank blanketing, which would replace the conventional inert gas cargo tank blanketing, was soon seen as an opportunity to reduce the FPSO’s emissions and overall environmental impact. When combined with recovery of low-pressure(LP) flare system releases and a closed high-pressure (HP) flare system, flare purgegas combustion could be avoided, resultingin an FPSO with zero hydrocarbon/CO2 re-lease to the atmosphere.

Yet the design of such a novel system had significant challenges such as managing all HP/LP interfaces, selecting the appropriatevapor recovery unit (VRU), and simultane-ous control of HP flare, LP flare and cargovent operating pressure for all operating cas-es, including offloading. This required that conventional systems be revisited throughan in-depth analysis to ensure that changes associated with the new configuration wereproperly managed and did not generate ad-ditional operational risk.

The complete VRU system, at normal ca-pacity, is able to recover and re-inject around 4MMcf/d of gas that would normally be lost tothe atmosphere, and allows the FPSO to pro-duce without flaring, except in emergencies.

The design basis specified that fuel gaswas to be used for cargo tank blanketing, in

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line with Australian regulatory requirements, which meant that it became necessary to implement a totally enclosed flare system col-lecting all continuous hydrocarbon releases – a first for SBM and for Australian produc-tion facilities. The principle of this system is simple: all LP hydrocarbon gases released from the process plant are sent to the LP flare header and, after liquid removal in the LP flare drum, sent to the VRUs for compres-sion. Gasses from the cargo tanks and the produced water tanks are routed directly to the suction of the VRU. The same is done for the HP hydrocarbon gases released from the process plant to the HP flare headers, which, after liquid removal in the HP flare drum, are sent to a centrifugal flash gas compres-sor and mixed with other gas. Recovered gases are either used as fuel gas, for gas lift (to boost crude production), or exported to shore. The key new components of this zero flaring system are: t��"�IZESPDBSCPO�NBJO�QJQJOH�TZTUFN�DPO-

necting all cargo and produced water tankst��5XP��WBQPS�SFDPWFSZ�VOJUT�t��2VJDL�PQFOJOH� TIVUEPXO� WBMWFT�EPXO-

stream of the HP and LP flare drums t��3VQUVSF� QJO� QSFTTVSF� TBGFUZ� WBMWFT� JO�

parallel to the quick opening shutdown valvest��"�ýBSF�UJQ�JHOJUJPO�TZTUFN�VTJOH�TQBSLT�

of an air-driven pellet. The Okha FPSO is designed with two-

stage crude separation on the topsides (high and low pressure) and a third and final sepa-ration stage in any one of the cargo oil tanks (COTs). Produced water goes overboard after passing through hydrocyclones and a flash vessel. Gas is exported primarily via an

export gas header to the Karratha gas plant and partly used for lift-gas to the wells, and fuel gas for the gas turbine generators.

Gas from the HP separator is compressed in a two-stage export gas compressor (EGC) with interstage gas dehydration. Gas from the EGC is routed to the lift gas compressor (LGC) and export gas header. Both the EGC and LGC are centrifugal compressors with Voith variable speed gear couplings driven by electric motors.

Gas from the LP separator is compressed in the flash gas compressor (FGC), a two-stage fixed-speed centrifugal compressor, and fed to the suction of the EGC. Gas flashed from the crude run-down in the COTs is fed to the VRU.

Marine system

A hydrocarbon gas header was added to the marine system to maintain the separation be-tween the inert gas and hydrocarbon systems. As the Okha is a conversion, the main chal-lenge of this is routing the header through the already constricted space on the main deck.

Flare recycle system

The VRU is a single-stage roots blower, com-pressing boil-off gas from the COTs as well as gas from the LP flare drum. For noise control, the VRUs were located in acoustic enclosures.

The FGC is a two-stage fixed-speed cen-trifugal compressor, compressing gas from the LP separator as well as the VRU and HP flare drum.

A number of changes to the flare system were required to create a flare-less unit. Up-stream of the flare drum, the system is only changed in that the LP and HP flare headers and flare drums are pressurized, which in-

creases the back-pressure on pressure safety valves (PSVs). This potentially impacts PSV selection, but for the Okha did not result in additional requirements for the relief devices.

A minor effect is that normal back pressure increases on all process units that usually are open to atmosphere, e.g. the produced water flash vessel and the glycol regeneration pack-age still column, where the increased pres-sure marginally reduces the efficiency of the regeneration system.

The discharge from the flare drum to the flare tip has two valves in parallel. The pri-mary pressure relief is a fast opening valve. The second, a rupture pin valve, provides a secondary mechanical relief device should the fast opening valve fail to open.

A rupture pin valve was chosen over a rupture disc because it allows the valve to be reset without requiring the valve to be isolated from the process, significantly sim-plifying the design. Being external to the process, the pin is also not subject to corro-sion from the process gas.

To prevent liquid sitting on the fast open-ing valve and rupture pin valve, piping de-sign required a dead-leg at a low point in the flare drum discharge piping. Liquid accumu-lation during flaring introduces the potential for liquid carry-over, something not seen in conventional flaring designs, where any con-densate drains back into the flare drum.

Ignition

Rather than maintaining a pilot flame, a pellet type flare ignition system is used. An exploding pellet is launched with instrument air through a guide pipe to ignite the flare. To guarantee ignition, two pellets are launched on every incident. The system is equipped

(Above) VRU enclosures.

(Right) Fast opening valve and rupture pin valve on flare drum discharge.

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with two air accumulators to ensure that the flare can be ignited in case of instrument air loss. Ignition is initiated automatically on the opening of either the fast opening valve or the rupture pin valve.

The pellet is armed on launch and ignites on leaving the guide pipe to the flare tip, while the pellet is caught in a fragment collector. One challenge during construction was to ensure that the guide pipe ran without any kinks to allow the pellet free travel to the flare tip and to minimize the possibility of a pellet sticking inside the guide pipe. The final ignition initiator is by spring-loaded wings popping out of the pellet as it leaves the guide pipe, ensuring that the pellet does not ignite before leaving the tube. A stuck pellet would be dif-ficult to locate and to remove safely from the guide pipe.

The pellet launcher requires manual reloading of the pellet maga-zine. An alarm alerts the operator when the magazine is half-full.

The case of a flare failing to ignite was studied and it was conclud-ed that in the worst case, the gas would disperse before reaching the deck. A secondary ignition system therefore was not required. As the system uses instrument air, failure of the air system would po-tentially cause a blow-down without the possibility of flare ignition. So, the system was equipped with two air reservoirs. Should the air pressure drop below the minimum required to send the pellet to the flare tip, the launch sequence is stopped. Integrity of this system relies on the sealing quality of one non-return valve (NRV) and has been proven on numerous North Sea facilities. Debris was found to obstruct the NRV on one launch but it has since proved reliable.

Operating envelope

The VRU has been operating from 0% to 100%. The low end is during offloads, when gas is diverted from the LP separator to the COTs to maintain pressure. Normal load is gas from production boil-off, relatively low flows from the TEG regeneration stripping column and the flare header fuel gas purges. Periodic increases in the load occur when loading of empty cargo tanks begins due to va-por disengagement on account of the fall height from inlet to the bot-tom of the COTs, and when hot produced water is routed inboard.

A number of solutions were proposed to deal with the challenge of designing for very low turndown. Among the proposals were 4 x 33% units, variable speed drives (VSD), water quench, and full recycle. In the end, the selected VRU design was 100% recycle and equipped with VSD (although these were primarily for frequency conversion). In actual operation, the VSDs are extremely useful for optimizing the operation of the VRU.

Offloading operations have less effect on the FGC as the main feed to the unit is from the LP separator. However, the entire com-pression train is affected by turndown, because the VRU adds a high molecular weight (MW) feed to the gas.

Rather than distributing oil along the bottom of the tank, the feed

is to a splash plate above normal liquid level, en-suring that there is sufficient liquid/gas separa-tion in the tanks to achieve the RVP (Reid’s va-por pressure) offload specification. This has two effects: increases turbulence, making the level measurement in the tanks to which rundown is being directed slightly less accurate; and a fall height during initial loading that increases the amount of boil-off gas generated, causing a tem-porary spike in COT pressure and increasing the duty on the VRU until the system stabilizes.

The VRU must cope with a wide range of molecular weights. During normal tank loading

operations, MW was modeled at 52 g/mol, down to 30 g/mol after offloading, when the cargo tanks have been fed with gas from the LP separator. This has a considerable impact on the main gas com-pressor trains, increasing efficiency as higher molecular weight gas is received from the VRU and FGC, but also increasing the amount of liquid knocked out in the drums. Tolerance for high variations in molecular weight and robustness were key factors in selecting the root blower for the VRU.

The only continuous sources to the HP flare drum are the HP and cold flare header fuel gas purges. Operations teams observed that the closed flare system made it easy to note when valves were ei-ther passing or left in open positions, as pressure in the flare drums would increase to push the extra gas through to the VRU or FGC.

Commissioning

After the usual pre-commissioning activities, including blower/motor alignment and instruments loop checks, the cause and effect logic were tested to ensure the VRUs would react as required in case of problems and were safe to run. The next step was to run the VRU on full recycle with a nitrogen/helium mix to confirm that the unit had not been damaged during transport/installation, and worked as required with connected utility systems. Calibration of all sensors – mainly vibration sensors – was confirmed by external measurements. However, due to the limited cooling medium capac-ity in the yard, the system could not be run in full recycle for a long period. As the system was designed to work with a wide span of inlet gas, the VRUs were tested in open loop, sucking air from cargo tanks and injecting it into LP flare system. This provided tempera-ture equalization within the unit to ensure stable operation in normal conditions.

Launcher with guide pipe,

fragment collector, and flare tip.

LP flare flow and pressure trend.

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This first batch of tests done onshore gave a good overview of how the system operates and what parameters could be used to tune the system. An electrical frequency convert-er was installed upstream of the main motor, which was used as a variable speed drive to avoid critical blower speed frequencies. Op-erations were later optimized for the lower through-put.

A loading philosophy for the VRU was de-veloped, based on the operating experience while running the unit on air in the yard, to ensure that critical speeds are not achieved in the blower. This required further optimiza-tion during hydrocarbon commissioning, but the baseline achieved during pre-commis-sioning significantly simplified later work.

One limitation of testing with air is that the system does not experience the same condensation as it does with water-saturated hydrocarbons. Hydrocarbon test runs con-ducted after the onshore commissioning suggested that the package was oversized, and that condensed water from the inlet gas mixture generated excessive vibrations in the system. This led to further work off-shore, including modifications to the cooling system to prevent over-cooling of the gas.

Operations

During normal operations, the fast open-ing valves on the flare drum discharges are closed and the paths to the VRU and FGC are opened. Pressure then begins to build in the flare drums until there is sufficient pres-sure to flow gas to the compressors.

Introducing boil-off gas from the COTs to the compression train was found to increase the formation of liquids in the main export gas compressor’s liquid knock-out drums and to decrease duty on the compressor as the mo-lecular weight of the gas increased. During operations with low gas loads, this resulted in much higher liquid formation than expected.

Operation of the FGC has been stable, coping well with valve leakages and high gas flow from the GTG fuel gas warm-up lines. Operating experience reiterated the need to step through changes slowly and to allow the system to settle as a whole. Once throughput was established, the system was found to operate smoothly as a whole.

Normally oil rundown is distributed along the bottom of the cargo tanks so as not to disturb the liquid and to ensure optimal level measurement in the tanks. Because the final stage of separation takes place in the COTs, the rundown to the tanks is at the top of the tanks. When marine operations change to loading an empty tank, the extra fall height results in increased vapor disengagement, which briefly increases the load on the VRU.

With the flare running, a significant amount of liquids condense in the flare stack

itself due to wind and ambient temperatures below that of the flare gas. Essentially, the flare stack becomes a very long air-cooler with a temperature differential of up to 20°C (68ºF) depending on run-down temperature, ambient temperature, and operations. This resulted in liquid formation of up to 25 liters per hour (6.6 gal/hr). Had the unit been de-signed to flare continuously, this would have drained back into the flare drum. However, as the flare system was designed to have a low point between the drum and the flare stack to prevent rain water from sitting against the fast opening valve, this liquid col-lects in the dead leg. When full, it is noted by flow and pressure fluctuating as liquid slosh-es back and forth with vessel motion. The chart shows the fluctuation in flow (pink) and pressure (red) as liquid filling the dead leg begins to impact the flow and pressure in the flare drum outlet.

The main concern of this is that if there is an incident soon after flare-less operations are restarted, but before operations teams have had time to drain the flare header, then liquids that have been suspended in the stack by the gas velocity can be pushed out onto the deck. Because the flare stack oper-ates more or less like an inefficient distilla-tion column, the liquid is water with some dissolved heavy hydrocarbons and there is no risk of the liquid igniting.

Over-cooling of the discharge gas from the VRU caused liquid build-up in the spare VRU due to pipework configuration at the outlet of both VRUs. The unit was equipped with a manual globe valve, but because of high differential pressure this did not pro-vide sufficient control. The addition of re-striction orifices to increase the back pres-

sure improved operations, but the units continued to experience liquid build-up. A temperature control valve was installed on one of the VRUs and both units ran success-fully. Installation of the same arrangement on the second unit is pending.

Use of tubing was found to exacerbate vibrations during operation, causing failure of small-bore lube oil and nitrogen lines. Decoupling these by installing small flexible hoses considerably reduced the effects of vi-bration and failure of the small-bore tubing.

Benefits

Obvious benefits of a closed flare system are increased production and a reduced en-vironmental footprint. The latter has further potential benefits in the form of carbon cred-its and reduced CO2 taxes.

As the flare tip itself is no longer subject to continuous flaring, wear and tear is signif-icantly reduced. Experience on other units has shown that continuously flaring may require several flare tip changes during the lifetime of the unit; this is now potentially re-duced to none. Similarly, the demand on the inert gas system is reduced.

Working conditions on the FPSO improve significantly with flare-less operation, particu-larly on top of the modules that are closest to the flare stack, where heat fatigue can other-wise be a significant issue in the summer.

Conclusion

In an effort to reduce greenhouse emis-sions, countries are increasingly imposing regulations that require flare-less oil and gas operations. The main points to consider for an optimal design of a vapor recovery sys-tem for an FPSO with hydrocarbon blanket-ing are: t��5VSO�EPXO �GSPN��UP��t��-JRVJE�DPOUSPM�EVSJOH�BMM�QIBTFT�PG� UIF�

operating envelope t��3PCVTUOFTT� PG� EFTJHO� UP� WBSZJOH� HBT�

composition, and the effect on the main compressor trainst��1PUFOUJBM�GPS�TPVS�XFMM�ýVJET�t��&GGFDU� PG� CBDL� QSFTTVSF� PO� PUIFS� QSP-

cesses.Flare-less operations can be implemented

with relative ease if required from the begin-ning. With drivers that include environmental regulations, emissions reduction, production optimization and improved working conditions, it is expected that flare-less designs will become the new standard for FPSOs and platforms. �

AcknowledgmentBased on a paper presented at the Deep Offshore

Technology International Conference & Exhibition held

Nov. 27-29, 2012, in Perth Australia.

Flare-less operations on the Okha FPSO.

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P R O D U C T I O N O P E R AT I O N S

Asset integrity management extends reachSpecific tools and services target more offshore facility types

M.F. Renard

Bureau Veritas

The value of asset integrity management systems (AIMS) is reach-ing into more corners of offshore oil and gas exploration and de-velopment. It is not only used for FPSOs, but also TLPs, spars,and semisubmersibles. It is applicable to fixed platforms, too.

Bureau Veritas has fielded requests for AIMS support forequipment at the seabed, from flowlines and risers to vessel moor-ings, topsides, and offloading equipment.

Operators and service companies see two broad benefits in imple-menting AIMS. The first is the obvious need to keep track of what is happening with these high capex, long-term investments to maxi-mize the returns.

The second broad benefit is to harmonize systems and proce-dures across multi-discipline teams spread across different parts of the world. While each AIMS can be specific to a facility, the consis-tency of the processes and tools used makes the results comparableand coherent. It improves information and documentation transfer.

The AIMS process also is flexible enough to be tailored to what an operator wants to know about a specific installation.

Combined, these can help minimize production shutdowns, and optimize maintenance and repair costs.

Offshore floating units are usually deployed under a long-termplan to handle the field production. This means they cannot be eas-ily removed for dry-docking and repair. An AIMS has been devel-oped for complex, major floating units and currently is in operationfor several major oil companies.

AIMS is implemented to ensure management and continuous follow-up of all floating units regarding safety, environmental, op-erational, maintenance, and quality management. It includes rec-ommendations on inspection, maintenance, and repairs. The main activities called for in this program are:t��4USVDUVSBM�BOE�NPPSJOH�BOBMZTJT�t��2VBMJUBUJWF�SJTL�CBTFE�JOTQFDUJPO�3#*�JNQMFNFOUBUJPOt��:FBSMZ�SFWJFX�PG�UIF�JOTQFDUJPO �SFQBJS �BOE�NBJOUFOBODF�*3.�QMBOt��%BUB�NBOBHFNFOU�BOE�TUPSBHFt��"TTJTUBODF�GPS�FNFSHFODZ�åSTU�SFTQPOTF�#VSFBV� 7FSJUBT�� 7FSJ45"3� "*.4� JT� BO� PQFO�8FC�CBTFE� TZTUFN�

with controlled access that allows AIMS teams to work worldwide.The system is designed to improve inspection management and in-formation control for different types of facilities. Information is storedand secured in a unique database and can be accessed in real timethrough the Internet or an intranet.

Integrity management cycle process

The integrity management cycle process comprises four main tasks:��%FWFMPQNFOU�BOE�NBJOUFOBODF�PG�åOJUF�FMFNFOU�NPEFMT�'&.�

and management tools2. Periodic reassessment of unit condition��3#*�BOBMZTJT�BOE�*3.�DZDMF��&TUBCMJTINFOU�BOE�NBJOUFOBODF�PG�FNFSHFODZ�SFTQPOTF�QSFQBSBUJPOT�Modeling software, data management tools, calculations services,

and other analysis/trends are provided within the scope of the First Assessment phase, which establishes the basis of the integrity man-agement cycle process.

5IF�*3.�QMBO�GPS�B�HJWFO�GBDJMJUZ�JT�EFWFMPQFE�CBTFE�PO�FOHJOFFS-JOH�BOBMZTFT �3#*�BOBMZTJT �PQFSBUJPOBM�DPOTUSBJOUT �BOE� JOTQFDUJPO�results. The plan is developed and optimized regularly from theVOJU�T�FYJTUJOH� *3.�QMBO��5IJT�TZTUFN�IFMQT� UIF� JOTQFDUPST�BOE�BMM�concerned people to better control the integrity of structures, moor-ings, and offloading systems.

FEM and management tools

The available tools, including software solutions for structural'&.� BOBMZTJT � IZESPEZOBNJD� BOE�NPPSJOH� BOBMZTFT � JOTQFDUJPOT �and data management, are fitted to support every step in a unit’s JOUFHSJUZ�NBOBHFNFOU�DZDMF�QSPDFTT � GSPN� *3.�BDUJWJUJFT� UISPVHI�the annual review of the asset condition.

A global structural model is provided for each floating unit us-ing finite elements modeling, depending on the shape of the floating unit (ship-shaped, barge, TLP, or spar) and on building materials. All items of the hull contributing to the resistance or to the stress of the structure are modeled.&OWJSPONFOUBM� EBUB� DPOTJEFSFE� JO� UIF� FOHJOFFSJOH� BOBMZTFT� PG�

FPSOs are based on the latest meteocean data for each specific site,including waves, current, and wind characteristics.

Load cases corresponding to the actual operating conditions used onboard are taken into consideration in order to assess the stressand fatigue induced in the structures by cargo, ballast, and otheroperating loads.

Fatigue life of selected details in the hull must be calculated. The calculations are based on production loads, local design, and localweather. The procedure to establish fatigue life uses the Miners summation approach, using stress-cycle (SN) curves.&BDI�ýPBUJOH�VOJU� JT�BMTP�QSPWJEFE�XJUI�B�NPPSJOH�TZTUFN�EBUB-

base (mooring lines, dynamic positioning, offloading buoys, etc.).Hydrodynamic response of the floating unit is assessed to provideJOQVU�EBUB�GPS�UIF�NPPSJOH�BOE�UIF�TUSVDUVSBM�'&.�BOBMZTFT�

For units coupled by flowlines, ropes, and gangways, for instance, a model containing the different floating units and their links is built.

Assessment of floating unit condition

The main objectives of the floating unit assessment condition are:t��"OBMZ[F�JOTQFDUJPO�SFTVMUT�BOE�FTUBCMJTI�USFOETt��$PNQBSF�NPOJUPSFE�PCTFSWBUJPOT�XJUI�åOJUF�FMFNFOU�BOBMZTJT

Typical FEM model of an integrated hull and topsides FPSO. CourtesyTOTAL.

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Mooring system database

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UFN�BOE�JUT�DPNQPTJUJPO�SFRVJSFE�GPS�TUBUJD�BOE�UJNF�EPNBJO�BOBMZTFT�Dynamic data.�"EEFE�NBTT�NBUSJY �EBNQJOH�NBUSJY �25'T�VTFE�

UP�DBMDVMBUF�UIF�TFDPOE�PSEFS�XBWF�ESJGU�BOE�NFBO�XBWF�ESJGU�MPBET�BOE�3"0T�VTFE�UP�DBMDVMBUF�UIF�åSTU�PSEFS�XBWF�NPUJPOT�GPS�DBMDV-MBUJPO�PG�UIF�FOWJSPONFOUBM�MPBET�PO�UIF�TZTUFN�JO�UIF�UJNF�EPNBJO�

Wave, wind, and current data.�5ZQF�PG�XBWF�TQFDUSVN �BNQMJ-UVEF �QFSJPE �BOE�IFBEJOH��UZQF�PG�XJOE�TQFDUSVN �WFMPDJUZ �BOE�IFBE-JOH��DVSSFOU�TQFFE�BOE�IFBEJOH��

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Silicon-free defoamers and antifoamers

improve performance, safety

Stable foaming tendency is often foundin oil and gas treatment due to the pres-ence of several substances or dispers-ing agents, and turbulence from thewellbore to the separation processes.

The presence of foam can generate unsteadyconditions in separators as well as carryoverof a great amount of liquid in the gas flow, andamount of dissolved gas in oil that flows out ofthe separator.

Offshore asset operators traditionally treatfoaming problems with chemical additivesbased on siloxy groups, which break the foamas soon as it is absorbed in the interphase gas/liquid. Silicon used in defoaming additives,however, can affect oil quality for final clients.Silicon can also generate aggregates that tendto precipitate in the process equipment.

For these reasons, Clorobencenos andPride Oleo have pointed out the need of addi-tives free of silicon and fluor for solving foamin oil, and have developed a series of dual-ef-fect defoamers/antifoamers competitive withthose based on silicon that have been used inproduction facilities offshore Mexico.

Foam and separation

The primary offshore separator, the firststage of separation, receives oil and gas fromthe reservoir. In this stage, most of the dis-solved volume of gas is separated. If there is ahigh foaming tendency, this stage will becomethe most critical. Generally, retention times forcrude oil without foaming problems are in therange of one to three minutes, which guaran-

tees an efficient separation of dissolved gas inoil. Oil with foaming problems requires moreretention time, and particular separator de-signs that may not be available in place. Foamcan lead to poor level control, and in severecases, platform shutdowns.

In second-stage separation vessels, an undesirable consequence of foam is the carryover of oil droplets in gas flowing out the separation vessel. In this case, the gas flow contaminated with liquid interfereswith the compression processes and scrub-bers downstream. Flooding can cause this equipment to be taken offline in the event of failure. At other times, this gas is flaredtogether with oil – and profits.

Gas carried in liquid can cause pump cav-

itation and increased compressor demands. Accumulated gas in liquid not only affectsseparation performance but also generates an increase in gas carryover in pipelines, which impacts the production schedule of offshore assets.

Foam control

Offshore operators destroy, prevent, or de-lay foam by using defoamers or antifoamersbased on alcohols, glycols, ester, and siloxygroups. Chemical additives with these groupsare absorbed on the lamellae (bubbles) to de-stabilize and break the foam.

Diluted or emulsified silicons and fluoro-silicons, the most common products used to treat foam in oilfield separation processes,reduce liquid carry-over in the gas streamand carry-under of gas in the oil stream. If foam-over occurs and silicon based antifoam is used, silicon carry-over can flocculate and precipitate inside oilfield production instru-ments or equipment.

Defoaming without silicon

An application of concentrated defoamer/antifomer additive free of silicon and fluorwas approved for a Pemex separator processin the Mexican sector of the Gulf of Mexico.Injection of a concentrated defoamer/an-tifoamer from the CBP series was done toprove the performance of the chemical ad-ditive to destabilize and/or eliminate foam-ing from a hydrocarbon flow. The aim wasto maintain a safe and continuous separation

Jesús Salvador

Flores-Mondragón

César Andrés Bernal-Huicochea

Pemex Exploración y Producción

Juan Carlos Sainz-De la Peña

Clorobencenos S.A. DE C.V

Juan de la Cruz Clavel López

Instituto Mexicano del Petróleo

Francisco Janitzio-Morales

José Gabriel Villegas-González

Pride Oleo Mexicana S.A. DE C.V.

Samples show the results of applying the concentrated non-silicon defoamer/antifoamer at a Pemex-operated satellite platform (left) and an offshore

processing center (right).

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20

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process while complying with quality standards. The application was performed for 72 hr. at a satellite platform and an offshore hydrocar-bon processing center operated by Pemex E&P.

Average conditions before application of CBP-AF (satellite platform):t��2VBOUJUZ�PG�PJM�� C�Et��2VBOUJUZ�PG�HBT��..DG�Et��4JMJDPO�CBTFE�BEEJUJWF�EPTJOH��-�E��QQNt��$POEFOTBUF�SFDPWFSFE��4MJHIUMZ�TPJMFEAverage conditions during the implementation of CBP-AF series

additive while maintaining stable conditions in the separation process:t��2VBOUJUZ�PG�PJM�� C�Et��2VBOUJUZ�PG�HBT��..DG�Et��%PTBHF�PG�OPO�TJMJDPO�CBTFE�BEEJUJWF�PQUJNJ[FE� GSPN� ��-�E�

��QQN�UP��-�E��QQN�t��$POEFOTBUF�SFDPWFSFE��OP�QSFTFODF�PG�SFTJEVBM�PJM�BOE�OP�PQBDJUZ�Average conditions before the application (processing center):t��2VBOUJUZ�PG�PJM�� C�Et��2VBOUJUZ�PG�HBT��..DG�E�t��4JMJDPO�CBTFE�BEEJUJWF�EPTJOH�EJMVUFE�� -�Et��$POEFOTBUF�SFDPWFSFE��1SFTFODF�PG�PJM�ESBH��DPOEFOTBUF�TUBJOFEt��4VDUJPO�QSFTTVSF�JO�QVNQJOH�TZTUFN��LH��TR�DN�Average conditions during the implementation of the non-silicon-

based additive:t��2VBOUJUZ�PG�PJM�� C�Et��2VBOUJUZ�PG�HBT��..DG�E�t��%PTBHF�PG�OPO�TJMJDPO�CBTFE�EFGPBNFS�SFEVDFE� GSPN�� -�E� UP�

��-�E�BOE�TVCTFRVFOU�SFEVDFE�EPTBHFT�UP��-�E�BOE��-�E��*U� JT� JNQPSUBOU� UP�OPUF� UIBU�PQUJNJ[BUJPO�PG� UIF�BEEJUJWF� SFNBJOFE�DPOTUBOU�GPS�DPOTFDVUJWF�EPTBHFT�� -�E ��-�E �BOE�åOBMMZ �B�

reduction of the dosage for a period of four hours. First the dosage XBT�SFEVDFE�GSPN��-�E�UP��-�E�EVSJOH�UXP�IPVST �BOE�B�MBTU�SFEVDUJPO�GSPN��-�E�UP��-�E�GPS�BOPUIFS�UXP�IPVST��t��$POEFOTBUF�SFDPWFSFE��/P�PJM�DBSSZPWFS��DMFBO�DPOEFOTBUF�

Conclusions

5IF�BQQMJDBUJPO�PG�UIF�BEEJUJWF�EFGPBNFS�BOUJGPBNFS �$#1�4FSJFT�"' � JO�PGGTIPSF� GBDJMJUJFT�XBT�CBTFE�PO� UIF�OFFE� GPS�B�VOJRVF�BOE�DPODFOUSBUFE�VOEJMVUFE�QSPEVDU�GSFF�PG�TJMJDPO�BOE�ýVPSJOF �DPOTJE-FSJOH�JO�JUT�DPNQPTJUJPO�CJPEFHSBEBCMF�QSPEVDUT �BDDFQUBCMF�EPTBHF �QSBDUJDBM�NBOBHFNFOU �BOE�BO�BQQMJDBUJPO�UIBU�XBT�UFDIOJDBMMZ�BOE�economically feasible.

The concentrated injection of CBP-AF ended with competitive EPTJOH�XJUIPVU�UIF�OFFE�UP�VTF�B�EJMVFOU �GBDJMJUBUJOH�JUT�BQQMJDBUJPO�BOE�SFEVDJOH�SJTL�UP�QFSTPOOFM�JO�UIF�BSFB�PG�JOKFDUJPO�

'PS�CPUI�TFQBSBUJPO�TZTUFNT �TBUFMMJUF�QMBUGPSN�BOE�PGGTIPSF�QSPDFTT�DFOUFS � JOKFDUJPO�PG�OPO�TJMJDPO�BOUJGPBNFS�EFGPBNFS�XBT�TVDDFTTGVMMZ�VTFE�UP�TPMWF�GPBNJOH��6OJGPSN�TUBCJMJUZ�XBT�NBJOUBJOFE�XJUI�PQUJNJ[FE�dosages relative to the consumption of silicon-based antifoaming addi-UJWF�VQ�UP��QQN�UP�USFBU�BO�BWFSBHF�� C�E�JO�UIF�TBUFMMJUF�QMBUGPSN�BOE��QQN�UP�USFBU�BO�BWFSBHF�� C�E�JO�UIF�QSPDFTT�DFOUFS��"T�HBT�PJM�SFMBUJPOT� JODSFBTF �OPO�TJMJDPO�CBTFE�BOUJGPBNFST�EFGPBNFST�offer a solution to offshore foaming problems. �

AcknowledgmentsThe authors thank GGPT-Pemex E&P for permission to use and publish data, and

Edgar Zamora-Reyes (Pemex), Héctor Castro-Monzón and Donaciano Ramírez-

Pantoja (Clorobencenos), Fabiola Vivas-Trujillo (IMP), Rogelio Legorreta-Romero

(IMP), Cecilia Hernández-Sedeño, Andrés Aviles-Aguilera and Andrea Villegas-

Avalos (Pride Oleo Mexicana).

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Statoil records first successful

North Sea HP/HT coiled tubing milling jobTelemetry proves critical for intervention

at Kvitebjoern on Norwegian continental shelf

Statoil learned valuable lessons during the planning and exe-cution of a high-pressure/high-temperature (HP/HT) coiledtubing milling job on the Norwegian continental shelf (NCS) in the North Sea at Kvitebjoern field. Kvitebjoern is a Statoil-operated gas and condensate field in block 34/11 with a res-

ervoir at about 4,000 m (13,120 ft) with pressure of 770 bar (11,168 psi) and temperature of 160º C (320º F).

Well 34/11-A-9 T2 was drilled as a gas producer and during the final completion phase, it was not possible through pressure cycling to open the HP/HT isolation ball valve set in the 9 7/8-in. liner at 6,245.7 m (20,486 ft) MD/3,795.8 m (12,450 ft) TVD. After severalfailed attempts with wireline using mechanical override tools, it was decided to punch above it to allow well production passing the out-side of the valve through the annulus between 9 7/8-in. liner and the 5½-in. tail pipe. However, the production performance was poor.A feasibility study evaluated ways to open or mill out the valve with the objective to improve the production characteristics and to allowaccess for future production logging.

The decision was to mill the stuck-closed isolation ball valve using coiled tubing (CT). Statoil had not performed any HP/HT CT opera-tions and the available experience was limited.

To minimize uncertainty relating to depth determination duringmilling, a telemetry system ran at its operational pressure and tem-perature limits to provide real-time casing collar locator (CCL) read-ings in addition to downhole pressure and temperature data.

The Super 13% chrome, 110 Kpsi yield isolation ball valve was stuck closed at a deviation of 57.8º. Its ID when open is 4.25-in with adrift ID = 4.151 in. The EOF seating nipple at 6,223 m (20,411 ft) MDfrom the rig kelly bushing was ID = 4.31 in., which represents the minimum wellbore restriction from surface down to the ball valve depth.

The 34/11-A-9 T2 well is in the Statfjord formation with the top ofperforations at 4,313 m (14,147 ft) TVD. The original prognosed res-ervoir pressure was 770 +45/-14 bar (11,168 + 653/-203 psi) and thedownhole temperature at reservoir was 160º C. The shut-in wellheadpressure was 571 bar (8,282 psi) in March 2011. The expected down-hole temperature at the ball valve was 145º C (293º F). The H2S andCO2 concentrations in the produced gas were less than 5 ppm and aconcentration of 3.477 mol %, respectively.

A feasibility study including an onshore milling test evaluated thepossibility of milling the isolation ball valve with an electrical mill assembly run on mono-conductor wireline cable. The report con-cluded with large uncertainty regarding the number of bailer runsnecessary to remove debris above the valve and reach milling depth, as well as the lifetime for the electrical milling equipment at the veryhigh downhole temperature. Based on this study and the low esti-mated likelihood of success (30 -- 40%), the Kvitebjoern license de-cided not to proceed with the wireline alternative.

New feasibility studies evaluated using CT, rig-assisted snubbing, and the rig for opening or milling out the isolation ball valve.

The CT alternative seemed to be feasible since similar jobs wereperformed at lower temperature and shallower depths, but the 15K psi well control equipment and CT string design would have to be specified and sourced specifically for the job.

Mohamed Ridene

Stephen Stragiotti

Tor Kristian Holst

Johnny Baardsen

Statoil ASA

Godwin Effiong

Baker Hughes

Wellbore schematic.

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Determination is in our nature

Finding oil used to be easy. So was recovering it. Today, oil exploration requires highly specialized skills to deal

with the vast challenges we are facing, like unfathomable depths and complicated geology. When we find the oil,

it can be difficult to recover due to high pressure and low permeability. And most importantly, we have to meet

the world’s toughest safety standards – our own. Luckily, we have a secret weapon; our attitude of constantly

raising the bar on everything we do. Or as we like to call it – never being satisfied.

Explore more at neversatisfied.statoil.com

Always exploring

Never satisfied

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The main drawbacks for the rig-assisted snubbing were the drill-ing crew’s rig-assisted snubbing experience, rig-assisted snubbing personnel experience, ram-to-ram stripping experience, and HP/HT well conditions.

For the rig alternative, the main risks were gas migration to the surface in addition to more time and cost relating to killing the well.

It was decided that the primary method to be further evaluated and developed for removal of the ball valve restriction from the well would be CT, the secondary method would be rig-assisted snubbing and the final method would be to use the rig.

Concept selection

During the concept selection phase, the rec-ommended method for deploying CT to remove the isolation ball valve from the wellbore con-sisted of the following steps:

Pre-CT job “pump and bleed” operation.

Displacing the wellbore from the current gas by re-peatedly bullheading 1.044 sg 40/60% MEG/fresh water from the kill wing valve of the christmas tree and bleeding the gas that migrates to surface. The aim of this “pump and bleed” step was to reduce the surface shut-in wellhead pressure (SIWHP) to the minimum before running the CT. This had advan-tages in safety and operations.CT drift and cleanout run(s). The well

was producing intermittently for few months through punched holes above the closed ball valve. It was suspected that fill and debris might have settled above the ball valve with the 11.5-m (38-ft) interval between the punched holes and

top of the ball valve being particularly vulnerable. Offshore crane capacity limits and the long CT string needed to reach the ball valve at 6,245.7 m (20,492 ft) MD RKB, the maximum CT string size that could be shipped in one piece was 2- in. OD. The well completion from surface to approximately the ball valve depth was 7 in., 35 lb/ft tubing with a 6-in. ID. Therefore, it was impossible to generate enough turbulence in the annulus between the tubing and CT to lift any fill or debris when run in hole (RIH) with the milling bottomhole assembly (BHA) to mill the ball valve. It was decided to RIH first with a with venturi jet junk basket (VJJB) to drift and clean out the wellbore to the top of the ball valve.CT milling run(s). This was the ultimate run to achieve the job

objective and mill the ball valve. The motor needed to provide enough torque to mill through the ball valve. In addition, its operating pump rate should be achievable through the specially designed 2-in. CT string. A yard test and a successful milling job of a similar ball valve in a well operated by Shell in the British section of the North Sea were on record. The mill was a 4.1-in. OD dome profile ball mill run with a hydraulically (pump rate) operated shifting tool and an anti-stall tool. All lessons learned during this Shell job were taken into account for this Kvitebjoern CT project. The mill was designed and tested to mill through the ball valve material. The mill size for this Kvitebjoern job was decided to be 4-in. OD to deploy the milling BHA through the 41⁄16-in. 15K psi CT BOP. This mill size is big enough to allow later production logging tools to run through the milled hole. This critical detailed planning phase took approximately five months. It consisted of organizing several meetings and coordinating between different departments, disciplines, and third parties.

Offshore execution

The job went as planned. The CT job was carried out through the drilling rig. The ball valve was successfully milled and drifted with the 4-in mill and the access to the lower wellbore was regained.

No serious HSE & Q incidents were reported during this first HP/HT CT job in Statoil and the Norwegian continental shelf with a high operating factor of 96.2%.

The total job duration was 31.6 days with equipment rig up includ-ing “pump and bleed” of 10.9 days; one VJJB clean up run and three milling runs totaling 9.1 days; extra production test and one extra

Well control stack as built.

CT equipment layout on pipe deck.

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3D multi-finger caliper log findings (October 2011).

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drift run with VJJB through and below the milled ball valve, 6.1 days; and equipment rig down and back load, 5.5 days.

Operational risk analysis

An operational risk analysis log sheet and risk register covering the different stepsof the operation was elaborated during de-tailed planning. This was important because this was the first HP/HT CT operation in Statoil and in the NCS.

The risk assessment involved representa-tives from all concerned disciplines within Statoil, including reservoir, well interven-tion, drilling and production, plus Statoil discipline advisors for CT, well intervention,well integrity, HP/HT, and well control, as well as third-parties representatives for CT services and the rig contractor.

The probability and the potential impact for each initial risk were assessed using a standard risk tolerance matrix. Preventionand mitigation actions were identified for each risk with the objective of reducing the probability and/or the potential impact of the corresponding risk.

This resulted in a detailed operational risk register including 41 identified hazards and 84 risk prevention and/or mitigation mea-

sures that were implemented during the planning and execution phases.

This risk register was sub-divided into 11 sections as following:

1. Mobilization and demobilization2. Spotting and equipment rig up3. “Pump and bleed” operation4. VJJB drift and cleanout run(s)5. Milling run(s)6. Well control stack up7. BHAs8. Fluids9. Contingency scenarios10. Rig down equipment11. Simultaneous contingency situations

in A-9 T2 and a second well.

Lessons learned

There were a number of lessons learnedon this project. They key lessons are de-scribed below.Telemetry tool performance. The te-

lemetry tool provided valuable CCL data to correlate the depth down to the ball valve. The telemetry tool failed in three of four runsat a bottomhole temperature around 145ºC (293º F). However, the CCL logging signal failed after the initial depth correlation. The telemetry tool was running properly for its

first few hours of exposure under extremedownhole pressure and temperature condi-tions before it failed. It was a known and ac-cepted risk prior to operation that the tool might fail if exposed to downhole conditions close to or above its operational specifica-tions of 8,000 psi/150º C (55 MPa/305º F) for a prolonged time. It could be concluded from the data that the telemetry tool oper-ated properly up to 564 bar (8,180 psi) and 146º C (295º F) before failure.Equipment availability. The equipment

availability for this special and non-frequentHP/HT CT job was a challenge. Early plan-ning and ordering of some critical equip-ment was vital, especially knowing the day rate of the drilling derrick to be used. This critical equipment included both CT strings, the gas tested 71⁄16-in./15K psi gate valve, the safety head handler, the gas-tested christ-mas tree crossover, and the 21⁄16-in 15K psi gas tested gate valves. Weekly meetings to review critical items were held with the CT contractor. The need for long lead items was identified early in the project, and Statoil issued purchase orders for relevant equip-ment.Site surveys. Three site surveys were

carried out by Statoil and CT contractor rep-

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resentatives to avoid conflict with platform interfaces, and to identify any limitations or special requirements.

Personnel HP/HT training. Two full-day sessions of CT aware-ness and HP/HT seminars were organized and presented by the CTcontractor to all involved personnel before the job start up. Bleed off procedure. The bleed off needed to avoid explosive

decompression of well control equipment elastomers was not pro-vided by the CT contractor. Rather, the local platform best practiceused during wireline operations was followed during this CT job. For future CT HP/HT operations, the bleed off procedure should be based on recommendations from the original equipment manufac-turer for standard and high-pressure well conditions, respectively.

Pump and bleed operation. Liquid losses into formation wereexperienced during the “pump and bleed” phase and it was not pos-sible to reduce the WHP. It was decided to abort the pump and bleed operation and to start running in the well while circulating throughthe CT. This alternative was effective in reducing the WHP.CT weight simulations. A drag reduction by 25% (from 0.24 to

0.18) was observed when displacing the wellbore with metal-to-metal friction reducer while RIH from 4,200 m (13,776 ft) MD RKB to the ball valve. Data proves that the actual CT RIH and pick up weights were within the operating limit at 80% yield of CT string material.Milling through the ball valve. It was difficult to control the

weight on bit (WOB) at 6,245 m (20,484 ft) MD while pumping 40/60% MEG/fresh water at 400 l/m pump rate and at 340 to 375 bar (4,931 to 5,439 psi) CT circulation pressure. During the first milling run, the WOB was set down gradually but the motor stalled 15 times. The first milling BHA was pulled to surface for inspection.During the second milling run, milling was carried out with patiencefor longer periods without increasing the WOB. Vibration and an anti-stall tool was expected to provide sufficient WOB. The top partof the ball valve was milled during the second run in approximately12 hours and the bottom part in an additional 12 hours. The experi-ence gained from the first milling run was used to optimize the mill-ing parameters of the second and third milling runs, and succeededto break through the ball valve with the 4-in. mill at the end.Confirmed milled ball valve. A 3D multi-finger caliper log was

run on wireline two months after the CT milling job to investigatethe wellbore status, particularly the milled ball valve area. The ball valve was confirmed to be milled out with a minimum ID of 3.97 in. at 6,245.7 m MD.

Conclusion

This CT project represents an excellent reference for future HP/HT CT operations for Statoil in Norway and worldwide. The job execution was performed as planned and in compliance with the relevant industry standards and local regulations. The stuck closed isolation ball valve was successfully milled and drifted with the 4-in. dome profile mill. No serious HSE&Q incidents were reported dur-ing this first HP/HT CT job in the Norwegian continental shelf, which had a high operating factor of 96.2%. Valuable lessons learnedfrom the planning and execution phases of this challenging opera-tion should be useful in future similar HP/HT CT applications. �

AcknowledgementsThe authors thank Statoil ASA, Baker Hughes (CT services with telemetry system),

Hunting Welltonic (milling and downhole tools), Rolls Royce (safety head handler),

and Tomax (anti-stall tool) for permissions to publish this paper. This article is

excerpted from a presentation made at the SPE/ICoTA Coiled Tubing and Well In-

tervention Conference and Exhibition held in The Woodlands, Texas, March 27-28,

2012. (Ref. SPE paper 154433)

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Pitting and crevice corrosion

of offshore stainless steel tubingSafe construction demands proper materials

Oil and gas platforms regularly use stainless steel tubing in process in-strumentation and sensing, as well as in chemical inhibition, hydraulic lines, impulse lines, and utility appli-

cations, over a wide range of temperatures,flows, and pressures. Corrosion of 316 stain-less steel tubing has been observed in off-shore applications around the world. Corro-sion is a serious development that can lead to perforations of the tubing wall and the escape, under pressure, of highly flammable chemicals.

The two prevalent forms of localized cor-rosion are pitting, often readily recognizable,and crevice, which can be more difficult to see. Many factors contribute to the onset of localized corrosion. Inadequate tubing alloy and suboptimal installation practices can lead to deterioration of tubing surfacesin a matter of months. It is speculated that today’s minimally alloyed 316 stainless steel tubing, with about 10% nickel, 2% molybde-num, and 16% chromium, may more readilycorrode than the more generously alloyed 316 tubing products produced decades ago.

Contamination is another leading cause for surface degradation. Such contamina-tion may be caused by iron particles fromwelding and grinding operations; surfacedeposits from handling, drilling, and blast-ing; and from sulfur-rich diesel exhaust. Periodic testing of seawater deluge systems, especially in combination with insufficientfreshwater cleansing, may leave undesirable chloride-laden deposits behind.

Pitting and crevice corrosion

Pitting corrosion of tubing usually is read-ily recognized. Individual shallow pits, and in later stages, deep and sometimes connect-ed pits can be seen with the unaided eye. Pit-ting corrosion starts when the chromium-rich passive oxide film on 316 tubing breaksdown in a chloride-rich environment. The higher the chloride concentration and the more elevated the temperature, the morelikely the breakdown of this passive film.

Once the passive film is breached, an electrochemical cell becomes active. Irongoes into solution in the more anodic bottom

of the pit, diffuses toward the top, and oxi-dizes to iron oxide. The concentration of the iron chloride solution in a pit can increase as the pit deepens. The consequences are ac-celerated pitting, perforation of tubing walls and leaks. Pitting can penetrate deep into the tubing walls, creating a situation wheretubing could fail.

Crevices are difficult, or even impossible,to avoid in tubing installations. They existbetween tubing and tube supports, in tubingclamps, between adjacent tubing runs, andunderneath contamination and deposits thatmay accumulate on tubing surfaces. Rela-tively tight crevices pose the greatest danger. General corrosion of tubing in a tight crevicecauses the oxygen concentration in the fluidthat is contained within a crevice to drop. Alower oxygen concentration increases thelikelihood for breakdown of the passive sur-face oxide film. The result is a shallow pit.

Unlike in pitting corrosion, formation of apit on tubing surrounded by a crevice leadsto an increase of the Fe++ concentration inthe fluid contained in the gap. Because of thestrong interaction of the Fe++ ions with theOH ions, the pH value drops. Chloride ionsalso will diffuse into the gap, being attractedby the Fe++ ions. The result is an acidic ferricchloride solution that can accelerate corrosionof tubing within the crevice.

Ideally, tubing should resist all forms ofcorrosion, including general, localized (pit-ting and crevice), galvanic, microbiological,chloride-induced stress corrosion cracking,and sour gas cracking. The tubing also shouldhave adequate mechanical properties, espe-cially when fluid pressures are high. Resis-tance to erosion comes into play when fluidscontain potentially erosive particles. The en-vironmental impact of the tubing also shouldbe a concern; aquatic life can be harmed bysmall concentrations of copper ions that canbe released by copper-zinc alloys.

The resistance of an alloy to localized tubing corrosion can be estimated from its chemical composition by calculating the al-loy’s pitting resistance equivalent number (PREN). The most frequently used relation-ship is: PREN = %Cr + 3.3 %Mo + 16 %N. The higher the PREN value of an alloy, the high-

Gerhard Schiroky

Swagelok Co.

Anibal Dam

BP Exploration & Production Inc.

Akinyemi Okeremi

Shell InternationalExploration & Production

Charlie Speed

Consultant

(Above) Corrosion of 316 stainless steel tub-

ing. (Below) Pitting often can be seen with the

unaided eye.

Iron goes into solution in the more anodic

bottom of a pit, diffuses toward the top, and

oxidizes to iron oxide (rust).

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er its resistance to localized corrosion, i.e., the higher its critical pit-ting temperature (CPT) and critical crevice corrosion temperature (CCT). These critical temperatures can be determined by common testing procedures such as ASTM G48 and ASTM G150.

Alloy selection

The importance of selecting the optimal alloy is demonstrated when austenitic 316 stainless steel tubing shows heavy corrosion while no signs of corrosion were detected on alloy 2507 superduplex tubing installed side by side. In a Gulf of Mexico installation of alloy 2507 tubing, only a few instances of external chloride crevice cor-rosion damage were identified. No perforations leading to the loss of containment of system fluids were observed. The only instances where crevice corrosion damage occurred involved the use of plas-tic support strips and neoprene gaskets.

Numerous alloys have been used or have presented themselves as candidates for use in installations that require resistance to sea-water corrosion. The most frequently used alloys have been the 300-series austenitic stainless steels, mainly 316 and in some cases 317. Alloys with at least 6% molybdenum, the so-called “6-moly” al-loys, perform well offshore. Typical 6-moly alloys include 254SMO, AL6XN, and 25-6Mo.

More recently, alloys with slightly more than 6% molybdenum have been introduced: 654SMO, AL6XN Plus, 27-7Mo, and 31. The published properties of these alloys suggest that they would per-form well in chloride environments.

Nickel alloys such as 825, 625, and C-276 are more frequently used in sour gas applications. Of these alloys, 625 and C-276 demonstrate excellent resistance to localized corrosion. Ferritic alloys like Sea-Cure and AL29-4C resist attack by aqueous chloride solutions and are pri-marily used as heat exchanger tubing. Tungum is a copper/zinc alloy has been used because it is relatively easy to install. However, its lack of hardness indicates susceptibility to erosive wear; low yield strength restricts its use to low pressures or requires high wall thickness; and corrosion liberates copper ions that can be detrimental to sea life.

Tubing alloys are available that offer a combination of attrac-tive properties for even unique applications in global construction projects. It is good practice to select an alloy with a critical pitting temperature above operating temperature. Depending on the appli-cation, it may be just as important to select an alloy with a critical crevice corrosion temperature above operating temperature.

Even highly corrosion-resistant tubing can be sacrificed when tubing surfaces are not kept clean. If possible, tubing should be installed following heavy construction activities that would other-wise allow weld splatter and grinding debris to accumulate on tub-

ing. Where adjustments of construction sequences are not possible, tubing should be shielded from contamination, and if contaminated, should be thoroughly cleaned.

The growing number of duplex alloys reflects the increasing use of this promising class of materials. The workhorse 2205 duplex alloy was introduced decades ago. Now there is superduplex alloy 2507, which has performed very well in recent years in more demanding applica-tions that require PREN values of 40 and above. More recently, the hy-perduplex alloy 3207 was introduced with an even higher PREN value.

At the low end of alloy content, several lean duplex alloys such as 2101, 2304, and 2003 are candidates for less demanding applications.

A graph plot of the critical pitting temperature and critical crevice temperature shows the increase in chromium, molybdenum, and ni-trogen leads to an increase in the CPT and CCT values of austenitic and duplex stainless steels. That also illustrates the economic ad-vantage of duplex alloys. Despite an overall lower content of costly nickel and molybdenum, they offer performance similar to that of highly alloyed austenitic stainless steels.

Not only do duplex alloys offer satisfactory resistance to local-ized corrosion, they also have high mechanical properties, which make them prime candidates for high-pressure applications. Note that 2507 has a yield strength more than three times that of 316L.

Jacketed tubing

For applications in seawater, a tubing alloy that is highly resistant to localized corrosion is not the only option. Alternatively, one may

Tubing is sandwiched between two half-round rods of thermoplastic.

Austenitic 316 stainless tubing shows corrosion while 2507 does not in

side-by-side tests.

Mechanical properties for duplex alloys.

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select a less resistant alloy and then shieldor protect the tubing.

Adequate protection appears to be offeredby a thermoplastic polyurethane jacket thatcan be cost-effectively extruded onto contin-uous tubing. Recent installations in the Gulfof Mexico combine this clamping concept with superduplex tubing, and will generate valuable performance data.

An alternate approach uses jacketed tubing.The extrusion of a thermoplastic coating ontotubing is an economically attractive solution.Tubing is typically 316 or 317 stainless steel,and the preferred coating is polyurethane.Limited installations that use urethane jack-eted 316 tubing report satisfactory results.

While the jacket must offer reliable pro-tection from corrosive fluids, it must fulfill additional requirements. The jacket must resist impact, abrasion, and degradation by UV-radiation. It must allow tubing to bend, and must allow for cost-effective tubing installation, i.e., removal of the jacket and make-up of tubing connections. Once made up, the connections typically have to be pro-tected from the environment using shrink tubing or tape. Without this protection, sea-water access could cause pitting corrosionof exposed tubing or crevice corrosion in the gap between the tubing and the jacket.

Appropriate tubing clamps must be selectedand care taken to prevent them from cuttinginto jackets and sacrificing their protectivecharacter. Jacketed tubing also can insulate, orheat and insulate, tubing when system fluidsmust be kept above ambient temperature.

Tubing supports and clamps

Many types of tubing supports and clamps have been used. Some have led to significant crevice corrosion, especially when tight crevices with large crevice surface areasresult in depletion of oxygen so the alloy cannot reform the passive oxide layer. In particular, plastic tubing clamps are proneto inducing crevice corrosion because the plastic deforms around the tubing to createtighter crevices that limit oxygen ingress.

One early approach to preventing or mitigating crevice corrosion was the use of marine aluminum alloys in tubing supportsand clamps. The tubing rests on a thin strip of aluminum alloy contained within a fiber-reinforced plastic tray. The tubing is held in place with an aluminum alloy bar.

Tubing support structures that use alumi-num alloys appear to perform well. Galvanic corrosion between aluminum alloy and stain-less steel may occur, but the aluminum alloy is more anodic than stainless steel, which

means aluminum will corrode preferentially.Once sufficient corrosion has taken place over a number of years, affected aluminum supports and clamps can be replaced while the stainless steel tubing remains in place.

An alternate design originally developedfor piping supports has recently been adoptedfor the installation of stainless steel tubing.The tubing is sandwiched between two half-round rods of a thermoplastic material. Withthe round tubing running perpendicular to theround support rod surface, the crevice contactarea is minimized. Theoretically, there shouldbe only one point of contact; however, someplastic deformation of the support rod takesplace that results in a finite contact (crevice)area. A benefit of this design is that the sup-ports/clamps allow for differential expansionof tubing and support structure.

Industry standards

The recently published industry standard,NACE SP0108-2008 “Corrosion Control of Off-shore Structures by Protective Coatings,” pro-vides guidance for more effective corrosionprotection for offshore structures. TAnotherindustry standard, API RP 552 “TransmissionSystems,” contains a section on installation prac-tices. Those described practices do not addressthe avoidance of crevice corrosion.�

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Resin emerging as alternative to cement

Well P&A aided by material’s water compatibility,

resistance to contamination

All frontiers invariably inspire expe-ditions. This has been true for the exploration and development of hy-drocarbon as it was for the discoveryand exploration of Mt. Everest. And it

has been true for the frontier inside the borewall, behind the casing. Advanced materials, methods, and wellbore designs are needed in this environment for safe and economical resource production.

While ultra-deepwater represents an epic frontier for our industry, there is a global network of scientists, chemists, rheologists,mechanists, and engineers who are pioneer-ing a realm of the microscopic: the molecu-lar frontier behind the casing. Their job is to interrogate molecular bonds, fluid flow dynamics, and the formation of hydraulic seals in spaces as narrow as three quartersof an inch.

Drilling has always been the route to hid-den hydrocarbon. It is generally agreed that the first oil well was drilled in 1859 in Penn-sylvania with a method known as cable-tool drilling, the lifting and dropping of a drill bit. When the rotary drill punched onto the scene in the 1880s, it efficiency opened a route through the overburden to the hydro-carbon-bearing strata.

Those drills were put on wheels, and these wheels created opportunity, but also limitation. Wells could only be drilled where

the drilling rigs could roll. This included the first offshore wells. The rigs rolled to the end of wooden piers built off the Santa Bar-bara coast of California in 1896. Then came the concept of floating, not rolling, a rig to where the oil was. A barge sailed beyond view of the shoreline in the Gulf of Mexico in 1947; at the end of 2012, there were 569 offshore rigs actively pursuing oil and gas, 44% of which were specifically designed and built for deepwater.

The frontier emerging behind the cas-ing is smaller than ever. Fracture gradient windows are narrowing, flow paths are tight and tortuous, and mechanical demands areincreasing. In this annular world there is one constant: the need for confining, isolat-

ing, and protecting multitudes of strata fromthe upward migration of gas and fluids.

Ultra-deep challenges

In 1919, when Halliburton ran the first cementing job in Oklahoma, the goal was not to transform oil and gas wellbore archi-tecture, but to help reduce risk and solve a problem. Nearly 30 years later, the company was part of the offshore frontier, cementing the first offshore well. As early as 1929, the company was investigating the propertiesof cement and the phenomena of cement hydration. These investigations expanded to the study of variables that could lead to incomplete cement placement or a loss of zonal isolation: the effects from mud con-

Sally Charpiot

Paul Jones

Halliburton

The low yield point of resin enables it to flow freely into micron-sized leaks without prior acid clean up.

Conventional resins (left) react exothermically with water.WellLock resin (right) is compatible with water.

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tamination on cement thickening time and tensile strength; increases in drag or incom-plete mud removal due to casing standoff and interface geometries; and increases in displacement pressures due to narrow path-ways for bypassing fluid, to name a few.

These investigations have resulted in hundreds of cement additives designed to optimize the chemical, rheological, and mechanical properties of cement blends, and to adjust performance to meet the chal-lenges of each individual well. The goal in this world of chemistry, fluid dynamics, and zonal isolation always has been to help operators balance the cost versus ultimate recovery equation while contributing to en-vironmental safety.

Obtaining a 360° annular seal for the life of the well is never easy. It is a realm defined by equivalent circulating density, in situ cor-

rosive elements, flow dynamics, thermal gradients, pressure and temperature fluctu-ations, regulatory statutes, and economics.

Cement remains the primary way to es-tablish a barrier against the upward migra-tion of fluids via the annulus, simply because cement provides the balance between cost management and pump-to-placement before setup. However, those two attributes have been challenged by ultra-deepwater, ex-treme downhole conditions, and unconven-tional source rock.

A cement alternative

Laboratory-modified resins for commer-cial use can be traced back to the 1860s, but the use of resins in the oil field begins some 80 years later. Once introduced, it was clear what resins had to offer: superior adhesion, resistance to many caustic and corrosive chemicals, excellent mechanical properties such as low yield point and low viscosity in the unset state, and flexibility and toughness after setting.

Despite these promises of performance,

practical application of resin as an annular barrier has remained just out of reach. Get-ting a resin downhole requires easy mix-ing and pumping without hardening before placement. Moreover, exothermic reactions triggered by water could cause damage downhole or to the surface equipment used for mixing and pumping.

In the past year, however, WellLock resin has overcome some challenges and has

been applied in situations where convention-al cement cannot effectively go. This resin lends itself to specific adjustments of rheol-ogy, density, and curing time to allow reli-able placement. The resin can withstand im-purities in the wellbore without significant degradation in performance and is compat-ible with water. The resin can be pumped in a fluid train ahead of or behind aqueous fluids without issues, and can be mixed and pumped through conventional equipment that may have aqueous residue.

Offshore applications

As a result of this resin’s compatibility with water, it has been used successfully to P&A an offshore well in the Gulf of Mexico that represented a closed system because the platform sheared away during a hurri-cane. The well was unable to accept fluid, yet regulations required decommissioning. A technical team determined that a weighted, low-viscosity fluid could be placed with mini-mal injectivity, yet provide high-compressive strength after setting. The resin ultimately

displaced the seawater in the well without generating heat downhole. The system re-mained in cohesive association – in other words, the resin formed a polymer network based on covalent bonds to develop a single molecule, the size of which is determined by the volume of material. This single mole-cule retains optimum shear bond values and tolerates up to 30% contamination without compromised mechanical properties, while resisting cracking.

P&A operations are nearly as active as new installations. Yet, due to the increasing-ly complex installations and challenging en-vironments, many operators are faced with the fact that conventional solutions may not address the challenges of a particular well. Care must be taken to avoid contamination, or channeling of wellbore fluids into the ce-ment plug.

The resin system was used in 2012 in an-other Gulf of Mexico well that could not be decommissioned by conventional methods. After an initial cut on the casing, bubbles were observed coming from the annulus. The probability that this bubble stream would channel through cement was high because pressure could not be held on the cement plug. In this case, the resin was used in a squeeze application, stopping the annu-lar leak. Subsequently, a 50-ft (15-m) resin plug was set. The resin has a low yield point, and due to its ability to be formulated free of solids, it can penetrate small casing leaks, micro-annuli, or gravel pack pores without the risk of particle bridging. Unlike cement, there is no prior clean-up required, eliminat-ing the time and cost of an acid treatment. In this case, permanent abandonment was established. �

The authors Sally Charpiot is manager, marketing & business

analysis, cementing, at Halliburton. Paul Jones is the

company’s principle scientist, cementing.

Throughout the transition from a liquid to a

solid state, the specially formulated resin con-

tinually transmits hydrostatic pressure to the

formation until a gas impermeable barrier forms.

Despite these promises of

performance, practical application

of resin as an annular barrier

has remained just out of reach.

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F L O W L I N E S & P I P E L I N E S

Pre-commissioning the Nord Stream pipelineProject represents the world’s longest offshore

dewatering operation/sealing tool run

As submarine gas pipelines get longerand more remote, the challenge ofpre-commissioning becomes greater.No project demonstrates this bet-ter than the groundbreaking Nord

Stream pipeline, which comprises two 760-milong, 48-in. diameter twin gas transmissionpipelines running from Russia to Germanythrough the Baltic Sea – a delicate marineenvironment that needs to be protected andpreserved.

In September 2011, the pre-commission-ing of the Nord Stream Line 1 was com-pleted ahead of schedule. Line 2 pre-com-missioning was completed one year later.These are the world’s longest single-section offshore pipelines.

The following discusses some of the chal-lenges experienced during the planning, engineering and preparation for the pre-commissioning of this pipeline, and relatethe relevant field experience collected dur-ing execution. A review of the schedule and lessons learned is also provided.

Nord Stream

The Nord Stream pipelines are defined as the offshore system which exports gas fromVyborg, Russia, crossing the Gulf of Finland and the Baltic Sea, to a receiving terminalin Lubmin (Greifswald), Germany. In addi-tion to crossing Russia and Germany, the pipelines also cross the Exclusive Economic Zones (EEZ) of Finland, Sweden, and Den-mark. Each pipeline has a capacity of 84 MM cm/d (2.9 bcf/d), with a total yearly capacity (for both pipelines) of 55 bcm (1.9 tcf).

The pipelines are designed with a seg-mented design pressure concept in accor-dance to the gas pressure profile along the route. There are no intermediate platformsalong the route.

Each of the three sections was installed

with offshore subsea terminations (start-upand laydown heads) designed for both the start-up and laydown operations and sub-sequent pre-commissioning activities. This was required because each of the sections had to be pressure tested separately.

Subsequently, the sections were joined by hyperbaric tie-ins at KP 297 and KP 675 thus creating a single 760-mi (1,223-km) pipeline.

Saipem was selected as the contractor for construction activities, while Baker Hughes was the selected contractor for the pre-com-missioning work. The design and construc-tion concept had a significant impact on the pre-commissioning execution.

Pre-commissioning concept

The initial concept was based on water fill-ing from onshore to onshore, using large-di-ameter crossovers at the subsea tie-in loca-tions for flooding. High-pressure crossoverswould then be installed for pressure testing. Thus, all three sections of the pipeline hadto be laid before commencing pre-commis-sioning operations.

Since the German area consisted of an al-most closed bay with very shallow water and low currents, flooding was to be performedfrom Russia to Germany with dewatering in the opposite direction. This plan requireda water winning and injection spread to be installed at the Russian landfall, with an air spread installed at the German landfall.

In an effort to reduce the environmentalimpact of the water treatment as much as possible, caustic soda (NaOH) and sodium bisulphite (NaHSO3) were initially selected as additives; the first to stifle anaerobic bac-teria activity, the latter as an oxygen scav-enger. The use of caustic soda generated significant concerns because of the possibil-ity of precipitation of carbonates and block-age at crossover locations. Consequently,detailed water sampling and analysis trials were performed.

All pre-commissioning activities on the Nord Stream project were essentially “one-shot” operations that could not be repeatedor reversed without major schedule impacts or affecting the permitting limitations for water disposal.

The pre-commissioning philosophy was further discussed and modified during the tendering phase with consultations between Nord Stream, Saipem, and Baker Hughes.

The resulting adopted philosophy was based on subsea intervention at the wet end of the sections from a subsea constructionvessel (SCV). This philosophy enabled each section to be completed independently of any other sections, and enabled Section 1 (closest to Russia) to be pre-commissionedearlier in the year, while the sea at the Rus-sian coast remained frozen and while Section 3 pipelay was still ongoing. This resulted in significantly increased schedule flexibility.

Marco Casirati

Jarleiv Maribu

Nord Stream AG

John Grover

Daniel Fehnert

Baker Hughes PPS

Nord Stream pipeline route. (Image courtesy Nord Stream)

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subsea pipeline would not tra-verse the permanent pig traps or permanent valvest��'MPPEJOH �DMFBOJOH �BOE�HBVHJOH�

'$(�XFSF�QFSGPSNFE�PGGTIPSF�POCPBSE� UIF� 4$7�� "MM� TVCTFB�IBOEMJOH�XBT�QFSGPSNFE�CZ�307t��8BUFS�XBT� USFBUFE�XJUI� TPEJVN�

bisulphite and ultra violet light 67�POMZt��1SFTTVSF�UFTU�PG�TFDUJPOT��BOE��GSPN�4$7t��1SFTTVSF� UFTU�PG�4FDUJPO� �� GSPN�UIF� SFDFJWJOH� UFSNJOBM� JO� (FS-many (to reduce vessel time and SJTL�GSPN�XBJUJOH�PO�XFBUIFSt��%F�XBUFSJOH�GSPN�(FSNBOZ�XJUI�XBUFS� EJTDIBSHF� JO�3VTTJB � BGUFS� DPNQMF-UJPO�PG�TVCTFB�IZQFSCBSJD�UJF�JO�BU�,1��BOE�,1��t��%SZJOH�GSPN�(FSNBOZ�UP�3VTTJBt��/JUSPHFO�BT�B�CBSSJFS�CFUXFFO�BJS�BOE�HBT�EVSJOH�DPNNJTTJPOJOH�PG�UIF�QJQFMJOFT�5IF�ýPPEJOH �DMFBOJOH �HBVHJOH �BOE�QSFT-

sure-testing spread were installed onboard the Saipem vessel Far Samson and included TVDUJPO� QVNQT � B�XBUFS� USFBUNFOU� TZTUFN �ýPPEJOH�BOE�QSFTTVSF� UFTU�QVNQT�� *O�BEEJ-UJPO �QSFTTVSF�UFTU�QVNQT�GPS�4FDUJPO��XFSF�JOTUBMMFE�BU�UIF�(FSNBO�MBOEGBMM�

The dewatering and drying spread was MPDBUFE�BU�(FSNBO� MBOEGBMM�BOE� JODMVEFE��Y��DV�N��Y�� DV� GU�TUFFM�XBUFS�UBOLT��5IF�3VTTJBO� MBOEGBMM�XBT� EFWFMPQFE�BT�B�XBUFS�SFDFJWJOH� GBDJMJUZ �BOE� JODMVEFE�B�TFUUMJOH�QPOE�BOE�B�UFNQPSBSZ��JO��ýPBUJOH�EJTDIBSHF�MJOF�5IF�'$(�QJH�USBJO�XBT�EFTJHOFE�UP�FOTVSF�

that the operation could be completed in a single pig run while providing contingency pigs to account for wet buckle scenarios EVSJOH� QJQF� MBZJOH�� 'PS� FBDI� TFDUJPO � GPVS�CJ�EJSFDUJPOBM�QJHT�XFSF�VTFE��5IF�QJHT�XFSF�back loaded into the subsea test head and installed on the seabed up to one year before UIF�PQFSBUJPO�

The dewatering pig train was designed to ensure that water removal and desalination could be completed in a single pig run: t��5IF�åSTU�CBUDI�PG�GPVS�QJHT�XBT�TFQBSBUFE�

by slugs of potable water designed to di-lute to an acceptable level the residual salt content remaining on the pipe wall t��5IF�TFDPOE�CBUDI�PG� GPVS�QJHT�XBT�TFQB-

rated by dry air to pick up water remain-ing after the desalination pigs

t��5IF�QJH� USBJO�XBT� TQBDFE� TP� UIBU� UIF� åSTU�four pigs could be received and removed be-GPSF�UIF�BSSJWBM�PG�UIF�TFDPOE�TFU�PG�GPVS�QJHT�

Key challenges

5IF�/PSE�4USFBN�QSF�DPNNJTTJPOJOH�XPSL�scope provided several key challenges because PG�JUT�TJ[F �HFPHSBQIJD�MPDBUJPO�BOE�FOWJSPONFO-UBM�TFOTJUJWJUZ��5IFTF�DIBMMFOHFT�JODMVEFE�

Pipeline length. This was the world’s lon-gest offshore dewatering operation and the XPSME�T�MPOHFTU�TFBMJOH�UPPM�SVO��&YQFSJFODF�from the pre-commissioning team and the pig vendor was important in ensuring that pig integrity could be maintained along the GVMM�QJQFMJOF� MFOHUI�� *U�XBT�BMTP�FTTFOUJBM� UP�FTUBCMJTI� UIF� MPDBUJPO� PG� QPTTJCMF� FWFOUT �particularly in case of gauge plate damage or TUVDL�QJHT��5IJT� SFRVJSFE� UIF�EFWFMPQNFOU�PG�B�DBSFGVMMZ�NBOBHFE�QJH�USBDLJOH�TZTUFN�

Pipeline volume and water depth.�&BDI��JO��QJQFMJOF�IBE�BO�JOUFSOBM�WPMVNF�PG��..DN��..HBM��5IF�NBYJNVN�XBUFS�EFQUI �DPNCJOFE�XJUI�MPTTFT �SFRVJSFE�B�EF-XBUFSJOH�QSFTTVSF�PG� ��CBSH��5IFSFGPSF �B�very large air compressor spread was neces-TBSZ�JO�(FSNBOZ�Vessel limitations. Since the flooding

TQSFBE�XBT�MBSHF �UIF�4$7�IBE�UP�DPNQMZ�XJUI�DIBMMFOHJOH�DSJUFSJB�JODMVEJOH�EFDL�TQBDF �BD-DPNNPEBUJPOT � 307T � DSBOFT � BOE� QPXFS�HFOFSBUPST��5IF�åUUJOH�PG�BMM�OFDFTTBSZ�FRVJQ-NFOU�GPS�B�TBGF�PQFSBUJPO�SFRVJSFE�JOQVU�GSPN�TQFDJBMJTUT�BOE�FYUSFNF�BUUFOUJPO�UP�EFUBJM�

Weather. Most of the Baltic Sea freezes in XJOUFS��5IJT�MJNJUT�UIF�PGGTIPSF�PQFSBUJPOBM�XJO-EPX��8BUFS�XJOOJOH�BOE�XBUFS�EJTQPTBM�DPVME�OPU�CF�QFSGPSNFE�XIJMF�UIF�TFB�XBT�GSP[FO�

Water treatment. The water treatment

philosophy was refined to provide the most environmentally friendly BQQSPBDI � JO� DPNQMJBODF�XJUI� UIF�applicable international and local SFHVMBUJPOT �XIJMF�NBJOUBJOJOH�DPS-rosion protection and minimizing the possible formation of precipi-UBUFT�JOTJEF�UIF�QJQFMJOF��Noise pollution. Strict noise re-

TUSJDUJPOT�SFRVJSFE�UIF�QVSDIBTF�PG�a custom air-compressor-spread to FOTVSF�DPNQMJBODF�Diesel handling and storage.

Large diesel volumes for the com-QSFTTPS� TQSFBE� JO� (FSNBOZ� SF-RVJSFE�B�DVTUPN�EJFTFM�TUPSBHF�BOE�handling system to receive and EJTUSJCVUF��DN�E�� HBM�E�PG�EJFTFM�XJUI�OP�DPOUBJONFOU�MPTT�

Waste management.�"�DPNQSF-hensive waste management system XBT�JNQMFNFOUFE�UP�TFQBSBUF �USBDL �and manage all the waste produced EVSJOH�UIF�QSPKFDU�T�FYFDVUJPO�

Schedule and execution

5IF�DPOUSBDU�GPS�UIF�/PSE�4USFBN�QSF�DPN-NJTTJPOJOH�XBT�BXBSEFE�JO�"VHVTU��5FO-EFSJOH� DPNNFODFE� FBSMZ � BMMPXJOH� TVGåDJFOU�time for multiple concepts to be considered before settling on the preferred concept upon which the pre-commissioning contract was CBTFE��5IF� UFOEFS� QFSJPE� SBO� GPS� BCPVU� OJOF�months concurrently with other project approv-BMT�UP�BMMPX�GPS�JNNFEJBUF�DPNNFODFNFOU�

The engineering procedures prepared GPS� QSF�DPNNJTTJPOJOH� UPUBMFE� TPNF� ��EPDVNFOUT� PWFS� BO� ��NPOUI� QFSJPE � BOE�XIJDI�SFRVJSFE�SFWJFX�BOE�BQQSPWBM�CZ�CPUI�4BJQFN� BOE� /PSE� 4USFBN�� 5IF� ��NPOUI�period was necessary not only for the base TDPQF� FOHJOFFSJOH � CVU� BMTP� UP� FWBMVBUF� BMM�QPTTJCMF�PQUJPOT�BOE�DIBOHFT�

To meet the flow and pressure demands while achieving the strict environmental BOE�OPJTF�UBSHFUT�TFU �B�MBSHF�QFSDFOUBHF�PG�UIF�QSF�DPNNJTTJPOJOH�FRVJQNFOU�XBT�QSP-DVSFE�OFX� GPS�UIF�QSPKFDU��5IF�FBSMZ�BXBSE�BGGPSEFE� B� ��NPOUI� QFSJPE� GPS� FRVJQNFOU�CVJMEJOH � UFTUJOH � BOE� EFMJWFSZ��%FTQJUF� SP-CVTU� DPOUSBDUJOH� TUSBUFHJFT � TPNF� WFOEPST�did not meet their delivery schedules; how-FWFS �UIF�XJOEPX�BMMPXFE�TVGåDJFOU�ýPBU�GPS�UIJT�UP�OPU�BGGFDU�UIF�QSPKFDU�T�TDIFEVMF�

The success and performance of the flood-JOH � DMFBOJOH � HBVHJOH � BOE� QSFTTVSF� UFTUJOH�PQFSBUJPOT� DBO� CF� BUUSJCVUFE� UP� �� DPOUJO-HFODZ�PG�DSJUJDBM�FRVJQNFOU�BOE� GVMM�POTIPSF�TQSFBE�GVODUJPO�UFTUJOH �JODMVEJOH�BMM�JOUFSDPO-OFDUJPO� QJQJOH�� *U� UPPL� �� EBZT� UP� DPNQMFUF�1JQFMJOF��BOE��EBZT�UP�DPNQMFUF�1JQFMJOF��

The success and performance of the de-XBUFSJOH �ESZJOH �BOE�OJUSPHFO�QBDLJOH�PQ-erations can be attributed to a combination

Flooding, cleaning and gauging activities were performed by the crew

aboard the subsea construction vessel. (Image courtesy Nord Stream)

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Dewatering pig. (Image courtesy Nord Stream) Sealing tool. (Image courtesy Nord Stream)Flooding, cleaning and gauging pig. (Image

courtesy Nord Stream)

of excellent pigs and reliable compressor spread performances. The full pre-commissioning of each line was completed in less

than 150 days from commencement of FCGT to the completion of nitrogen injection.

From the formation of the Nord Stream pre-commissioning team in early 2008, to the completion of pre-commissioning operations on Line 2 in August 2012, the following milestones were achieved:t��3'2�JTTVFE�GPS�QSF�DPNNJTTJPOJOH�PQFSBUJPOT �/PWFNCFS��t��1SF�DPNNJTTJPOJOH�DPOUSBDU�BXBSEFE�UP�#BLFS�)VHIFT �"VHVTU��t��&OHJOFFSJOH�BOE�QSPDVSFNFOU�PQFSBUJPOT�DPNNFODFE �4FQUFNCFS��t��$POUSBDUT�QMBDFE�GPS�BMM�8FU�#VDLMF�$POUJOHFODZ�8#$��FRVJQNFOU �%FDFNCFS��t��8#$�FRVJQNFOU�NPCJMJ[FE�BOE�GVODUJPO�UFTUFE �.BSDI��t��$POUSBDUT�QMBDFE�GPS�BMM�QSF�DPNNJTTJPOJOH�FRVJQNFOU �+VOF��t��1SF�DPNNJTTJPOJOH�'$(5�FRVJQNFOU�NPCJMJ[FE �'FCSVBSZ��t��0QFSBUJPOBM�QFSJPE�GPS�'$(5�PO�-JOF�� .BSDI�UP�.BZ��t��%FXBUFSJOH�BOE�ESZJOH�FRVJQNFOU�NPCJMJ[FE �+VOF��t��0QFSBUJPOBM�QFSJPE� UP�EFXBUFS �ESZ �BOE�/

2�QBDL�-JOF� � � +VMZ� UP�

August 2011t��-JOF��HBT�JO�XPSL�DPNQMFUFE �4FQUFNCFS��t��0QFSBUJPOBM�QFSJPE�GPS�'$(5�PO�-JOF�� .BSDI�UP�.BZ��t��0QFSBUJPOBM�QFSJPE� UP�EFXBUFS �ESZ �BOE�/

2�QBDL�-JOF� � � +VMZ� UP�

August 2012t��-JOF��HBT�JO�XPSL�DPNQMFUFE �4FQUFNCFS��t��1SF�DPNNJTTJPOJOH�TJUFT�SFJOTUBUFE �0DUPCFS��

Results

5IF� TVCTFB� IFBET � UIF� IPU� TUBCT � BOE� UIF� QJH� USBDLJOH� TZTUFN�XPSLFE�ýBXMFTTMZ�EVSJOH�UIF�'$(5�PQFSBUJPOT�

All the FCG pigs performed as expected and no damage was ob-served. The water filtration, additive system, and pumping spread operated consistently at or above their specified duty.4VDDFTT�PG� UIF�ýPPEJOH�PQFSBUJPO�XBT�EFNPOTUSBUFE�EVSJOH� UIF�

pressure test where air content was confirmed to be well within the DNV requirement of less than 0.2%.5IF�DMFBOJOH�PQFSBUJPO� SFNPWFE� MFTT� UIBO� ��LH� �� MC�PG�DPO-

struction debris in each section, supporting the belief that almost all the construction debris was removed. Some iron oxide, small amounts of sand, and some red-colored dust were also removed.

The gauging plates confirmed the internal diameter to be within UIF�EFTJHO� SFRVJSFNFOUT��0VU� PG� TJY� TNBSU�HBVHF� SVOT � POMZ� POF�HBWF�B�EBNBHF�JOEJDBUJPO�XIJDI�XBT�QSPWFE�UP�CF�GBMTF�

The pressure test operations were all accepted after only hours PG�QSFTTVSF�TUBCJMJ[BUJPO�QSJPS�UP�UIF�NBOEBUPSZ��IPVS�IPMEJOH�QF-SJPE��5IF�NBJO�SFBTPO�GPS�UIF�RVJDL�BOE�TVDDFTTGVM�QSFTTVSF�UFTU�XBT�the favorable spring weather conditions, whereby the temperatures XFSF�TJNJMBS�BU�UIF�TVSGBDF�BOE�BU�UIF�CPUUPN�PG�UIF�#BMUJD�4FB�

Dewatering and drying

The use of temporary onshore pig traps, together with the tempo-SBSZ��JO��WBMWF �SFTVMUFE�JO�B�WFSZ�TNPPUI�BOE�DPOUSPMMFE�EFXBUFS-

ing operation. This made it easier to control the operation and to LFFQ�XBUFS�BOE�BJS�TFQBSBUFE�EVSJOH�UIF�MBVODIJOH�PG�UIF�USBJO��5IF�USBJO�XBT� MBVODIFE�XJUI�1JH� �� BT� B� iQFSGFDUw�CBSSJFS�CFUXFFO� UIF�desalination water and the air.

The compressor spread and dryers, as well as all support sys-tems, met or exceeded their specified duties throughout the opera-tion. As planned, air injections ceased when the dewatering pig train had traveled 60% of the pipeline length, with the remaining pig travel driven by the expanding air. This was implemented to save fuel and UP�NJOJNJ[F�UIF�EFQSFTTVSJ[BUJPO�SFRVJSFNFOUT�BGUFS�SFDFJQU�PG�UIF�QJH�USBJO�JO�3VTTJB��5ISPVHIPVU�UIF�EFXBUFSJOH�PQFSBUJPO �UIF�QJH�USBDLJOH�WFTTFM�GPM-

MPXFE�UIF�EJGGFSFOU�QJHT�BMM�UIF�XBZ�UP�UIF�3VTTJBO�DPBTU��'JSTU �UIF�UXP�TFUT�PG�TFBMJOH�UPPMT�POF�TFU�GSPN�,1��BOE�POF�TFU�GSPN�,1��BSSJWFE �BOE�UIFO�UIF�EFXBUFSJOH�USBJO��4VDI�BDDVSBUF�QJH�USBDL-ing was necessary when diverting the water in front of each pig to the settling pond.

During the receipt of the pig train, the desalination water was DIFDLFE�GPS�DIMPSJEF�DPOUFOU��5IF�BOBMZTJT�EFNPOTUSBUFE�UIBU�UIF�åOBM�chloride content was well below the specified limit of 200 ppm. The amount of water received in front of the swabbing pigs was very small. #BTFE�PO�FYQFSJFODF�GSPN�1JQFMJOF��WFSZ�MJUUMF�XBUFS �UIF�ýPX�

in front of the swabbing pigs was routed through the silencers for 1JQFMJOF��#BTFE�PO�DBMDVMBUJPOT�BOE�PCTFSWBUJPOT � UIF�BNPVOU�PG�XBUFS� JO�

GSPOU�PG�UIF�TXBCCJOH�QJHT�XBT�MFTT�UIBO��DV�N��HBM��5IJT�JT�BO�impressive result and occurred because of good pigs, internal coat-JOH �BOE�WFSZ�TNPPUI�PQFSBUJPOT�XJUI�POMZ�UIF�VTF�PG�UIF�EJTDIBSHF�control valve toward the end of the operation to maintain maximum ��N�T�WFMPDJUZ��

The desalination pigs showed little wear after traveling the length of the pipeline. The swabbing pigs showed greater wear, but still maintained sealing integrity. That indicates that they had been run-ning mostly dry and confirmed the excellent results. 5IF�ESZJOH�PQFSBUJPO�GPS�1JQFMJOF��XBT�DPNQMFUFE�BGUFS��EBZT �

BOE�JODMVEFE�B�TPBL�QFSJPE�PG��IPVST��"O�BUNPTQIFSJD�XBUFS�EFX-QPJOU�PG�CFUUFS� UIBO� ��¡$��¡'�XBT�BDIJFWFE�BOE�DPOåSNFE�CZ�B��IPVS�TPBL�QFSJPE��#BTFE�PO�UIJT �QJQFMJOF��XBT�ESJFE�UP�CFUUFS�UIBO��¡$�BOE�BDDFQUFE�XJUIPVU�B�TPBL�QFSJPE��%VSJOH� UIF�ESZJOH � ��DV�N� � ��HBM�PG�XBUFS�XBT� SFNPWFE�

DBMDVMBUFE�CBTFE�PO�EFX�QPJOU�SFBEJOHT�BOE�BJS�WPMVNF��5IJT�DPS-SFTQPOET�UP�B�XBUFS�åMN�UIJDLOFTT�PG��NJDSPO�PO�UIF�QJQFMJOF�XBMM �BOE� EFNPOTUSBUFT� UIF� CFTU� EFXBUFSJOH� SFTVMUT� FWFS� BDIJFWFE� SF-HBSEMFTT�PG�QJQFMJOF�TJ[F�BOE� MFOHUI��%SZOFTT�XBT�BMTP�DPOåSNFE�post-commissioning where gas dew point levels were recorded.

Nitrogen

5P�BWPJE�FYQMPTJWF�NJYUVSFT�JO�UIF�QJQFMJOF�BT�TFU�PVU�JO�%/7�04�'��EVSJOH�DPNNJTTJPOJOH�HBT�åMMJOH �UIFSF�XBT�B�OFFE�UP�VTF�an inert gas as a barrier between the air and the natural gas in the QJQFMJOF�� 'PS� WBSJPVT� SFBTPOT � OJUSPHFO� QBDLJOH� EJGGFSFE� CFUXFFO�

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lines 1 and 2:t��-JOF��XBT�DPNQMFUFMZ�åMMFE�XJUI��QVSF�OJUSPHFO�GSPN�(FSNBOZ�t��-JOF� ��XBT�QBSUJBMMZ� åMMFE� GSPN�3VTTJB� HBT� åMMJOH�FOE�VTJOH�B�

��QVSF�OJUSPHFO�CBUDI�FRVBM�UP��PG�UIF�QJQFMJOF�WPMVNF�'PS�CPUI�QJQFMJOFT �UIF�NJYJOH�[POF�CFUXFFO�BJS�BOE�OJUSPHFO�XBT�

BQQSPYJNBUFMZ� ��LN� ��NJ��5IF�NJYJOH� [POF�CFUXFFO�OJUSPHFO�BOE�HBT�XBT�BQQSPYJNBUFMZ��UP��LN��UP��NJ��

*U�XBT�JNQPSUBOU�UP�NBJOUBJO�UIF�JOUFSGBDF�WFMPDJUZ�BCPWF�UIF�DSJUJ-DBM�NJOJNVN�UP�PCUBJO�UIFTF�SFTVMUT�

Water treatment

5SFBUNFOU� PG� UIF� TFB�XBUFS�XBT� DBSSJFE� PVU� POCPBSE� UIF� 4$7�XIFSF� UIF� TFBXBUFS� JOKFDUJPO� QVNQT�XFSF� JOTUBMMFE�� 1SF�DPNNJT-TJPOJOH�XBUFS�XBT�QVNQFE�JOUP�UIF�QJQFMJOFT�BU�,1��BOE�,1��5IF�XBUFS�USFBUNFOU�JODMVEFE�UIF�GPMMPXJOH�TUFQT�

t��'JMUSBUJPO�UISPVHI��N�BOE��N�DBSUSJEHF�åMUFSTt��0OMJOF�JOKFDUJPO�PG�PYZHFO�TDBWFOHFS�04 �B�DPNNFSDJBM�TPMVUJPO�PG�TPEJVN�CJTVMQIJUF�BOE�JSPO�CBTFE�DBUBMZTUt��67�MJHIU�USFBUNFOU�5IF�LFZ�BOBMZUJDBM�QBSBNFUFST�PG�TFBXBUFS�GPS�UIF�DPOUSPM�PG�UIF�

USFBUNFOU� PQFSBUJPOT�XFSF� PCUBJOFE� JO� B� MBCPSBUPSZ� POCPBSE� UIF�4$7�.FUFSFE�BNPVOUT�PG�04�XFSF�EPTFE�BOE�BEKVTUFE�EBJMZ�UP�NBUDI�

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HFOFSBMMZ�BU�TBUVSBUJPO�WBMVFT�PWFS�TBUVSBUJPO�DPODFOUSBUJPOT�XFSF�BMTP�NFBTVSFE�BU�UJNFT �SBOHJOH�CFUXFFO��NH�M�BOE��NH�M�4QFDJBM�BUUFOUJPO�XBT�HJWFO�UP�UIF�QPUFOUJBM�FOWJSPONFOUBM�JNQBDU�

PG�PYZHFO�EFQMFUFE�XBUFS�BU�UIF�EJTDIBSHF�MPDBUJPO��"�TQFDJBM�XBUFS�EJGGVTFS�XBT�EFTJHOFE�BOE�JOTUBMMFE��5IF�QVSQPTF�XBT�UP�BDIJFWF�B�IJHI�SF�PYZHFOBUJPO�FGGFDU�JO�UIF�QSPYJNJUZ�PG�UIF�EJTDIBSHF�QPJOU��5IJT�XBT�B�SFRVJSFNFOU�PG�UIF�XBUFS�EJTDIBSHF�QFSNJU�GSPN�UIF�3VT-TJBO�BVUIPSJUJFT��5IF�FGGFDUJWFOFTT�PG�UIF�EJGGVTFS�XBT�DPOåSNFE�CZ�åFME�NFBTVSFNFOUT�EVSJOH�EFXBUFSJOH��

"�67�USFBUNFOU�VOJU�XBT�BMTP�JOTUBMMFE�POCPBSE�UIF�QSF�DPNNJT-TJPOJOH�WFTTFM��5IF�VOJU�IBE�B�EFTJHO�iLJMMJOH�SBUFw�PG�NPSF�UIBO��PG�UIF� JOJUJBM�CBDUFSJB�DPVOU�BU�FGGFDUJWF�67�EPTBHFT�PG��NK�DN2��#BDUFSJPMPHJDBM�BOBMZTJT�XBT�DBSSJFE�PVU� JO� UIF� MBCPSBUPSZ�PO-CPBSE�UIF�4$7�EVSJOH�UIF�'$(�PQFSBUJPOT�GPS�CPUI�UPUBM�BOBFSPCJD�BOE�UPUBM�BFSPCJD�CBDUFSJB�CFGPSF�BOE�BGUFS�UIF�67�QBDLBHF�5IF�DBMDVMBUFE�iLJMMJOH�SBUFTw�GPS�BOBFSPCJD�CBDUFSJB�XFSF�HFOFS-

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Environmental considerations

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CFGPSF�CFJOH�EJTDIBSHFE�CBDL�UP�TFB��5IJT�XBUFS�XBT�EJWFSUFE�UP�UIF�XBUFS� TFUUMFNFOU�QPOE��8BUFS� TUPSFE� JO� UIF�QPOE�XBT�EJTDIBSHFE�UP�TFB� UISPVHI�åMUFST�BGUFS�B�NJOJNVN��IPVS�TFUUMJOH�QFSJPE��"MM�XBUFS�EJTDIBSHFE�UP�TFB�XBT�DMFBO�BOE�DPOUBJOFE�OP�PYZHFO��5IF�EJTDIBSHF�QPJOU�XBT��N�� GU�PGGTIPSF�BOE�XBT�åUUFE�

XJUI�B�EJGGVTFS�OP[[MF�UP�FOTVSF�SBQJE�PYZHFOBUJPO�PG�UIF�XBUFS�5IF�EJTDIBSHF�XBUFS�XBT�DPOUJOVPVTMZ�NPOJUPSFE�CZ�UIF�FOWJSPO-

NFOUBM�BVUIPSJUJFT�BOE�TIPXFE�DPNQMJBODF�XJUI� MPDBM�BOE� JOUFSOB-UJPOBM� SFHVMBUJPOT� PYZHFO� MFWFMT�XFSF� GPVOE�HSFBUFS� UIBO� �� QQN�XFMM�XJUIJO��N��GU�EJTUBODF�GSPN�UIF�EJGGVTFS�BT�SFRVJSFE�CZ�UIF�SFHVMBUJPOT��

5IF�OPJTF�HFOFSBUFE�JO�(FSNBOZ�XBT�NPOJUPSFE�CZ�B�UIJSE�QBSUZ��5IF� DPNQSFTTPS� TQSFBE� DPNQMJFE� JO� GVMM�XJUI� UIF� TUSJOHFOU�OPJTF�MJNJUBUJPOT�GPS�UIF�QSPKFDU�5IF�TPVOE�QSPPåOH�PG�BMM�JOEJWJEVBM�VOJUT�BMTP�JNQSPWFE�UIF�XPSL-

JOH�FOWJSPONFOU�GPS�UIF�PQFSBUJPOBM�QFSTPOOFM�BOE�JNQSPWFE�TBGFUZ �BT�OPSNBM�WFSCBM�DPNNVOJDBUJPO�XBT�QPTTJCMF�XJUIJO�UIF�BSFB�PG�UIF�DPNQSFTTPS�TQSFBE�

Lessons learned

"�TVNNBSZ�PG� UIF� MFTTPOT� MFBSOFE�EVSJOH� UIF�FYFDVUJPO�PG� UIF�XPSL�VOEFSTDPSFE�UIF�JNQPSUBODF�PG��t��&BSMZ�JEFOUJåDBUJPO�BOE�GPDVT�PO�MPOH�MFBE�JUFNT�t��&BSMZ�FTUBCMJTINFOU�PG�B�QSF�DPNNJTTJPOJOH�DPODFQU�t��&BSMZ�TFMFDUJPO�PG�NBJO�XBUFS�TPVSDF�BOE�XBUFS�USFBUNFOU�SFHJNFt��&BSMZ�TUBSU�PG�FOHJOFFSJOH�BOE�QMBOOJOHt��&BSMZ� JOWPMWFNFOU� JO�QFSNBOFOU�EFTJHO�XPSL� JEFOUJGZ�QSF�DPN-NJTTJPOJOH�SFRVJSFNFOUTt��&BSMZ�FTUBCMJTINFOU�PG�BOZ�BEEJUJPOBM�MPDBM�BVUIPSJUZ�SFRVJSFNFOUT�t��&BSMZ�FTUBCMJTINFOU�PG�QSF�DPNNJTTJPOJOH�FOWJSPONFOUBM�CBTJT�t��&BSMZ�JEFOUJåDBUJPO�PG�SJTLT�BOE�NBJOUBJOJOH�B�GPDVT�PO�UIFN�t��.BJOUBJOJOH�B�SJTL�SFHJTUFS�XJUI�SFHVMBS�SFWJFXT�BOE�VQEBUFT�t��.BJOUBJOJOH�GPDVT�PO�FRVJQNFOU�BOE�GVODUJPO�UFTUTt��$BSFGVMMZ�TFMFDUJOH�LFZ�TVCDPOUSBDUPST�BOE�TVQQMJFSTt��$BSFGVM�BOE�DPNQSFIFOTJWF�GPMMPX�VQ�BOE�DPOUSPM�PG�DSJUJDBM�TVQ-QMJFT�BOE�TVQQMJFSTt��"QQSPWJOH�QSPDFEVSFT�XFMM�JO�BEWBODF�PG�åFME�PQFSBUJPOT��

*O�BEEJUJPO�UP�UIFTF �JU�XBT�GPVOE�UIBU�QJH�USBDLJOH�XBT�WFSZ�VTFGVM�GPS�DPOUSPM�PG�PQFSBUJPO�BOE� GPS�BDDVSBUF� JOGPSNBUJPO� UP�TUBLFIPME-FST��"OE�JO�HFOFSBM �UIF�QSPKFDU�BMTP�VOEFSTDPSFE�UIF�JNQPSUBODF�PG�NBJOUBJOJOH�DPOUJOVJUZ�PG�LFZ�QFSTPOOFM��

Conclusion

(JWFO� UIF� DPOTJEFSBCMF� DIBMMFOHFT � QSF�DPNNJTTJPOJOH� PG� UIF�/PSE� 4USFBN� QJQFMJOFT� XBT� SFNBSLBCMZ� TVDDFTTGVM�� #FTJEFT� CF-JOH�DPODMVEFE�XJUIJO�CVEHFU�BOE�BIFBE�PG�TDIFEVMF � UIF� UFDIOJDBM�BDIJFWFNFOUT�XFSF�JNQSFTTJWF��5IFZ�JODMVEFE�t��8PSME�T�MPOHFTU �TJOHMF�TFDUJPO�EFXBUFSJOH�PQFSBUJPOt��8PSME�T�MPOHFTU�USBWFM�EJTUBODF�GPS�UJF�JO�TFBMJOH�UPPMTt��$PNCJOFE�EFXBUFSJOH�TFBMJOH�UPPM�SFNPWBM�PQFSBUJPO��t��&GGFDUJWF� EFXBUFSJOH� PQFSBUJPO� DPOåSNFE� CZ� UIF� RVJDL�ESZJOH�PQFSBUJPOt��2VJDL�BOE�FGGFDUJWF�QSFTTVSF�UFTU�PQFSBUJPOT�GBWPSBCMF�UFNQFSB-UVSFTt��&GGFDUJWF�XBUFS�QVNQJOH�UISPVHI�UXP��JO��-')�� DV�N�IS�PS�

��N�T�QJH�TQFFE�JO��JO��QJQFMJOFt��&GGFDUJWF�DMFBOJOH�BOE�HBVHJOH�PQFSBUJPOT�t��&GGFDUJWF�QJHT�TQFDJåDBMMZ�EFTJHOFE�GPS�UIF�XPSLt��4VDDFTTGVM� QJH� USBDLJOH� GPS� HPPE� DPOUSPM� BOE� PQFSBUJPOBM� DPOå-EFODFt��&GGFDUJWF�XBUFS�USFBUNFOU�DPODFQU�XJUI�QSBDUJDBMMZ�OP�FGGFDU�PO�UIF�FOWJSPONFOU��5IFTF�SFTVMUT�XFSF�PCUBJOFE�CZ�FYQFSJFODFE�QFSTPOOFM�XPSLJOH�

BT�B�UFBN�BOE�GPDVTJOH�PO�t��&BSMZ�FOHJOFFSJOH�BOE�QMBOOJOH�t��&BSMZ�JOWPMWFNFOU�JO�QJQFMJOF�EFTJHO�SFRVJSFNFOUTt��&BSMZ�GPDVT�PO�MPOH�MFBE�JUFNT�F�H��QJQFMJOF�IFBEt��)JHI�RVBMJUZ�FRVJQNFOU�BOE�FYQFSJFODFE�QFSTPOOFMt��$POUJOVPVT�BUUFOUJPO�UP�TBGFUZ �SJTL �BOE�FOWJSPONFOUt��$PSSFDU�QSPDFEVSFT�QSFQBSFE�FBSMZ�CZ�JOWPMWFE�QFSTPOOFM�t��1SPGFTTJPOBM�PQFSBUJPOBM�FYFDVUJPO �NPOJUPSJOH�BOE�DPOUSPM��

AcknowledgmentBased on a paper presented at the Deep Offshore Technology International Confer-

ence held Nov. 27-29, 2012, in Perth, Australia.

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Robotics improve insulated pipe cutbacksNew system affords greater safety, reliability,

and flexibility in preparing pipe ends

Tor Bredeli

Paul Kleinen

Arno Wainikainen

Bredero Shaw

Coated line pipe entering robot cell (note unfinished end of insulation).

As the search for energy moves further offshore, the demands placed on pipelines and flow assurance systems increase.Pipelines are made of individual pieces of pipe, welded to-gether, and plant-applied insulation is complemented with insulation applied in the field: a field joint.

However, prior to joining pipe together, a “cutback” must be pre-pared to remove insulation from the welding area. After the weld is inspected and accepted, the exposed area must be insulated.

Bredero Shaw has developed and commercialized a robotictechnology for preparing cutbacks safely and reliably, and was re-cently recognized for this accomplishment with a 2013 Spotlighton New Technology Award from the Offshore Technology Confer-ence (OTC).

Offshore pipe preparation

Flow assurance is the term used to describe the technologies used to maintain the flow of oil and gas in a pipeline. Because both oil and gas may contain substances that can solidify at lower temper-atures and obstruct flow, thermal insulation is a key element of most flow assurance systems. To meet the demanding requirements ofoffshore pipelines, thermal insulation is often applied in plants usingmanufacturing processes designed to assure corrosion protection,thermal insulation, bonding of different system elements to each other, and field joints to deliver a fully integrated system capable ofreliable operation in a range of challenging conditions.

As with many engineered systems, overall performance requiresconsistency at the interfaces and, with insulated pipelines, an inter-face is created every time a pipe is welded to another pipe of point of connection. With off-shore pipelines ranging in length from a few kilometers to hundreds of kilometers, therecan easily be over 10,000 interfaces in the pipeline itself. This establishes the require-ments for safe and reliable cutbacks on the ends of an insulated pipe.

Cutbacks are manufactured on each end of insulated pipe with typical diameters of 8 to 24 in. and with up to 120 mm (4.7 in.) of insulation. Typical cutback specifications require a combination of bare steel; a tran-sition area or “toe” of fusion bond epoxy (FBE) at the point where the steel meets the insulation; and a conical chamfer face at an angle of 30°, free of burrs or irregularities.The manufacturing process requires a cut-back cycle time of approximately 20 minutes (depending on pipe diameter and insulation thickness).

In addition, the following requirementsare derived from manufacturing: t��3FMJBCMF��5FDIOPMPHZ�OFFET�UP�TVQQPSU�FY-

tended operations of 24/6t��4BGF��.JOJNJ[F�NBO�NBDIJOF�DPOUBDU��"EBQU�

to multiple geometries while minimizing risk of contact between cut-ting tool and pipet��$BQBCMF��1SPEVDF�DPOTJTUFOU�QSPåMF�HFPNFUSZ�XJUIJO��NN��¡ �

throughput of three to four joints per hourt��'MFYJCMF��$IBNGFS�BOHMF �DVUCBDL�MFOHUI �'#&�UPF �11�UPF �TIFBS�SJOHT �

windows for FJ trialst��3BQJE�DIBOHFPWFST��"CJMJUZ� UP�RVJDLMZ�DIBOHF� GSPN�POF�DVUCBDL�

geometry and type to anothert��$PTU�FGGFDUJWF��$BQJUBM�BOE�PQFSBUJOH�DPTUT�

must be consistent with effective plant eco-nomics.A preliminary technology evaluation identi-

fied significant shortcomings in common ex-isting manufacturing processes such as wirebrushing, scraping, and grinding:t��-BCPS�JOUFOTJWF��0OF�QFSTPO�JT�SFRVJSFE�GPS�

each end of the pipe for each shiftt��-JNJUFE�HFPNFUSZ��0OMZ�TJNQMF�TIBQFT�DBO�

be manufacturedt��4BGFUZ�IB[BSET��*OUFOTJWF�NBO�NBDIJOF�JO-

volvement entails many hazards including hand injury, dust, objects in the eye, and fatiguet��)JHI�DPTU��#SVTIJOH�BOE� TDSBQJOH� TZTUFNT�

have high labor and maintenance costst��-POH�DZDMF�UJNF��#SVTIJOH�BOE�TDSBQJOH�BSF�

inefficient, requiring frequent tool changes

Robotic cutback – milling pass.

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Trusted. Tested. True.For the past ten years, TenarisHydril Blue® connections have proven their worth with capabilities that exceed

the highest industry standards and will continue to do so under the forthcoming revision of the API RP 5C5

Testing Protocol. The Blue® connection is one of a kind, offering 100% fully tested pipe body rated seal,

excellent overtorque capacity and the versatility to perform in all environments. Its reliability and running

efficiency have been proven extensively in the most complex operating conditions around the world.

In sum, an easy choice. Learn more about Blue® connections and performance at www.tenaris.com/blue.

Technology that makes the difference.

TenarisHydril Application Guide Available on the App Store

TRUE BLUE

®

� 70 ISO 13679 CAL IV tests

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� 7 million feet installed with Dopeless® technology

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http://www.tenaris.com/blue







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Search for new technology

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Next steps

5IF�OFYU�TUFQ�JO�UIF�UFDIOPMPHZ�TFMFDUJPO�QSP-DFTT�XBT�UP�JODPSQPSBUF�JOEVTUSJBM�SPCPUJDT�JOUP�B�JOUFHSBUFE�TPMVUJPO� UIBU� JODMVEFE�QJQF�IBOEMJOH�TZTUFNT� GPS� SFDFJWJOH�BOE�NPWJOH� GVMMZ�DPBUFE�BOE�åOJTIFE� MJOF�QJQF��DVUUJOH� UPPMT� GPS� UIF�SP-CPUT�UP�SFNPWF�B�WBSJFUZ�PG�DPBUJOH�UZQFT��QPXFS��TBGFUZ� TZTUFNT�� JOUFHSBUFE� DPOUSPMT�� BOE�XBTUF�DVUUJOHT�NBOBHFNFOU�

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DIBMMFOHF �CFDBVTF� UIF� SPCPUJD�DVUCBDL�TZT-UFN�XBT�UP�CF�VTFE�JO�DPODFSU�XJUI�UIF�#SJH-EFO�NPCJMF�NPEVMBS� DPBUJOH� UFDIOPMPHZ�� *O�PSEFS�UP�NFFU�SFRVJSFNFOUT�GPS�HMPCBM�NPCJM-JUZ� BOE�NPEVMBSJUZ � ��PG� UIF� SPCPUJD� DVU-CBDL�TZTUFN�NVTU�åU�XJUIJO�B�TUBOEBSE� *40�DPOUBJOFS �BOE�UIF�TZTUFN�NVTU�SFTJTU�JNQBDU�MPBET�FYQFSJFODFE�JO�USBOTJU��5IJT�DSFBUFE�UIF�PQQPSUVOJUZ� GPS� JOOPWBUJWF� EFTJHO�� 4FWFSBM�EJGGFSFOU� MBZPVU�PQUJPOT�XFSF�EFWFMPQFE�BOE�BOBMZ[FE�VTJOH�DSJUFSJB�TVDI�BT�TQBDF�VUJMJ[B-

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Component selection

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Current status

3PCPU� DVUCBDL� UFDIOPMPHZ� IBT� OPX� CFFO�VTFE� TVDDFTTGVMMZ� PO� EP[FOT� PG� QSPKFDUT� BOE�IBT�QSPWFO�UP�CF�TBGF�BOE�SFMJBCMF��5IF�PSJHJOBM�JOWFTUNFOU�XBT� KVTUJåFE� PO� UIF� CBTJT� PG� DPO-TFSWBUJWF� JNQSPWFNFOUT� JO� QSPEVDUJWJUZ� BOE�SFEVDFE�NBJOUFOBODF�DPTU �CVU�UIF�CFOFåUT�JO�BSFBT�TVDI�BT� JNQSPWFE� åSTU�UJNF�RVBMJUZ�BOE�UISPVHIQVU�IBWF�QSPWFO�UP�CF�BU�MFBTU�BT�JNQPS-UBOU �JG�OPU�NPSF�TP��"�DBESF�PG�SPCPU�PQFSBUPST�JT�OPX�USBJOFE�BOE�BCMF�UP�TFU�VQ �DBMJCSBUF �UFTU �BOE� PQFSBUF� UIF� SPCPUT�� "� QSFWFOUJWF�NBJOUF-OBODF�QSPHSBN� JT� JO�QMBDF� BOE�CBTJD� USPVCMF-TIPPUJOH�TLJMMT�BSF�CFJOH�CVJMU��0OF�BEEJUJPOBM�FOWJSPONFOUBM� CFOFåU� XBT� BMTP� SFBMJ[FE�� UIF�BCJMJUZ�UP�SFDZDMF�UIF�DVUUJOHT��5IF�EVTU�DPMMFD-UPS�EFQPTJUT�UIF�DIJQT�JO�B�EFCSJT�DPOUBJOFS�BOE�UIFTF�BSF�SFVTFE��

(Right) Completed cutback showing bare steel and

chamfered insulation.

(Below) Robotic cutback system is portable and

rapidly deployed onsite.

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May 2013

www.offshore-mag.com

Houston London Paris Stavanger Aberdeen Singapore Moscow Baku Perth Rio de Janeiro Lagos Luanda

World Trends and Technology for Offshore Oil and Gas Operations

NOIANational OceanIndustries Association

Special Report

Photo courtesy Dockwise

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Offshore drilling requires a strategy, especially in

today’s environment where the wrong move can be

more costly than ever. That’s why the first move should

be to look for a company with worldwide

capability and experience. And that’s Transocean.

Transocean has more experience drilling deepwater

and harsh-environment wells than anyone. We also

have the largest and most diverse fleet in the world,

so we can deliver exactly the service our customers

need when and where they need it. And we operate in

every major oil and gas area, so we can save on

mobilization and demobilization costs worldwide.

Put them all together and you can see why

more and more customers have learned that the

right move is frequently the easiest move. That’s

why they call Transocean.

Transocean: We’re never out of our depth.®

www.deepwater.com

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Offshore development contributes

to American energy renaissanceRandall Luthi

President,National Ocean

Industries Association

Randall Luthi

www.offshore-mag.com�r�May 2013 Offshore 137

As the industry gears up for its big-gest event of the year, operators,contractors, and vendors are lookingforward to the growing developmentopportunities in the offshore market.

This once-a-year event allows the offshoreoil and gas industry to showcase the tech-nological marvels that help make the off-shore industry tick. However, as you wanderthrough the metal miracles, please keep inmind that what you see here represents onlya part of what makes this industry great.

The amazing hardware on display is merely the platform for one of the stron-gest job creating industries in the countryand a bright spot in these uncertaineconomic times. The offshore industry,alongside the entire oil and natural gas in-dustry, continues to innovate, create jobs, generate federal revenue, and ensurenational security.

US oil and gas jobs are at their highest point since 1989, and what was once thought of as a boom has become an energy renaissance. The Bureau of Labor Statistics jobs report shows that oil and gas jobs have increased 6.5% since Febru-ary of 2012, while many segments of our economy were losing jobs. Overall therehas been 23% increase in oil and gas jobs since 2010. These are quality jobs with very competitive wages, and even though most are associated with onshore develop-ment, the offshore world is teetering on the brink of another energy rush that would usher in tens of thousands of new jobs and billions of dollars in revenue.

Why? First, because the resources arethere and ripe for the picking. If the feder-al government would open up new areasin the outer continental shelf (OCS), it is expected that the industry would sustain 1.2 million jobs over the next 30 years and generate $1.3 trillion in additional revenueto the US economy. The key to ensur-ing America’s energy for generations to come must include opening up access to offshore resources.

While many in Washington boast aboutincreased oil production and an “all of the

above” energy policy, the reality isthat 96% of that increased produc-tion has come from the develop-ment of private and state lands.Our current federal policies are do-ing little, if anything, to encourageoil and gas production from federallands. The numbers speak forthemselves – production from fed-eral lands has fallen over the pasttwo years, and offshore produc-tion has dropped over 20% since 2010. Thepolicy climate for offshore developmenthasn’t changed for decades, with 85% of theOCS continually off limits to exploration,let alone development. And to the creditof the current administration, it will staythat way until 2017, unless Congress andcitizens call for immediate change.

All is not lost, and there is hope! Lastyear, the House of Representatives passeda version of what is called the five-year planthat would have opened parts of the EastCoast, the eastern Gulf of Mexico, the Pa-cific, and even more sales off the coast ofAlaska. Hopefully the Senate will rise up tothe challenge and pass similar legislationthis year. Why? Because it makes sensefor our country and our people.

First, from a revenue perspective our country is in desperate need of additional resources. The oil and gas industry is usually the second largest contributor to the US Treasury, and is consistently reli-able. According to the Office of Natural Resources Revenue, the offshore oil and gas industry provided approximately $6.5 billion in revenues in 2011. The onshorecoal, oil and natural gas industry ponied up approximately $4 billion. Of the total revenues, including bonus bids, rents,royalties and other revenues, the offshoreindustry supplied 58.3%, onshore 36.8%, and American Indian lands 4.9%. Thereare higher figures for 2012, onshorecoal, oil and natural gas coming in at approximately $4.4 billion; offshore oil and natural gas at approximately $6.8 billion. The percentages are similar, with onshore providing 36.8%, offshore 57.3%, and American Indian lands up to 5.9%. Opening up the remaining 85% of the OCS would push annual offshore revenues into tens of billions.

Increased production will also lead to increased energy and national security.

The less we import from caustic areas of the world the moresecure we are at home. Increaseddomestic energy places the bargaining chips of foreign policy back in the hands of the US and allows us to not be beholden to irrational demands from abroad.Ten years ago, the thought that we could drill our way to energysecurity was a pipe dream. Today

it is a reality. Just last month, the EnergyInformation Administration projectedthat US monthly crude oil production is expected to exceed imports late this year.In addition, the IEA is forecasting that the US is on track to surpass Saudi Arabia in oil production by 2020.

Ushering in this next era of Americanenergy will require hard work and coor-dination. On the industry side, we needto make sure we continue to explore anddevelop in a safe and environmentally con-scious way. Never has safety been moreparamount and in the forefront of societyas today. Safety is a challenge that we muststrive to achieve with perfection, whileacknowledging there will always be roomfor improvement. We must continue to rec-ognize that it is a privilege to develop theseresources and it is our duty to treat themas the national treasures that they are.

As the offshore industry and the US gets back to work, I implore the federal government to open the offshore spigot and let Americans access the resourcesthey are entitled to. Frivolous attacks on the oil and gas industry through the proposed revocation of tax deductions granted to other industries throughoutthe country does nothing more than hurtthe small, independent companies that are the lifeblood of the offshore industry.There is no such thing as an oil and gas subsidy, but there is such a thing as oil and gas subsidizing the governmentthrough taxes, revenues, and increasedeconomic prosperity. Mr. President, I ask that you let us help you help us. Let the offshore oil and gas industry have access to the 85% of the OCS that has been closed for nearly a generation. And I promise we will help you, Mr. President,usher this country into an era of American prosperity and security unlike anything we have seen. �

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Opening new offshore areas will create new jobs,

produce more energy, and enhance federal revenue

Dick Alario

Last month in Washington DC, I happily accepted the chairmanshipof the National Ocean Industries Association (NOIA), of which I have been a proud member for

many years. NOIA is a unique and effec-tive member-driven association which advocates on behalf of the entire offshoreenergy industry. The NOIA membership consists of all segments of the industry,including companies engaged in business activities ranging from producing to drill-ing, engineering to marine and air trans-port, offshore construction to equipment manufacture and supply, telecommunica-tions to finance and insurance, and even renewable energy. Since NOIA focuses solely on the offshore energy industry, it is no surprise that the overarching issue driving the association’s work is offshoreaccess, or more to the point, the lack thereof.

NOIA was established four decadesago, and congressional and administrativebans kept our industry from exploringabout 85% of the outer continental shelf(OCS) for nearly three of those decades.Those bans were lifted in 2008, and theirabsence finally laid our nation’s entire OCSon the table for oil and gas exploration andpossible development, and handed the Sec-retary of the Interior a golden opportunityto include more offshore areas in the 2012-2017 OCS Oil and Gas Leasing Plan.

Instead, the Obama Administration approved a plan that continues to lock up approximately 85% of the OCS to oil and natural gas exploration through at least 2017. Under the plan, industry is forced to continue to explore the same areas it has for the last three decades – in just 15% of the OCS.

Resource estimates for these areasare decades-old, due to the previouslymentioned exploration bans. So while we know oil and natural gas is out there, we don’t really know how much, and based on history in the Gulf of Mexico, chances are we will find a lot more than we think.

In the 1980s, scientists working both for private industry and the governmentsignificantly underestimated the resourc-es available in the Gulf. In fact, thanks to industry-driven technological advances, we’ve since produced at least six times more oil from the Gulf than was estimated

to exist back in the 1980s. And thanks to advancements in seis-mic and exploration technology,huge discoveries continue to be made in the Gulf. There may be similarly tremendous possibili-ties for the 85% of the OCS not included in the administration’s new offshore leasing plan, but we won’t know unless allowed the chance to look.

President Obama likes to promote his“all of the above” energy strategy and theneed for science-based decisions withregard to energy and environmental policy.It is wise to incorporate the latest scienceand technology to pursue every energy op-tion we have, and that includes exploringthe Atlantic OCS. Thus, the Department ofthe Interior is preparing an Atlantic seismicenvironmental impact statement (EIS) toinform how best to proceed with a safe andenvironmentally protective assessment ofthe oil and natural gas resources beneathfederal waters in the Atlantic.

The Atlantic seismic EIS will open thedoor to the collection of information that willallow us the opportunity to decide whetherand where it may or may not be appropri-ate to explore for and extract oil and gas inthe Atlantic. The DOI said the EIS wouldbe completed by April 2012, but we arenow an entire year past that date, and theenvironmental impact statement has yet tobe completed. In an effort to speed thingsup, a bipartisan contingent of US Housemembers recently sent a letter to PresidentObama pleading for the EIS’s swift comple-tion.

The potential benefits of explorationand possible production of offshore oil andgas resources in the Atlantic are huge. Ontop of increased domestic energy security,there is enormous potential for increasedeconomic activity, increased revenue forgovernment, and increased jobs. Accord-ing to a recent report from the Institutefor Energy Research, opening the Atlantic

OCS to oil and gas activity could increaseUS economic output by nearly $8 billionper year from 2013-2021 and $33 billioneach year thereafter. That not only meansmuch needed revenue being pumped intoour economy to pay down debt but nearly40,000 jobs created each year for the first

eight years and over 160,000 jobscreated each year thereafter. Thatis over 1.44 million new jobs.

But we won’t realize these benefits unless actual physical exploration and development occur. And that process can only take place if there are actual lease sales in the mid and south Atlantic or eastern Gulf of Mex-ico. This brings us back once

again to the current offshore leasing plan, which restricts oil and gas exploration to a mere 15% of the OCS through 2017.

The need for oil and natural gas as a sustainable, reliable, and cost-effectivesource of energy is not going away any-time soon. Current projections of energyuse for the next generation indicate that even with a much greater emphasis on nontraditional forms of energy such as wind, oil and natural gas will still be a major energy source and will be needed to supply the energy market and jobs. Nontraditional sources will only supply about 15% of our energy in 2035. The Energy Information Administration predicts that traditional energy will supply approximately 85% of our energy needs in 2035, with 58% of that being oil and natural gas. Nontraditional fuels cannot meet the energy demand for the foresee-able future, although they are a welcome supplement.

Clearly, offshore oil and natural gas area vital part of an “all of the above” energystrategy. NOIA believes that this strategyshould apply to more than the limited areaswhere exploration is currently allowed. Wewill continue to advocate for greater accessto the 85% of the OCS that remains closedunder the current offshore leasing planand where the lack of modern seismic dataleaves us guessing as to its true resourcepotential. Opening new offshore areas willopen the door to new jobs, energy, andeven more revenue to the federal treasurywhich could be used to help reduce thegrowing federal deficit. �

Dick Alario

Chairman, President and CEO, Key Energy Services

Chairman, National Ocean Industries Association (NOIA)

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CONNECT withPENNWELL’S OFFSHORE EVENTS!

PennWell’s Offshore Events cover key issues, trends and technologies relative to offshore oil and gas E&P operations. Covering

every aspect of the offshore industry including topsides, platforms and hulls, subsea tiebacks, deepwater production, operations and

exploration and technologies. With events all over the world, PennWell’s Offshore events bring together global attendees representing

operators, contractors and equipment manufacturers from key regions in the industry.

Owned & Produced By: Presented By:

Connect now at www.offshoreoilevents.com!

NOIA represents all phases

of offshore energy

The National Ocean Industries Association (NOIA) is theonly national trade association representing every segmentof the offshore energy exploration and production industry.

Comprising more than 275 companies, NOIA repre-sents offshore drillers, producers, supply vessels, air

transport, geophysical survey, shipyards, offshore construction,wind power, equipment manufacture and supply, telecommuni-cations, financiers, insurers, and much more.

NOIA focuses on two core issues:1. Securing reliable access to the nation’s valuable offshore

energy resources in order that they may be developed, produced, and supplied in an environmentally responsiblemanner

2. Improving the economic climate for NOIA members to conduct business in the United States.

About NOIA

In 1972, industry leaders joined to form the National Ocean Industries Association – a unique organization interested in ex-panding the federal offshore leasing program by promoting the safe and efficient development of outer continental shelf (OCS)lands. NOIA’s advocacy relies on the guidance of the entirespectrum of the offshore energy and related industries.

Today, more than 250 companies have united in support of

reliable access to offshore energy resources, forming a powerfulcoalition that achieves positive results in Washington, D.C.

Tradition of service

NOIA’s staff wields the combined clout of every one of themember companies as it advocates before Congress and the ex-ecutive branch, and influences industry-related policy decisions.

NOIA:t��'BDJMJUBUFT�NFNCFS�BDDFTT�UP�SFHVMBUPSZ�BOE�MFHJTMBUJWF�

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dialogue on energy issues, showcasing the industry’s tech-nological pioneering and environmental performancet��)PTUT�UIF�UXP�MBSHFTU�BOOVBM�HBUIFSJOHT�PG�TFOJPS�FYFDV-

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the public about energy issues and help the nation makeinformed decisions concerning the use of energy, such as the/BUJPOBM�&OFSHZ�&EVDBUJPO�%FWFMPQNFOU�/&&%�1SPKFDU��

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A leader in offshore topsides design.

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NOIA Officers, Board of Directorsand Executive Committee*

*Chairman

Dick Alario

Chairman, President, CEO

Key Energy Services

*Vice Chairman

President & CEO

John Rynd

Hercules Offshore

Mitch Ackal

Vice President Business Development

LLOG Exploration Offshore

*Burt A. Adams

President

LLC OGRS, LLC

W. A. “Cappy” Bisso

Chairman

Bisso Marine Company

Doss Bourgeois

Executive Vice President E&P

Plains Exploration Company

Stuart M. Brightman

President & CEO

TETRA Technologies

Scott Cameron

VP Deepwater Exploration & Appraisal

Shell Energy Resources Company

Richard Clark

President

Deep Gulf Energy LP

*William E. Chiles

President & CEO

Bristow, Inc.

Galen Cobb

Vice President Industry Affairs

Halliburton

*Brady L. Como

Executive Vice President

Delmar Systems, Inc.

*Pamela T. Darwin

Vice President Geoscience

ExxonMobil Production Company

*Carl A. Davis

Consultant

Forum Energy Technologies

Robert Drummond

President, North America

Schlumberger

Robb Erickson

Vice President Sales

Dockwise USA LLC

*Bruce Gresham

President, North America

Heerema Marine Contractors U.S. Inc.

Lynne L. Hackedorn

Vice President Government & Public

Affairs

Cobalt International Energy Inc.

*Quinn Hebert


Cal Dive International, Inc.

Robert Hobbs

Chief Executive Officer

TGS-NOPEC Geophysical Company

*Darrell Hollek

Vice President GOM Operations

Anadarko Petroleum Corporation

Todd M. Hornbeck


Hornbeck Offshore Services, LLC

Paul L. Howes

President & CEO

Newpark Resources, Inc.

Kenneth Lang

President & COO

Ridgewood Energy Corporation

Richard Lunam

Vice President

North America Exploration

ConocoPhillips

*Kevin McEvoy

President & CEO

Oceaneering International

David Moles

Vice President Special Projects

Eni US Operating Co. Inc.

*Jack B. Moore


Cameron

Richard Morrison

Regional President, Gulf of Mexico

BP

William C. New

President

New Industries

Jason Nye

Senior Vice President,

DPNA US Offshore

Statoil

Jeff Platt

President & CEO

Tidewater Inc.

Daniel W. Rabun


Ensco plc

W. Matt Ralls

President & CEO

Rowan Companies

Courtney B. Ramsay

President & CEO

Aries Marine Corporation

Larry Rigdon

Director

Terresolve Technologies Ltd.

Steven W. Roll

Vice President & General Manager

McDermott International

Robert J. Saltiel

President & CEO

Atwood Oceanics, Inc.

John Schiller

Chairman & CEO

Energy XXI

Nicholas L. Swyka

Advisory Director

Simmons & Company International

*Cindy Taylor

President & CEO

Oil States International

*Jamie Vazquez

President

W&T Offshore, Inc.

*David H. Welch


Stone Energy Corporation

Erik Wiik

President

Aker Solutions

Richard L. Williams

President, US Region

Baker Hughes

Richard J. Williams

Senior Vice President

Fugro Chance

Warner Williams

Vice President GOM SBU

Chevron Corporation GOM Operations

Robert Workman

Group President, Distributions,

Transmissions

National-Oilwell Varco

*Executive Committee

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For information about joining NOIA, visit www.noia.orgor email [email protected]

For more than 40 years, the National Ocean Industries

Association has helped the offshore energy industry

navigate the channels of Washington, D.C. Policy decisions

in Washington can chart our path to greater energy

security or steer us in the opposite direction. As our

economy struggles to thrive, NOIA remains a powerful

industry advocate and our member companies stand

ready to supply the energy and innovative spirit that

powers America and provides American jobs.

AMERICA’S OFFSHORE ENERGY INDUSTRY

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NOIA MembershipActeon Group

Adams & Reese LLPAker Solutions

Alaska Oil & Gas Association (AOGA)Amegy Bank N.A.

American Fire and Safety LLC American Petroleum Institute

American Pollution Control CorporationAmeriforge Group

Anadarko Petroleum CorporationANKOR Energy LLCApache CorporationAqueos CorporationArena Energy, L.P.Arena Offshore, LP

Aries Marine CorporationAssociation Of Diving Contractors International, Inc.

ATP Oil & Gas CorporationAtwood Oceanics, Inc.

BAE Systems, Inc.Baker Hughes Incorporated

Baker Hughes U.S. Land RegionBaker Hughes US Land Pumping Region

Baker Hughes Gulf of Mexico Region Baker Hughes Global Products & Services

Baker Hughes Drilling & Evaluation Baker Hughes Completions & Production

Baker Hughes Industrial PortfolioBaker Hughes Pressure Pumping Product Line

Bee Mar LLCBeveridge & Diamond, P.C.

BHP Billiton PetroleumBisso Marine Company, Inc.

Black Elk EnergyBlake International USA Rigs

Bollinger Shipyards, Inc.George Boyadjieff

BPBracewell & Giuliani LLPBreaud & Meyers, APLC

Bristow Group, Inc.Bristow U.S., LLCBroadpoint, LLC

Brownstein Hyatt Farber Shreck LLPCal Dive International, Inc.Callon Petroleum Company

CameronCameron Subsea Systems

Cameron Valves & Measurement GroupCameron Process & Compression Systems

Cameron Drilling SystemsCameron Surface Systems

Canal Barge CompanyCandy Fleet Corporation LLC

Otto Candies LLCCape Wind LLC

Celerant Consulting Inc.Cenergy International Services LLC

Center for Offshore SafetyCentury Exploration New Orleans, LLC

CHC HelicopterChalmers, Collins & Alwell, Inc.

Chevron USA Inc. *Chevron North America E&PChickasaw Distributors Inc.

Cobalt International Energy, LPCompressco

ConocoPhillips

Contango Oil & Gas CorporationContinental Shelf Associates Inc.

CSA International Inc.CORE Laboratories Credit Suisse, LLC

The Cross Group Incorporated Crowley Maritime Corporation

Crowley SolutionsDahlman Rose & Company LLC

DanosDawn Services, LLC

Deep Gulf Energy, LPDeepwater Wind

Delmar Systems, Inc.Deltide Energy Services LLC

Deltide Fishing and Rental Tools, Inc.Diamond Offshore Drilling, Inc.

Dockwise U.S.A. Inc.Dorado DeepDril-Quip, Inc.

Dupré Energy Services, LLCEdison Chouest Offshore

Ellsworth CorporationEMAS-AMC, Inc.

The Energy CouncilEnergy XXI

Eni Petroleum Co. Inc.ENSCO plc

Expert E & P Consultants, LLCExpert Oil & Gas, LLC

Expert Riser Solutions LLCExxonMobil Exploration Company

ExxonMobil CorporationExxonMobil Production Company

FairfieldNodalFMC Technologies

Forum Energy TechnologiesFoster Marketing

Fowler Rodriguez Valdes-FauliFugro (USA) Inc.

Fugro Chance Inc.Fugro Geoservices Inc.

Fugro Global Environmental and Ocean Sciences, Inc.Fugro-McClelland Marine Geosciences Inc.

Fulbright & JaworskiGalloway, Johnson, Tompkins, Burr & Smith, PLC

GE Oil & GasGE TransportationGH Services, LLC

Global Energy Capital, LPGlobal Hunter Securities

Gulf Economic Survival Team (GEST)Gulf Island Fabrication Inc.

Gulf Marine FabricatorsGulfmark Offshore

Gulf Publishing CompanyHalliburton

Hall Houston Oil CompanyHarris Caprock Communications

Hart Energy Publishing LPHarvey Gulf International Marine

Heerema Marine Contractors U.S., Inc.Hercules Offshore, Inc.

Hess CorporationHoover Container Solutions, Inc.Hornbeck Offshore Services, Inc.

Houston Energy, LPHoward Weil Incorporated

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www.offshore-mag.com�r�May 2013 Offshore 145

Hunting PLCIberia Bank/Iberia Capital Partners

Imperial CapitalIndependent Petroleum Association of America (IPAA)

Intermoor, Inc.International Association of Drilling Contractors (IADC)

International Association of Geophysical Contractors (IAGC)International Marine Contractors Association (IMCA)International Petroleum Museum and Exposition, Inc.

Jackson Offshore OperatorsJDR Cable Systems (Holdings) Ltd.Raymond James & Associates, Inc.

Key Energy ServicesKiewit Offshore Services, Ltd.

Kiewit Energy CompanyKilgore Marine

Laborde Marine Management, LLCLanding String Solutions, LLC

Landry Harris & Co. LLCLEED Petroleum LLCLime Rock Partners

Litton Consulting GroupLLOG Offshore Exploration, LLCLocke Lord Bissell & Liddell LLP

Lockton Marine & SafetyLogica North America Inc.

Louisiana Mid-Continent Oil and Gas AssociationLouisiana Oil & Gas Association (LOGA)

MAERSK Oil Houston, Inc.MAN Diesel & Turbo NAMarathon Oil Company

Marine Spill Response Corporation (MSRC)Maritech ResourcesMarlin Energy, LLC

McDermott InternationalMcGriff, Seibels & Williams of Texas, Inc.

McMoRan Oil & Gas LLCMontco Offshore, Inc.Morgan City Rentals

MTN Satellite CommunicationsMurphy Oil Company

Murphy Exploration & Production CompanyMustang Engineering, LP

National Oilwell VarcoNatural Gas Partners

NautronixNecesSea LLCNew Industries

Newfield Exploration CompanyNewpark Drilling Fluids LLC

Newpark Environmental Services LLCNewpark Resources, Inc.

New Tech Global VenturesNexen Petroleum U.S.A., Inc.

Noble CorporationNoble Energy, Inc.

Oceaneering International, Inc.OceanGate, Inc.

Ocean Specialists Inc.Oceanweather, Inc.

Offshore Energy Services, Inc.Offshore Engineer

Offshore Magazine, PennWell Publishing CompanyOffshore Marine Service Association (OMSA)

Offshore Operators CommitteeOGRS, LLC

Oil States InternationalPacific Drilling, S.A.

Panther EnergyParagon Integrity Solutions

PPHBPason Offshore

Pason Systems Corp.Patton Boggs

Perkins Coie LLPPetroleum Equipment Suppliers Association (PESA)

Petro-Hunt LLCPETSEC Energy Inc.

Pharma-Safe Industrial Services Inc.Phelps Dunbar LLP

PHI Inc.Pillsbury Winthrop Shaw Pittman LLP

Pisces Energy LLCPlains Exploration & Production Company

Prosep Inc.QTEC Environmental Services Inc.

Rattler Tools, Inc.Red Willow Production

Ridgewood Energy CorporationRowan Companies, Inc.

SBM OffshoreSCF PartnersSchlumberger

SEACOR Holdings Inc.Sea Technology Magazine (Compass Publications, Inc.)

William A. SearsChris Seaver

SEMPCheck Services, Inc.Serimax North America, LLC

Shell Exploration & Production CompanyShell Energy Resources Company

Shell Oil CompanySimmons & Company InternationalSmith, a Schlumberger Company

Sonardyne Inc.Southern Ute Indian Tribe Growth Fund

StatoilSteptoe & Johnson LLP

Stone Energy CorporationStress Engineering Services, Inc.

Subsea 7Carroll W. Suggs

Superior Energy Services, Inc.Sutherland

Swire Oilfield Services, LLCTaylor Energy Company

Technip USA Inc.Telos Resources LLC

Terresolve Technologies LtdTETRA Technologies, Inc.Texas Institute of Science

TGS-NOPEC Geophysical CompanyTidewater Inc.

Tidewater Marine LLCTransocean Management Ltd.United Vision Logistics, LLC Upstream Engineering, LLC

US Oil & Gas AssociationVallourec & Mannesmann USA Corporation

V & M StarVAM Drilling

VAM Tube AlloyVAM USA

Venari ResourcesVersabar Inc.

Vinson & ElkinsW & T Offshore

Walter Oil & Gas CorporationRobert E. Warren

Wells Fargo Energy GroupWells Fargo HSBC Tradebank, N.A.

Westney Consulting Group, Inc.Woodside Energy (USA) Inc.

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OCTOBER 22-24, 2013 | THE WOODLANDS WATERWAY MARRIOTT HOTEL & CONVENTION CENTER | HOUSTON, TX USA

www.deepoffshoretechnology.com

OWNED & OPERATED BY: PRESENTED BY: HOSTED BY:SUPPORTED BY:

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OTC 2013Houston, 6-9 May 2013

www.gep-aftp.com

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Organized by GEP-AFTP

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F R A N C E

GEP-AFTP helping French suppliers

to penetrate emerging offshore sectorsCouncil completes restructuring,

raises international profile

Gérard Momplot

France’s leading oil and gas contrac-tors and suppliers are present in most of the world’s offshore arenas. Lower down the scale, the country’s niche technology specialists are winning

work offshore in varying degrees, but need more help to break into emerging markets. Offshore talked to General Manager Gérard Momplot of French suppliers council GEP-AFTP to find out how the association is re-sponding to its members’ demands.

Offshore: Is the process of restructuring GEP-AFTP completed? Are the merged as-sociation’s image and capabilities now fully recognized, both in France and by the oil and gas industry worldwide?Momplot: In terms of restructuring, yes:

all the tasks and missions have been reas-signed since the merger in mid-2011. In France, I think that the positioning is now clearer than it was two years ago. As for international exposure, GEP was better known than AFTP. What is important now is that our association combines both profes-sionals and companies, i.e. high technical expertise and business, and is therefore po-sitioned as such. It remains, however, that our full name, GEP-AFTP, is an awful one to pronounce and understand abroad.

Offshore: Are the various committees that the previous individual entities operated still in place, or have new ones been established, in particular to respond to emerging tech-nologies?Momplot: At present we have nine such

committees acting as think tanks. Quite a few are completely new and some of the pre-vious ones have been regenerated. Among the new ones, one is devoted in particular to oil and gas shales, while another to come shortly will deal with energy efficiency. Four new committees to be set up are still in the process of recruiting more volunteers.

Offshore: What would you say are the main achievements of the merged group in the two years since the union was an-

nounced, and what are its long-term goals?Momplot: Simplification and

better coordination of initiatives have been achieved. I must re-call that GEP and AFTP were already acting together before merging. Our members have the feeling that GEP-AFTP is stronger and more visible. In a nutshell, long-term goals are twofold. The first one is to mo-bilize more young professionals among our company members and convince more students to join the oil and gas industry. The second one is to maintain and reinforce the link between big companies and small and medium companies both on an innova-tion level and on international markets.

Offshore: Is GEP-AFTP succeeding in at-tracting new member companies and petro-leum individuals in the same numbers as in the past? Can you say how many have joined, and what the new companies perceive as the main benefit of being part of the association?Momplot: Since 2009, when I joined GEP,

the recruitment of companies has increased from 160 to 220. I do think that the merger has definitely accelerated recruitment. The impact of the network not only in France but also abroad is certainly one of the main driv-ers for a company to join.

Offshore: Has the group staged or devised any interesting new offshore technology presentations, both to members in France and to associations in other countries? And if so, what has been the general response? Momplot: The CITEPH initiative has

granted more than 140 projects over the last six years. Of those, 64 deal with off-shore technologies and 54 are already com-pleted. The results have been presented to members and some others presented by the companies themselves in conferences such as Deep Offshore Technology, OTC, or MCEDD. In the meantime, GEP-AFTP

had the opportunity to present the program and its outcomes to several European and central Asian countries. A very posi-tive feedback was reported and there is a demand for advice to implement such a program in those countries.

Offshore: What would you say are the most pressing issues facing your members, and what is GEP-AFTP doing to help them? In what areas in particu-lar are smaller French suppliers struggling to make an impact?

Momplot: Local content, either regulated or not, is certainly one of the major issues our members are facing. At GEP-AFTP we have recently set up a working group dedi-cated to this matter. It provides a neutral arena to discuss and exchange about best practices and optimizations to improve ef-ficiency. Small-sized French suppliers have no access to a national oil or gas market off-shore in particular, compared for instance to the US, the UK, or Norway. So they have no choice but to export or prospect vigorously outside France. Recruitment is also an issue, since our members are generally less finan-cially attractive. Needless to say, the French suppliers are facing a shortage of qualified manpower.

Offshore: Please can you provide an over-view of some of GEP-AFTP’s initiatives to promote development of offshore technolo-gies, both among their members, and in emerging offshore sectors worldwide?Momplot: Two main initiatives are worth

mentioning, the CITEPH program and the CLAROM committee. The first is a unique opportunity for applicant subject matter experts to obtain funding and carry out projects corresponding to large companies’ needs. CITEPH, run by Phil Perreau, is now pretty well known by a great number of com-panies even beyond the oil and gas services industry in France. CLAROM, comprising

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Since 1965, the name “DORIS”has been attached to the mostchallenging offshore projects,under the harshest environmentalconditions.

Worldwide Network of Partners Design Engineering to Turnkey Contracts Offshore and Onshore Oil & Gas Fields

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DIFFERENCE

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F R A N C E

25 companies, is entirely devoted to offshorewith five dedicated working groups dealing with subsea, flow assurance, geotechnics, robotics, and offshore structures design.

Offshore: Can you provide an update onthe work of GEP-APAC in Singapore, andhow this is helping French companies bid forprojects in the Asia/Pacific region? Are thereplans to set up a similar operation elsewhere?Momplot: GEP-APAC started its operations

just a year ago. So far nearly 20 companieshave joined the Singaporean association head-ed by Ben Dupal. The network is expandinggradually in the area. Many agreements withpeer organizations help GEP-APAC membersto meet local companies and facilitate accessto local tenders and joint ventures. Missionsare also organized and customized for themembers. The latest was in Myanmar. For thetime being we want to learn from our Singa-pore initiative before launching new offices inBrazil or central Asia, for example.

Offshore: What progress is GEP-AFTP making on fostering technology cooperation between French suppliers and contractors and their counterparts elsewhere – do the trade missions overseas continue?

Momplot: Trade missions as far as GEP-AFTP is concerned are preferably staged ona technical and consistent basis. Better thanvisiting a customer with a heterogeneouscatalog of products or services, GEP-AFTPfocuses on a set of companies which canprovide the correct answer to specific needsidentified in advance. The international com-petition is so fierce that we absolutely need

to differentiate that way. The preparation withour members is of the utmost importanceotherwise money and time are spent for nuts.Not all countries are addressed but only alimited number are prioritized, generallymore or less emerging oil and gas countries.

Offshore: How are French suppliers re-

sponding to the unprecedented activity in new offshore oil and gas projects worldwide, would you say, compared with other compet-ing nations?Momplot: The answer is quite different

for big companies and SMEs but all areeager to position themselves for those proj-ects. As I mentioned before, they have no domestic market to test and confirm new

technologies, so they must grow locally,as for instance Technip has done in Brazil. Smaller companies are much more focused on niche markets and need to take on mul-tiple clients and work in more countries to grow. Both large and small companies need to provide first-class services if they want to compete with oil-rich countries’ suppliers. �

Both large and small companies

need to provide first-class

services if they want to compete

with oil-rich countries’ suppliers.

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http://www.doris-engineering.com





More3than33503qualified3inspectors3worldwide3working3on3Oil3&3Gas3Projects

Main3offices3in3France,3Italy3and3China

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Piping

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F R A N C E

Sodexo helping installation owners

improve quality of life offshore

Extended drilling operations in harsh or remote offshore regions are placing in-creasing demands on drill crews. The same applies to staff on seismic acqui-sition vessels operating for long peri-

ods in frontier areas, and to platform person-nel based in cold or humid environments.

“Quality of Life Services” specialist So-dexo, founded by Pierre Bellon in Marseille in 1966, has been attending to the offshoresector’s needs for more than 40 years, adapt-ing its services to reflect changing priori-ties. For sought-after younger offshore en-gineers and technicians in particular, this can mean creating a more comfortable and stimulating offshore workplace, leading to improved productivity. The overall goal is to relieve installation owners of day-to-day staff demands, leaving them freer to focus on technical performance and safety.

Sodexo’s wide-ranging services offshore Offshore accommodations unit.

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http://www.ats-inspection.com





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Saft batteries,built to lastYou use increasingly sophisticated technology in

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ensure the highest levels of efficiency, reliability and

safety. Saft can help. Only Saft has Li-ion batteries

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Saft’s unparalleled experience to power your MWD,

LWD, PIG and other high-temperature oil and gas tools.

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F R A N C E

include accommodation design and refurbish-ment, electrical engineering and plumbing,supervising crew changes and helicopter land-ings, food services, housekeeping, laundry,waste management, and personalized physicalfitness/motivation programs. Currently, thecompany is active on 500 offshore sites in 35countries, according to Sodexo Western Re-gion COO Simon Seaton, based in Houston.

“Offshore there are three global players with a presence to some degree in everymarket, often competing in regions with lo-cal service providers that are more onshore-focused. There are also niche offshore com-petitors in fields such as food services. But on a global basis, we are the market leader.There is tremendous growth for our type of services everywhere.

“Our clients fall into two main groups.Drilling contractors, such as Rowan, Seadrill and Transocean, account for two-thirds of our offshore business. The others are large-ly oil and gas operators, with many large,fixed facilities in the North Sea, where Talis-man, BP, and ConocoPhillips are big clients for us. Within that mix, some of the facilities are managed by duty holders and we workwith them on their behalf.”

Some of the arrangements are master ser-vice agreements involving provision of sup-

port services on a call-out basis. More typi-cally, Sodexo works under one- to three-yearcontracts (or longer) with extension options. “Mostly clients contract us on a regional ba-sis, i.e. in the North Sea, Gulf of Mexico, or the Middle East only, although some such as Seadrill engage us under a global frame agreement.” In this case, Sodexo’s Global Offshore and Marine Center of Excellence oversees all catering, cleaning, and janitorial services on Seadrill’s worldwide rig fleet.

Offshore India, the company ensuresfood supplies to 12 Transocean rigs working on shallow water and long-term deepwater programs, necessitating a constant threemonths stock of food onboard. “I under-

stand the difficulties of remote sites logis-tics, having worked 22 years myself for a tra-ditional oilfield services company,” Seaton said. “But because Sodexo deals with food, it’s even more complex considering the ad-ditional challenges of hygiene, temperature,and food safety.” Additionally, Sodexo as-sists Transocean with implementing safety regimes offshore, monitoring key perfor-mance indicators, and providing training for accident reporting procedures.

“Another of our goals is to be engaged as early as possible in the design of the client’s newbuild facilities, in order to create the right atmosphere to ensure that their crewsget the rest, privacy, and nutrition they

An example of a Sodexo installation.

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http://www.saftbatteries.com






F R A N C E

need. We follow rig newbuilding programs,for example, and try to get involved in the construction process at the yards in the Far East. Often these projects are driven by technical specifications, with less thought given to the accommodation areas.

“We also refurbish existing offshore instal-lations. In the North Sea, some platforms de-signed for a shelf life of 10-15 years have re-mained in service for 40 years. But the livingquarters are not always what a modern work-force expects. We can assist with re-design,which we have done, for example, on Talis-man’s Montrose platform in the UK sector,and on Marathon Oil’s East Brae complex.”

In the Gulf of Mexico, Sodexo operateson 45 offshore sites, and claims to be theregion’s largest provider of offshore foodservices, with a local distribution centerthat spans from Brownsville, Texas, to PortFouchon, Louisiana. Offshore installationsinclude deepwater platforms on the Auger,Magnolia, and Thunder Horse fields and nu-merous drilling rigs. “In this region we focusspecifically on how to help offshore crewscope with the physical demands of heat andhumidity. We are looking to introduce a newservice this summer to educate and monitorthe workforce in this regard, ensuring theyhave access not just to fluids, but the right typeof fluids to combat under-hydration. We havedone surveys on this subject in the North Seaas well.

“We also have a business continuity planand the value we bring to our clients when astorm passes is that we are ready to resumework quickly to minimize business disruption,thanks in part to the fact that our distributioncenter has an independent power source.”

As for future trends, “we see nothing but expansion in the short term,” Seaton said, “with the global offshore rig fleet likely to in-crease by 150-170, and growing investment in the US and the mature UK industry. The UK alone needs another 50,000 workers, so attraction and retention of staff is a big issue. But throwing money at them won’t solve the problem – people coming into the industrynow are younger, and may have differentexpectations about connectivity, comfort,and healthy eating. So clients are working increasingly on how to build quality of life offshore to attract and retain new talent.”

One Sodexo solutions is Well Track, a three-pronged approach that includes indi-vidually tailored fitness programs, motiva-tion incentives, and virtual concierge ser-vices.

“Related to this is safety. If you look at the offshore industry’s safety record, the trendfor incidents was steadily downwards fromthe mid-1990s to the late-2000s, but therehas been a plateau over the last four to five years. Accidents still occur offshore, and

there is a growing belief that ‘human fac-tors’ are to blame, with people taking risks by choosing not to follow procedures. That can be because staff are demotivated or un-der pressure, so how can we help people im-prove productivity?

“What Shell did onshore in Qatar was to invest in a global ‘village’ camp managed by Sodexo at the Pearl GTL plant, making it a nice place for people to stay. That sense of wellbeing led to higher productivity, better

HSE, and lower attrition of staff. “Another trend we have noted is the wide

range of sub-contractors our clients are deal-ing with. One told us 50% of his spend was with seven core contractors, 30% with 50 contractors, and 20% with over 1,000 sup-pliers. Sodexo helps clients manage these non-core suppliers, including when their staff come offshore – for instance, to fix a photocopier – ensuring continuity and qual-ity of life.” �

CONSTRUCTION

MAINTENANCE

TURNAROUND

REVAMPING / HOOK-UP

HEAD OFFICE

1 rue Lilienthal - Emerainville - BP 7977312 Marne-la-Vallée Cedex 2 FRANCETEL. : +33 (0) 1 64 11 11 64FAX : +33 (0) 1 64 11 11 [email protected] - www.ponticelli.com

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F R A N C E

(Above) Structural steel prefabrication at Ponticelli Nigeria’s Silhouette

yard. (Below) Total Ofon II project/OFP1 platform, early stage of offshore

works, approach of floatel Otto 5.

Ponticelli adapting Nigeria platforms

for next-phase Ofon production

Total’s Ofon Phase 2 project offshore Nigeria calls for con-struction of four new platforms for the shallow water Ofon field. Additionally, the company is modifying existing facilities which have been in service since 1997. The goal is to mon-etize the field’s gas, which will be compressed and sent to

shore, and to develop oil reserves and increase production.The Ponticelli Frères Group has been awarded the $200-million

contract for tie-ins and modifications on existing facilities. Its previ-ous major overhaul job was on Total’s Girassol FPSO offshore An-gola, to prepare the facility to receive production from the satellite Rosa field. But the work on Ofon is the company’s most complex and demanding offshore assignment to date, according to Jean-PhilippeCau, oil & gas business development manager of the Ponticelli Frères Group, based near Paris.

The workscope includes installation of 300 metric tons (330 tons) of piping and equipment, 200 metric tons (220 tons) of new steel structures, 100 km (62 mi) of electrical wiring, and instrumenta-tion/telecommunications work on the existing Ofon OFD1 and OFP1 drilling and production platforms in 40 m (131 ft) water depth, 60 km (37 mi) offshore Nigeria. The upgrades are needed to ac-commodate production from new wells that will be drilled from two new drilling platforms and one new platform, and to connect the in-stallations to the new bridge-linked OFP2 production platform thatHyundai Heavy Industries is building in South Korea.

Ponticelli is EPC contractor for the program. As with all new Nige-rian offshore projects, the emphasis is on maximizing local content.Ponticelli has subcontracted detailed engineering locally to ISEL in Lagos, with the support of Doris Engineering.

Since the contract signing in September 2011, the main focus has been on procurement of items such as valves, motors, vessels, andpipes, cables, and instruments. Prefabrication of replacement piping and steel structures started in late 2012 at the Ponticelli Nigeria-owned Silhouette yard in Port Harcourt. Work offshore started late last year, and Ponticelli specialists will probably be based on the in-stallations for a further two years, beyond the planned start-up ofPhase 2 in 2014.

“This is a SIMOPS (simultaneous operations) situation, a field inwhich we are specialists,” Cau says. “We have to maximize the amountof hot work that can be done offshore without disrupting normal op-erations, and organize tasks on the facilities during the various shut-downs planned later this year and next year during marine operations,i.e. jacket installations. A lot of the platforms’ primary structures haveto be changed, and we have to reassess the structural conditions dueto all the new equipment that has to be put in.”

An overall reassessment of the facilities’ structural integrity is also planned. Some structural elements will likely have to be re-placed to meet long-term production requirements.

“On the existing OFD1 drilling platform, Total plans to drill threenew wells,” Cau said. “We will modify the jacket structure to supportthree new conductor pipes by installing a frame below the water line. We will also put in new cable trays, with electrical installationssubcontracted to SNCF, and we have to adapt the existing pipe net-work to the gas-lift system on the new production platform. And dueto Total’s commitment to stop gas flaring, the nose of the existingflare on OFP1 will be modified for depressurization – again, this job

will be subcontracted to a specialist company.”Rosa, although a 2-million man-hour job offshore, basically in-

volved tie-ins of a few large modules. “For Ofon, however, we areinstalling and changing out a large number of small pieces, and each section of pipe or structure has to be integrated. Doing this requiresa careful assessment of the associated risk and involves a lot of pa-perwork, and very heavy preparations. The same level of prepara-tion, in fact, for a 50-ton module as for a single piece of pipe weighing less than 1 ton.”

Ponticelli expects to maintain a crew of 50-60 specialists on the two platforms working on a SIMOPS basis, with most of the work completed by mid-2014, when the new production platform is due to be installed and the bridge links are in place. The team is de-ployed from a floating accommodation barge stationed close to theplatform.�

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Cegelec Oil & Gas Your Long Standing Partner

Cegelec Oil & Gas, with more than 2000 engi-neers and technicians, ensures a worldwide presence in West Africa, the Middle East and Asia, with established offices in Angola, Congo, Cameroon, Nigeria, Abu Dhabi, Bahrain, Qatar, Saudi Arabia, Korea...

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F R A N C E

Spring-energized seals selected for world’s

first subsea gas compression station

Statoil is due to install the world’s first subsea gas compression station in 2015 on the Åsgard field in the Norwe-gian Sea. Saint-Gobain Performance Plastics, Seals Group will provide poly-

mer spring-energized seals, specially engi-neered to address performance and reliability needs relating to the axial control valves por-tion of the gas compression system which will operate in a water depth of 3,000 m (9,842 ft). In line with API 6A PR2 test procedures, the seals successfully completed a 500,000-strokes endurance testing without leakage.

Subsea compression technology, devel-oped in Norway, is designed to improve gas recovery and offers numerous advantages compared to the alternative of installing a new platform. These include reduced ca-pex and operating costs, a smaller environ-mental footprint, and safer operations. This enabling technology has great potential to change offshore gas field developments worldwide as projects move into deeper wa-ters farther from shore.

However, operating conditions in deeper, more remote locations are often severe, char-acterized by pressures beyond 15,000 psi (1,034 bar) and temperatures above 150°C (302°F), as well as aggressive chemicals aris-ing from the more complex reservoirs and implementation of recovery techniques.

Due to new industry requirements, con-tractors and OEMs are being pushed to switch to new sealing solutions that exceed the limits of conventional solutions such as packings and O-rings. Over time, the per-formances of elastomers have decreased in direct proportion to the difficulties experi-enced with extreme operating conditions and chemically aggressive environments. Moreover, elastomers under high pressures have proven to be susceptible to rapid gas decompression.

Polymer spring-energized seals were ini-tially introduced to the oil and gas sector primarily to solve reliability and durabil-ity problems caused by the performance limitations of elastomeric seals. Polymer spring-energized seals are pressure-assisted sealing devices, consisting of a PTFE jacket or other polymer, partially encapsulating a corrosion-resistant metal spring energizer. The spring-energized seals are designed to withstand critical areas of concern such as aggressive media (sour gas with H2S > 15%,

methanol, and other harsh chemicals) and extreme temperatures and pressures.

The OmniSeal-103A seals that Saint-Gobain Seals Group will supply for the Ås-gard subsea gas compression station were engineered and manufactured with a unique blend of the company’s Fluoroloy material, qualified to the NORSOK M710 standard. The latter describes the required physical tests for sealing materials: in this case, most of the tests were conducted at Saint-Gobain’s R&D facilities, while the ageing tests were performed by an independent laboratory.

We have developed a specific PTFE-based formulation of Fluoroloy for the Åsgard proj-ect which is being used for the jacket of our spring-energized seal. Also, the seals for this application have been custom-designed based on the technical specification of our customer, the valve OEM. In addition, we have back-up rings to prevent extrusion of the jacket material into the extrusion gap. These back-up rings are made from PEEK-based material.

Ageing results can be used to estimate service life for materials in sour applica-tions as well as a more general assessment of their suitability for sour service. For this specific ageing test in the qualification pro-cess, Fluoroloy materials were subjected to extreme temperature and high percentages of hydrogen sulfide of up to 15% H2S, giving new insights and potential application pos-

sibilities into the properties of these high-performance and custom formulated com-pounds.

To date the subsea axial control valves have completed the following qualification program:t��'.&$"�� *O� PSEFS� UP� FTUBCMJTI� BMM� GBJMVSF�

modes, a Failure Mode, Effects, and Criti-cality Analysis (FMECA) was performed for anti-surge valves and for regular con-trol valves.t��$PNQPOFOU� RVBMJåDBUJPO�� 5IF� TFBM� BS-

rangement and the volume compensator have been designed specially for the sub-sea control valve. Both have been tested thoroughly prior to use.t��"1*�UFTUJOH��'PMMPXJOH�BTTFNCMZ�BOE�WFSJ-

fication the API 6A PR2 test was conduct-ed, which involved testing of the valve at the pressure and temperature extremes, proving the quality level of the design.t��&OEVSBODF�UFTU��5P�TJNVMBUF�B�MJGFUJNF�PG�PQ-

eration, the subsea valve has been subjected to an accelerated endurance test. During this test 500,000 strokes were made in all possible combinations of operating tempera-tures and internal/external pressures. The endurance test was passed with zero leak-age to the environment.t��)ZQFSCBSJD� UFTU�� )ZQFSCBSJD� UFTUJOH� IBT�

been completed. A 12,000-stroke test was performed at 165 bar (2,393 psi) external pressure, simulating 1.5 times the proj-ect’s water depth.t��1SPEVDUJPO� UFTUT�� 'PS� FBDI� EFMJWFSZ� QSP-

duction tests are applicable. The standard program includes material testing, dimen-sional verification, non-destructive engi-neering, operating thrust measurement, hydrostatic pressure, and leakage testing.As the industry continues to extend field

development in ever-deeper waters, the oil and gas supply chain needs to focus on and develop new materials and components for subsea production systems including trees, wellheads, BOPs, manifolds, gate, ball and choke valves, flow meters and couplings, that allow them to operate at higher pres-sures and temperatures.

All these new systems must also adhere to strict requirements for sealing at 20 psi (1.37 bar) and 205°C (401°F) for 2,000-3,000 m (6,561-9,842 ft) water depth; seals have been identified as a critical component in the development of these systems. �

Christophe Valdenaire

Saint-Gobain Performance Plastics, Seals Group

The OmniSeal-103-A.

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Offshore Energy Division

EIFFAGE Construction Métallique48-50, rue de Seine - 92 707 Colombes cedex

Tel: +33 (0)1 47 60 47 54 Fax: +33 (0)1 47 60 47 01

www.eiffageconstructionmetallique.com

EIFFAGE Construction Métallique : our name represents more

than a hundred years experience acknowledged worldwide in the field of steel

construction and civil engineering structures.

Offshore for over forty years our platforms, modules and living quarters

enable Petroleum Companies to explore and exploit petroleum fields on the

world’s seas and oceans in excellent technical conditions of safety and comfort

for their operators.

Quality – Safety – Environment : these are the essential priorities

of our company every day, based on the expertise, competence, adaptability

and dedication of our teams.

As a genuine quality trademark, Made by ECM is the expression of our

commitment and a guarantee of satisfaction for all our clients.

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F R A N C E

Construction of the decks for the Ofon OFQ

platform at Niger Dock, Lagos.

Nigeria’s most “home-made” living quar-ters platform to date should sail out later this year to Total’s Ofon field. Although

Eiffage Construction Metallique’s yard in Fos, southern France, is contributing three levels of the deck, the remainder is under construc-tion by indigenous fabricators Aveon Offshore and Niger Dock.

ECM was awarded the $420-million engi-neering, procurement, construction, and com-missioning contract for the OFQ facility in November 2011, as part of a consortium also involving EIFFEL Nigeria Ltd. and Nigerian design company OOPE. It is one of four new platforms that Total has commissioned for the Ofon Phase 2 development in Oil Mining Lease 102, 65 km (40 mi) offshore southeast Nigeria. Water depth is 40 m (131 ft).

OFQ will comprise an 800-metric ton (882-ton) jacket fixed to the seafloor by 1,200 met-ric tons (1,323 tons) of piles, supporting a six-deck topsides weighing 5,000 metric tons (5,511 tons). The latter will include technical/control rooms and accommodation for up to 140 crew members.

The Fos yard is working on the intermediate deck, the lower deck modules, and the central control room. All structures are due for load out in September and will be installed with Saipem’s S7000 construction vessel. The facilities will be connected to other new production and process-ing platforms forming the Phase 2 complex.

Niger Dock in Lagos is working on the OFQ deck’s three upper levels, containing the accommodation, while Aveon’s yard in Port Harcourt is responsible for the helideck, spider (cellar) deck, jacket, and piles. These should be loaded out in October.

The degree of Nigerian engineering and construction content is unprecedented for a living quarters platform, says ECM’s offshore energy director Arnaud de Villepin.

Coordinating the various activities has been challenging, he says: “It is difficult to manage three different sites for fabrication. Usually there are one or two yards respon-sible for the topsides and jacket, but because of the need to increase local content, the topsides in this case are being produced in three separate packages.

“To ensure things run smoothly, we have built an integrated team with Niger Dock personnel, and we have sent more supervi-sory personnel from ECM to monitor orga-nization of work programs and schedules.”

ECM is now looking to bid for living quar-ters platforms on other new shallow-water Nigerian projects. This could involve working with the same Nigerian design/construction partnership. There are also prospects for new wellhead platforms, not just in Nigeria, but

offshore Cote d’Ivoire, Congo-Brazzaville, and Angola. “Targeting these projects is in line with the new policy of our parent company Eiffage to develop business in Africa generally,” de Villepin points out. �

Ofon accommodation construction on schedule

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http://www.eiffageconstructionmetallique.com





Our energy is your energy

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New tools and technology for the offshore industrySchlumberger releases new CT, MWD, RSS,

and PCD bit technology

E Q U I P M E N T & E N G I N E E R I N G


CoilScan from Schlumberger is a newly released system the company says aims to identify pipe defects before running coiled tubing (CT) downhole and thereby reduce non-productive time (NPT) by supplying real-time coiled tubing pipe inspection during intervention.

CoilScan has been field tested in offshore and onshore environments from the US to Saudi Arabia, to Malaysia. During field trials, the real-time CT pipe inspection system moni-tored more than 1.5 million running ft of CT pipe in various environments and applications.

In field trials onshore in North America, CoilScan provided inspection results from beginning to end of the CT life. Typical CT strings at the test location are used for ap-proximately 500,000 running ft, resulting in an average of 25 to 30 runs. The tested string ran an additional 200,000 ft, or a total of 40 runs. Defects and fatigue areas of the CT were monitored actively to provide confidence needed to continue running the pipe longer

with a low potential for failure, resulting in lower overall intervention costs.

“Most CT failures in the field can be traced back to some initial defects, such as mechani-cal damage or a manufacturing defect, result-ing in costly NPT and increased exposure to potential health, safety, and environmental issues,” says Chaden Lassoued, president, Well Intervention Services, Schlumberger. “The CoilScan system combines real-time dimensional measurements, including wall thickness and diameter, depth measurements, and defect detection, to proactively address CT pipe failures.”

Slimhole MWD service

Schlumberger’s new DigiScope slimhole measurement-while-drilling (MWD) service transmits high-quality data to the surface for real-time reservoir description and geosteer-ing in extended-reach, deepwater, and land wells.

This new high-speed telemetry service

powers the complete suite of Schlumberger slimhole LWD services in the same bot-tomhole assembly. Fully compatible with the Orion II data compression platform, DigiScope service has a modulation algorithm that trans-mits high-quality data from the deepest wells to facilitate wellbore surveying, drilling optimi-zation, and advanced formation evaluation.

In an application in Mexico, the customer wanted real-time data from a high-angle development well in a depleted reservoir that required a low mud weight to minimize losses. The range of telemetry bandwidth, combined with the new modulation technique, was ap-plied to MWD for the first time. The operator acquired quality data with a high signal-to-noise ratio and was able to safely guide drilling to total depth.

“The DigiScope service transmits real-time drilling optimization and formation evaluation data at high physical bit rates of up to 36 bps, minimizing rate of penetration restrictions in the deepest onshore and offshore wells,”

The new slimhole PowerDrive Archer high build rate rotary steerable system bottomhole assembly.

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says Steve Kaufmann, president, Drilling & Measurements, Schlumberger. “The powerful tool telemetry is six times faster than tradi-tional MWD services as proven with more than 200,000 ft drilled in the most challenging formations across four continents in the last three years.”

New high build rate

slimhole RSS

Schlumberger has released the slimhole PowerDrive Archer high build rate rotary steerable system (RSS). This RSS deliv-ers build rates of up to 18°/100 ft, with full directional control and dogleg assurance for complex 3D well profiles and multi-lateral well designs, says Schlumberger.

Built on the PowerDrive X6 system, the slimhole PowerDrive Archer RSS combines push- and point-the-bit technologies to im-prove performance in geosteering and open hole side track applications. It has proven itself in more than 130 field test runs in North America, the Middle East, West Africa, Eu-rope, and Asia, according to Schlumberger.

In the Permian basin, Cimarex Energy needed to drill a 61⁄8-in. horizontal section within a 7-ft thick true vertical depth zone in the Bone Spring shale formation. The well design included high dogleg severity with a 10°/100-ft curve.

The slimhole high build rate RSS was select-ed to eliminate additional trips downhole, and the challenging curve and lateral were drilled in one run, saving 26 hours of drilling time.

“The slimhole PowerDrive Archer RSS can drill well profiles previously only possible with motors, in one run, with the ROP and wellbore quality of a fully rotating RSS,” says Kaufmann. “Expanding the capabilities of our high build rate RSS services, this slimhole edi-tion has drilled 130,000 ft in carbonate, sand, and unconventional reservoirs as part of our integrated drilling systems offering, including advanced Smith PDC drill bit technology.”

Conical diamond element

enhances PCD

bit performance

Smith Bits, a Schlumberger company, has released its Stinger conical diamond technol-ogy. The Stinger polycrystalline diamond element enables high-point loading to fracture rock more efficiently during drilling for increased rate of penetration and durability, says Smith.

Developed using proprietary synthetic dia-mond manufacturing technology, Stinger has a polycrystalline diamond layer thicker than conventional PDC cutters. Also, the shape is optimized for strength in axial compression. When centrally positioned in a PDC drill bit

cutting structure, the Stinger improves per-formance by crushing formation core at the borehole center, increasing drilling speed.

“The central Stinger conical diamond ele-ment allows our customers to drill at higher ROPs by improving cutting action in a wide range of formations, reducing both drilling hours and the number of bits used in each well,” says Guy Arrington, president, Bits & Advanced Technologies, Schlumberger. “The first application of Stinger technology also delivers a more stable bit with less vibration to reduce stress on drillstring components and improve the reliability of downhole tools.”

Using the IDEAS integrated drill bit design platform, simulations were conducted show-ing ROP increases in a range of different rock types, including shale, limestone, and sandstone. The virtual drilling environment demonstrated central Stinger element place-ment would yield an ROP increase of at least 18%, says Smith.

In the Williston basin, an 8¾-in. PDC bit typically drills the vertical hole before the curve and lateral section in the Bakken oil-bearing sands. In field tests, centrally placed Stinger technology was added to the baseline vertical section bit design. Average ROP was increased by more than 46% when compared to the next best performance in offset wells, with a record ROP increase of 77%. �

How can a subsea system operate in an unknown location, with indefinite duration of deployment during a severe weather event? OceanWorks is answering this question by building a subsea fluid injection system ca-pable of autonomously intervening in a subsea oil well containment incident.

By placing the fluid pump station subsea, it is sheltered from surface weather conditions.

OceanWorks also developed the capability to swap battery packs. The battery packs are absorbed glass mat units which are marinized using pressure-balanced oil-filled housings that are ruggedized for subsea deployment.

The bladder skids can be filled prior to or during deployment to allow use of a range of vessels of opportunity. Additionally, hoses are stored onboard to simplify and speed deploy-ment.

The battery, pump, and bladder skids are scalable in number for ease of manipulation, says OceanWorks.

Jim English, senior vice president of Ocean-Works comments: “Our pump, power, and fluid storage bladder skids combine like Lego blocks, so operators can define requirements during deployment, not during design. An emergency will define those requirements for you. You need to be able to respond flexibly,

with what you already have.”OceanWorks’ smart electronics are key

to monitoring and controlling the system, and also detect damage so users can reroute around it.

Using its existing subsea UPS power supply designed for the US Navy, Subsea Autonomous Dispersant Injection (SADI) bladder skids, and long-term subsea electron-

ics control and monitoring systems built for the VENUS, NEPTUNE, and OSB ocean observatories, OceanWorks says it was able to develop a system to suit the particular needs of its client, the Marine Well Containment Co. (MWCC).

“We wanted this system to be three things: simple, scalable, and tough,” concludes English. �

Autonomous subsea fluid injection skid built by OceanWorks for MWCC

OceanWorks skid-mounted subsea fluid injection system.

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New

tools and

technology



For fast, reliable BOP, hose, manifold valve system, and riser line hydrostatic testing, Clo-ver Tool offers a variety of BOP hydrostatictest unit models. These all electric, stainless steel test units are excellent for drilling rigs

because they are small footprint, explosion proof, and easy to

customize, maintain and operate. The manufac-turer claims that over 150 hydrostatic test units areoperating in BOP test applications worldwide

with no failures over the past 12 years.The Clover dual Model

CTU-20P-D2-4 offers triple hydrostatic test capabilities up to 30,000 psi. During critical op-erations, one side can be used as an immedi-ate back up. When operating in tandem as a single station, it can cut BOP fill/test time in half, according to Clover. Operating indepen-dently, integral twin recorders allow separate tests simultaneously at different psi. For less critical operations Clover offers its moreeconomical 15,000 psi single test unit Model CTU-15P-S1. �

Scientific Drilling Interna-tional (SDI) has launched its next-generation mud pulse MWD system. The FALCONMWD offers superior reliability,precision wellbore placement, higher durability, deeper reach,and safer operations, all while allowing for faster drilling, says Scientific Drilling.

Features of the FALCONMWD include bi-directionalmud pulse telemetry, positive pulse (three to five bits/second), full accelerometer and drill-ing dynamic package, ruggedthread-mount throughout, the required surface equipment and software upgrades, bottomhole assembly sizes from 3½ in. to 9½ in., and flow rates of 50 to 1,500 gal/min.

Scientific adds that the new system has a high-speed telemetry mode resulting from improvementsin both the uphole and downhole systems.

“FALCON MWD is a full-featured mud-pulse MWD system, providinga telemetry mechanism for all other SDI MWD, gyroMWD, LWD rotarysteerable, and Smart Motor components,” says Ben Hawkinson, GlobalProduct Line manager. “The control module also has the capability tomeasure basic drilling dynamics as well as mud flow and rotation for the

purposes of drilling optimization and power management.”The FALCON MWD leverages SDI’s True Utilization Factor (TUF),

a proprietary preventative maintenance process combining key environmental measurements collected while drilling. With a detailedunderstanding of component durability derived from thousands of hours of destructive system testing, TUF provides a proactive edge in delivering customer confidence and superior reliability, concludesScientific Drilling. �

Clover Tools produces BOP/Hydrostatic test units

Scientific Drilling launches new mud-pulse MWD system

Rendering of the new Scientific Drilling mud-pulse MWD bottomhole assembly.

Clover Tool says that its BOP hydrostatic test unit models are excellent for drilling rigs because they

are small footprint, explosion proof, and easy to customize.

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New

tools and

technology



Bluebeam Software, developer of PDF-based collaboration solutions, has released the latest version of its flagship prod-uct, Bluebeam Revu. The company says Revu lets project engi-neering teams electronically review P&IDs with customizable annotations, track all markups in a list, electronically assemble documents such as work packs, store project files online, and collaborate in real time with Revu’s integrated cloud feature,Bluebeam Studio – all from a desktop or tablet PC.

New features in Revu 11 make it easier to organize digital information so that docu-

ments and data are quicker to access in the field. Users can create PDF book-marks and page labels from title blocks or other PDF content using AutoMark so they can easily find the pages to

review, says Bluebeam. Searching for drawing elements such as

valves is done using the VisualSearch tool, which is enhanced to make it easier to find items

regardless of rotation or size, and to provide a count of all identified search results.

Standardized annotations can be made on the fly using the Format Painter by selecting a markup with the desired settings, choos-ing markups to adjust, and letting Revu do the rest.

Revu 11 also enhances Revu’s cloud-based collaboration feature, Stu-dio, by enabling users to check out and edit PDFs and other file types

stored in projects even when Internet connectivity is lost. The ability to access and review and edit files, even offline, provides offshore and onshore project team members with the information they need, when they need it, says Bluebeam. �

Falmouth Scientific Inc. (FSI), a providerof precision oceanographic instrumentationand marine systems integration, is furtherdeveloping its product line of HMS-620 Bubble Gun seismic systems, and has announced two important enhancements.

FSI’s Bubble Gun Systems are suitable for small-boat shallow-water surveys. Data col-lected with the HMS-620 rivals that of much larger, heavier, and more expensive air-gun, boomer, and sparker systems, and its small size makes it easily deployable without the need for heavy machinery, winches, or cranes.

Bubble Gun systems use a 15 cu in. air vol-ume to generate narrow band, low frequencyacoustic signals. This proven technology provides superior signal penetration throughcoarse sand, gravel tills, and other difficult to penetrate sediments.

By adding a second transmit channel to the existing transceiver enclosure, and by synchronizing the two signal generators, FSI says it has realized significantly higher energyoutput, which results in much deeper signal penetration. The two Bubble Gun sourcetransducers can be mounted together on one tow vehicle, or can be configured as two separate single-source vehicles.

All of FSI’s Bubble Gun systems can be fitted with a 24 VDC power option, which al-lows them to be powered by lead-acid marine batteries. This means that you can perform

shallow-water seismic surveys without the need for a generator or ship’s power. Twodeep-cycle marine batteries will allow over 10 hours of survey time on a single charge, with no generator noise, no fuel, no exhaust, and no degradation of the data.

Falmouth Scientific offers other sen-sor based products such as current, wave, and tide meters; solutions for drilling and

vortex-induced vibration monitoring; portablesidescan sonar imaging; and other acoustics-based underwater instrumentation. Serviceareas include custom design, development, integration, and production of marine systems and acoustic transducers; and manufacturing services such as prototyping, product assem-bly, encapsulation (potting), calibration, and pressure testing. �

PDF-based electronic system eases P&ID review

Falmouth Scientific enhances Bubble Gun family

FSI’s HMS-620 complete portable seismic system, shown with transducer suspended on display frame.

Example screen from Bluebeam Revu collaboration system.

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Moody Gardens Hotel & Convention Center

Galveston, TX | November 5-7, 2013

www.deepwateroperations.com

Yesterday’s Experience,Tomorrow’s Innovations and Solutions

The Deepwater Operations Conference and Exhibition will continue the tradition of

excellence in addressing operational challenges involved in developing deepwater

resources. We will return to the Moody Gardens Hotel and Convention Center on

November 5 – 7, 2013 in Galveston, Texas.

Challenges in deepwater production are complex and command our attention to

develop solutions that are economical and long-term. The Deepwater Operations

Conference and Exhibition provides a unique experience for attendees and exhibitors

to share, learn and connect in a forum dedicated to addressing these challenges.

Go to www.offshoreoilevents.com to sign up today! Follow us on

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Images courtesy of Anadarko Petroleum Corp.

Gold, Silver – Wednesday Lunch &Silver - Thursday Lunch Sponsor:

Golf HoleSponsors:

Elite Recharging Station& Title Golf Sponsor:

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B U S I N E S S B R I E F S


Braga

People

Jonathan Roger will step down as manag-ing director of Centrica Energy Upstream at the end of June. He will be succeeded by Sarwjit Sambhi.Mark Preece has stepped down as CEO of

Reef Subsea Group. DuncanMacPherson,the current managing director of Reef Subsea Norway, will assume the interim role of CEO for the group. Mel Fitzgerald has been ap-pointed board chairman.

ValvTechnologies has named Julie Bodine

as director of global marketing.MODEC has appointed Shigeru Usami

and Kensuke Taniguchi as representative managing director.

Swift Worldwide Resources has hired Mark

Coetzee to lead its North American opera-tions as managing director.José C. Grubisich has been named to Hal-

liburton’s board of directors. He will serve on the Audit and the Health, Safety, and Environ-ment committees.

Precision Polymer Engineering has appoint-ed Eric L. Crawford as a material analyst.Simon Luffrum has joined Magma Global

as project manager for the riser development team.

Zenith Oilfield Technology has appointed Steve Beattie as Eastern Hemisphere sales manager, and Euan

Gray as company finan-cial controller.

CGG has appointed Luiz Braga as vice president, Latin Ameri-ca regional geomarket director.

Boltight Ltd. has ap-pointed Colin Gibson

as sales engineer.Andreas Chrysos-

tomou has been appointed the 111th presi-dent of the Institute of Marine Engineering, Science and Technology. Richard Vie has been appointed president-elect.

Noreco’s board of directors consists of Ståle Kyllingstad, chair; Hilde Drønen,Eimund Nygaard, Erik Henriksen, and Marika Svärdström.

Ashley Thomson has joined Paradigm Flow Services as development manager.

The 2013 Louisiana Gulf Coast Oil Exposi-tion officers are Kirby

Arceneaux, chair-man; Steve Maley,chairman-elect; and Kenneth Crouch,treasurer.Vicki Quesada

has formed her own company VQ Media Resource, which offers

businesses of all sizes personalized, highly focused strategic planning, media buying, and analysis (market and competitive) on a regional and/or international basis.

Saltire Energy has appointed Craig Mitch-

ell as business development director.Atwood Oceanics has appointed Jeffrey A.

Miller to its board of directors.Dolphin Geophysical has appointed Sergio

Grion as geophysical research manager, Stuart Denny as geophysical technology manager, and Rich Bartlett as depth imaging manager.

DNV has appointed Frank Ketelaars as its head of UK advisory services. He will have overall responsibil-ity for the company’s advisory units in London, Manchester, and Aberdeen, and will also be responsible for enhanced collaboration with colleagues based in Paris, Milan, Rotterdam, and Bilthoven.

Rockhopper Exploration has appointed Fiona Margaret Ma-

cAulay to the board as technical director.Mike Blakemore

has joined SLR Consult-ing to lead business-consulting growth in the oil and gas team.

Ron Person has joined Klüber Lubrica-tion North America as director of business development for oil and gas.

Greene’s Energy Group has named Ryan

LaBorde Gulf Coast regional manager for the Testing and Services business unit, Todd Naquin general manager and Blayne

Prejean operations manager of Cherokee Services.

The ASCO Group has appointed Scott

Donald as Europe finance director, Zak

Fleming as Europe logistics and operations director, and David

Rae as Europe com-mercial director. The appointments join Walter Robertson on the ASCO Europe board.

Steve Wynne has joined iSiS-Ex as an international sales manager to develop new business channels in Europe, the Middle East, Africa, and Asia.

Paul Shaw has joined Houlder as director of the marine equipment business.

Foster Marketing has named Rachel

Bonnette marketing assistant.

Atlas has appointed Lambert Ebot as re-gional manager, USA.

Cobalt International Energy has elected William P. Utt to its board of directors.

Rowan Companies has promoted Thomas

P. Burke to president. He will remain as the company’s COO. W. Matt Ralls will continue to serve as CEO until his retirement in mid-2014, when it is anticipated that Burke will succeed him and Ralls will assume the role of executive chairman.

The board of directors of ConocoPhillips has elected Gay Huey Evans as a new out-side director. She will serve on the Audit and Finance Committee.Guy Downie has joined Vikoma Interna-

tional Ltd. as sales and marketing director.AGR Petroleum Services has appointed

David Grant as the senior subsea manager of the newly-established subsea project manage-ment division.

Kristian Sætre has been appointed manag-ing director of Ulstein Verft.

2H Offshore Inc., an Acteon company, has named Glen Jewell and Hanh Ha as additional directors of its London office. Ha’s primary activity sector will be flexible riser, flowline and umbili-cal engineering, and Jewell’s focus will be drilling and production risers and conductor systems.Nadir Mahjoub has

joined SPEX Group as COO.

BG Group has appointed Lim Haw-

Kuang as a non-execu-tive director.Graham Westgarth

has joined the board of Seagull AS as a non-executive director.James Moffat has

taken up his role as CEO of Lamprell.

Randy Johns has joined FairfieldNodal

Ketelaars

Ebot

Westgarth

Nagel

LaBorde

Naquin

Prejean

Arceneaux

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B U S I N E S S B R I E F S


as the director of new ventures.

HB Rentals has promoted John Nagel

to vice president of product development.

IMV Projects, a Wood Group Mustang company, has appointed Sandra Hall as vice president, business de-velopment and strategy.

Bracewell & Giuliani LLP has added energy finance partner Jason Fox to its London office.

SIGMA3 Integrated Reservoir Solutions Inc. has appointed Todd Deering as director of software quality, and David Abbott as global director of operations for microseismic and borehole seismic imaging processing and interpretation.Troy Coker has

joined American Elec-tric Technologies as director of sales for the upstream oil and gas market.

Atkins has appointed Kim Weninger as op-erations director of its US oil and gas division.

Company news

Unique System FZE is teaming with the UK’s National Hyperbaric Centre to develop a training center and training courses in the UAE.XPD8 Solutions has been awarded

contracts to provide condition monitoring services to CNR’s platforms in the North Sea, Wood Group PSN on Dana’s Triton platform in the North Sea, and with Hess in Equatorial Guinea.Expro has opened a new well intervention

facility in Aberdeen.Premier Oil has awarded Bond Offshore

Helicopters a three-year contract for crew change flights in the UK North Sea. The new Sikorsky S-92 aircraft will be operated under an arrangement with Bond’s sister company Norsk Helikopterservice.

Oceaneering Asset Integrity has secured a five-year global risk based inspections frame agreement with Teekay Petrojarl. The services will consist of the development of inspection strategies, RBI analysis, inspection programs, and offshore inspection services. Modus Seabed Intervention has estab-

lished an Autonomous Underwater Vehicle division.H2O Offshore has acquired Lafayette-

based Owens Manufacturing & Specialty

Co. Inc.

Greene’s Energy Group has opened new facilities in Alice and Pleasanton, Texas. The facility in Pleasanton is the base for Greene’s well testing and torque and testing services.HB Rentals Dubai, a Superior Energy

Services company, has secured contracts to supply 12 A60-DNV-approved eight-man link-able sleeper units onboard two Lloyd’s-classes liftboats in Abu Dhabi and Saudi Arabia, and four linkable A60-DNV 2.7-1-approved modules for a barge installing cables offshore Saudi Arabia.Caley Ocean Systems Ltd. and Brazilian

company LIG Global Services Ltda have formed OSS Sistemas Offshore Ltda to supply a range of handling systems for cable laying, and subsea umbilicals, risers, and flowlines projects.

Atlas Services Group has acquired GOSS Consultants Ltd. and GOSS (North

Sea) Ltd.

AXON Energy Products has acquired the radio frequency identification technology and assets of Merrick Systems.Technip has acquired Ingenium AS, a

Norwegian engineering company that designs and develops mechanical and electro-hydrau-lic tools and equipment.Bibby Ship Management India Pvt.

Ltd. has contracted Kongsberg Maritime

to deliver a KONGSBERG offshore vessel simulator (KOVS) including an upgrade of its existing KONGSBERG Dynamic Positioning simulator in Mumbai. The extension to the established Bibby Training Institute Mumbai represents the first KOVS in India.Lamor has appointed Unique System

FZE as its authorized distributor for the Middle East region for the entire range of oil spill response kits.Hydro Group has opened a new office in

Singapore.The Ferguson Group has relocated its

Asian operations to a larger purpose-built facility at the Loyang Offshore Supply Base in the industrial area of Loyang, Singapore.

ABB has completed the acquisition of San Diego-based APS Technology Group. The acquisition adds optical character recognition and gate automation capabilities to ABB’s crane and harbor automation business.SIGMA3 Integrated Reservoir Solu-

tions has brought together its Colorado-based engineering disciplines to streamline collaboration, foster integration, and provide enhanced real-time services to clients at its newly expanded Englewood office.Jennison Manufacturing Group has

received final audit approval and obtained its American Petroleum Institute certification. The company received API SPEC Q1, ISO/TS 29001, ISO 9001:2008 certifications.BP has awarded Frazer-Nash Consul-

tancy a North Sea master services agreement

for consultancy services. RigData has added an Android version to

its drilling rig location mobile application.National Oilwell Varco has completed the

acquisition of Robbins & Myers.Vallourec has completed qualification of

its new tubular connections finishing plant in Dammam, Saudi Arabia.Clyde Blowers Capital has acquired En-

ergy Services International. The $20-mil-lion deal also includes the company’s trading businesses Southern Technology and

Services and Vicksburg Marine.Z Trim Holdings has entered into a

joint development agreement with New-

park Drilling Fluids LLC to develop new, environmentally-friendly drilling fluids using Z Trim’s proprietary industrial materials that could replace drilling mud additives such as guar and xanthan gums.CSL has completed the acquisition of Proj-

ect Excellence LLP, a specialist project and risk management consultancy provider that will now trade as CSL Project Excellence.Freudenberg Oil & Gas has acquired

Vector Technology Group, a global supplier of high integrity sealing solutions.Variable Bore Rams has entered into an

agreement with Weatherford Asia Pacific

Pte Ltd. to provide BOP rams. Badger Explorer ASA has signed a

sponsorship agreement with Chevron

Energy Technology Co. for the develop-ment of the Badger autonomous drilling tool through the Badger Explorer Demonstrator Program. The objective of the program is to move the company’s technology from the prototype stage to a viable and robust com-mercial product.

In 2012, more than 2,600 students from more than 300 universities worldwide benefit-ted from dGB Earth Sciences’ academic licensing policy. Under the academic license agreement, universities get free access to the company’s OpendTect seismic interpreta-tion software and the commercial plugins developed by dGB and its partners: ARK CLS, Earthworks, and Sitfal. dGB also started the Open Seismic Repository, a database of seismic datasets with interpretations that can be used freely under the creative commons license agreement.GE has agreed to acquire Lufkin In-

dustries Inc., a provider of artificial lift technologies for the oil and gas industry and a manufacturer of industrial gears, for about $3.3 billion. Lufkin will broaden GE Oil & Gas’ artificial lift capabilities beyond electric submersible pumps to include rod lift, gas lift, plunger lift, hydraulic lift, progressive cavity pumps, and an array of well automa-tion and production optimization controls and software. The transaction is expected to close in the second half of 2013. �

Hall

Weninger

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Oilfield Helping Hands provideshope to people in our industry whoare in dire need of financial assistancebecause of crushing medical bills,a housing crisis, or a wide range ofother hardships incurred through nofault of their own.

Find out how you can help by visitingoilfieldhelpinghands.org

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PENNWELL PETROLEUM GROUP

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David Davis (Worldwide Sales Manager) [email protected]

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SINGAPORE

19 Tanglin Road #05-20 Tanglin Shopping Center Singapore 247909

1)0/&��t�'"9��Michael Yee [email protected]

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*OUFSBET�-UE� �"�� 4IJWBMJL �/FX�%FMIJ��1)0/&��t�'"9��

Rajan Sharma [email protected]

/*(&3*"�8&45�"'3*$"��

'MBU�� SE�ýPPS�0MVXBUPCJ�)PVTF��"MMFO�"WF �*LFKB �-BHPT �/JHFSJB

1)0/&��PS��Dele Olaoye [email protected]

SALES OFFICES

Aegion ............................................................... 4www.aegion.com

Aker Solutions .................................................11www.akersolutions.com

Alimak Hek AB ................................................ 97www.alimakhek.com

ASRY Offshore Services ................................ 51www.asry.net

ATS Inspection ...............................................151www.ats-inspection.com

Audubon Engineering .................................... 40www.audubon-engineering.com

Avondale .......................................................... 61www.hii-avondale.com

Baker Hughes Incorporated ....................43, 139www.bakerhughes.com

Beele Engineering B.V. ........................... Outsertwww.beele.com

Biglift Shipping B.V......................................... 96www.bigliftshipping.com

Bluebeam Software, Inc. ................................ 33www.bluebeam.com

BOURBON ......................................................149www.bourbon-online.com

Bredero Shaw .................................................. 47brederoshaw.com

C&C Technologies, Inc.: Survey Services .... 83www.cctechnol.com

Cameron .......................................................... 29www.c-a-m.com

Carboline Company .......................................105www.carboline.com

Cegelec Oil & Gas..........................................155www.cegelec.com

CGG ................................................................. 31www.cgg.com

Challenger Institute of Technology ............... 60acept.challenger.wa.edu.au

CJ Winter ......................................................... 68cjwinter.com

Clover Tool Company ..................................... 95www.clovertool.com

Co.L.Mar. S.r.l. ................................................120www.colmaritalia.it

COSCO Shipyard Group ................................ 59www.cosco-shipyard.com

CRC-Evans ...................................................... 89www.crc-evans.com

Delta Rigging & Tools ..................................... 91www.deltarigging.com

DORIS Engineering .......................................150www.doris-engineering.com

Dril-Quip ............................................................ 1www.dril-quip.com

EIFFAGE Construction Métallique................157www.eiffage.com

EMAS ............................................................... 80www.emas.com

EXPRO International Group Ltd. ................... 66www.exprogroup.com

Fincantieri Offshore ........................................ 65fincantierioffshore.com

FloaTEC ........................................................... 53www.floatec.com

FMC Technologies ..........................................C4www.fmctechnologies.com

Forum Energy Technologies .......................... 25www.f-e-t.com

Frank Mohn Flatøy AS .................................... 71www.Framo.com

GEP-AFTP ..................................................... 147www.gep-aftp.com

Greene’s Energy Group .................................. 85www.GreenesEnergy.com

Grieg Filters ..................................................... 56www.griegfilters.com

GVA Consultants AB ...................................... 62www.gvac.se

Halliburton ....................................................... 45www.halliburton.com

Hanno, Inc. ...............................................18, 120www.Hannoinc.com

Hardbanding Solutions by PostleIndustries ........................................................ 46

www.hardbandingsolutions.comHarris CapRock ................................................. 7

www.harriscaprock.comHeerema Marine Contractors ......................... 21

www.heerema.comHYTORC........................................................... 79

www.hytorc.comINTECSEA ........................................................16

www.intecsea.comIntellian Technologies .................................... 77

www.intelliantech.comJD Neuhaus Group ........................................103

www.jdngroup.com

Karmsund Maritime Offshore Supply ........... 19www.kamos.no

KBR .................................................................. 35www.kbr.com

KOBELCO / Kobe Steel Group....................... 67www.kobelcocompressors.com

LaRose Scrap & Salvage, Inc. ....................... 17www.larosescrapandsalvage.com

Lincoln Electric ............................................... 44www.lincolnelectric.com

Lloyd’s Register Energy - Drilling ................113www.lr.org/drilling

M-I SWACO ........................................................ 3www.miswaco.com

Magnetrol International .................................. 23www.magnetrol.com

McDermott International, Inc. ........................ 37www.mcdermott.com

Multi-Contact USA .........................................121www.multi-contact-usa.com

National Oilwell Varco. .................................... 27www.nov.com

Newpark Drilling Fluids. ................................. 57www.newparkdf.com

NOIA. ...............................................................143www.noia.org

Nylacast. ............................................................ 6www.nylacast.com

Oceanic Marine Contractors .......................... 63www.oceanicmc.com

OFD Engineering, LLC ................................... 41www.ofdeng.com

Offshore Heavy Transport .............................. 99www.oht.no

Oilfield Helping Hands ................................. 166oilfieldhelpinghands.com

PennWellDeep Offshore Technology

Conference & Exhibition ......................... 146www.deepoffshoretechnology.com

Deepwater Operations Conference & Exhibition ......................... 163

www.deepwateroperations.comOffshore Group ...........................10, 125, 140

www.offshore-mag.com PennWell Books ......................................... 62

www.PennWellBooks.comTopsides, Platforms & Hulls

Conference & Exhibition ..........................119www.topsidesevent.com

PONTICELLI .................................................. 153www.ponticelli.com

POSCO ............................................................. 13www.posco.com

Ranger Offshore, Inc. ....................................... 5www.rangeroffshoreinc.com

Reed Exhibitions - SPE Offshore Europe ................................... 123

www.offshore-europe.co.ukRolls-Royce Marine........................................115

www.rolls-royce.comSAFT ...............................................................152

www.saftbatteries.comSANDVIK.......................................................... 49

www.smt.sandvik.comSaudi Aramco .................................................. 75

www.Aramco.Jobs/OMSchlumberger .................................................C2

www.slb.comSeaway Heavy Lifting ....................................101

www.shl.com.cySembcorp Marine ............................................15

www.sembcorpmarine.com.sgSiemens AG ....................................................... 9

www.siemens.comSlingmax, Inc................................................... 69

www.slingmax.comSocotherm Group ..........................................109

www.socotherm.comSpectrum Geo, Inc. .........................................C3

www.spectrumasa.comSpir Star, Inc. ....................................................18

www.spirstar.comStatoil ..............................................................117

neversatisfied.statoil.comSTEARNS ........................................................ 54

www.stearnsflotation.comStrategy Engineering & Consulting LLC ...... 38

www.strategyeng.comT-REX Engineering & Construction............... 93

trexec.comTenaris Global Services ........................ 111, 133

www.tenaris.comTOTAL .............................................................158

www.total.comTransocean .....................................................136

www.deepwater.comVarel International ........................................... 87

varelintl.comVersabar, Inc.................................................... 39

www.vbar.comVICINAY MARINE ............................................ 55

www.vicinaymarine.comViking SeaTech ............................................... 73

www.vikingseatech.comWilliams ..........................................................107

www.williams.comWood Group Mustang ...................................141

www.mustangeng.com

The index of page numbers is provided as a ser-vice. The publisher does not assume any liabilityfor error or omission.

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This page reflects viewpoints on the political, economic, cultural, technological, and environmental issues that shape the future of the petroleum industry. OffshoreMagazine invites you to share your thoughts. Email your Beyond the Horizon manuscript to David Paganie at [email protected].


B E Y O N D T H E H O R I Z O N

The use of chemical sources in logging-while-drilling (LWD) op-erations poses health, safety, and environmental (HSE) risks that include direct contamination or extended close contact with the hu-man body. Abandoning a chemical source downhole also presentsan environmental risk that can have long-term effects, lasting thou-sands of years.

Eliminating the need for chemical sources improves operation-al efficiency in challenging onshore and offshore environments,where operational guidelines have become increasingly stringent and compliance more time-consuming to ensure that the risks facedby personnel and the environment, particularly in extreme or re-mote conditions, are kept to a minimum.

Sourceless formation evaluation has been on the industry’s wish list since radioisotopic chemical nuclear sources were first used to acquire neutron and density measurements in 1942 and 1959, re-spectively. The industry accepted the HSE risks associated with the transportation, deployment, and storage of these sources as there was no other means to determine formation porosity and fluid content as reliably as comparing the density and neutron porositymeasurements that the nuclear sources facilitated. These became so fundamental to formation evaluation that the density and neutronmeasurements, together with formation resistivity, became known as the industry-standard “triple-combo” – the minimum suite of measurements required to evaluate porosity, water saturation, and hence hydrocarbons in place.

The introduction of nuclear magnetic resonance (NMR) in the1960s showed much promise as a sourceless means to evaluate po-rosity. The NMR measurement responds exclusively to hydrogenin the pore fluids. However, experience has shown that attempting full formation evaluation with only NMR hydrogen index is fraughtwith difficulties, including under-polarization and unknown fluid characteristics. In addition, very short or long decay rates that fall outside the measurement envelope can easily result in inaccurate evaluation. The elegance of density-neutron interpretation is that the measurements cross-validate each other such that measurement in-consistencies can be readily recognized, keeping the risk of inaccu-rate evaluation and wasted operations to a minimum.

Today, density and neutron measurements are used in the vast majority of formation evaluation workflows. Consequently, signifi-cant effort has been invested in developing techniques to acquirethese fundamental measurements without the use of radioisotopic sources. The most promising approaches use electronically con-trolled particle accelerators to generate the required nuclear spe-cies on demand. When the accelerator is off, no nuclear particlesare emitted, so tools containing this technology can be treated inthe same way as other non-nuclear tools. Not only does this simplify

transport and handling of tools and auxiliary equipment, it improvesoperational efficiency because sources do not need to be loaded and unloaded. Should the tool become stuck downhole, in most juris-dictions fishing requirements, abandonment procedures, and side tracking operations are greatly simplified.

Electronically controlled pulsed neutron generator (PNG) tech-nology was introduced to the industry in the 1980s. In addition toproviding neutrons for the traditional neutron porosity measure-ment, the ability to create pulses of neutrons by turning the PNG on and off enables additional measurements to be derived. Neutroncapture spectroscopy and thermal neutron capture cross-section– more commonly known as sigma – require a pulse of neutronsfollowed by a “quiet” measurement period. Spectroscopy providesvaluable information about the elemental composition and miner-alogy of the formation. Sigma provides information about porosity,lithology, and fluids. Both provide complementary information to the density and neutron measurements for sophisticated formationevaluation.

While both wireline and LWD technologies have been provid-ing neutron measurements without the use of a chemical neutronsource for many years, the means to acquire a density measurementwithout the use of a chemical source had remained elusive.

The first quantitative sourceless neutron-gamma density (SNGD)measurement was made commercially available in 2012. The SNGDmeasurement uses high-energy neutrons emitted from a PNG to induce gamma rays in the formation. An array of detectors config-ured near the PNG characterizes the neutron distribution, induced gamma source, and the subsequent gamma ray scattering which provides formation density information.

The introduction of the SNGD measurement has finally complet-ed the quest for the sourceless triple-combo suite. The NeoScopesourceless formation evaluation-while-drilling service is currentlyonly available on LWD and for 8 ½-in. (216-mm) diameter holes, but the tool will be made available in other hole sizes. Wireline-conveyedsourceless density will also become available, completing the wire-line sourceless triple-combo offering. Together these technologieswill provide a full range of options to perform established interpre-tation workflows using data from state-of-the-art, environmentallyresponsible technologies.

The industry is just beginning to benefit from the enhanced for-mation characterization, reduced HSE risk, and improved opera-tional efficiency that sourceless formation evaluation technologyprovides.

Roger Griffiths

Petrophysics Domain Head, Drilling & Measurements, Schlumberger

Sourceless formation evaluation

decreases HSE risks

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Equatorial Margins BrazilMulti-Client Seismic - Data Available for Brazil Round 11

+1 281 647 0602

[email protected]

www.spectrumasa.com

Seismic section from the Potiguar Basin dataS i i ti f th P ti B i d t

Spectrum is active in five basins along the Equatorial Margins of Brazil,

all of which are available to license in Round 11. We offer new PSTM

and PSDM data for each of the Foz do Amazonas, Barreirinhas, Ceara

and Potiguar, all of which were acquired with 10,000 m offsets and 10-13

second record lengths.

Reprocessing efforts are underway along the Equatorial Margins. The first

is a 9,600 km program in the Para-Maranhao Basin that links the Foz do

Amazonas Basin to the Barreirinhas Basin. The second project covers

7,783 km in the deep waters of French Guiana. This will link the Zaedyus

discovery with data recently acquired offshore Brazil.

The well tie data will be available in April and the remaining data in May. Our

Multi-Client team is committed to delivering high quality data in advance

of the upcoming Round 11. Companies participating in Spectrum’s

programs will have a competitive advantage in this round.

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Optimize. Accelerate.

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VISIT US AT OTC BOOTH #1941.

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CAREER INSIGHTS

Networking After College

RECRUITERS

PRACTICUM

Attracting Graduatesto Industry

Fo r t he i ndu s t r y ’ s c a r e e r - m inde d p r o f e s s i ona l s SPRING 2013

A sup p l emen t t o P ennWe l l pub l i c a t i on s | w w w.P ennEne r g yJOB S . c om

The NewLeadershipNeeded in Energy

TRAINING INSIGHTS:

Skilled Transition

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______________

http://www.chevron.com/careers





2 EDITOR’S LETTER

Energizing the Next

Dorothy Davis, PennWell

3 The New Leadership Needed in Enegry

Dorothy Davis, PennWell

6 TRAINING INSIGHTS

Skilled Transition

Hilton Price, PennWell

10 CAREER INSIGHTS

Networking After College

Tony Lee, CareereCast.com

12 RECRUITERS PRACTICUM

Attracting Graduates to Industry

Jamie Ferguson, Maxwell Drummond

w w w . P e n n E n e r g y J O B S . c o m

SPRING 2013

A PENNWELL PUBL ICAT ION

Stacey Schmidt, Publisher

[email protected]

Dorothy Davis, Content Director

[email protected]

Hilton Price, Editor

[email protected]

Cindy Chamberlin, Art Director

[email protected]

Daniel Greene, Production Manager

[email protected]

Tommie Grigg,

Audience Development Manager

[email protected]

PennWell Corporation

1421 South Sheridan Road

Tulsa, Oklahoma 74112

918 835 3161

PennWell.com

Recruitment Advertising Sales:

Brent Eklund

Petroleum Account Executive

720 535 1264

[email protected]

Ad ve r t i s e r s ’I nde x Chevron .............................................................................................................. C2

Map Search .......................................................................................................... 5

PennEnergy Books ............................................................................................... 9

PennEnergy Research Services .......................................................................... C3

PennEnergy Jobs ................................................................................................ C4

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___________________________________

http://www.PennWell.com

http://www.CareereCast.com

http://www.PennEnergyjobs.com





2 Spring 2013 | FOR JOB OPPORTUNITIES, VISIT www.PennEnergyJOBS.com | EnergyWorkforce

Ed i to r ’ sLe t t e r

AS a member of the PennWell team, PennEnergy’s parent company, I am fast

approaching my seventh year of being engaged in energy. Although my initial

career ambitions were not remotely tied to energy, the knowledge and relationships I

have gained in this industry have changed the course of how I plan to spend the rest of

my working life.

In preparing for this issue, what kept returning was the need to engage the next

group of energy professionals. How do we pass on the passion and commitment needed

to keep this vital industry thriving? We begin by exploring the new leadership needed

in energy on page 3.

For those just starting their

careers, one of the toughest

challenges can be making

the skilled transition from

the classroom to the field.

On page 6 PennEnergy

speaks with three graduates

of BP’s Challenge Program,

a corporate initiative that

addresses this learning gap to

empower new energy professionals to maximize their careers.

Rounding out this edition are insights from career experts with CareerCast

and global search consultancy Maxwell Drummond. Job seekers will learn how to

effectively network after college on page 10, while recruiters will gain an understanding

of what it takes to attract new graduates to the industry on page 12.

PennEnergy is immersed in the companies, projects, policies and people that impact

all segments of our industry. Most importantly, we are charged with providing content

resources that matter to the true experts, the energy workforce, so you might energize

the next.

Carpe diem!

—Dorothy Davis

Energizing the Next

“Although my initial career ambitions were not remotely

tied to energy, the knowledge and relationships I have

gained in this industry have changed the course of

how I plan to spend the rest of my working life.”

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Cover STORY

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EnergyWorkforce | FOR JOB OPPORTUNITIES, VISIT www.PennEnergyJOBS.com | Spring 2013 3

The New Leadership Needed in EnergyBy Dorothy Davis

IN the Fall semester of 2012 The

University of Tulsa (TU) launched

a new energy focused post-graduate

degree offering, the online Master

of Energy Business program. As the

content director for PennEnergy, I was

invited to join a speaking panel that

would address the first class.

Initially, I chose to focus my speech

on the growing trend of integration be-

tween the power and oil & gas sectors.

However, the night before my presen-

tation I had the opportunity to attend

a dinner with those students and enjoy

several presentations from prominent

members of the energy industry. What

I heard that evening not only inspired

me to shift the focus of my presentation

for those incoming TU post-grads, but

was successful in setting me on a path of

active industry advocacy and education.

Along with learning about some ex-

citing new project developments and the

robust growth of the energy sectors, what

stood out was the enthusiastic call from

those already tenured in the industry to

encourage those in attendance to seek

positions of leadership. What they want-

ed most for the energy sectors was to in-

spire others to take up the mantles of re-

sponsibility, service and innovation.

Part of what was so

moving about this expe-

rience is that until my

move to Tulsa, Okla-

homa, in 2001, I had

next to no knowledge of

the industry that pow-

ered my world. While

raised and educated in

New York City as a mas-

sive consumer of energy

products and services,

the industry remained

something abstract for

me. Even as an active

member of community

programs which focused on raising envi-

ronmental awareness, energy remained

a peripheral. I was disconnected from

just how connected I was.

In late 2006 I began my career with

PennWell, a business to business media

company serving the energy sectors. I

came into this field with a background

in human services and communica-

tions, but found here an opportunity to

maximize my existing skills and chal-

lenge me toward establishing a success-

ful new career. A career that for me, and

I am certain for many you, has since be-

come a passion.

Now here I am, a pro-

fessional under 40 going

into my seventh year

within a corporation

that has been function-

ing in energy for over a

century. As a young pro-

fessional in service to an

industry both vast and

demanding I can no lon-

ger imagine doing any-

thing else. Energy after

all touches everything.

While my role in en-

ergy is primarily an out-

lying one, the demands of

my position are not much different from

what many of you will encounter as they

advance. Rather than requiring exper-

tise in a singular sector, my position re-

quires that I cultivate a level of exper-

tise across the industry as a whole. And

not just the industry of today, but its rich

history as I work to stay at the forefront

of what is ahead.

The most important detail in all of

this is that my experience is not the

exception. Today, energy profession-

als both in outlying roles such as mine

and in more direct fields such as engi-

neering or the geosciences will need

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to possess a broad skill set to remain

competitive. Not just competitive, but

in moving the industry forward. That’s

what clicked for me that evening. What

I needed to share with those incoming

post-graduates was not an overview of

the growing trends and benefits of cross

sector collaboration, but the benefits of

cultivating strong leaders to drive it.

The needs of the industry are broad-

ening. Energy now, not in some unspec-

ified future, is actively recruiting its next

thought leaders. Further, from what I was

hearing the key concepts behind the suc-

cess of that leadership will be diversity,

collaboration and innovation. While

functional and technical specialists will

always be needed, those beginning or

continuing their professional lives with-

in today’s energy must bring more to the

table. Programs like TU’s Master of En-

ergy Business are an important step, but

understand it’s just the beginning. True

masters never stop seeking knowledge.

To quote Eric Hoffer, American so-

cial writer and recipient of the Presiden-

tial Medal of Freedom, “In a time of dras-

tic change, it is the learners who inherit

the future.”

Make no mistake; this is a time of

drastic change. While the energy indus-

try has long been subject to intense cy-

cles, what is on the horizon for our sec-

tors is far more significant than a period

of boom or bust.

The new leaders of our industry will

be challenged with maintaining many

of the core initiatives and values that

have strengthened energy since its ear-

liest years while finding the means to

integrate an evolving culture of diversi-

ty, collaboration and innovation.

The message being shared was that

while it is a very good time to be in en-

ergy, it’s an even better time to be a

trailblazer.

As the industry average continues to

near retirement age, most companies are

bracing to see around half of their profes-

sional staff leave within the next decade.

Further complicating matters, is the fact

that a good portion of those numbers rep-

resents the industry’s current leadership.

Meanwhile, the U.S. Energy Infor-

mation Administration forecasts that de-

mand is expected to rise more than 40

percent over the next 25 years. To frame

this more plainly, we are losing close to

half of our industry professionals as de-

mand will nearly double. This presents

both a daunting challenge and an im-

mense opportunity.

We must encourage young profession-

als to be the leaders this industry needs

and get fully engaged in energy. We must

also encourage energy companies to

broaden their horizons through training

resources and recruitment efforts beyond

traditional industry focused degrees.

The industry today requires all

hands, across all decks. The burdens

of a strained global economy, increas-

ing regulation, resource limitations and

the need to modernize are not oil &

gas problems, utility problems or infra-

structure problems, they are global chal-

lenges. As our industry moves ahead in

finding ways to connect and integrate

diverse resources, the energy sectors

must also strive to do the same with

their business resources. How? I return

again to diversity, collaboration and in-

novation. These will drive our evolving

industry and its new imperatives.

To grow we must be all-of-the above

in all things. I do not say that lightly and

certainly not as the echo of any political-

ly biased policy. It is meant as a univer-

sal way forward that respects the heritage

of our industry while taking the neces-

sary steps to ensure it continues to thrive.

There is a bright future for all sectors

if we can apply the principles of diver-

sity, collaboration and innovation. Re-

newables are in their awkward adoles-

cent phase and like unruly teenagers

with proper guidance and development

they will prosper and be so worth it. Coal

is facing brutal regulation. To play on

the title of a favorite movie, we must ac-

cept this is no country for old coal. Old

being the operative word in that turn of

phrase; coal is too abundant for the in-

dustry to do anything but cultivate new

ways to harness its power both efficient-

ly and profitably.

While unconventional natural gas

has us swooning, the past has taught us

not to rely too heavily on any single re-

source. Natural gas has its place and it is

in being one part of a dynamic portfo-

lio of energy resources. Hydrocarbons in

general must be approached differently.

While we continue to make great strides

in exploration and production we know

resources are indeed limited. But our vi-

sions and our talents are not. There is al-

ways a way forward.

In my mind, the way ahead is through

a cultivated thought leadership bold

enough to cross boundaries and inte-

grate to meet challenges. We start with

ourselves by taking on the responsibility

of being energy stewards. In doing so we

inspire the next to diversify, collaborate

and innovate! ⊗

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Skilled Transition

How one corporate training program is helping

industry graduates energize for the future.

By Hilton Price

PREPARATION through education

and training is the cornerstone

of entry into the power and pe-

troleum industries. For new graduates

and recruits, it is preparation that pro-

vides the tools to stand out from the

crowd. For the companies hiring these

men and women, it is preparation they

look for when determining who will be

essential staff moving forward.

BP’s Challenge Program is a glob-

al initiative for new graduate recruits in

their first three years with the compa-

ny. PennEnergy had the chance to in-

terview three graduates of the program,

to discuss how it supplemented their ed-

ucation and prepared them for careers

in the industry.

Here’s what they had to say.

Tracy Gunness

Tracy Gunness is a geologist current-

ly working in Upstream: Exploration

and Appraisal for BP in Trinidad and

Tobago. The graduate of the University

of the West Indies, St. Augustine, Gun-

ness joined the company following an

internship experience. She is current-

ly in the second year of BP’s Challenge

Program and is working on an appraisal

project involving the Manakin field on

the border of Trinidad and Venezuela.

As a first year Challenger Gunness won

Technofest, a global competition for

BP’s Challengers.

As a BP intern, did you feel prepared

to handle the challenges ahead of you?

How effective was the education you’d

had before joining the BP internship

program?

TG: I graduated at the top of my

class from the University of the West

Indies, St. Augustine, with a Bachelor’s

degree and First Class Honors in pe-

troleum geosciences. While the uni-

versity helped prepare me for the in-

ternship, at BP Trinidad and Tobago I

had a great opportunity to participate

in a real life project that I used for my

university thesis. The project allowed

me to apply my knowledge from uni-

versity and integrate different aspects

of subsurface, which aided in develop-

ing my technical ability in a holistic

manner far beyond what I could have

achieved solely from university studies.

I was very impressed that BP entrust-

ed in me to lead and complete such an

important project. It was such a great

experience that set the foundation for

my entrance into the company.

As a BP Challenger, you won the Tech-

nofest. What elements of that win were

directly fueled by education and train-

ing through BP?

TG: My coaches definitely believed

in me before they knew what I was ca-

pable of, since I entered the competi-

tion only a few months after joining the

company as a Challenger. They even

envisioned me winning globally before

the results of the local round were even

announced. Their enthusiasm and con-

fidence in my ability inspired me to al-

ways bring my best to the table. I tru-

ly believe that even though I stood as

an individual in the competition, we

won as a team since my win is a testa-

ment to the great coaching that I re-

ceived throughout my project and to

date. That’s one thing I like about BP.

The company takes pride in teaching

and developing the skills of others.

TRAINING Insights

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Tess us about an experience you had as

an intern that fueled your professional

development.

TG: The story that always sticks out for

me was when I first started my internship I

was given several objectives for my project.

I was basically tasked to determine fault

evolution, timing and linkage for the area

with some additional geochemical work.

When I finished the task, I knew some-

thing was missing to complete the story, so

I showed my data to the team leader and he

told me to take the project and run with it.

I was really surprised! I thought they would

send this project to someone more senior,

but my supervisor trusted me to get the job

done and I got the go ahead. I took my data

and integrated it to create an evolutionary

model for the area that showed trap for-

mation and modification through time,

as well as gas migration and accumulation.

Then, I used the model to identify where

the best sites could be for exploration. I pre-

sented the work that I had done to my su-

pervisors and other senior decision makers.

They were pleasantly surprised and hap-

py about what I discovered and presented.

They even said that the project I led was

more on a Masters level, not a bachelor’s

level, which was quite satisfying to hear.

How has the Challenge Program sup-

plemented your existing education?

TG: Since I am still relatively new to

the working world, I would say the ob-

stacles I face are the same as any new

employee – developing the right techni-

cal skills, working alongside a team and

adapting to a new environment.

The Challenge Program has helped

supplement my existing education by

providing consistent, structured learn-

ing and development throughout the first

three years of my career. I am constantly

impressed by the way BP invests time

and resources to help new employees

through comprehensive training cours-

es. These courses are designed in such a

way to bridge the gap between academia

and the industry. They set the founda-

tion with a strong technical understand-

ing followed by exercises in industrial ap-

plication and examples.

It has also helped me grow profession-

ally by providing a roadmap for my career

and allowing me to sample three differ-

ent roles within the organization.

What were the biggest benefits of the

BP Challenge Program?

TG: I’m actually still in the Challenge

Program and am at the end of my second

year. Aside from allowing me to sample

two different roles within the organiza-

tion and providing consistent and struc-

tured learning, Challenge has provided

a sense of community and events which

allow us to give back. Since I have been

here, BP staff members have participat-

ed in several community projects, such

as painting schools and feeding the poor.

What makes me most proud to work at

BP is the company’s community interac-

tion and positive impact.

Carter Clemens

Carter Clemens will soon begin a new

international assignment for BP and was

most recently a production engineer in

the San Juan South Basin in Farming-

ton, New Mexico. In New Mexico, Cle-

mens worked with natural gas and coal-

bed methane, managing 200 wells for BP.

Clemens is a graduate from the Universi-

ty of Texas who studied petroleum engi-

neering and joined the company follow-

ing college. A member of the Challenge

Program who recently completed the

program, Clemens also worked in Wyo-

ming initially, where he was in charge of

nearly 400 wells.

What was it like joining BP after col-

lege? Were you overwhelmed entering

the industry, or did you feel your educa-

tion had prepared you properly?

CC: I chose to work at BP because

of its culture. Specifically, I like that the

company employed many young people

as well as the company’s “Challenge” pro-

gram that includes technical training. It’s

like college but now you get to apply what

you learned on actual projects around the

world. College prepared me very well for

the oil industry, but the difference with

BP was that it involved hands-on experi-

ence on actual projects. It has a different

feel to it. For me it was standing at the

wellhead after executing a workover I de-

signed and waiting to see whether the well

came back online- it’s tough to get that in

the classroom.

In New Mexico, you oversee 200 wells

for BP. In Wyoming, it was 400. How

did the Challenge Program prepare you

for that responsibility?

CC: You are given a lot of responsibil-

ity from the beginning here at BP. Chal-

lenge also provides you with a world class

training program. I’ve been able to attend

training programs taught by both univer-

sity professors and BP’s technical experts

which allow you to see a very practical

side to things. You also have a huge peer

base that you can use as a resource. As

soon as you join BP you gain a network

of several hundred people with knowl-

edge on different areas of BP’s business.

It also comes in handy to meet others if

you’re new to Houston or a particular

field location.

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Do you feel the knowledge and experi-

ence of the older generation of oil & gas

professionals is available to you?

CC: At BP our teams work in a very

interactive open air environment and, as

a result, we have full access to technical

experts who really are the superstars of

this industry. They serve as our teachers

and mentors. Along with programs like

Challenge they ensure we’re prepared for

the responsibilities of the job.

What is another memorable element of

your post-college training?

CC: One of the things I’ve enjoyed

most is the field experience. My work

has taken me to Texas, Wyoming, New

Mexico, and Colorado. In addition to the

change in scenery and side trips that these

provide, it’s been helpful more me to see

a wide spectrum of reservoir types. From

an engineering standpoint, different op-

erating conditions provide different chal-

lenges. I feel that the ability to see several

different areas has given me better per-

spective as an engineer. Also, it’s always

fun to tackle new challenges. Out in the

field you gain a big appreciation of how

much impact what you are doing has on

people. It’s motivating.

Michael Wolanski

Michael Wolanski is a Completions En-

gineer on the Magnus Platform in the

North Sea. His role involves drilling wells

using some of the latest technology. His

career highlight to date, has been the

delivery of the world’s first ever subsea

multi-stage acid fracture using a new type

of technology. Michael is 27 years old and

has been with BP for five years.

North Sea platforms present unique

environmental challenges for workers.

How prepared were you for this environ-

ment, and how did training and prepa-

ration through BP influence you?

MW: I worked as an offshore drilling

engineer for the first year of the Chal-

lenge program, during which time I

gained first-hand, operational experi-

ence on a rig. BP did prepare me before

I went to spend time on the platforms.

For instance, as well as receiving standard

technical training, I had basic explosive

awareness training and also underwent

a helicopter crash simulation that taught

me how to escape if an accident were to

occur over water.

What were your impressions of the in-

dustry before you began the Challenge

Program? How were they different upon

completion of the program?

MW: The oil and gas industry and

BP have both been a part of my life since

I was quite young. I remember BP staff

used to come and give talks at my school

and once I was taken on a trip to see one

of their facilities. I think it was this early

exposure that led me to appreciate the im-

portance of the sector in delivering ener-

gy to the UK and also the contribution it

makes to the economy. This undoubtedly

influenced my decision to enroll in a BP

summer internship in 2006. The intern-

ship was in completions and I enjoyed the

experience so much that I decided it was

the field I wanted to work in, and BP was

the company I wanted to work for. For-

tunately, I was offered a conditional po-

sition, which motivated me to work even

harder in the final year of my robotics and

cybertronics degree. In the end, I got the

results I needed and was able to join BP’s

graduate program in 2007.

What has impressed me throughout

my career at BP is how much knowl-

edge we have in the industry and what

we are able to achieve technically. The

scale and accuracy of the drilling, for in-

stance, is mind blowing. I am currently

writing the procedure to install the com-

pletion in a well that more than five miles

long, and despite its huge scale, the well

will hit very precise coordinates to access

hydrocarbons.

You garnered praise for delivery of the

world’s first ever subsea multi-stage acid

fracture using a new technology. How

did BP’s training and education aid in

this process for you?

MW: I worked with a team to devel-

op and deliver the world’s first ever sub-

sea multi-stage acid fracture, using a new

type of technology. Technically, it was the

most interesting piece of work I have ever

undertaken.

It involved designing a system that

would activate various components by

dropping different sizes of activation

balls. This was done while pumping acid

at high rate and high pressure.

To give an idea of scale, the acid was

pumped at a rate that could fill a bath-

tub in about a second and at a pressure

that is the equivalent of an elephant

It’s like college but now you get to apply what you

learned on actual projects around the world.

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Books, Books…

So Many Books

Check out over 50,000 energy industry titles at

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t Oil & Gas

t Power Systems

t Renewable Energy

t Business Management

t Mechanical & Chemical Engineering


standing on an inch of space. The sys-

tem was significant because it could po-

tentially enable access to more hydrocar-

bons, changing how financially viable it

was to further develop certain areas of

the field we were working on.

Speak a little on preparation, how it has

factored into your career, and how it can

be best addressed for newcomers to the

industry.

MW: The work you get to do at BP

is extremely interesting, but it can be

a steep learning curve. Fortunately, it’s

a great environment to learn in, as the

people working at BP have a lot of ex-

perience to share. You end up learning

a lot from colleagues in both formal

and informal settings and there is al-

ways support if you need it. I also have

a mentor who I meet with on a regular

basis to look at technical challenges.

I also act as a mentor and technical

coach to a number of summer interns

and new BP engineers, which is very

rewarding.

What were your biggest surprises from

training with BP?

MW: I think it’s that every day is dif-

ferent. Some days you receive techni-

cal training, other days its health and

safety training, but it’s that variety that

keeps things interesting. The role itself

is similarly diverse, and some days are

spent performing in depth engineering,

such as stress analysis, and others can

be spent at a vendor’s office looking at

new products.

What more can the company do to aid

in training future candidates?

MW: BP invested heavily in my

training during the Challenge pro-

gram and has continued to support me

in my subsequent career and I think

the company does a good job of devel-

oping young talent. However, there is

room for improving training across all

companies operating in the sector. We

need to become better, as an industry,

at sharing best practices and in collab-

orating to deliver standardized training

across companies. ⊗

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http://www.PennEnergy.com

http://www.PennEnergy.com






CAREER Insights

Networking After CollegeBy Tony Lee

TRYING to find a job

by calling people you

don’t know and asking

them for help probably sounds

dreadful, like a cross between

telemarketing and door-to-

door sales. After all, nobody

likes rejection, and this job-

search strategy is sure to pro-

voke a rash of apologies and

unreturned phone calls.

Yet, what if it works? What

if you can find a great job sim-

ply by making phone calls and

meeting with people who want to help

you? Would you try it? That’s the prem-

ise behind networking, the practice of

contacting everyone you know (and ev-

eryone they know) to ask for their advice

and support. And it works.

A survey of more than 1500 success-

ful job hunters shows that 63% found

new positions by tapping their networks

of friends, family members, acquaintanc-

es and anyone else who would help. In

comparison, only 11% found jobs by an-

swering ads, and just 2% by sending un-

solicited resumes to company recruiters,

reports a New York-based career consult-

ing firm.

Although most job hunters have

heard successful networking stories from

friends and colleagues, some avoid the

technique because they don’t like the way

it sounds. They hate the idea of “using”

people to find a job, and the equate net-

working with sleazy tactics used by un-

scrupulous salesmen.

“It sounds like a ‘what can you do for

me’ kinds of tactic that I’d only try if I

knew I’d never see the person again,” says

one recent college graduate. He couldn’t

be more wrong.

An effective networking relationship

helps both parties. Contacts enjoy talking

about themselves, how they got jobs after

college and how companies in their in-

dustry are doing. And if they can match

you up with a job somewhere, they’re do-

ing both you and your new employer a fa-

vor that they hope will be returned one

day. It’s a win-win situation.

Where to Start?

The best people to enlist as you

launch a networking campaign

are those you know well and

who know you, such as:

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cousins and any other relatives

who are willing to help, includ-

ing your parents

College friends now in the

workplace

Past professors who also work as

consultants or who have left ac-

ademia for the business world

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or part-time jobs, internships or work-

study assignments

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Write down a list of people who might

have information on available jobs or,

more importantly, who know other peo-

ple who might be helpful. Realize the

importance of building a wide range of

contacts. Although many of these peo-

ple may never hear about job openings,

they’re critical because of the many

friends and contacts they’ll refer to you.

Next, decide what you’ll say when you

reach people on your list. An approach

that works well is to first explain your sta-

tus (eg, a recent graduate) and your in-

terest (to gather information about hir-

ing trends in their industry and names

of others who might help you). If the per-

son says she doesn’t know of any open-

ings, reiterate that what you really want

is her opinion of the hiring market and

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_________

_____________

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http://www.careercast.com

http://www.jobrated.com

http://www.careercast.com


the names of people who might know of

openings. With this reassurance, most

contacts will agree to a brief call, or will

at least call back with a name or two. If

the contact still doesn’t understand, say

thanks and move on.

When calling a contact you don’t

know who was referred to you, use the

same two-part approach, but add a new

introduction: “Hello, Mr. Jones. My for-

mer college roommate Jill Smith sug-

gested I call you.” Or, “Jill Smith at ABC

Corp. thought you might be able to help

me.” Then explain your status and inter-

est and ask for a brief meeting.

Most people love to give

advice and are very willing

to talk about their filed and

the job market if you ap-

proach them the right way,

say career counselors, who

say that recent grads typi-

cally face three types of po-

tential contacts when net-

working. About 25% are real nice and will

help you no matter what you say. About

25% are mean and won’t help no matter

how good or polite you are. The rest are

in the middle and will respond based on

how well you approach them. If you act

like you’re going to plop yourself down in

their chair and say, “Tell me everything

you know,” they won’t help. You have to

guide them, coach them and ask good

questions, they say.

Sometimes your best contact is the

most unlikely. Christine Bowman inter-

viewed on campus for insurance and sales

positions before graduating with a busi-

ness administration degree from the Uni-

versity of Iowa. But she landed her present

position as a staff accountant in Chica-

go through her boyfriend’s sister-in-law.

“Knowing the right people at the

right time helped me get the job,” says

Bowman.

Preparation is Key

To elicit someone’s support in a phone

call, know all you can about the person

you’re calling. Getting through to a con-

tact and making arrangements to see

that person isn’t a victory. That comes

only after you’ve completed a success-

ful interview, and that doesn’t happen

by accident.

Career counselors suggest research-

ing contacts’ companies and industries

before each meeting. Develop an under-

standing of each person’s interests so that

you can discuss your education and ex-

perience as it relates to their background

and to potential needs in the market-

place, he says.

After a successful exchange, send a

thank-you email; then continue to con-

tact the person every month or so to re-

port your progress and ask for new leads.

Don’t become a pest, but don’t think that

one five minute call or meeting will en-

gage their attention.

“You need to be relentless in using

your network contacts, but don’t be de-

fensive if they don’t return your calls,”

says Taunee Besson, president of a career

consulting firm in Dallas, Texas. If you

rely on contacts to remember you weeks

after a brief meeting or phone call, you’ll

likely be disappointed.

Proven Approaches

To launch and maintain an effective net-

working campaign, consider the follow-

ing five tips suggested by Ms. Besson:

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Determine who you want to meet early

on and what you want to find out from

each person. As you efforts progress,

evaluate the types of people who are

most helpful and try to contact others

who share their attributes.

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TDIFEVMF

The months before graduation can be

crazy, but you need to devote at least

15 or 20 minutes to your network each

day for it to pay off. Remember, the

best time to reach most executives by

phone is early (before 8 am) and late

(after 5:30 pm).

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TBSJMZ�MJLF�DBO�CF�IFMQGVM

Sometimes, they’re the most objective

sources of solid information. On the

other hand, people you like and with

whom you share common interests will

be your most valued contacts over time.

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JOH�B�GSJFOETIJQ�m�SBUIFS�UIBO�HFUUJOH�

TPNFUIJOH�m�ZPVS�QSJNBSZ�HPBM

If they like you, people who lack useful

information now will think of you when

an opening arises.

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Campus groups are great, but reach be-

yond them to join organizations com-

posed of working professionals who can

serve as terrific contacts and mentors.

Networking isn’t easy, but compared

to most other job-search strategies out

there, it’s a highly effective technique

you can’t afford to ignore. ⊗

Sometimes your best contact

is the most unlikely

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RECRUITER’S Practicum

Attracting graduates to industryBy Jamie Ferguson

THE oil and gas industry offers

new entrants a diverse range of

challenging career options with

longevity, variety and opportunities for

world-wide travel. However, the pub-

lic’s perception of the industry is often

distorted. Many people living outside

energy hubs like Aberdeen, Calgary

and Houston are unaware of the impor-

tance of the oil and gas sec-

tor in the global economy,

supporting hundreds of

thousands of jobs, contributing

billions of dollars every year to Govern-

ments and supplying the vast majority of

the world’s energy needs. How to attract

young professionals to the oil and gas

industry is high on the agenda at OTC

2012 with a whole event dedicated to

the subject on the opening day.

Figures from the World Petroleum

Council found that 50 percent of its 60

member countries’ workforce is due to

retire in the next ten years. Over the

years, environmental disasters and safe-

ty breaches have contributed to a some-

what negative public opinion of the

energy industry. Last year, research by

the Gallup Organization found only

20% of participants viewed the oil and

gas industry positively- ranking sec-

ond last. This negative perception has

a direct affect on the ability to attract

emerging talent.

Parents of 20-somethings consider-

ing their career path may warn their

children of what was previously an

unstable industry. The energy market

is dictated by oil prices and fluctuating

prices in the 1990’s meant downsizing

and less hiring. As

a result, average work-

force age in developed economies is

somewhere in the mid to late 40s.

The ability to locate hidden reserves

and extract precious hydrocarbons is

based on a comprehensive understand-

ing of science, math and engineering.

These are subjects fewer students in

the Western World are keen to pursue.

In contrast to India and China where 1

million engineering students graduate

annually, 120,000 engineering students

in the U.S is extremely low.

How do we re-position the oil and gas

industry as an attractive career choice to

today’s young graduates? As an indus-

try, we should do more collectively to

engage talent in the countries we oper-

ate. We need to collaborate with

academia and with govern-

ment sectors. Many major oil

companies for example, have long-

term research commitments with major

universities around the world. We must

be proactive in our attempt to reach the

young as they are about to enter univer-

sity and again whilst they are contem-

plating career choices. We should edu-

cate the public about the investment

that the industry makes annually in

research and development, the diversity

of the geographical locations in which

they could live and work, the many

technically challenging projects exe-

cuted each year, the advances in envi-

ronmental safety and how lucrative a

career in the oil and gas industry can

be compared to others. There is mile-

age in the idea that the career choices

of the young should be seen as the larg-

est investment that the industry makes.

It should be tackled with all the same

effort, cunning and intelligence that a

consumer company harnesses when it

looks to attract its customers; especially

so, as energy and the humans that play a

part in producing it, are the life blood of

our civilization. ⊗

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_________________________

http://www.pennenergyresearch.com





We’ve got people.

PennEnergy JOBS is the key to attracting the

energy industry professionals you need to hire to

meet your business goals. Our process puts your

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This approach offers you the flexibility to create

custom recruitment advertising campaigns best

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| Learn More |

Visit: www.PennEnergyJOBS.com

Call: 1-800-738-0134

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