offshore engineer-october 2012

R E Q U I R E D R E A D I N G F O R T H E G L O B A L O I L & G A S I N D U S T R Y S I N C E 1 9 7 5

PLUS: HAS ANYONE FATHOMED OUT THE POTENTIAL MARKET DEPTH OF SEABED-BASED SEISMIC?

OCTO

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OFFSHORE ENGINEER

Breathing new life into the Norwegian shelf

Dutch debut for tight-gas horizontal well fracturing

Beefing up in Brazil

OCTOBER 2012DRILLING &

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PIPELINE RESEARCH l SUBSEA VESSELS

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Content is copyright protected and provided for personal use only - not for reproduction or retransmission.For reprints please contact the Publisher.

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OctObER 2012

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Pemex payback; braked Alaska; BP’s saline solution; Chinook online; Ghana gains; Mozambique move; Berangan break; Bonita bounty; Plains sailing; Åsgard tie-in first; Geitungen delivers; Gorgon grows; Norway’s mature mix.

With massive investment and aggressive technology development required to match world energy demand in coming decades, South America’s ‘southern cone’ will have a big role to play. Russell McCulley reports from Rio de Janeiro. PLUS: Statoil plans four-well Barents drilling campaign – but its Arctic ambitions go much farther; Caribbean concerns over regional spill preparedness; magnet motor is the key to new multiphase subsea pump system; DNV-FNI study looks to bridge the Arctic ‘perception gaps’.

New software for the offshore and shipping industries, including optimal voyage planning for safe journeys and minimum fuel consumption, are expected to emerge from a partnership agreement between Star Information Systems and weather experts StormGeo. Meg Chesshyre explains.

Sometimes the surf seems to be up, but those big waves that make the surfer’s day just don’t quite materialise. That more or less sums up where proponents of ocean bottom seismic surveying sit right now, observes Andrew McBarnet.

Brazil’s oil & gas potential continues to grab the industry headlines, with Petrobras confirming more than a score of offshore discoveries, most of them deepwater, in the last 18 months alone. Newcomer OGX confirmed a number of discoveries too, albeit in the country’s shallower waters. It’s not all plain sailing though, as Jennifer Pallanich notes.

9/10 DIGEST

13-20 ANALYSIS

24 BUSINESS

27-30 G&G NOTEBOOK

31-39 BRAZIL OFFSHORE

contentswww.offshore-engineer.com Number 10Volume 37

COVERThe largest semisubmersible production platform yet built in Brazil – P-55 – takes shape for Petrobras at the Rio Grande Naval Hub in preparation for a scheduled September 2013 startup in the 1500-1900m water depths of the Campos Basin’s Roncador field. Not all of Brazil’s ambitious floating hardware construction efforts are going strictly to plan, however, with the Petrobras hierarchy laying the blame on ‘excessive optimism’ and ‘unrealistic ramp ups’ (see page 31).

oe_contentsOCT.indd 3 28/09/2012 14:15


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A number of operators on the Norwegian shelf revealed updates of their field development plans at the recent Offshore Northern Seas (ONS) conference in Stavanger, with a substantial list of projects and refurbishments going forward as part of the revitalisation of the Norwegian shelf. Meg Chesshyre has the details.

The effective development of low-permeability tight gas reservoir resources requires operational efficiency to improve production performance. In this opener to OE’s two-part drilling & completions review, Erik Schrama, Robin Naughton-Rumbo and Fred van der Bas, Shell; Josef Shaoul, Fenix Consulting Delft; and Mark Norris, Schlumberger discuss the North Sea’s first true tight-gas horizontal well fracturing application.

An innovative cased-hole expandable liner system has been deployed to repair casing corrosion in an offshore Congo well. Weatherford’s Scott Durment and Doug Farley explain why and how.

‘Effective tension’ is one of the key concepts in pipeline and marine riser engineering since it tells the user how to account for the pressure in the fluid inside and outside the pipe. Although known and understood for at least 60 years, engineers still sometimes overlook it and get into trouble. Prof Andrew Palmer and Agustony Sabtian discuss the outcome of a recent National University of Singapore experiment aimed at removing any remaining uncertainty.

New or upgraded vessels have been very much in evidence lately as the subsea and deepwater vessel markets continue to grow and more renewable energy opportunities emerge. Reports by Meg Chesshyre and Russell McCulley.

As Israel/Iran tensions ratchet up, Prof Michael J Economides sees an interesting sub-text developing over the role of Iran’s traditional backer, Russia.

OE contacts (6), Contracts (10), Offshore data (15), Rig market (20), Letters (22), Products in action (65/66), Firms & Faces (69-73), Diary (74), Display advertisers index (77).

40-43 NORWAY OFFSHORE

45-48 FRACTURING FIRST

51-53 CONGO CASING

54-58 PIPE POSER

60-63 VESSELS IN ACTION

78 EBB & FLOW

REGULAR FEATURES

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E N G I N E E R I N G P L A S T I C S O L U T I O N S

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US POSTAL INFORMATION: offshore Engineer (UsPs 017-058); (Issn 0305-876X) is published monthly by atlantic communications LLc, 1635 W alabama, Houston, tX 77006-4101. Periodicals postage paid at Houston, tX and additional offices. Postmaster: send address changes to offshore Engineer, atlantic communications, Po Box 2126, skokie, IL 60076-7826.

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1. Publication title: OE (Offshore Engineer).2. Publication number: 0305-876X.3. Filing date: September 7, 2012.4. Issue frequency: Monthly.5. Number of issues published annually: 12.6. Annual subscription price: $160.00.7a. Complete mailing address of known office of publication:Atlantic Communications, 1635 W Alabama, Houston, TX 77006-4101.7b. Contact person: Brion Palmer.7c: Contact tel: 713-874-2216.8. Complete mailing address of known office of publisher:Atlantic Communications, 1635 W Alabama, Houston, TX 77006-4101.9a: Full name and complete mailing address of publisher:Brion Palmer, 1635 W Alabama, Houston, TX 77006-4101.9b: Full name and complete mailing address of editor:David Morgan, The Arena, Stockley Park, Uxbridge, Middlesex UB11 1AA, UK.9c: Full name and complete mailing address of managing editor:David Morgan, The Arena, Stockley Park, Uxbridge, Middlesex UB11 1AA, UK.10: Owners: International Exhibitions Inc (50%), 1635 W Alabama, Houston, TX 77006-4101; PL Investments (50%), 1635 W Alabama, Houston, TX 77006-410111: Known bondholders, mortgagees, and other security holders owning or holding 1% or more of total amount of bonds, mortgages or other securities:None.12: Tax status: Has not changed during preceding 12 months.13: Publication title: OE (Offshore Engineer).14: Issue date for circulation data below: August 2012.15: Extent and nature of circulation:

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a. Total number of copies 29,209 29,329b. Paid and/or requested circulation:1. Paid/requested outside-county mail subscriptions stated on Form 3541 12,628 13,1882. Paid in-county subscriptions stated on Form 3541 3. Sales through dealers and carriers, street vendors, counter sales and other non-USPS paid distribution 14,227 14,4834. Other classes mailed through the USPS 0 0c. Total paid and/or requested circulation 26,855 27,671d. Free distribution by mail:1. Outside-county as stated on Form 3541 0 02. In-county as stated on Form 3541 0 03. Other classes mailed through the USPS 0 04. Free distribution outside the mail 2,354 1,658e. Total free distribution 2,354 1,658f. Total distribution 29,209 29,329g. Copies not distributed 0 0h. Total 29,209 29,329i. Percent paid and/or requested circulation 91.9 94.3

No of copiesof single issuepublishednearest tofiling date

Average no ofcopies eachissue duringpreceding12 months

oe_contactsOCT.indd 6 28/09/2012 18:44


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digest

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digest

will enable the production of some 42 million barrels of additional oil compared to waterflooding with untreated seawater, making a significant contribution to the estimated 640 million barrels of recoverable oil from the development. BP plans to deploy Lo Sal in all appropriate oil field developments from now on, and has at least five new and retrofit projects under evaluation beyond Clair Ridge, with the Mad Dog phase two project in the Gulf of Mexico expected to be the second application of Lo Sal.

of Shetland. Lo Sal, which BP started investigating in the 1990s, is based on a fundamental understanding of the chemistry which binds oil molecules to rock surfaces in reservoirs. BP found that by injecting lower salinity water into reservoirs, these bonds can be weakened, allowing more oil to be flushed out. Clair Ridge, which will have two platforms and is expected to come onstream in 2016, will include desalination facilities at a cost of around $120 million to create low salinity water from seawater. The operator estimates this

drilling program calls for up to four wells in the Beaufort Sea and up to six wells in the Chukchi Sea. US regulators in August signed off on top hole drilling but are waiting for the containment system to be successfully tested before granting final approval to the program.

Saline SolutionBP is to use its proprietary Lo Sal enhanced oil recovery technology for the first time on a large-scale offshore project, for reservoir waterflooding at the £4.5 billion Clair Ridge development, West

Pemex PaybackMexican state operator Pemex chalked up its first deepwater light crude oil discovery in the Gulf of Mexico in late August with the Trión 1 well, drilled in 2500m water depths 39km south of the maritime border with the US. The well encountered 320m of pay in formations with 18-25% porosity and permeability of up to 250mD, ‘just enough to guarantee productivity and an estimated flow of up to 10,000b/d,’ Pemex said. The company estimated the find could contain recoverable reserves of 350mmboe. Trión 1 is Pemex’s first well in nearly a decade of deepwater exploration to discover commercially viable crude oil reserves. The Bicentenario rig is drilling ahead to explore deeper Paleocene reservoirs.

braked alaSkaShell revised its 2012 drilling program offshore Alaska after a containment dome, part of an Arctic spill containment system, was damaged during testing. Rather than drilling to hydrocarbon zones as planned, the operator opted to drill as many top hole wells as possible before the Arctic drilling season ends. The wells will be capped and temporarily abandoned while the company awaits final regulatory approval of its multi-year exploration plan. Shell’s 2012/13 Alaska

chinook online: Petrobras announced first production from the chinook field in the deepwater Gulf of mexico 6 September, a little more than six months after the nearby cascade field went onstream. both fields produce to the BW Pioneer, the region’s first FPSo, moored in 2500m of water in Walker ridge block 205. the FPSo has a processing capacity of 80,000b/d of oil and 500,000m3/d of gas, and an oil storage capacity of 500,000 barrels. the chinook-4 well taps lower tertiary reservoirs at a depth of around 8000m. Petrobras operates chinook with 66.67% interest, total holding the remainder. cascade is 100% owned and operated by Petrobras.

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GeitunGen deliversStatoil logged an oil discovery in the Geitungen prospect on Utsira high in the Norwegian North Sea’s PL265 licence. Exploration well 16/2-12, drilled by the Ocean Vanguard to a vertical depth of 2045m in 115m of water, encountered a 35m oil column in a Jurassic reservoir. Statoil estimates recoverable oil equivalents of 140-270mmb at Geitungen.

GorGon GrowsChevron’s Satyr-2 well in the Greater Gorgon Area found 128ft of net gas pay, marking the company’s 15th discovery in Australia since mid-2009. The well, in the WA-374-P permit off Western Australia, was drilled to a depth of 12,454ft in 3570ft of water.

Mature MixNorway’s ministry of petroleum & energy reports record interest in the 2012 Awards in Predefined Areas (APA 2012) on the Norwegian continental shelf, and has received applications from 47 companies. The ministry plans to award new production licences under the round in January 2013. ‘Exploration results in recent years have shown that there is still significant potential for discovering new resources, also in mature areas,’ commented energy minister Ola Borten Moe.

Brazil’s Sergipe-Alagoas Basin. The 1-BRSA-1088-SES well, known as Moita Bonita, found a 300m hydrocarbon column with 52m of porous sandstones bearing light oil, gas and condensates. The well is 35km southwest of the Barra accumulation, where the 1-SES-158 well discovered what Petrobas deemed ‘the first significant signs of gas in ultra-deep waters in the Sergipe-Alagoas Basin.’

Plains sailinGHouston-based independent Plains Exploration & Production acquired a significant chunk of mature deepwater Gulf of Mexico acreage in a $6.11 billion deal with BP and Shell. The acquisition will give the company a production boost of 59,500boe/d, operating interest in five fields and working interest in two others. At a cost of $5.55 billion, Plains will take 100% ownership of BP’s Marlin, Dorado and King fields, collectively known as the Marlin Hub, as well BP’s 100% stake in the Horn Mountain field, 33.33% non-operating interest in the Diana-Hoover field, 31% interest in the Ram Powell field and a 50% operating interest in the Holstein field. Plains also acquired, for around $560 million, the remaining 50% interest in the Holstein field from Shell.

Ghana GainsEni reported the first oil discovery in the Offshore Cape Three Points block in Ghana’s Tano Basin. The Sankofa East-1X well in 825m of water was drilled to a total depth of 3650m and encountered 76m of gross oil pay and 28m of gas and condensate in Cretaceous sandstones. The well produced around 5000b/d during a production test with flow rates constrained by surface infrastructure, Eni said. The company plans to drill more wells to determine the size of the discovery.

MozaMbique MoveTotal has signed a farm-in agreement with operator Petronas to acquire a 40% interest in the PSCs covering two offshore Mozambique blocks – areas 3 and 6 – in water depths ranging up to 2500m. An exploration well is planned by year-end. ‘After Kenya and Uganda, Total is entering into the southern part of the prolific Rovuma Basin, whose potential might equal the gas potential of the northern part,’ said the French supermajor’s SVP exploration & production, Jacques Marraud des Grottes.

beranGan breakLundin Petroleum’s Berangan-1 well in block SB303 offshore Malaysia encountered a gross gas column of more than 165m in mid-Miocene sands. The vertical well was drilled to a total depth of 1709m in 70m of water offshore Sabah, near the Swedish operator’s Tarap and Cempulut gas discoveries. Lundin CEO Ashley Heppenstall said Berangan is the company’s third gas discovery in SB303 and the fourth in the contract area which also includes the Titik Terang discovery. ‘The four gas fields lie within a 10km radius and present a clear opportunity to evaluate the potential for a gas cluster development,’ he added.

bonita bountyPetrobras reported a good quality oil and gas discovery in 2775m of water at the SEAL-M-499 concession in

ContraCt brieFsla subsea wellhead production systems contract awarded by Petrobras to Ge oil & Gas is being hailed as the world’s largest to date. worth almost $1.1 billion, it calls for the delivery of some 380 subsea wellheads and installation tools, with over 75% of the parts expected to be made in brazil.lBaker Hughes has reached an agreement with statoil to provide integrated drilling services for 25 fields on the Norwegian continental shelf. the firm two-year portion of the contract is worth about NKr3 billion, with options to extend by four years. schlumberger landed a four-year contract with statoil for electric wireline services on the Norwegian shelf. the NKr2 billion deal begins 1 February 2013 and includes several extension options.ltechnip secured a €210 million offshore commissioning contract from inpex covering the FPso and central processing facility for the ichthys lnG project in the browse basin, western australia.ldril-Quip won a four-year, $650 million contract with Petrobras for the supply of subsea wellhead systems and associated tools. the equipment will be used in the drilling of deepwater wells offshore Brazil starting in 2H 2013.lschlumberger’s Framo engineering won a $100 million contract with norske shell for the supply of a subsea multiphase booster pump system in 250m of water on the draugen field offshore norway. installation is planned for summer 2014.lRussia’s Vostochniy Offshore structures construction yard was selected by Rosneft and exxonMobil to conduct a concept evaluation and feasibility study for a relocatable Arctic gravity base platform capable of extending the drilling season in the Kara sea’s shallow waters (up to 60m) by several months. lkvaerner will perform the offshore hook-up and commissioning of lundin norway’s 21,000t edvard Grieg topsides under a nkr525 million contract. in May kvaerner landed the platform’s nkr8 billion topside ePC contract. ltechnip was contracted by swiber Offshore Construction to supply flexible pipe to support Brunei shell Petroleum’s Champion waterflood project offshore Brunei. the contract covers the supply of 12 flexible flowlines with a total length of 19km.lsubsea 7 landed a $60 million ePiC contract from talisman energy for development of a gas export pipeline at norway’s varg field.

tie-in tiMe saver: statoil performed what the company claims is the first subsea hot tap installation of a new tie-in point on a live gas pipeline without the line being prepared in advance. the tie-in was installed on the Åsgard b production flowline in 265m of water as part of the Åsgard subsea gas compression project, scheduled to start up in 2015 (OE april). working from technip’s Skandi Arctic, teams used subsea robotics to weld a t-piece onto the live pipeline. a remote-controlled drilling machine then tapped in to the line with no effect on pressure or production, statoil said. ‘when the compressor module and the manifold for Åsgard subsea compression are installed next year, we will connect the pipeline from these to the hot-tap tie-in point,’ said statoil project manager kjell edvard apeland. the hot tap operation took ten days with no interruption of production, setting a cost-saving precedent for future projects, added torstein vinterstø, statoil’s portfolio manager for subsea compression projects.

oe_news.indd 10 28/09/2012 09:55


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ANALYSIS

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Moreover, the US has pledged $5 million to investigate the use of marine methane hydrates for gas. ‘The Department of Energy calls these methane hydrates the world’s largest untapped fossil energy resource, twice as abundant as all of the remaining natural gas and petroleum reserves in the whole world,’ Sieminski noted. ‘The conclusion that I draw from all of this is that resources are not going to be a binding restraint.’ But Sieminski and his fellow panelists acknowledged that efforts to harness those resources will not come easy, or cheap. Bertani, CEO of Rio de Janeiro-based Barra Energia and the first representative from Brazil to hold the top job at the WPC,

Thanks in large part to Brazil’s pre-salt discoveries, unconventional

gas prospects in the US and the Gulf of Mexico’s nascent deepwater plays, ‘peak oil’ warnings from a decade ago proved to be premature, US Energy Information Administration chief Adam Sieminski told an audience midway through this year’s Rio Oil & Gas expo and conference. Sharing a dais with World Petroleum Council president Renato Bertani and Jerome Ferrier, president of the International Gas Union, Sieminski said the EIA, the US Department of Energy’s statistics division, projects that the world holds nearly ten times the 600tcf of shale gas already proved in the US.

Brazil to play key role in energy futureWith massive investment and aggressive technology development required to match world energy demand in coming decades, South America’s ‘southern cone’ will have a big role to play. Russell McCulley reports from Rio de Janeiro.

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supply in the 21st century, or any other century,’ he said. Sieminski said the money to fuel growth in the industry should be readily available ‘as long as markets are allowed to function’. ‘International oil companies will invest if the rate of return is attractive. This does not even have to be a problem for state owned oil companies as long as the model they are working under is appropriate for the goal. Saudi Aramco, for example, has proven to be a global leader in terms of both oil production and advanced technology.’ Others, like Venezuela’s PDVSA, struggle to maintain production as governments extract a heavy toll from profits, he said. Sieminski acknowledged

that oil producers are often hampered by the difficulty of planning investments in an industry beset by

price volatility and the ‘problem of statistical

transparency’ in many developing, resource-rich and energy-hungry countries. But the pre-salt revolution in Brazil, the oil sands of Canada and America’s shale boom ‘could dramatically alter the politics of oil in the next few decades’, he said – provided technology keeps pace. ‘Spending on research, demonstration and development of new energy technology, both in supply and demand, and in operations and controls, has the potential to transform our energy supply in the 21st century in ways that we could hardly have dreamed only a few years ago.’lRigdelaysdampendeepwatercarnival,seefeaturepage31.

he said. ‘Second, governments have to be responsible to their people and to the companies that are operating in their countries.’ Strong capital markets, innovative technology and ‘competent education, universal education’ are critical to sustain growth. ‘These conditions are the basis for providing the foundation of economic growth. But they are also necessary for dealing with the challenges of providing energy

gas pipeline, and ‘regulatory integration’ to ensure safe practices. ‘Not all countries are on the same level in terms of safety,’ Ferrier said. Globally, said Sieminski, the conditions essential for industry growth come down to five points. ‘We need fair and consistent legal systems in the countries that are producing the energy,’

pointed out that world oil consumption is projected to grow by 2.3% annually, to 108-110 million barrels per day by 2030. At the same time, he said, we will witness an annual production decline of 3.5% from fields currently onstream, leaving a gap of around 60-65 million barrels per day that will have to be filled to keep pace. ‘Nevertheless, the reserves are there and are constantly being replaced,’ Bertani said. To keep the taps running, he continued, could require an investment of up to $20 trillion between now and 2030. While some estimates put the remaining global oil reserves at 1.45 trillion barrels, including difficult-to-produce very heavy oil, ‘there is no single company or group of companies that will singly be able to place 60 million barrels of oil per day in the market’, Bertani said. Other potential stumbling blocks are restricted access to acreage and a shortage of workers. ‘We need trained people, and not only here in Brazil,’ he said.

Transnational potentialNoting that ‘Brazil will play a key role in the energy future’, Ferrier focused on the potential for a transnational LNG industry in the southern reaches of South America, and called for development of unconventional resources in Brazil, Argentina and Bolivia. The IGU president said industry groups, South American leaders and stakeholders should meet to discuss the development of LNG infrastructure, including a transcontinental

RioOil&Gasconferencepanelinsession(left to right):EIAchiefAdamSieminski,WPCpresidentRenatoBertani,IBPpresidentJoaoCarlosdeLuca(moderator)andIGUpresidentJeromeFerrier.

OE

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analysis

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Quick statsOE ’s at-a-glance guide to offshore hydrocarbon reserves and key offshore infrastructure globally is updated monthly using data from leading energy analysts infield systems (www.infield.com).

Greenfield reserves 2012-16

Water Field Liquid Gas depth numbers reserves reserves (mmbbl) (bcf) (last month) (last month)

shallow 1216 71,370.99 662,998.25 (1221) (71,567.94) (798,891.25)

Deep 159 14,764.49 69,069.74 (163) (15,767.49) (77,069.74)

Ultra-deep 83 15,000.25 47,441.00 (86) (15,619.45) (49,121.00)

1458 101,135.73 779,508.99

all reserves figures are proven + probable.

Global offshore reserves (mmboe) onstream by water depth

2010 2011 2012 2013 2014 2015 2016

Shallow water 9836.40 10,181.38 27,450.53 53,784.03 36,821.53 40,093.79 30,482.61(last month) (9834.94) (10,176.04) (27,867.49) (55,432.49) (34,824.38) (40,410.36) (54,253.45)

Deep 2422.13 1316.73 2754.45 3500.05 6230.50 6948.06 7542.54(last month) (2422.13) (1321.23) (2945.45) (3150.05) (6567.23) (6867.76) (9849.55)

Ultra-deep 938.06 35.26 1686.30 2636.00 2682.61 4262.97 12,096.68(last month) (938.06) (35.26) (1696.80) (2721.98) (2756.77) (5097.47) (12,006.94)

Total 13,196.59 11,533.38 31,891.28 61,304.51 45,734.64 51,304.82 50,121.84

Production systems worldwide (operational and 2012 onwards)

Floaters: Operational 263 Under construction/conversion 37 Planned/possible 313 613 (613)

Fixed platforms: Operational 9573 Under construction/conversion 146 Planned/possible 1488 11,207 (11,225)

Subsea wells: Operational 4275 Under development 410 Planned/possible 5686 10,371 (10,326)

(last month)

New discoveries announced

Depth range 2009 2010 2011 2012

shallow 113 92 102 39

Deep 37 26 24 14

Ultra-deep 32 31 19 24

Total 182 149 145 77Note: Operators do not announce discovery dates at the time of

discovery, so totals for previous years continue to change.

Pipelines (operational and 2012 onwards)

<8in (km)

Operational/installed 40,756 Planned/possible 22,208 62,964 (62,811)

8-16in Operational/installed 75,047 Planned/possible 47,264 122,311 (121,824)

>16in Operational/installed 85,815 Planned/possible 50101 131,191 (132,235)

(last month)

Reserves in the Golden Triangle by water depth 2012-16

Water Field Liquid Gas depth numbers reserves reserves (mmbbl) (bcf)

Brazilshallow 37 3923.00 16,210.00 Deep 17 3258.75 1760.00 Ultra-deep 31 8585.00 8970.00

United Statesshallow 22 107.95 1416.50 Deep 33 1749.37 2510.78 Ultra-deep 30 3764.25 4314.00

West Africashallow 129 3117.08 14,711.66 Deep 46 7624.00 6450.00 Ultra-deep 15 2490.00 1690.00

360 34,619.40 58,032.94 (last month) (371) (36,377.60) (61,256.94)

Note:shallow water: <500mDeep water: 500-1500mUltra-deep: >1500m

Caribbean concerns

As a number of Caribbean nations set sights on developing potential deepwater reserves, concerns have surfaced about the region’s ability to respond to a

Macondo-style subsea leak. The topic is especially prominent in a swath of sea where tourists, drawn by picture-perfect beaches and rich undersea life, are responsible for a large share of island income. In September, officials from several Caribbean nations joined energy industry representatives in Port of Spain, Trinidad, to discuss lessons from Macondo and to lay the groundwork for a regional emergency response effort. The inaugural ‘One Caribbean – One Response’ forum drew about 100 participants from eight countries, including the Bahamas, Jamaica, Mexico, Cuba and Trinidad & Tobago. The roster of speakers included the former US Bureau of Ocean Energy Management, Regulation & Enforcement director, Michael Bromwich, who oversaw the restructuring of the US offshore regulatory regime after Macondo. Lee Hunt, president emeritus of the International Association of Drilling Contractors and organizer of the conference, said the region has sufficient capacity for surface spill containment but lacks equipment to handle the ‘third dimensional’ nature of a subsea blowout. ‘They know they need to have industry provide the capacity and the resources to handle that third dimensional problem, a subsea response,’ he said, adding that Trinidad & Tobago, which has existing offshore oil and gas infrastructure and is less reliant than its neighbors on tourism, would likely serve as a response staging hub and storage site for a well containment system. Trinidad’s energy minister Kevin Ramnarine has aggressively sought to position the nation as a regional energy hub, Hunt said. ‘He wants to promote Trinidad being the hub for any spill response planning in the region, as well as a hub of general deepwater drilling services for the surrounding companies. They have the infrastructure, they have the ports, they have the harbors, they have the facilities. ‘So rather than duplication [of response systems], I think centralizing a staging area is very much part of his plan, as well sharing the very robust spill response plan that has just been developed for Trinidad & Tobago.’ Spain’s Repsol launched a deepwater drilling program off Cuba this year. Exploration offshore the Bahamas is planned, pending results of an April 2013 referendum on offshore oil & gas activity. A consortium led by Shell has spudded the first deepwater well off French Guiana, while Trinidad recently granted leases for offshore blocks to a number of operators, including BP. Cuba’s entry in deepwater E&P just months after Macondo raised fears in the US that a spill could reach its shores and that the 50-year old US embargo could prevent American companies from offering well control help. Officials from the US and Cuba are fine-tuning protocols of a joint spill response plan, including provisions that grant US companies authority to respond to an emergency in Cuban waters, Hunt said. ‘The professionals in the [US] State Department have come to recognize the significance of US interests in helping the region plan for a potential spill, including one in Cuba,’ he said. ‘My assessment is, the ability of Cuba and its neighbors, including the US, to respond to a spill in Cuba is 100% better than it was two years ago, although it’s not 100% complete.’ RM



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O F F S H O R E E N G I N E E R | o c t o b e r 2 0 1 2 w w w. o f f s h o r e - e n g i n e e r. c o m16

is under way in Beaufort Sea licence 460 offshore western Canada, where Statoil holds 40% interest with operator Chevron holding 60%. Seismic data acquisition is also being gathered at the Shell-operated Anu and Napu prospects offshore west Greenland, in blocks 5 and 8, respectively. Statoil holds non-operating interest in the blocks, and in early 2012 acquired a 30.6% stake in the Cairn Energy-operated Pitu prospect, in block 6. Dodson said the company would make a ‘drill or drop’ decision for the Pitu block next year. Although Ovrum stressed the need for greater co-operation among operators to overcome the considerable technological challenges of Arctic E&P, she said Statoil is working in-house on the Arctic rig concept and development of seismic data acquisition in ice conditions. According to earlier Statoil briefings, the rig will operate in a range of Arctic water depths ‘and will involve integrated operations in drifting ice’. Statoil and researchers from the Norwegian University of Science & Technology launched a research cruise to northeast Greenland in September. The mission will test technologies in ice management, Ovrum said. Norway will hold a Barents Sea drilling round in spring of 2013, with 72 offshore blocks on offer. Revitalising the Norwegian shelf, see feature page 36.

a joint venture agreement with Rosneft to team up on bidding for Arctic licences offshore Norway and to explore the Perseevesky block in the Russian Barents Sea and the Magadan 1, Lisyansky and Kashevarovsky blocks in the Sea of Okhotsk. Drilling in the Russian Arctic could begin in 2016, Dodson said. Meanwhile, Statoil has secured Seadrill’s West Aquarius rig for a three-well drilling programme offshore Newfoundland, Canada to begin later this year. The wells are planned for the Harpoon and Cupid prospects in the Flemish Pass and the Federation prospect in the Jeanne d’Arc Basin. Seismic exploration

from NKr80 million in 2012 to NKr250 million next year, said Margareth Ovrum, EVP of technology, projects and drilling. Ongoing research includes the development of an Arctic drilling rig capable of dynamically positioned station-keeping at shallow water depths of 40m. ‘So far, no robust solution exists for dynamic positioning in ice,’ Ovrum noted. Statoil used the biennial ONS conference and exhibition to set out its multi-year strategy for exploration in the Arctic, which the company says could contain 20%-25% of the word’s undiscovered conventional oil & gas reserves. In May 2012, Statoil entered

Statoil will spud the first of its planned Skrugard wells in the Barents – at

Nunatak – in December and drill and complete four wells at the Nunatak, Kramsno, Skavl and Iskrystall prospects over the following six months. The Norwegian operator’s executive vice president of exploration, Tim Dodson, said at ONS that first production from Skrugard is tentatively scheduled for 2018. The Norwegian Barents Sea is one of the Arctic’s less challenging areas because it lies in a year-round ice-free zone, he said. With the Arctic region believed to contain up to 25% of the world’s yet to be discovered hydrocarbons, ‘we believe these petroleum resources will be critical for a growing world’, he added. ‘We see great potential in the Arctic.’ The drilling program will continue with two to three wells in the Hoop prospect in summer 2013 targeting shallow reservoirs 600m below the surface, Dodson said. Hoop includes the Atlantis and Apollo fields and will mark the northernmost wells drilled in Norway. Seadrill’s West Hercules semi will conduct drilling under a five-year contract. Later in 2013, Statoil will return to the Hammerfest Basin to drill exploration wells at Ensis and Askepott near the existing Goliat and Snøhvit discoveries. Statoil also plans to triple its Arctic research budget

Statoil sets sights on northern lightsStatoil will launch a drilling campaign in the Norwegian Barents Sea before the end of the year with four exploration wells in the Skrugard area, the company announced at this year’s Offshore Northern Seas (ONS) conference in Stavanger. But its Arctic ambitions go much farther, as Russell McCulley reports.

‘So far, no robust solution exists for dynamic positioning in ice.’ Margareth Ovrum

‘We see great potential in the Arctic.’

Tim Dodson

Statoil has contracted Seadrill’s West Hercules ultra-deepwater semi for its Arctic exploration programme. The rig has been prepared for Arctic conditions and is scheduled to begin drilling the Skrugard prospect in December.



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the overall package size while allowing a wider liquid gap between the pump’s rotor and stationary elements. The resultant reduction in drag losses means the pump can operate faster or, at an equivalent rate of an induction machine, with less energy use. According to Perry, a 6MW multiphase pump FMC is developing will be able to withstand pressures of up to 15,000psi and be designed primarily for the Paleogene prospects in the deepwater Gulf of Mexico. ‘If you go with a conventional motor, there’s a limit to how far you can go,’ Perry noted. ‘With this technology, you can break through that limit. The motor is the key.’ RM

will be a robust and efficient pumping system. ‘The motor is new technology, the hydraulics are field proven, and the systems around the pump really call on FMC’s subsea experience,’ Perry said. ‘If you’re an operator, you like to have multiple choices. And this product, where it starts to differentiate is that it gives you a broader application envelope than what’s currently on the market.’ Multiphase pumps enable the entire production stream to be gathered and boosted. The new pump, Perry said, differs from pumps powered by induced electrical currents in that the permanently magnetized motor reduces

we have targeted what we intend to develop and have qualified,’ Halvorsen said. FMC director of subsea processing Rob Perry said combining Sulzer Pumps’ proven hydraulics with FMC’s high-speed permanent magnet motor technology created what

F ull qualification testing of a 3.2MW multiphase subsea pump system

capable of operation in pressures up to 5000psi has now been completed, FMC Technologies and Sulzer Pumps confirmed during Stavanger’s ONS show. Unveiling the new system, Tore Halvorsen, FMC’s senior VP of subsea technologies, described it as a key component in the company’s goal of developing a full subsea ‘factory’ by the end of the decade. ‘We have a technology roadmap that takes us from today’s position all the way to the ambition where we think we can have a truly subsea based system, and each year

cour

tesy

sulz

er pu

mps

Magnet motor key to subsea step change

The pumping system’s permanently magnetized motor.

The new 5000psi-rated, 3.2MW multiphase subsea pump system during final qualification testing.

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shorter shipping routes and confidence that enhanced scientific knowledge and maturing governance processes will ensure Arctic peace and predictability,’ said Knut Ørbeck-Nilssen, chief operating officer of the class society’s Norway, Russia and Finland division. ‘However, this is a highly diverse region that defies simple, clear-cut definitions and generalisations. There are great variations within the Arctic and the public perceptions of promises and risks are polarised as never before: the Arctic as unspoilt nature with an acute need for protection from modern civilisation’s onslaught versus the great new energy frontier that can provide energy security, fortunes and job opportunities along Arctic coasts.’ RM

today, calling for a major effort to reduce the probability of incidents, to prevent accidents from happening, but also to develop systems that can handle emergencies.’ While noting that some barrier disputes remain, the DNV-FNI study maintains that the Arctic ‘is more characterised by co-operation than by conflict’, with most resources clearly under the jurisdictions of the Arctic coastal nations of Russia, Norway, the US, Canada and Denmark/Greenland. The study cites the delimitation agreement between Russia and Norway as a model for settling remaining territorial disputes in the region. ‘Interest in the Arctic is growing rapidly, fuelled by melting sea ice, promises of vast energy and mineral resources, prospects of

DNV and Norway’s Fridtjof Nansen Institute released a joint study

during ONS calling for improved technology, better spill response preparation and greater co-operation among stakeholders in order to safely develop Arctic resources. The study, Energy and the environment – Arctic resource development, risks and responsible management, proposes a ‘performance-based system’ to manage risk in the Arctic along with greater communication between industry, governments and society ‘to bridge perception gaps’. ‘Important remaining challenges require strong focus on technology development,’ the report concludes. ‘Oil spills in ice and escape, evacuation and rescue of personnel are not managed sufficiently

Jackup semis

OE ’s analysis of current rig market data is updated monthly using statistics provided by Rigzone.com

Rig marketUtilization for the worldwide mobile offshore drilling fleet continues to hold steady at 77% – almost five points higher than this time last year. The trailing twelve-month utilization average is at 75%. Floater utilization in the Gulf of Mexico is a robust 93% (excluding cold stacked rigs and rigs that will be leaving the region once they have completed their shipyard stay). Along with recent contract announcements in the ultra-deepwater sector, up to 15 newbuilds will be making their way to the Gulf of Mexico on long-term contracts. A few newbuilds have already arrived and a steady stream of new units will arrive 2013/14. The Gulf of Mexico deepwater rig market is experiencing tightness as many of the units currently in the region are carrying out development work. While most operators in the region are focused on development work in the near term, many are moving forward with exploration plans. The recent central and western Gulf of Mexico lease sales saw vigorous activity for deepwater blocks. As of early September, 75 permits for new wells (both exploratory and development) in water depths greater than 500ft had been approved by the US Bureau of Ocean Energy Management.

Worldwide rig utilization

Jackup

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Bridging the Arctic ‘perception gaps’



oe_advert.indd 1 28/09/2012 16:46


LETT

ERS


unreasonable to assume, therefore, that some of the projects at the planning stage in April 2012 will not make it to project sanction, either. Germany’s other power giant, RWE, declared in 2011 that it had no plans for new fossil power projects because of their ‘poor prospective economics’. While RWE then warned of severe power shortages, E.On now dismisses such concerns as unfounded even though it, too, then warned of massive power cuts as a result of retiring the nuclear fleet. The reasons for shelving plans for new fossil plants appear to be twofold: first there is the massive build-out of renewables and second there is the market-distorting gift of free CO2 certificates bestowed on power companies by the German government. This freebie allows generators to continue to operate very profitably their long-written-off, comparatively inefficient and polluting existing plants and scale back

efficiency lags some 6% behind modern plants. In March 2012 there were still 23 coal fired plants with a combined capacity of 24.7GW under construction or planned. Some of these were at the very early scoping/planning stages and not all would necessarily be realised, considering that a total of 17 previously planned coal projects with a combined capacity of 14.6GW had already been cancelled at that time. Between March and April a further nine coal fired plants

were then apparently axed. And that trend is continuing. On 5 September, E.On announced that it will not build any new coal fired or gas fired power plants in Western Europe because ‘the European market does not until 2020 require additional capacity beyond those projects already under way’. It is not

power plants with a total capacity of 36GW were planned or under construction. Of these, 14 were coal fired plants (15.7GW), 25 gas fired, 22 wind and four pumped storage plants. Arguably, a not insignificant proportion of those 14 coal fired plants are intended to replace existing facilities whose average age exceeds 30 years and whose

POWER PLANTS POSERSir, Professor Economides’s claim that Germany will build 84 new power plants just to offset the retirement of its nuclear assets is not plausible (‘Marching to the wrong tune’, OE August 2012). As of April 2012, some 69

OE welcomes letters reflecting all shades of offshore industry opinion but reserves the right to edit and condense.

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oe_letter.indd 22 28/09/2012 10:18


LETTERS


now reached 25%, second only to that of lignite-fired generating plants, and it continues to grow. Prof Economides is correct in saying that significant fossil generating capacity is still needed, but the time when much of it will not be, may not be too far off. Joachim GroegerIndependent petroleum management consultant, Schneverdingen, Germany

Utilities must frequently sell at knock-down prices their surplus electricity, which arises as a result of renewables enjoying priority access to the grid, to France where additional supplies are needed to shore up its system because the country’s nuclear plants can frequently not meet demand. The renewables’ share of the German electricity supply has

7GW while wind added another 1GW. Increasingly often there is a surplus of electricity attributable to renewables that sometimes cannot even be given away. Economides’s claim that Germany is forced to buy in nuclear-generated electricity from France has been repeatedly debunked as pure power industry propaganda; the opposite is true!

investment in lower return new projects.

Renewables riseThe relentless rise of renewables must have influenced these decisions, too. Uncertainties attached to predictions of the renewables’ market penetration over the next decade may have been one factor, given that past projections have consistently and significantly underestimated their growth. On the other hand, utilities may indeed have a clear view of the further inroads renewables will have made by 2020, and are therefore disinclined to invest in new fossil projects now in order to meet a notional capacity shortfall after 2020 that may never come to pass. By the middle of 2012 installed solar generating capacity in Germany totalled 32GW, while total installed wind capacity stood at around 31GW. Solar capacity in the first half of 2012 alone grew by up to

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oe_letter.indd 23 28/09/2012 10:17


BUSI

NESS


is looking to benefit from a SIS customer base of more than 1500 ships, as well as over 150 offshore units operating globally. Offshore clients include BW Offshore, COSL, Cotemar, Japan Drilling, Northern Offshore, Ocean Rig, Odebrecht, Petrofac and Seadrill. In May this year, StormGeo, as part of a strategic move into the US market for meteorology and weather related services, acquired all outstanding shares of Houston-based ImpactWeather from Universal Weather & Aviation. The combined group now covers all geographic areas of the world on a 24/7 basis. Two years ago it acquired Swedish company Seaware, adding ship dynamics and performance expertise to the mix. SIS has recently completed the installation of its Star Information & Planning System software package for Solstad Offshore’s fleet of 50 fully owned/jointly owned and leased vessels. The contract with Solstad Offshore also includes Star IPS functionality covering planned maintenance, guarantee claims, asset management, projects and document management. Another large software upgrade project currently under way is for Dutch offshore contractor Van Oord’s 90-strong vessel fleet.

customers to build a safer and more cost efficient operation.’ StormGeo chairman Erik Langaker observes: ‘We recognised that there could be an opportunity for StormGeo to integrate other software suppliers’ asset data with our more traditional meteorological forecasting and risk assessment models. The ultimate goal of our new relationship with SIS is to provide customers with an optimum decision platform for safe journeys and minimum fuel consumption. We hope to be able to take optimal voyage planning to a new and more sophisticated level – both on an individual vessel basis, as well as for large fleets servicing offshore and shipping segments.’

Extended networkSIS is expected to benefit from StormGeo’s extended network of office locations around the world – particularly Houston and Dubai. StormGeo operates out of 12 offices in nine countries. SIS, meanwhile, is expanding its operations in Singapore and Brazil. For its part, StormGeo

even more powerful when it is combined with operational data from engine management for handling events and initiating safety measures. SIS chief executive Per Anders Koien says: ‘We see that our customers are facing new and more demanding requirements for safe operations from the authorities and their own customers. We also see that their activity is increasing in more demanding locations, such as Arctic areas. By combining machinery and operational performance information with weather forecasting we can help our

Star Information Systems (SIS) is among the largest providers of software

systems for maintenance, safety management, purchasing and logistics within both the shipping and offshore sectors. StormGeo lays claim to being the world’s leading provider of meteorological decision systems to the offshore industry and is experiencing rapid growth in the more traditional shipping sector. In agreeing to work together on the development of leading edge software – with StormGeo taking a 15% stake in SIS, with an option to increase this in the future, and its chairman Erik Langaker becoming SIS’ non-executive chairman – the two companies are looking to have the first fruits of their partnership on the market within 12 months. Detailed meteorological information and decisions already provide the shipping and offshore industries with crucial tools to safeguard people and equipment while operating in harsh conditions. However, SIS and StormGeo believe that this data becomes

Safer hands across the seaNew software for the offshore and shipping industries, including optimal voyage planning for safe journeys and minimum fuel consumption, are expected to emerge from a partnership agreement between Star Information Systems and weather experts StormGeo. Meg Chesshyre reports.

StormGeo’s Erik Langaker (left) and Star Information Systems CEO Per Anders Koien shake on last month’s deal. OE

IAN M

CINN

ES

oe_business.indd 24 28/09/2012 10:21


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G&G NOTEBOOK

27

contractors have preferred to focus their attention on refining towed streamer technology to provide an increasingly acceptable and significantly cheaper way of achieving 4D seismic, where OBC would otherwise be the obvious solution in terms of repeatability and quality of data. The Norwegian start-up company Reservoir Exploration Technology (RXT), equipped with a full wave ocean bottom digital recording system from Input/Output (now ION Geophysical), tried to challenge the orthodoxy by launching a fleet of customised OBC vessels. Early successes were followed by an implosion from which the company has still to properly recover. Some of this could be put down to the difficulty of a small, asset heavy company maintaining investor confidence in the market

subsurface than towed streamer data. The use of any form of seabed cable or node does restrict the operational use of OBS to location-specific reservoir appraisal or production monitoring projects, but this is where it can provide the improved high resolution data needed to optimise the extraction of oil and gas. The case for some permanent facility for seismic monitoring of fields over time also seems very persuasive in the context of improved oil recovery. It is of course true that the OBS experience to date has not been an especially happy one. The main contractors concluded a long time ago that ocean bottom cable (OBC) seismic amounts to a high maintenance operation, for which few oil companies would be prepared to pay the premium price needed to make it viable. In the last decade

Sometimes the surf seems to be up, but those big waves that make the surf boarders’ day just don’t quite

materialise. That more or less sums up where purveyors of all options for ocean bottom seismic (OBS) surveying, both retrievable and permanent, sit right now. On the surface, market conditions look as favourable as they possibly could be, oil companies have plenty of ostensibly viable technology to choose from and they have the cash; and yet orders for any form of OBS amount to no more than a ripple. The good news is that a modest crescendo of industry voices is beginning to sing the praises of seabed seismic, even if the level of current activity does not reflect this. The argument in favour of OBS is well known. Placing recorders on the seabed still provides indisputably better (multi-component) imaging of the

by Andrew [email protected]

Is there a seabed seismic shift?No-one seems to have fathomed out the depth of the potential market for seabed-based seismic surveys. Andrew McBarnet reviews the state of play.

Norway’s Ekofisk complex: site for CGGVeritas OptoWave PRM solution.

‘A modest crescendo of industry voices is beginning to sing the praises of seabed seismic.’

oe_G&G.indd 27 28/09/2012 13:59



G&G

NOtE

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cable-laying vessel to a hybrid nodal seismic vessel that can serve as a source vessel with its own node-handling ability. It will be joining FaifieldNodal’s New Venture and C-Pacer as part of a ‘super crew’ in the Main Pass area offshore Louisiana. The crew will be able to deploy over 4500 nodes at 50m station spacing using 225,000m of recovery rope in a single patch, making it the world’s largest ocean-bottom nodal crew. Apache must consider this large-scale node-based survey and the expected multi-component, full azimuth imaging results as the most cost-effective method for appraising a large swath of acreage. It is early days but in certain circumstances this type of survey appears to present a potential challenger to the towed streamer wide azimuth approach to imaging complex geological settings found in the Gulf of Mexico and elsewhere. Obviously towed streamers can cover a much wider area but wide-azimuth surveys are big and costly operations which is why providers such as WesternGeco, PGS, CGGVeritas and TGS have so far adopted a multi-client approach. FairfieldNodal also offers its deepwater Z3000 system which requires ROVs like the CGGVeritas and Fugro competition. The company has conducted 12 deepwater node-based operations in the Gulf of Mexico, the first for BP in 2006, and has had a continuing contract with Shell since Easter 2010. The Z3000 crew has also worked for Shell in Brunei and for Chevron in the North Sea. However, there clearly has not been a queue of oil companies wanting to employ the service. Not that the customer base is likely to be that large, given that deepwater offshore operations the world over are really the preserve of the supermajors and some savvy national oil companies with the resources to fund these hugely expensive projects. However, FairfieldNodal has sensed an opportunity in the even more exotic market of permanent reservoir monitoring (PRM), which continues to languish in the doldrums. At the Society of Exploration Geophysicists (SEG) annual meeting in Las Vegas next month, the company is due to launch a node-based semi-permanent PRM system aimed at

majors notably Total, Chevron and BP in West Africa, the North Sea and the Gulf of Mexico respectively. But in a virtual replay of RXT’s experience, the company struggled to find consistent backlog with cost and operational issues big hurdles along with insufficient funding. This latter was taken care of this year with the purchase of SeaBird’s entire node operation for $120 million by Fugro. The acquisition said something about Fugro’s faith in node-base seabed seismic, but that is by no means the end of the story. Just as OE went to press, CGGVeritas startled the market with the purchase of Fugro’s entire Geoscience division in a $1.1 billion transaction. A detailed assessment of the implications will have to wait another issue. But a key feature of the deal is that the two companies will pool their respective resources to form a Seabed Geophysics joint venture which includes Fugro’s and CGGVeritas’ ocean bottom nodes businesses and CGGVeritas’s transition zone, ocean bottom cable and permanent reservoir monitoring activities. Fugro will make a cash payment of €225 million to CGGVeritas for a 60% controlling interest. The arrangement suits Fugro’s strategy of wanting to divest from the volatile seismic exploration market and focus more on the extended production phase period in the life cycle of oil and gas fields. CGGVeritas, which has dabbled in node technology in the past, and late last year ‘confirmed’ its commitment to what it referred to as the emerging deepwater node market with an order for the manufacture of an additional 800 Trilobit four-component (4C) ocean bottom nodes (OBN) to make a total of 1000 units in its equipment pool. The new nodes were scheduled to be commercially available earlier this year, but there is no news yet of their deployment on a commercial contract.

March of the nodesLeading the march of seabed nodes into the seismic market is the privately held company FairfieldNodal, which has deployed a far greater number of nodes on projects – in the North Sea and the Gulf of Mexico – than any of its rivals. It is just about to embark on a job for Apache in the Gulf of Mexico which will set a new benchmark for node deployment and OBS surveys in general. The mega survey is expected to cover some 1100 blocks using the company’s Z700 nodes, so called ‘nodes on a rope’ because they can be placed and retrieved without ROV assistance. The survey will involve the company’s latest fleet addition European Supporter, the result of a conversion from an ocean

downturn a year or two ago. OBC projects were always likely to be the first to be shelved by oil companies as a bit of a luxury. A towed streamer alternative existed for some projects and the extra value of the OBC multi-component data was by no means a slam dunk. But RXT also seems to have been dogged by some ugly operational and financial challenges. Judging from its recent filings, the company acknowledges that it still has some work to do to address those issues.

Significant backlogOn the positive side RXT has generated some significant backlog. It is working its way back to operating two crews and its Brazilian partnership GeoRXT in which it has a 45% interest has 12 months of work with Petrobras. The ongoing contracts at least suggest that oil companies view OBC as a viable technology, for the time being at least. Of the main players CGGVeritas and WesternGeco but not Petroleum Geo-Services (PGS) have kept their toe in the water. CGGVeritas has two OBC crews working on long term contract in the Middle East and two in the Far East, all deploying technology based on products from its Sercel manufacturing subsidiary. WesternGeco has been operating just the one crew working mainly for BP using Q-Marine-inspired equipment. The company line has long been that ocean bed seismic is still a business best left to the niche players. This is of course easy for it to say. The deep pockets of parent Schlumberger could always be called upon to rapidly augment its OBS offering, or buy in technology, should the pay-off on investment look sufficiently inviting. If the market is going to be propelled forward, the betting probably has to be on node-based seabed solutions rather than OBC. From a historical perspective this may be a surprising conclusion. In the early 2000s SeaBed Geophysical, as it was then, intrigued the market by winning a contract to carry out a seabed seismic survey in the Caribbean using node receivers positioned by ROV. This proved to be a one-survey wonder until 2006 when SeaBird Exploration acquired the company and launched the custom-built Hugin Explorer for node-based surveys. The company attracted support from

RXT vessel Vikland: operational problems have hampered performance.

European Supporter: addition to the FugroNodal fleet.

oe_G&G.indd 28 28/09/2012 14:00



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OYO Geospace will be supplying 600km of cable worth $160 million over three years. Earlier in the year OYO Geospace won a $14.9 million contract from the BC-10 Consortium offshore Brazil, operated by Shell, to provide over 100km of cable for the field’s proposed deepwater (1700m) PRM system. OYO Geospace won these contracts against competition from other conventional OBC and fibre optic tenders, which has to be a major feather in its cap. But it does not resolve the technology debate and probably complicates it. Post tender feedback suggests that the oil company clients were persuaded by track record, price and how rapidly the equipment could be manufactured and supplied. More interestingly there is an impression that oil companies may be becoming less fixated on the reliability of the system over the life cycle of an oil field, ie it is unrealistic to expect perfection over such a long period and interventions are probably inevitable. It is said that all PRM systems in place have experienced problems which in a way is what you would expect. This is why the flexibility and lower initial cost built into the FairfieldNodal PRM system may attract some interest. It would be based on a spread of proven Z3000 deepwater autonomous (battery powered) ‘optical nodes’ from which recorded data can be extracted ‘optically’, no cable required. The nodes can effectively be switched on and off as required to preserve battery life and can remain on the seafloor for an estimated 3-4 years. Meanwhile ROV deployment/recovery operations mean reduced installation costs, flexibility in the spread design, plus ease of maintenance, repair and potential upgrade. Of course we should not get too excited by the addition of this PRM option into the mix. Experience suggests that it may only serve to prolong understandable but nonetheless frustrating oil company indecision.

Correction: In the August issue, the PGS GeoStreamer was inadvertently referred to as a dual streamer system. This should have been dual sensor system.

system on the Ekofisk field and at least four repeat surveys have been conducted. Meanwhile PGS is in the process of setting up a life of field seismic system for the Petrobras Jubarte field offshore Brazil. The debate over PRM technology is of course much more nuanced in the sense that companies have to be convinced that it is worth gambling on existing equipment when, in a technology driven business such as seismic, something better will almost certainly come along sooner rather than later. Then there must be the nagging feeling that retrievable OBS systems and/or increasingly sophisticated broadband-based towed streamer techniques are perfectly viable and cheaper options. PRM advocates argue that it does not take many repeat surveys for the permanently installed system to end up cheaper than conventional 4D seismic monitoring surveys using towed streamers or conventional OBC. The trouble is that capital outlay is all upfront requiring the oil company to take a long term perspective when the outcome is by no means clear cut. Nor does money upfront suit asset managers who are under pressure to show return on new investments over a very short period, and have no incentive to leave the benefits and kudos accruing for their successors on the project.

Life of field surpriseGiven the circumstances, a real turn up for the book this year has been the award of two LoFS cable system contracts to OYO Geospace, supplier of the seabed cable to all the BP projects. Most recently Statoil, which has partner knowledge of the Valhall project and has extensively tested fibre optic systems, initiated what should evolve into a major PRM contract for the Snorre and Grane fields offshore Norway. Assuming all the pre-award conditions are met,

meeting some of the existing oil company resistance to wider adoption of PRM.

Tenth anniversaryThose who follow the scene will know that the life of field seismic (LoFS) project on BP’s Valhall field offshore Norway will be celebrating its 10th anniversary next year. The UK-based group WGP announced the other day that it had just completed the 15th monitoring survey over the field adding weight to the numerous testimonials to the fact that PRM works, in other words the seismic data really does provide valuable information to the reservoir management team in the bid to optimise the field’s development. BP has needed no convincing, because it followed Valhall with a further LoFS project on the Clair field in the UK offshore sector and a LoFS adaptation on the Azeri-Chirag-Gunashli fields in the south Caspian. For quite some time no companies followed the BP lead, even though you would have thought that the potential additional reserves and ultimately the contribution to the bottom line would offer a massive incentive for operators of giant fields around the world. Instead the oil companies appeared to get themselves hung up on a number of issues which rightly or wrongly provided the recipe for procrastination. As a completely new technology there were immediate questions about whether the buried conventional OBC system supplied by OYO Geospace would last the anticipated 25 year life of the field. A number of companies, including PGS (OptoSeis), CGGVeritas (OptoWave), and TGS (Stingray), proposed that the no in-sea electronics alternative provided by fibre-optic cable would be a more reliable, long lasting option evidenced by the performance of ocean cable for the telecommunications business. To date two new companies have been persuaded. ConocoPhillips installed the CGGVeritas

Jubarte plan: what the PGS OptoSeis PRM system will look like.

Placing the nodes Fugro style.

OE

oe_G&G.indd 29 28/09/2012 14:00


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BRAZIL OFFSHORE

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Petrobras, in its efforts to minimize the chance of further delays in the arrival of drilling rigs, has created new production unit departments in China, Korea, Rio de Janeiro and São Paulo to track progress on the rigs daily. Graça Foster said Petrobras is watching rigs under construction very closely ‘because the loss in oil is enormous and it cannot happen again’. While the company works to bring in the drilling rigs that were delayed, it is also focused on the rigs it has ordered in the last 18 months or so. Petrobras awarded the first seven in a series of 28 newbuild drilling rigs with a $4.64 billion contract in February 2011. The first seven are slated to begin operations in 2015 following construction by Sete Brazil and the Estaleiro Atlântico Sul shipyard (EAS) in Brazil. The

with the production curve that was assigned to some of the reservoirs. And finally . . . we have significant delays on new rigs that should have been arriving in Brazil by 2010 and early 2011, and are still arriving this year. But with this we have a big impact in our production targets for 2011, 2012, and 2013.’ There are other reasons Petrobras reset its production goals, including ‘unrealistic ramp ups’ and optimistic production curves as well as optimistic timing for well construction and interconnection. The company’s 2011-15 business plan assumed production of 4.9 million boe/d in 2020 from its Brazilian operations, while the 2012-16 plan has lowered that target to 4.2 million boe/d. The delays in drilling rig delivery run from just over 80 days to over 850 days.

Petrobras’ discoveries in the deep waters offshore Brazil represent 63% of all deepwater finds off the

country in the last five years, according to Maria das Graças Silva Foster, who replaced Sergio Gabrielli at the helm of the Brazilian state operator in February. Despite the level of exploration activity and success, the company is working through some delays that affect its production targets. The company’s 2012-16 business plan attempts to answer a shortfall of 700,000b/d to 1 million b/d on production targets through 2020 that Petrobras set out in its 2011-15 plan. During an event outlining the 2012-16 plan, Petrobras E&P director José Miranda Formigli said ‘excessive optimism’ had originally informed the schedule for the delivery of new units. ‘Sometimes we were also very optimistic

Rig delays dampen deepwater carnivalBrazil’s oil & gas potential continues to grab the industry headlines, with Petrobras confirming more than a score of offshore discoveries,

most of them deepwater, in the last 18 months alone. Newcomer OGX confirmed a number of discoveries too, albeit in the country’s shallower waters. It’s not all plain sailing though. Construction delays have stalled some projects lately and another deepwater field was

compromised by a subsea blowout. Jennifer Pallanich updates OE’s files on the Brazilian scene.

‘The loss in oil [from drilling rig delivery delays] is enormous and it

cannot happen again.’ Maria das Graças Silva Foster

Berthing of the P-62 at Atlantico Sul shipyard in Brazil.

oe_Brazil.indd 31 28/09/2012 13:04



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lies in block BM-S-11, held by Petrobras (65%), BG (25%) and Galp Energia (10%). Elsewhere in the pre-salt, the Carioca Nordeste EWT to the FPSO Dynamic Producer started in November 2011 at 23,400b/d. Petrobras and its partners were to file a commercial viability announcement on the Carioca area that same month, but the partners requested a delay to the end of 2013 to allow for three additional exploratory wells and an EWT. Petrobras (45%) operates block BM-S-9, containing Carioca, on behalf of BG (30%) and Repsol-Sinopec (25%). Petrobras had a 216km pipeline installed to serve block BM-S-11. Known as the Lula-Mexilhão gas pipeline, the system connects the Lula field to the shallow water Mexilhão platform. The 18in pipeline can transport up to 10mmcm/d of gas from the pre-salt cluster. The line, which went onstream in September 2011, starts in 2145m of water from the Cidade de Angra dos Reis FPSO in the Lula field and runs to the Mexilhão platform in 172m of water. Petrobras saw its first well begin producing on a commercial basis in the Santos Basin pre-salt cluster in July 2011 with the 9-RJS-660 well in the Lula field. The well produced an average of 28,436b/d of oil, or 36,322boe/d, to the Cidade de Angra dos Reis. This year, the FPSO is expected to reach a production level of 100,000b/d. A few months prior to that, Petrobras started an EWT in the northeastern part of its Lula field, producing to the BW Cidade de São Vicente FPSO in 2120m of water. More recently, the FPSO Cidade de Anchieta saw first oil from the pre-salt Baleia Azul field in the Campos Basin. The SBM Offshore-operated FPSO

involved in the contracts. Drillships are slated for delivery beginning in 2016 to drill wells up to 10,000m long in water depths of 3000m. Petrobras expects to use the drillships primarily in the pre-salt region of the Santos Basin.

Pre-salt productionPetrobras has already seen a bit of production from its pre-salt fields through extended well tests (EWT) since 2009. Earlier this year, the FPSO BW Cidade de São Vicente received first production in the Iracema pre-salt area. The FPSO, which is connected to the RJS-647 well, is in 2212m of water depth. Going online in 1Q 2012, the well was expected to flow for about six months to allow Petrobras and its partners to gather technical data on the behavior of the reservoirs and the oil flow in the subsea lines. Block operator Petrobras said it expects the well to flow at about 10,000b/d, restricted, during the test phase. Partner BG said all information gathered through the well test would support the development of the final production system in the area, expected to be in operation by the end of 2014 with the installation of the 150,000b/d capacity FPSO Cidade de Mangaratiba. Iracema

newbuilds will have an average dayrate of $430,000 to $475,000. A year after that, Petrobras announced it had approved the award of 21 rigs to Sete Brazil and five to Ocean Rig. In July 2012, Petrobras finalized the contracts with Sete Brasil for six semi drilling rigs, which are part of the 21-rig package announced in February 2012. Delivery for the semi drillers, intended for drilling up to 10,000m in up to 3000m water depth, is slated to begin in 2016. The rigs will be chartered for 15 years to Petrobras, and Petroserv will operate three. Queiroz Galvão will operate two, and Odebrecht will operate the final rig. The following month, Petrobras ordered six drillships to be built by Estaleiro Jurong Aracruz, with three each to be operated by Odfjell and Seadrill. The units, to be delivered in 2016, will be used primarily for pre-salt drilling in the Santos Basin. The units are specified to be able to drill up to 10,000m and operate in 3000m water depth. Also in August 2012, Petrobras signed on for nine drillships to be built in Brazil and chartered to the operator for 15 years. The nine represent the final phase in Petrobras’ plan to order 21 rigs from Sete Brasil. Odebrecht and Etesco are also

‘Sometimes we were also very optimistic with the production curve that was assigned to some of the reservoirs.’ José Formigli

FPSO Cidada de Anchieta in Keppel Shipyard, Singapore.

oe_Brazil.indd 32 28/09/2012 13:05


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be completed in March 2014, the P-75 in October 2014 and the P-76 and P-77 in 2015. The work, announced in May 2012, will be done at the Inhaúma Shipyard, which was leased by Petrobras. Following conversion, each hull will move to a different construction site for installation of the production plant and the oil & gas processing modules, along with the integration of the units. Each platform is planned to have production capacity up to 150,000b/d and compression capacity of 7mmcm/d. The units are expected to operate at the Franco and Tupi Northeast prospects, both located in the Santos Basin pre-salt.

Beyond the saltThe Papa Terra project, which entails an FPSO and a TLWP, will see 30 producers and injectors brought online. The project, with 140,000b/d of total capacity, was behind schedule in June, with planned progress of 65% – at late June, according to Formigli, progress was at 52%. First oil has been targeted for July 2013. Roncador Module 3 is expected to begin production from 17 producer and injector wells to the P-55 semi. Rates are expected at 180,000b/d with peak production slated for April 2015. First oil is targeted for September 2013; Roncador itself has been onstream for years. Roncador Module 4 is expected to begin production through 17 wells to the P-62 FPSO in March 2014. The fourth module is expected to reach similar production levels to Module 3. Peak production is expected in June 2015. At the same time, Petrobras has opted to postpone certain Campos Basin projects, such as Aruanã and Carindé. Formigli has told investors the reserves are there and EWTs have shown good results, but that the company wants to be realistic about the performance of the reservoir. Any unit placed in the fields would be ‘probably very customized to the location.’

from Sapinhoá Norte and Iracema Sul in 2014; Lula Alto, Lula Central, Lula Sul, Franco 1, Carioca 1, Lula Norte and Franco 2 in 2016; Lula Ext Sul, Iara Horst, NE Tupi, Carimbé, Aruanã, Iara NW and Franco 3 in 2017; and Franco 4, Sul de Guará, Jupiter, Caracá, and Franco 5 in 2018. According to co-venturer BG, the partners in Iara expect an EWT in 2013 and to declare commerciality in December 2013; the same targets hold true for the Carioca area. Part of Petrobras’ production strategy for the pre-salt area, as outlined in PLANSAL, relies on mass-produced FPSOs, with their hulls being built in Brazil. In July 2012, partners in blocks BM-S-9 and BM-S-11 approved $4.5 billion in contracts for the construction of six of eight topside modules for planned replicant FPSOs. The contracts, which cover the processing plant, utilities and living quarters, went to DM Construtora de Obras/TKK Engenharia, IESA Oleo e Gas, Tome Engenharia/Ferrostaal Industrieanlagen, Keppel Fels do Brasil, Jurong do Brasil Prestação de Serviços and Mendes Jr Trading Engenharia/OSX Construção Naval. At the time, Petrobras said it expected to award contracts for the final two topside modules, as well as integration packages, to the same companies within the next 18 months. Of the FPSOs, six are reportedly slated for the Lula field in block BM-S-11, with two allocated for the Sapinhoá field in BM-S-9. Two months earlier, Petrobras lined up a series of four VLCC conversions. The VLCCs will become the hulls of the P-74, P-75, P-76 and P-77 platforms, which will operate in the pre-salt transfer of rights area in the Santos Basin. Under the $1.7 billion contract with a consortium formed by construction companies Norberto Odebrecht, OAS and UTC Engenharia, the P-74 conversion will

received first oil on 10 September. The FPSO, which is moored in 1221m of water, has the capacity to process 100,000b/d of oil and 3.5mmcm/d of gas. Produced natural gas will be pumped through the Sul-Norte Capixaba pipeline to the Cacimbas natural gas treatment unit on the coast of Espírito Santo.

Pre-salt calculationsUnder Petrobras’ 2012-16 business plan, a dozen production units under construction are expected to go onstream – to the tune of 1.2 million b/d of increased capacity – between 2012 and 2015. From 2016 to 2018, Petrobras will see seven new systems per year. These steps are intended to help the company reach its 2020 goal of 4.2 million b/d of production onshore and offshore Brazil. The business plan calls for Petrobras’ E&P Brazil segment to invest $131.6 billion, with 69% of that allocated for production development, 19% for exploration and 12% for infrastructure. Of the $131.6 billion total E&P investment, just over half – 51% – will go to the pre-salt cluster. By 2020, Petrobras expects to see pre-salt production making up 40.5% of Brazil’s oil output. The company has pinned the breakeven range for the first pre-salt fields at $35-$40/bbl. At the end of 2011, Petrobras declared the Guará field commercial and renamed it Sapinhoá. This field holds an estimated recoverable volume of 2.1 billion boe. The field in block BS-M-9 contains 30°API oil. First oil from the Sapinhoá pilot project is expected in January 2013, with production peaking in 2014. The project is expected to produce 120,000b/d. Based on the experience it has has gained to date from pre-salt activities, Petrobras has been increasing the capacity of units planned for the pre-salt area. For instance, the Sapinhoá north FPSO will have a 150,000b/d and 6mmcm/d capacity. First oil from the Lula Nordeste pilot is slated for May 2013, with production reaching 120,000b/d and 5mmcm/d of gas. The pre-salt region figures heavily in Petrobras’ calculations. According to the latest business plan’s production curve, following next year’s anticipated startup of production from the Sapinhoá and Lula NE pilots, Petrobras expects production

OE

FPSO Cidada de São Paulo.

Petrobras completed what the company deemed a record-breaking heavylift during the deck mating operation for the P-55 semisubmersible at the Rio Grande Naval Hub.

oe_Brazil.indd 34 28/09/2012 13:05



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lTheMoitaBonitawellintheSergipe-AlagoasBasininblockBM-SEAL-10,foundoilandgas.Thewellwasdrilledin2775mofwater.PetrobrasannouncedthefindinAugust2012.lThe barra 1 extension well found oil about 30km away from the Moita bonita well. This well found a 300m hydrocarbon column with 52m of sandstone bearing light oil, gas and condensate. Petrobras announced the find in august 2012.lTheFrancoSWwell,whichisthefourthwelldrilledinthetransferofrightsareaoftheSantosBasin,found28°APIoilin2024mofwater.PetrobrasannouncedthefindinAugust2012;atthetime,Petrobraswasstilldrillingaheadbuthadverified295mofoilcolumn.lThe Carcará appraisal in block bM-S-8, in 2027m of water, showed 31°aPI oil. The well has turned up over 400m of oil column. Petrobras (66%) operates the block on behalf Petrogal brasil (14%), barra Energia (10%) and Queiroz Galvão E&P (10%).lTheSouthernGuaráwell,whichisinthetransferofrightsarea,liesin2202mofwaterintheSantosBasin.InAugust2012,Petrobrassaidthewellturnedupa93mcolumnoflightcrude.lThe Pecém accumulation in the deepwater Ceará basin was discovered in august 2012. located in 2129m of water, the discovery lies in bM-CE-2 concession, which Petrobras operates (60%) on behalf of bP (40%).lPetrobrasfound15°APIoilinthepost-saltlayerofblockES-M-661oftheEspíritoSantoBasin.TheGranaPadanowell,64kmawayfromtheGolfinhofield,isin1208mofwaterdepth.Petrobras(40%)operatestheblockonbehalfofpartnersIBV(30%)andAnadarko(30%).TheoperatorannouncedthefindinJuly2012.lOver 700 million barrels of light crude and 3tcf of gas is in the pre-salt Pão de açúcar area, according to block operator Repsol-Sinopec. block bM-C-33 in the Campos basin holds the Seat, Gávea and Pão de açúcar discoveries. The Pão de açúcar well was drilled in 2800m water depth and encountered 500m of hydrocarbon column with about 350m of reservoirs. block partner Petrobras said the Pão de açúcar well confirms the potential of block bM-C-33. Petrobras E&P director José Miranda Formigli has said the find of over 700 million barrels of recoverables at ‘Pão de açúcar was responsible for the opening of a new frontier

in the pre-salt oil province’. The find, initially reported in February 2012, is operated by Repsol-Sinopec (35%) on behalf of Statoil (35%) and Petrobras (30%).l InApril2012,BGsaidtheIaraWestappraisalwellin2150mwaterdepthencountered21-26°APIoilinthepre-saltcarbonatereservoirs.ThewellisthethirddrilledintheIaraarea.PetrobrasoperatesblockBM-S-11holdingIarawith65%interestonbehalfofBG(25%)andGalpEnergia(10%).lThe april 2012 discovery Dolomita Sul pushes the potential of the pre-salt region beyond initial expectations, according to Petrobras. The Dolomita Sul well, drilled north of the lula field in the Santos basin in 1747m of water, has initially confirmed oil via cable test oil sampling in the pre-salt carbonate reservoirs. Petrobras operates the concession with 100%.lPetrobrasfound31°APIoilinMarch2012withtheCarcarádrilledintheBem-te-viprospectin2027mwaterdepthintheSantosBasin.Petrobras(66%)operatestheblockonbehalfofPetrogalBrasil(14%),BarraEnergiadoBrasilPetróleoeGás(10%)andQueirozGalvãoExploraçãoeProdução(10%).la second well drilled after the execution of the transfer of rights agreement with the aNP, brazil’s national oil, natural gas and biofuels agency, confirmed the discovery of good quality oil in the area known as Tupi Northeast, in the Santos basin pre-salt.lThe1-BRSA-976-RJSwelldrillednortheastoftheLulafieldinawaterdepthof2131mfound26°APIoil.ThisMarch2012discoveryhadlocatedanoilcolumnover290minthicknessinthepre-saltcarbonatereservoirswhenPetrobrasannouncedthefindinthetransferofrightsarea.

lDrilled in 2149m of water about 4.5km from the discovery well, Carioca Sela recovered 27°aPI in block bM-S-9. Petrobras (45%) operates the block on behalf of partners bG Group (30%) and Repsol Sinopec brasil (25%).lFrancoNW,drilledin1860mofwater,found28°APIoil,PetrobrasreportedinFebruary2012.Thewellisthefirstdrilledfollowingthetransferofrightsagreement.l In January 2012, the Tambuatá well found natural gas and light oil in 1520m water depth. The find, 7km from FPSO Cidade de Vitória on the eastern side of Golfinho field, was drilled as part of Petrobras’ Varredura project, designed to bolster the production of hydrocarbons in new discoveries close to existing production systems.lAtBiguá,PetrobrasreportedinNovember2011finding25°APIin2180mofwater.ThewellisinblockBM-S-8.Petrobras(66%)operatestheblockonbehalfofPetrogal(14%),BarraEnergiadoBrasilPetróleoeGás(10%)andQueirozGalvãoExploraçãoeProdução(10%).lThe Tucura well, in 523m of water, turned up 20°aPI oil in the post salt. located 3km from the Marlin field in the Campos basin, Tucura is also part of the Varredura project. Petrobras reported the discovery in November 2011.lAlsoinNovember2011,PetrobrasfoundgoodqualityoilwiththePatolawellin299mofwaterinthesouthSantosBasin.LocatedintheareaknownasTiroandSídon,thenewwellturnedup36°APIoil.lThe abaré well in the Carioca area of block bM-S-9 located 28°aPI oil in November 2011. Petrobras (45%) operates the block on behalf of bG (30%) and Repsol Sinopec (25%).

lMalombewellin980mwaterdepthfoundoilinblockES-M-414,operatorPetrobras(88.1%)announcedinNovember2011.RepsolSinopecholdstheremaininginterest.lThe barra well, in 2341m of water, found 32°aPI oil in a lower interval and 43º aPI oil in an upper interval. The well was drilled in block SEal-M-426 in the Sergipe-alagoas basin by operator Petrobras (60%) on behalf of IbV (40%). Petrobras announced the find in September 2011.lPetrobrasreportedthePédeMolequeandQuindimfindsin1900mofwaterintheEspíritoSantoBasininJuly2011.ThefindswereinblockES-M-525.lThe Gávea discovery in 2708m of water depth was reported in June 2011. Repsol Sinopec (35%) operates the consortium on behalf of Statoil (35%) and Petrobras (30%).lTheBrigadeirodiscoveryintheCretaceousreservoirsoftheEspíritoSantoBasinwasreportedinJune2011.Drilledin1900mofwaterinblockES-M-525,thewellisoperatedbyPetrobras(65%)onbehalfofShell(20%)andInpex(15%).lPetrobras announced a new pre-salt oil accumulation in the albacora field in 380m of water. according to Petrobras’ april 2011 report, preliminary volume estimates were 350 million barrels of light oil.lTheIaraHorstwellinblockBM-S-11confirmedthereservoir’s28°APIoilquality,whichPetrobras(65%)reportedonbehalfofpartnersBGGroup(25%)andGalpEnergia(10%)inMarch2011.lThe Macunaíma well in 2134m of water discovered 26°aPI oil in the pre-salt Santos basin, Petrobras reported in February 2011. Petrobras (65%) operates on behalf of partners bG Group (25%) and Partex brasil (10%).lTheCariocaNordestewellin2151mofwaterturnedup26°APIoilinthepre-saltreservoirsofblockBM-S-9.Petrobras(45%),whichoperatestheconcessiononbehalfofBG(30%)andRepsol(25%),announcedtheresults–whichincludes250mofgoodqualityreservoir–inJanuary2011.

Petrobras’ pre-salt Baleia Azul field in the Campos Basin sent first oil to the SBM-operated FPSO Cidade de Anchieta on 10 September.

The platform SS-11 Atlantic Zephyr takes first oil from the Tiro and Sídon areas through an extended well test in 2010 in the Santos Basin. In February 2012, Petrobras declared the pair of fields commercial. The accumulations were renamed Bauna and Piracaba. The fields, located in block BM-S-40, are in shallow water. Petrobras, which operates with 100%, estimates total recoverables of 113.4 million boe of 34°API oil for Bauna and 83.1 million boe of 32°API oil for Piracaba. At this development, Petrobras expects to see first oil this month, with production peaking in January 2014.

PetrobrasdiscoveriesOver the last 18 months or so, Petrobras has a string of reported discoveries to its credit. Company CEO Maria das Graças Silva Foster said the 2011 discoveries alone added 1.24 billion barrels of equivalent oil to Petrobras’ numbers, with 1 billion of that coming from the pre-salt area.

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Martelo, the accumulation spans across the shallow water blocks BM-C-39 and BM-C-40, which OGX operates with 100% interest. It anticipates recovering 285 million barrels of oil from the pair of Campos Basin blocks. The oil was discovered with the OGX-25 well in December 2010; first oil is expected in 2H 2013 using the FPSO OSX-3 and the wellhead platform 2, which Modec and Techint, respectively, are building. The drill stem test of the first production well for the field, concluded in June 2011, showed a production potential of 40,000b/d of 23°API oil; neighboring accumulations in the adjacent block have shown 26-28°API oil. OGX has had a few shifts in management this year. In August, Paulo de Tarso was named exploration director. In June, Paulo Mendonça, who served as general executive officer until being assigned the post of CEO in April, was named special advisor to the chairman of EBX Group; Eike Batista is the chairman. Luiz Eduardo Guimarães Carneiro, chief executive of OSX, was named CEO of OGX. Also in April, Paulo Ricardo dos Santos was named exploration and reservoirs officer, Reinaldo Belotti production officer and Roberto Monteiro CFO.

Rio de Janeiro in October 2011. It is under a 20-year charter to OGX. The Aker Wayfarer handled subsea installation. Wellstream supplied the flexible lines. Oceaneering produced the control umbilical. Baker Hughes supplied the electric submersible pump. OGX has said it intends to drill a significant number of production wells in the Campos Basin in the next four years. GE will supply drilling & production equipment for three fixed production platforms for the Waimea and Waikiki fields under a contract valued at up to $230 million. OGX is awaiting the delivery of two more FPSOs, OSX-2 and OSX-3, from Singapore; those vessels are expected to begin receiving production in 2H 2013. Wellhead platforms 1 and 2 are scheduled to be delivered by 1H 2014 for the Waimea and Waikiki complexes, respectively. In addition, in April 2012, OGX ordered wellhead platforms 3 and 4 from Techint. OGX declared the Waikiki accumulation commercial in April this year. Now to be known as Tubarão

Brazilian independent OGX kicked off 2012 with production at its offshore Waimea development. First oil came

in January via an extended well test (EWT) to the FPSO OSX-1 just over two years after the field was discovered with OGX-3 in December 2009. As of mid-June, the EWT for the Tubarão Azul, formerly Waimea, field in the Campos Basin showed test rates of 4000b/d to 18,000b/d of 20°API oil at the OGX-26 and OGX-68 wells. Based on those results, OGX said the ideal flow rate will be 5000boe/d per well, without water injection. OGX, so named for oil & gas plus the mathematical multiplier symbol, declared the field commercial in 1H 2012. By mid-2013, the company expects to have two more producers as well as two injectors connected to the shallow water FPSO, enabling it to recover over 100 million boe from the field in block BM-C-41 in 135m water depth. The OSX-1 was built in Korea and customized by Keppel in Singapore; the 272m long vessel, which can store up to 900,000 barrels of oil and handle production of up to 80,000b/d, arrived in

Waimea well test

The OSX-1 FPSO is serving OGX’s Waimea field in the shallow waters offshore Brazil.

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The Itacoatiara well, or OGX-79, found a hydrocarbon column of about 150m with 64m of net pay in the Albian section in the Campos Basin. The block BM-C-39 well, drilled in 102m of water, is 100% operated by OGX, which announced the find in April 2012. The Fortaleza, or OGX-63, well intersected a hydrocarbon column of 1000m in the Albian with about 110m of net pay. The well, in 155m of water, is in block BM-S-57 in the Santos Basin. OGX, which operates with 100% interest, confirmed the find in January 2012. The Tupungato, or OGX-20, well in 130m of water in block BM-C-41 found an 80m oil column with about 50m of net pay in the Albian section. OGX, which operates the block with 100% interest, announced the Albian find in October 2011. A September 2011 drillstem test on OGX-11D in the Natal accumulation indicated a production potential of 1mmcm/d and 1200b/d of 47°API condensate in a vertical well and up to 5mmcm/d and 6000b/d of 47°API condensate with a horizontal well. The well in Santos Basin block BM-S-59 is in 180m of water. OGX operates the block with 100% interest. The Tambora, or OGX-52, well found 174m of hydrocarbon column with 96m of net pay in the Albian section and a 12m hydrocarbon column with 5m of net pay in the Santonian. The well was drilled in 130m of water in block BM-C-41, which OGX operates with 100% interest. OGX announced the find in July 2011. The Maceió, or OGX-47, well in Santos Basin block BM-S-59 found a hydrocarbon column of 131m in the Santonian section with about 51m of net pay. The well, drilled in 185m of water, was announced in July 2011. OGX operates the block with 100% interest. A later drillstem test, with three production intervals, indicated a production potential of 1mmcm/d in a vertical well, which could reach 2.5mmcm/d in a horizontal well, both at absolute open flow, OGX said. The Salvador, or OGX-30, well found a 330m hydrocarbon column in the Albian age. The well, in Santos Basin block BM-S-58, was drilled in 150m of water. OGX announced the find, which it operates with 100% interest, in May 2011. The OGX-40D Pipeline appraisal well drilled in 130m of water found an oil column of 204m with about 107m of net pay in the Albian. OGX announced the find in April 2011. It operates the well in block BM-C-41 with 100% interest. The OGX-41D Waikiki appraisal well in block BM-C-39 in 105m of water found an oil column of about 148m with about 92m of net pay in the

Albian-Cenomanian. OGX, which operates the block with 100% interest, announced the find in April 2011. The Chimborazo, or OGX-33, well found an oil column of 95m with about 42m of net pay in the Albian. The well in 127m of water in Campos Basin block BM-C-41 is operated by OGX with 100%. OGX announced the results in April 2011. The OGX-35D appraisal of the Waikiki accumulation in Campos Basin block BM-C-39 discovered an oil column of 158m with about 80m of net pay. The well was drilled in 105m of water. OGX, which operates the block with 100% interest, announced the results in March 2011. OGX-36, an appraisal of the Pipeline accumulation in Campos Basin block BM-C-41, hit 136m of oil column with 60m of net pay. Operator OGX (100%) confirmed the find, in 128m of water, in March 2011. The Osorno, or OGX-31, well in block BM-C-41 hit an oil column of 149m with 48m of net pay in the Albian and a 59m column with 23m of net pay in the Aptian. The Campos Basin well in 135m of water is operated 100% by OGX, which announced the find in March 2011. The Carambola-B well in Maersk Oil-operated block BM-C-37 found up to 17m of potential net pay in the Albian section. The well is in 130m of water in the Campos Basin. OGX announced the find in February 2011. At the time of discovery, Maersk Oil operated BM-C-37 with 50% on behalf of OGX with 50%. In a March 2012 deal, OGX acquired an additional 20% interest from Maersk as well as the operatorship of the block. The Illimani, or OGX-28D, well found a 52m hydrocarbon column with 24m of net pay in the Albian. The well, in Campos Basin block BM-C-41, is in 125m of water. OGX, operator with 100%, announced the discovery in January 2011. The OGX-25 well in block BM-C-39 found a 198m column with total net pay of 145m in the Albian and Cenomanian sections and additional pay in the Eocene. OGX operates the block with 100% interest and announced the Eocene discovery in January 2011. Maersk Oil found 14m of potential net pay in the Santonian as well as 43m of potential net pay in the Albian and 12m of potential net pay in the Aptian sections of a Campos Basin BM-C-37 well in 135m of water. OGX announced the find in January 2011. At the time of discovery, Maersk Oil operated BM-C-37 with 50% on behalf of OGX with 50%. In a March 2012 deal, OGX acquired an additional 20% interest as well as operatorship of the block.

OGX discoveriesMaintaining a steady level of exploration activity, OGX has marked a number of successes.

OGX delivered its first shipment to Shell Western Supply & Trading from the FPSO OSX-1 this March.

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causing heavy seeps. The report cleared Transocean’s Sedco 706 semi, which was drilling on the field, of responsibility. While the immediate leak was halted within days of the 9 November 2011 incident, a secondary leak became evident in March this year, prompting Chevron to ask for a temporary suspension of production at the field. At that time, output was at 60,000b/d. ANP told Chevron in July that the company could resume production but not water injection or any new drilling. Chevron operates Frade, which began production in 2Q 2009, with 51.7% interest on behalf of partners Petrobras (30%) and Frade Japão Petróleo, a JV of Inpex, Sojitz and Jogmec (18.3%).

Later, however, ANP ordered Chevron to shut in one of the 11 Frade producers and four water injectors. Chevron also suspended all drilling operations offshore Brazil indefinitely. The Brazilian federal government filed a $10.7 billion civil lawsuit against Chevron and its partners. In addition to the civil lawsuit, the companies involved face penalty fines. The ANP’s report on the incident found Chevron culpable on 25 infractions, and the company can be fined nearly $1 million per incident. In its report on the leak, the ANP said Chevron missed an underwater blowout and that its failure to properly manage pressure during drilling led to the kick,

Oil seeps at Chevron’s Frade field nearly a year ago have led Brazilian regulator ANP to assess millions

in fines against Chevron and ultimately halted output at the troubled Campos Basin field. In November 2011, Chevron P&A’d an appraisal well after oil seeps were found in the Frade area in 1200m (3800ft) of water. According to Chevron, there was never any oil flow from the wellhead but rather about 2400 barrels of oil had come from nearby seep lines on the ocean floor. ANP has pegged the number at more like 3700 barrels. During the seep incident, Chevron maintained full production activities at Frade with output of about 79,000boe/d.

Frade seeps continue to haunt

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of 60% from the fields operated by the company on the Norwegian continental shelf. From last year to this year the average oil recovery rate for Statoil-operated fields in Norway rose from 49% to 50%, constituting 327 million barrels of oil. ‘We work internally in the company and together with partners, research institutions and suppliers to increase recovery,’ explained Siri Espedal Kindem, Statoil’s SVP for technology excellence. ‘We begin this work before a field is even developed and we continue this through the entire production phase.’ Half of the company’s NKr2.8 billion research budget is earmarked for projects to improve recovery, including a special centre for increased recovery in Trondheim. Statoil’s sub-surface team on the Øseberg field was awarded the Norwegian Petroleum Directorate’s prize for improved oil recovery (IOR) for its work

Major) discovery on the Utsira High is targeted for the end of next year with submission of a field development plan in late 2014 and first oil from an initial phase in 2018. It will be a flexible development based on standard solutions, dependent on subsurface conditions, according to field development SVP Øivind Reinertsen. Statoil is planning to deploy a spar on the Aasta Hansteen field (previously Luva) with an investment decision end 2012/early 2013 ready for first oil end 2016. This will be the world’s largest spar, the first on the NCS, and the first with condensate storage. The harsh environment and water depth of 1300 metres pose particular technical challenges. Technip has a letter of intent for the hull and will lead the project in a consortium with Hyundai Heavy Industries of Korea. Statoil has also set itself an ambitious target to achieve an average recovery rate

Statoil is targeting concept selection for the Skrugard area development in the Barents Sea in 2013, leading

to a final investment decision and PDO submission in 2014, Statoil VP development Erik Strand Tellefsen revealed. The operator is hoping to turn the development into a field centre. Skrugard, discovered in April 2011, and Havis in January this year, contain an estimated 4-600 million boe. Three concepts are under consideration – a circular unit with storage, a ship-shaped until with storage or a 240km pipeline to shore. A pipeline solution requires more capex and offshore loading more opex. Pre-drilling is expected to start in 2016 leading to first production in the later part of 2018. A total of about 40 wells are planned over an eight year drilling programme. Concept selection for the giant Johan Sverdrup (previously Avaldsnes/Aldous

Revitalising the Norwegian shelf a number of operators on the Norwegian shelf revealed updates of their field development plans at the recent Offshore Northern Seas conference in Stavanger, with a substantial list of projects and refurbishments going forward as part of the revitalisation of the Norwegian shelf. Meg Chesshyre has the details.

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due to subsidence in the seabed and the need for more efficient operation of the field. It has a design life of 40 years, and replaces the QP, DP and PCP platforms. It has a processing capacity of 120,000b/d of oil and 143mmcf/d of gas. The hotel facilities were put into use last year. There are 180 single bed cabins. It is powered from shore via a 294km long DC cable from Lista. The old PCP platform was shut down in late July. BP is also mulling the construction and installation of two new platforms, Hod 2 and Valhall Flank West (VFW) between 2015 and 2020 as part of the Greater Valhall appraisal programme. This represents an investment of NKr25-30 billion including drilling of between 20 and 30 production and injection wells in phase one. The aim is significantly to increase the Hod recovery rate and to enhance the development of the west flank of the Valhall field. Removal of the old PCP, DP, QP and Hod1 platforms is scheduled for 2020-25. By 2050 BP aims to have achieved its vision of around 2 billion barrels of oil produced, double the amount produced from the Valhall area so far. New wells and major workovers are also planned on Ula/Tambar starting

work proceeds on tying back new discoveries to existing installations. The Stjerne development will come onstream next year. In addition, there are plans for more seabed templates and a fast-track development project in the prospective Øseberg area. BP Norge’s new Valhall process and hotel platform is expected to start production later this year. A new platform, installed in 2010, was required

in increasing recovery by means of gas injection at ONS (pictured above). The recovery success story on Øseberg began with the Troll Øseberg gas injection project (TOGI), which came on stream in 1991. From 1991 to 2002 some 21.7bcm of gas were injected into Øseberg. Since then the Øseberg field has used its own gas as pressure support to extract more oil. In addition to further drilling on the four permanent installations on Øseberg,

Øseberg field centre.

ONS 2012, held in Stavanger, Norway, at the end of August, had 59,913 visitors – a new record – almost 10,000 more than in 2010.

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in June 2011 and construction is well under way at the Samsung yard in Korea. Transocean Searcher will start drilling six production wells mid-2013. The proposed development concept for the Bream field (17/12-1) is similar to Knarr, with subsea wells tied into a leased FPSO. Sanction is currently anticipated end 2012/beginning 2013 ready for first production in 3Q 2015. ConocoPhillips Norway has three large projects currently in the execution phase – the Ekofisk 2/4L accommodation and field centre, Ekofisk South and Eldfisk II. In addition extensive modifications are being carried out on existing facilities within the Greater Ekofisk area. The owners are investing NKr83 billion in the various development projects (2011 value) on Ekofisk and Eldfisk. Through the three development projects, ConocoPhillips says it is now laying the foundations for value creation in the Greater Ekofisk Area over the next 40 years. The 2/4L jacket (built by Kvaerner Verdal) and the bridges (built by Smoe in Singapore) were installed on the field in June. The topsides, currently being constructed by Smoe, will be installed on Ekofisk in 2013. The Ekofisk South project includes the construction of the Ekofisk 2/4Z wellhead platform and the subsea facility Ekofisk 2/4VB. The jacket (built by Dragados) and bridge are due for installation this year. The topsides (constructed by Aker Egersund) go in next year. The 2/7S jacket for Eldfisk II is under construction at Dragados and is due for installation next year. The topsides being built by Kvaerner Stord will be completed in 2014. A new equipment room for Eldfisk 2/7A, built by Kvaerner Stord, was installed in July this year.

Swedish spendSweden’s Lundin Petroleum is planning capital expenditure of NKr25 billion in Norway over the next four years, of which NKr15 billion will be on its operated Edvard Grieg and Brynhild fields, and on Bøyla, in which it is a partner. Production start up from Edvard Grieg (previously Luno) in block 16/1 is looked for in October 2015. Total capex for Grieg is NKr24 billion. A commercial agreement is in place for a co-ordinated development with Ivar Aasen (previously Draupne), operated by det norske oljeselkap, which is expected to start up in the autumn of 2016. Submission of the Ivar Aasen PDO is planned in December 2012, for a production start in the autumn of 2016. Lundin has selected Norwegian fabrication contractors for Edvard Grieg. Kvaerner Verdal is due to deliver the 13,000te jacket in March 2014, and Kvaerner Stord the 21,000te topsides in April 2015. Transport and installation has gone to Saipem, and Prosafe is supplying

Norwegian Sea is now looked for in the fourth quarter of this year. Start-up has been delayed for a number of reasons – construction delays in Korea, a recent strike in Norway, and weather delays last winter affecting the riser pull-in campaign. The Polar Pioneer is carrying out development drilling. BG Norge is looking at start-up from the Knarr field in block 34/3 in 1Q 2014. The development consists of subsea wells tied into an FPSO with offshore loading to shuttle tankers and gas export through a new pipeline system into the UK Segal system. A lease-and-operate contract for the Knarr FPSO was awarded to Teekay

next year to extend field life to 2028 and beyond. First production from BP’s Skarv field (Skarv FPSO pictured above) in the

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plans are reflected in the rapidly growing number of employees. In 2013 the Wintershall head count in Stavanger is set to rise from over 200 to 300.

range between 60 and 160 million barrels of recoverable oil. Commercial viability as well as potential further upside will need to be confirmed during appraisal drilling in 2103. Additional exploration wells are also planned for 2012/13. By the end of 2015 Wintershall is planning to invest up to €2 billion in exploration and field development in Norway and the UK. Field development in Norway will concentrate on Knarr and Edvard Grieg, and on Catcher and Cladhan in the UK. Wintershall’s target is to raise the daily production more than tenfold to 50,000 barrels of crude oil equivalent by 2015. The expansion

a newbuild flotel. Statoil is responsible for the export lines, but the contract has yet to be awarded. Last month Lundin confirmed an option in the Edvard Grieg topside contract for Kvaerner to perform the offshore hook-up and commissioning assistance. Lundin project director Bjorn Sund is confident of meeting a tight 36-month delivery schedule through the use of Norwegian yards. He observed that Korean yards lacked co-ordinated engineering and procurement, and time was lost with equipment manufactured in Europe being transported to Korea and back. ‘When we evaluated thoroughly you need to add another six months’ minimum construction time [building in Korea], which means that you are losing a season,’ he explained. First oil from Lundin’s Brynhild field, a tieback to the Haewene Brim FPSO located at Shell’s UK sector Pierce field, is expected in 4Q 2013. Among the contractors are Aker (subsea production system), Technip (pipelines and installation) and Maersk Drilling (jackup). Shell is responsible for topsides modifications on Pierce. Marathon submitted a PDO for Bøyla (previously Marihøne) in block 24/9-9S in June. Development of the discovery is planned with a subsea facility tied back to Alvheim (pictured above right). Expected production start-up is end 2013 or beginning 2014. Technip has EPIC contract for the subsea facilities. Total Norge is hoping to award topsides, SURF and FSO contracts for the Martin Linge (previously Hild) field in blocks 30/7, 29/9, 30/4 and 29/6 by the end of the year. A contract for the 16,500te jacket for the field was awarded to Kvaerner in February. Production drilling starts in 2014 and first production is looked for in 2016. A PDO for the NKr26 billion field development was approved by the Storting in June. It has total recoverable reserves estimated at 189 million boe. Partner interests are Total (operator) 51%, Petoro 30% and Statoil 19%. Wintershall is now eyeing a 2017 production start for the Maria discovery in Norwegian block 6406/3, Bernard Schrimpf, managing director Wintershall Norge said at ONS. The company is looking at either a standalone facility or a subsea tieback to the Heidrun or Kristin fields. Maria has an estimated 60-120 million barrels of oil as well as 2-5bcm of recoverable natural gas. An appraisal well in May confirmed the upper end of the discovery estimate. Concept selection is expected in early 2013, and FID in late 2013/early 2014. Preliminary resource estimates for Skarfjell, discovered in March this year about 17km south-west of the Gjøa field,

OE

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dRIllING & cOmplEtIONS

45

sections that are separated by a thin shale layer, and fracture conductivity. The shale layer acts as a barrier for gas flow, but does not contain the fracture height growth. Inflow modeling suggested that the orientation of the fractures is longitudinal compared with the well trajectory. The distance between the fracture initiation points is around 200m. It also showed an optimized fracture half-length of about 50m, which should prevent potential interaction between the fractures. The fracture geometry will be radial shape. The selected fracture treatment includes a delayed borate crosslinked gel and coarse resin-coated proppant (16/20 mesh intermediate strength proppant) at a target average concentration of 2.5-3lb/ft2, which is a common fracturing treatment in the North Sea. This high-viscosity fluid, combined with the designed pump rate of 25bpm, enhances fracture height growth. Several components were brought together to conduct this operation. A specially converted platform supply vessel (PSV) to serve as the stimulation vessel. The Olympic Princess (above), a modern DP2 PSV, was secured and converted to suit the needs of the job. The conversion was planned to provide redundancy in executing each treatment and to allow the vessel’s stimulation capacity to be attractive to other users in the area. Table 1 provides the equipment listing for the vessel.Coiled tubing reel. To lift the 42te, 23/8in coiled tubing reel onto the jackup barge, the reel was stripped of internal pipework and a drop-in power stand was selected to reduce weight. The reel was lifted onboard from the jack-up barge at its previous

production history) and a production forecast.

Drilling the sidetrackThe well was drilled with an oil-base mud, but large washouts were seen in the shale sections (up to 10in in shales vs 6in in sandstone), which was also experienced in the vertical wells. Due to the shape of the reservoir and the location of the field with respect to the platform, the well was drilled in the direction of maximum horizontal stress, such that the fractures were longitudinal. A 1.5km long horizontal reservoir section was completed with a 41/2in cemented liner with advanced flexible cement technology to minimize the effect of pressure and temperature cycles. The well was completed with 51/2in x 5in Cr-13 production tubing, which was selected to allow for high pumping rates and running of composite bridge plugs (as a contingency for sand plugs).

The fracturing planThe key parameters in the fracture design were the fracture height, which should connect with the various reservoir

Since its discovery in 1986, a tight gas field (average reservoir permeability below 0.1mD) in the Dutch sector

of the North Sea has undergone several well developments aimed at draining the reservoir at sufficiently high and sustainable rates. These developments, which included drilling a deviated appraisal well and fracture stimulating the first horizontal development well, gave initial production rates ranging from 0.2 million Nm3/d to nearly 0.09 million Nm3/d. However, factors such as liquid loading soon brought the production rates down to the range of 0.07-0.09 million Nm3/d. Drawing on the lessons learned from these previous drilling campaigns, Shell, Schlumberger and Fenix Consulting Delft joined forces in 2008 to drill a horizontal sidetrack and place five hydraulic fracture stages to effectively drain the reserves in the block. This article reviews the drilling and fracturing operations in the development of this well, including the fracture design methodology, operational issues, post-fracturing production analysis (with more than one year of

Tight-gas horizontal well fracturing in the North Seathe effective development of low-permeability tight gas reservoir resources requires operational efficiency to improve production performance. Erik Schrama, Robin Naughton-Rumbo and Fred van der Bas, Shell; Josef Shaoul, Fenix consulting delft; and Mark Norris, Schlumberger discuss the North Sea’s first true tight-gas horizontal well fracturing application.

Table 1. Principal items of equipment on vessel.

The Olympic Princess during fracturing operations in the North Sea.

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Followingaseriesofdatafracstomeasureinjectivity,themainfracturetreatmentwaspumpedat30bpm.Slurrystagesfrom1ppato10ppawerethenpumped,withatail-inof14.5ppatomaketheproppantplug.Theslurrywasdisplacedwith35bblcrosslinkedgelfollowedbylineargel.Atotalof128,000lbsofproppantwasplacedintheformationforstageone. Coiledtubingwasusedtocleanoutsufficientfilltoaccessthenextstageandsand-jetperforations. Apressuretestwasconductedontheremainingfilltotestitssuitabilitytoisolatethefirststagetreatment.Theclosedintubingheadpressure(CITHP)wasincreasedto345barandheldfor10minuteswithsuccess. Thissamegeneralprocesswasrepeatedfortheremainingfourfracturestages. Followingwellcleanup,duringwhichthevolumeoffluidreturnedonlocationwas13.3%ofthetotalfracturingfluidinjected,thewellwashookeduptothefacilitiesandproductioncommenced.

additiveswerestoredinIJmuiden,allowingthevesseltorapidlyre-supplyaftereachfracturingoperation. Eachfracturetreatmentwasdesignedfor250,000lbmofproppanttobeplacedusing150,000gallonsoffluidatapumprateofatleast20bpmandsurfacepressureof8000psi.Ahydraulicfracturingspreadof12,000hhpwith700,000lbmofproppantstorageand400,000gallonsoffluidstoragewasdesignedandinstalled.

Fracturing procedureFracturingoperationsbeganinNovember2009.Followingalinercementationcheckanddepthreferencerunoncoiledtubing,thefirstsetofperforationswasmadewithasand-jettingtoolstringcontainingthreenozzlesat120°phasing.Theperforationsweremadebypumpingalineargelladenwith100-meshsandataspecificrateforaspecifictimeperiodbeforepullingoutofhole(POOH)by0.25m.Intotal,12perforationsweremadeateachintervalwithin0.75m.Acirculationsubwasthenopenedwithadropball,andthegelandsandwerecleanedout.

locationandsea-fastenedforthejourneytothenormallyunmannedinstallation.Theeffortsavoidedanyneedforspoolingand/orweldingoffshore,ahigh-riskactivitygiventhenumberofcoiledtubinginterventionsplanned.Flowback spread.Theflowbackspreadconsistedofaliquid-onlyflowbackloopandamultiphaseflowbackloop.Theliquid-onlyloopconsistedofanadjustablechokeandashakersystemtotakereturnsduringcoiledtubinginterventionswhentheformationispluggedoffandanoverbalancemaintained.Themultiphaseloopcouldbeactivatedatanytimeandconsistedoftwohigh-pressuresandknockoutvessels,high-pressuredualsandfilters,achokemanifold,aheater,ahigh-pressureseparator,gaugetank,stocktanks,andwatertreatmentfacilities. VesselriggingupoperationscommencedinearlyOctober2009inMontrose,Scotland,andwerecompletedandcommissionedwithinthreeweeks.ThevesselsailedtotheNetherlandsinpreparationforthefirstfracturetreatment.Proppant,brineandchemical

Table 2.Results of breakdown analysis.

Figure 1.Fracture dimensions and conductivity for Fracture 1.

oe_Shell/SLB.indd 46 28/09/2012 13:15




47

Fracture treatment analysis The fracture treatment data was evaluated on a zone-by-zone basis to estimate the average formation permeability and the fracture dimensions. A summary of the breakdown injection analyses is shown in Table 2. The estimated permeability, which is based on the fluid leaking off from the fracture while it is closing, varied from 16µD to 40µD. This was quite close to the pre-fracture estimate of 50µD average permeability to gas (at in situ conditions). The simulated fracture dimensions for Fracture 1 (Figure 1) were slightly smaller than the total payzone height. Screenout was attributed to a width restriction at the wellbore, combined with the large diameter proppant (16/20 mesh). To avoid screenout in subsequent zones, treatment execution was altered by pumping smaller proppant volumes with larger pad volumes and lower maximum proppant concentrations. The resulting fracture half-lengths were also shorter, with less propped fracture width, as summarized in Table 3.

Post-fracture Initial post-fracture production from the well was lower than expected, based on pre-fracture simulations. Because no well test (with buildup) was performed following the initial cleanup, there was uncertainty in trying to ascertain the cause of the production discrepancy. An initial analysis with a simple 2D model, using only the first few weeks of production data, suggested that the poorer-than-expected production could be due to poor cleanup of the proppant pack, which led to a reduced effective propped length - a phenomenon often observed in tight-gas wells. During the first year of production, the gas rate did not exhibit the steep decline typical of tight-gas wells, and the surface pressure remained constant at 33 bar. A

Table 3. Results of main fracture treatment analysis.

Figure 2. Pressure distribution in the reservoir after one year of production.

calculated bottomhole pressure (BHP) was generated using a wellbore model, which was used for history matching the first year of production with a full 3D reservoir simulation model. The production record contained several shut-ins, which also gave valuable information about the reservoir pressure evolution. A 3D reservoir simulation model was created by upscaling the geological model; porosity, permeability and water saturation data were also upscaled. The simulation model was constrained by using the measured (allocated) daily gas production rate. However, during the initial cleanup period, a measured water rate was also available. The first step in the history matching process attempted to match the observed water rate and the production logging tool (PLT) results. By reducing the effective fracture length for the different zones, it was possible to match both the water production and the PLT results. The results of this initial matching of the early time production gave an estimated effective fracture half-length on the order of 25m for the first four zones, and a much better length of 55m for the final fracture (#5). With these parameters, it was only possible to match early time behavior.

Matching the remaining part of the first year of production required an improvement to the model to reflect that the actual well production index (PI) was increasing during that time; these increases were most pronounced after each well shut-in. This match was made by increasing the effective length of each of the five fractures over time, corresponding to the points where the well’s PI increased. It was also noted that to match the buildup data, a significant near-wellbore choke effect had to be added to the model, consistent with convergent flow in the fracture due to the very short perforated intervals. At the end of the simulation, all five fractures were producing with their total propped length open to flow. In this interpretation, it took one year for the propped fractures to fully cleanup. The average formation permeability in the history-matched model was about 0.02-0.03mD at initial water saturation, which agreed well with the permeability of 0.02-0.04 mD estimated from the fracture treatment data analysis. This analysis was used to predict long-term production. The pressure distribution at the end of the first year of production, shown in Figure 2,

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broadening his expertise as a contract holder. He is currently on assignment in Sichuan, china as c&WI operations team lead for the exploration and appraisal activities on two unconventional gas fields.

Erik Schrama studied offshore engineering at delft University of technology and joined Shell in 2003 as a production technologist. After two years in R&d and technical services and a spell working in Siberia’s Salym field, he joined

Shell’s offshore operating unit in the Netherlands in 2006. during 2009/10 he project managed the drilling and hydraulic fracturing phase of the first offshore tight gas development using a horizontal well with multiple fractures. He currently works as a senior production technologist for Shell subsidiary petroleum development Oman.

Josef Shaoul, engineering manager at Fenix consulting delft (formerly StrataGen delft), conducts fracture stimulation studies, on-site fracture engineering, Fracpro training courses, welltest analysis, reservoir simulation studies

and software development. He worked at RES from 1989-96, where he was the lead software engineer for development of Fracpro. He has over 20 years’ industry experience and received his Bachelor’s and master’s degrees from mIt in electrical engineering and computer science.

Fred van der Bas is a subject matter expert on hydraulic fracturing at Shell based in the Netherlands, where he has worked for more than 30 years. After his physics study he joined Shell Research in the petrophysics

department and then moved to production technology working on well stimulation research projects with a focus on fracturing. He is currently supporting the design, execution and evaluation of Shell’s fracturing operations in Europe, Asia and Africa.

Mark Norris, stimulation domain manager and engineering advisor for Schlumberger Well Services in Aberdeen, is involved in multi-disciplinary engineering for major North Sea stimulation campaigns while extending support

and experience to the operational phases. Since receiving his Bachelor’s degree with honors from Robert Gordon University in engineering, he has accumulated over 30 years’ industry experience working in well construction and reservoir stimulation and was recently recognized by the SpE for his contribution to industry.

convergent flow at the perforations.l Tail-in with a small volume of an even larger proppant size (ie 12/18). Given the low permeability, the main proppant for the treatments could actually be a smaller size (ie 20/40), which should also reduce the risk of near-wellbore screenout.l After executing all the fracture treatments, jet or perforate additional holes over the same interval, increasing the total perforated length from 600mm by a factor of two or three. While the new perforations may not hit the longitudinal fracture, any increase in inflow area will significantly reduce the near-wellbore pressure drop. Finally, to try to reduce proppant pack damage in the near-wellbore area caused by pressure testing of the proppant plugs, it is recommended to increase breaker concentration in the flush fluid.

Robin Naughton-Rumbo joined Shell in November 2005 having earned his master’s degree in mechanical engineering from Imperial college, london. He built up his competence as a completions and well interventions (c&WI)

supervisor and engineer with NAm in the Netherlands and on assignment to pinedale, Wyoming, US. He spent two years

highlights the elliptical pressure around the horizontal well. At this point, the reservoir boundary had not been reached, and the production simulation predicted that this would occur in the higher permeability layers after more than two years of production. The forward simulation (Figure 3) also predicted that the total water production after five years will still be only 1400m3 out of the 2100m3 of fracture water pumped into the well.

Future recommendationsFor the first time in the North Sea a true tight gas reservoir was successfully developed using a horizontal well with multiple fractures. The production improvement compared to an unfractured horizontal well approached a factor six, which is very encouraging for future tight gas developments. The one-year production match using a numerical reservoir simulator has provided valuable insights to explain why the well’s production has remained constant for such a long time. For future wells of this type, a variety of methods can be used to reduce the effect of

Figure 3. Production forecast for four years based on history match of first year’s production.

OE

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51

Theinstallationprocessinvolvespositioningthelinersystemtothedesiredlocationdownholeandapplyingsurfacepressuretoexpandandsetaninternaljackingsystemtoanchortheliner.Byusingadownholehydraulicjackthereisnoneedforhigh-volumepumpingservices.Therigthensimplypullsaconethroughtheliner,thusexpandingitfromthebottomup.Theintegralcarbideanchoringmechanismpositivelylocatesthelinerinpositionandpreventsanyfurthermovement.Alternativelyiftherigorworkstringislimited,thesystemcanberesetandcanbeexpandedwithrepeatedstrokingofthejacksystem. Theinnerdiameteroftheexpandablelinerandtheconnectionsareneverexposedtoexpansionpressure,therebymaintainingtheintegrityofthesystem.Becausemultiplejointsofthiscased-holelinercanbeconnecteddownhole,anylengthofcasingcanbeisolateddependingonwellobjectives. Thesystemistypicallyinstalledinonedayandinasingletrip.Becausethere

well.Forexample,additionalliners,scablinersorstraddle-packassembliesallrestricttheoriginalholesize,thusreducingproduction. Inaddition,ifcementsqueezesarenotproperlydeployed,theycanproveunpredictablerequiringmultiplesqueezestoberun.Shortterm,thecementmaybreakdown.Longerterm,theycanbecomehighrisk,exposingtheformationtohighpressuresandcontaminationofthereservoirfromthecementduringthesqueeze. Weatherfordhasdevelopedanalternativecasing-remediationsolutionwiththeMetalSkincased-holesolidexpandablelinersystem.Designedtobridgethecasing-repairgapbetweencementsqueezingandscabliners,thesolidexpandablesystemprovidespermanentisolationtothedamagedsectionofthecasing,regardlessofthedamagemechanismandprovidesalargerIDandbetteraccesstoreservesthanscablinersforfuturedrilling,completion,productionorinjectionoperations.

Casingdamageinolderwellscomesinmanyformsandfrommanysources,includingdeformationor

completeseparationduetoformationmovement;erosionalwearbyworkoversordrillingactivity;andcorrosionduetothepropertiesofthewelleffluent. Anoperatorworkinginamatureshallow-water(197ft)fieldoffthecoastoftheRepublicofCongoneededacost-effectiveandlong-termsolutiontorepairasectionofcorrodedcasingatadepthof385mto423mononeofitswells.Overthecourseofitsnearly40-yearoperatinghistory,thelow-pressurereservoir,located820-1312ftbelowtheseafloor,hasproducedviscousoilandexperiencedsignificantwaterencroachmentwithwatercutof96%duetocorrosion.Inaddition,thewellinquestionwasinaremotelocationandproducedfromanoffshoreplatformwithbothdeck-spaceandweightlimitations,whichpreventedtheoperatorfromusingatypicalworkoverrig.This,combinedwiththepresenceofH2Sgas,makesproductionoperationschallengingandcallsforplatformpersonneltoconsistentlyremainvigilantofanypotentialhealth,safetyandenvironmentalrisks. Theobjectivewastorepairthecorrodedcasingtoregainwellintegrity,commenceoilproductionandshutoffwaterflowwhilemaintainingasafeworkingenvironment. Inaddition,giventheeconomicbalancebetweenamature-fieldremediationprogramanditscost,thedesiredsolutionalsoneededtobeefficientandprovidealong-termbenefitthatprecludedtheneedforanotherintervention.

Second skin for casingResolvingthesesituationstogetdrillingorproductionbackonlinerequiresanintervention.Severalstandardapproachesexist,buthavedemonstratedvaryingdegreesofsuccessandmaynegativelyimpacttheeconomicsofthe

Restoring well integrity Congo-styleAn innovative cased-hole expandable liner system has been deployed to repair casing corrosion in an offshore congo well. Weatherford’s Scott Durment and Doug Farley explain why and how.

Congo platform showing the basic parameters of the rig, crane and blowout preventers.

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are no darts, plugs or shoes required to generate pressure when the anchor is set, no drillout is required. The casing can be tested immediately and the subsequent operations can commence. Once installed, the cased-hole liner provides minimal ID reduction to the casing, which helps optimize completion designs for higher production or injection rates.

Planning and risk assessmentBecause of the economic and long-term benefits of solid expandable liner, the company was selected to install an H2S-resistant, 51/2in x 7in, 29# expandable cased-hole liner in the Congo well between 1224ft and 1608ft. The remote location and safety concerns made the intervention more difficult and required significant pre-job planning. Because of deck space and weight limitations and no present workover rig, special consideration and planning was conducted prior to the installation. The liner casing would be deployed using a mast with a maximum over-pull of 12te, and a maximum height under hook of 41ft . The equipment would be conveyed into the wellbore using a surface jack system that is unique to this field given platform’s limitations with a working travel of 63in, using 1.6m cylinders capable of 80 tons of force. Equipment The MetalSkin expandable cased-hole liner.

oe_D&C2.indd 52 28/09/2012 13:22



DRILLING & COMPLETIONS

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ConclusionThe expandable liner was successfully installed and expanded at the proper depth in a single trip, isolating the corroded zone. The installed liner provided a post-expansion drift of 5.265in to enable the well to be produced at a rate of 250b/d, with no water production. The minimal ID restriction in the wellbore post remediation allowed the client to continue production with the same completion strategy without having to downsize the electric submersible pump. Finally, through continual communication with the client, all operations were performed without injury in a safe and professional manner, allowing the client to resume production with full HSE integrity.

Doug Farley is global product line manager for Solid Expandable Systems at Weatherford. A graduate of Texas State Technical College, he has over 30 years’ experience in operations, manufacturing, and engineering of drilling

and completion tools and has been involved in international manufacturing facilities start-up.

Albert Durment is a project coordinator for the Critical Wells Team Wellbore Construction group at Weatherford. Based in Houston, he has over 30 years’ oil & gas industry experience, with a diverse background ranging from

positions as a floorhand, technical advisor, to his current role.

Liner installation Pre-job operations included a clean-out trip with bit and mill assembly to ensure that all downhole obstructions or tight spots were cleared, as well as a caliper log to verify the inside diameter of casing down to and across the planned setting depth of the expandable liner. Once satisfied with the condition of the wellbore and casing to accept the expandable liner, installation commenced. Thirteen connected liner joints were tripped in hole with a workstring to TD at a maximum run-in-hole speed of 60ft/min. The entire liner assembly was run 2-3ft past setting depth and picked back up to the setting depth mark on the pipe, which closed the slide valve in the string. The liner was then expanded using a setting tool requiring 5000psi inside the workstring to achieve expansion and anchoring the liner. Once anchoring was confirmed, a jack system pulled the workstring out of hole so as to expand the liner in 5ft intervals. Expansion continued using an over-pull of 36-40 tons. During this time, the rig was pumping water in the hole to prevent the release of gas. The cone section was pulled out of the top of the liner on joint number 13, which was verified by a weight drop from nine tons to three tons on the indicator. The liner top was confirmed at a depth of 1224ft.

handling and peripheral operations would be performed using a crane with a maximum load of 3.8te at 18m. Blowout preventers are located 6.6ft below the main deck. In addition, prior to the installation, the company collaborated with the operator to evaluate the potential risks in working in the H2S environment. These risks were documented and a mitigation plan was implemented that was designed to address the potential release of H2S during the operation. High priority was given to adhering to and implementing the safety policies developed jointly between Weatherford and the client. Safety meetings and job safety analysis (JSA) were conducted before each phase of the equipment and well preparation and prior to the expandable installation to ensure that all personnel were completely aware of the actions during each segment of the installation process. These meetings offered an opportunity for all personnel to ask questions, make comments or suggestions and be made aware that they were all empowered to shut down the operation if they questioned an activity or if they observed anything that could be unsafe. At times, work was stopped to ensure that safety remained the utmost priority.

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RESE

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the column between two parallel lines drawn perpendicular to the chain-dotted line. Figure 1(b) is an expanded view of the element AB and the lines that define it, and shows the forces and moments that act on it. At the upper end A, there is a downward force equal to the compressive force in the column, as can be confirmed by considering the equilibrium of the column section above A. At the lower end B, there is an upward force equal to the compressive force in the column. Because the column is deflected, the downward force at A is not in line with the upward force at B. That offset creates a couple: if element AB is to be in equilibrium that couple has to be balanced by bending moments at A and B. It is because those moments create curvature that the column can buckle, even though there is no lateral load. The analysis of Euler buckling looks for the condition under which an initially-straight elastic column can remain in equilibrium even though it has deflected sideways. The lowest critical load at which that can happen is close to the load at which real slender columns buckle. At the cost of increased mathematical complexity, the analysis can be made more sophisticated by taking account of large deflections, but the practical conclusion is essentially the same.

It has been known for a very long time, at least since the early work of Lubinski (1950), that buckling calculations about the longitudinal force in a pipeline or a riser need to take

into account the longitudinal force in the fluid contents as well as the longitudinal force in the wall of the pipe. That is why a longitudinally-constrained pipe can buckle under internal pressure alone, as can readily be demonstrated by experiment (Palmer & Baldry, 1974). In that instance, the longitudinal force in the pipe wall is tensile because of the Poisson effect, but there is a larger longitudinal compressive force in the contents, and so the resultant longitudinal force is compressive and the pipe can buckle if the resultant longitudinal force is large enough. It turns out that the condition under which buckling can occur is a simple one: the constrained pipe buckles when the resultant compressive force, counting both the pipe wall and the contents, is equal to the calculated buckling force that corresponds to the pipe dimensions, material and end conditions. The reality of this effect is understood and recognised, and it routinely forms part of calculations (see, for example, Sparks, 2007) and of codes (see for example, Det Norske Veritas, 2010, section 4 G 306). Neglect of it has occasionally led to accidents. However, arguments about the point still surface occasionally. They are often based on an assertion that the contained fluid cannot exert a lateral force on a pipe, and that in consequence the pipe cannot buckle, or alternatively that a pipe cannot buckle if the pipe wall is in tension. The objective of the experiments described here is to demonstrate the effect by a simple theoretical analysis, followed by a straightforward experimental demonstration, designed to leave no room for argument about the details.

TheoryIt is helpful first to consider an initial straight column rather than a pipe. That example has the advantage of not being controversial: nobody argues that an Euler column cannot buckle because there is no lateral force on it. The classical structural analysis shows that the column buckles under a load that can readily be calculated, and many experiments confirm that.. Figure 1(a) shows a weightless column. Initially the column was straight and stress-free, and lay along the chain-dotted line. Under load, the column has deflected away from the original line. It is loaded by equal and opposite compressive forces that act along that line; there is no lateral load. AB is an element of

Effective tension and compression in pipeline and riser buckling‘Effective tension’ is one of the key concepts in pipeline and marine riser engineering since it tells the user how to account for the pressure in the fluid inside and outside the pipe. although known and understood for at least 60 years, engineers still sometimes overlook it and get into trouble. Prof Andrew Palmer and Agustony Sabtian discuss the outcome of a recent National University of Singapore experiment aimed at removing any remaining uncertainty.

Figure 1.

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Consider next the pipe shown in Figure 1(c), internally pressurised by a weightless fluid and deflected away from its initial position in which the tube axis lies along the chain-dotted line. Again define an element of the pipe and its contents AB between two parallel intersecting planes perpendicular to the line. That element is redrawn in Figure 1(d). The downward-pointing heavy arrow at the top represents the force exerted by the pipe and the fluid above A across the plane A and onto the element AB. The upward-pointing heavy arrow at the bottom represents the force exerted by the pipe and the fluid below B across the plane B and onto the element AB. Those forces are not in line, and again the offset creates a couple. Figure 1(e) shows the fluid (not the tube and fluid together) between the parallel planes A and B. The heavy arrows represent the forces exerted on the fluid element between A and B, by the fluid above the element at A and below the element at B. Again those forces are not in line, and together they create a couple. There is no shear across the fluid boundaries at A and B. The element of fluid is in equilibrium. There must therefore be a balancing couple, represented by the circle with arrowheads, which is the resultant couple that corresponds to the forces exerted by the wall of the tube on the element of fluid. An equal and opposite couple is exerted by the fluid element onto the wall of the tube between A and B. Exactly as in the case of the Euler column in Figure 1(a), it is that couple that can create buckling, and that needs to be accounted for in calculations. These issues are explored at greater length in numerous publications. They take account of additional factors such as the weight of the fluid contained within the tube, but again without altering the underlying conclusion. Lubinkski’s original work (1950) did not use the term effective tension, and that came in later (Lubinski, 1977). In retrospect, it was perhaps not the ideal choice of words, but it is nowadays so widely used that it would be counter-productive to try to change it.

Experimental schemeFigure 2(a) is a uniform straight tube. Two possible loading systems are illustrated in Figure 2(b) and 2(c). Loading 1 in Figure 2(b) loads the tube as a pin-ended column, as in the classical Euler buckling analysis; the internal pressure is atmospheric. The axial load is transmitted to the pipe wall by end plugs. The tube wall is under longitudinal compression, and the longitudinal stress is compressive and equal to the

Figure 2.

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13FLP100A potentiometers, so that absolute deflection could be calculated as the vector sum of the two deflections. Figure 5 is a detailed drawing of the top end plug in loading 2. The scheme described in Figure 2(c) is an ideal experiment with frictionless end plugs. A practical implementation has to contend with some friction in the end plugs. Figure 6 plots the longitudinal force against the lateral movement at the mid-height of the tube, for loading 1 (longitudinal compression applied externally) and loading 2 (internal pressure). The longitudinal force in loading 1 is the force measured by the load cell. The longitudinal force in loading 2 is the force measured by the load cell, but because of the effect of friction on the end plugs that force is a little smaller than the measured internal pressure multiplied by the internal cross-sectional area. At the end of the test, the load cell force is 571N and the pressure multiplied by the internal area is 660N, and therefore the tube wall carries a longitudinal tension of 89N. It is to be expected that the tube will be put into tension, because in the ideal situation with frictionless plugs (Figure 2(c)) the pipe wall would be in pure circumferential tension, and the tube would therefore shorten longitudinally because of the Poisson effect. Partial frictional restraint therefore puts the tube into longitudinal tension. It can be seen that the loads at which the deflections become large agree well. It is not to be expected that the deflections will coincide perfectly. Although the two tubes in the two tests were nominally identical, each of them has an initial

axial load divided by the cross-section area of the pipe wall. The circumferential hoop stress is zero. Loading 2 in Figure 2(c) loads the tube by applying internal pressure. The pressure is contained by frictionless end plugs at both ends, but now the plugs are slightly different, so that they are free to move axially within the tube. The plugs have to be constrained so that the internal pressure does not push them out of the tube, but the plugs are free to rotate in the plane of the diagram, so as to provide the same pin-ended end conditions as in loading 1. The longitudinal stress is zero. The circumferential hoop stress is tensile. The force on each plug is the internal pressure multiplied by the internal cross-sectional area of the tube. In summary, then, the longitudinal force is carried wholly by the pipe wall in loading 1 but wholly by the pipe contents in loading 2. The accepted theory of effective longitudinal force tells us that the resultant longitudinal force at which the pipe will buckle will be the same in loading 2 as in loading 1. If, on the other hand, the longitudinal force in the contents does not need to be taken into account, as objectors to the effective force concept occasionally argue, then the pipe will not buckle at all in loading 2, and the internal pressure can be increased up to the point at which the pipe bursts. This allows a straightforward experimental test of the theory.

ExperimentThe tube was Swagelok 316L stainless steel, outside diameter 9.53mm, wall thickness 1.25mm. The elastic modulus measured in a tension test was 188.5GPa. Significant departure from linearity began when the stress reached 175MPa, the 0.5% yield stress was 280MPa, and the ultimate tensile stress 580 MPa. Sabtian (2012) describes the experiment in detail. Figure 3 is a sketch showing how the tube was mounted in the Tritech 100kN testing machine, for the test under internal pressure, loading 2. The same set-up was used for loading 1, but with the pump, valve and pressure gauge removed. Two different tubes were used for loading 1 and loading 2: they had the same specification and identical dimensions. Figure 4 is a photograph of the end bearings in loading 1. The tube was mounted so that it could laterally deflect freely in any direction, and the central deflection was measured by two perpendicular pairs of Sakkae

Figure 3. Figure 4.

Figure 5.




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out-of-straightness, and the out-of-straightness will not be exactly the same: this point is quantified below. The same graph includes the calculated buckling load. The Euler buckling load of an elastic pin-ended column with length L, elastic modulus E and second moment of area I is π2EI/L2. In this instance E is 188.5GPa (1.885×105N/mm2), I is 285.0mm4 and L is 920mm. The corresponding buckling load is 626N.

Southwell plotsA real column can never be perfectly straight, and so it begins to deflect at loads less than the buckling load. Southwell (1936) put forward an elegant method for analysing buckling tests on columns. His method makes it possible to determine the elastic critical load and the initial out-of-straightness without continuing the test to the point at which the deflections become large and the column begins to deform inelastically. The relationship between the load and the lateral deflection becomes (Britvec, 1973)

(1)

whereP is the compressive force in the columnPcr is the Euler critical load∆0 is the initial out-of-straightness when the compressive force P is 0.u is the additional lateral deflection that occurs when the compressive force is increased from 0 to P.

Equation (1) rearranges into

(2)

Southwell plots u/P against u. The slope of the resulting line is 1/Pcr, and the intercept on the u/P axis is ∆0/Pcr. Figure 7 shows the Southwell plots for loadings 1 and 2. In the loading 1 case, the buckling load derived from the plot is 652N, and the initial out-of-straightness is 0.9mm. In the loading 2 case, the buckling load derived from the plot is 630N, and the initial out-of-straightness is 1.9mm. The linearity of the Southwell plot depends on the dominance of the first Fourier component of the out-of-straightness. That component becomes dominant as the load approaches the Euler

Figure 6.Measured midpoint deflection, u (mm)

Experimental load deflection curveCo

mpr

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Agustony Sabtian recently received his BEng (Honours) in civil engineering from the National University of Singapore. During his undergraduate years in the NUS Department of civil & Environmental Engineering, his studies focused on offshore engineering. His final year thesis is used as reference for this article.

AcknowledgementThe authors thank Charles Sparks and Jack Bayless for their participation in the stimulating discussions that led to the tests described in this article.

ReferencesBritvec, SJ. 1973. The stability of elastic systems. Pergamon Press.Det Norske Veritas. 2012. Submarine pipeline systems, Offshore Standard DNV-OS-F101. Det Norske Veritas, Høvik, Norway.Lubinski, A. 1950. A study of the buckling of rotary drilling strings, Drilling and Production Practice, American Petroleum Institute, 178-214. reprinted in Developments in petroleum engineering: Collected works of Arthur Lubinski (ed Miska, S), Gulf Publishing, (1988).Lubinski, A. 1977. Necessary tension in marine riser. Revue de l’Institut Français du Pétrole. Reprinted in Developments in petroleum engineering: Collected works of Arthur Lubinski (ed Miska, S), Gulf Publishing, (1988).Palmer, AC & Baldry, JAS. 1974. Lateral buckling of axially-compressed pipelines. Journal of Petroleum Technology, Vol26, pp1283-1284.Sabtian, A. 2012. Effective tension in pressurised pipelines. Unpublished BEng dissertation, Department of Civil & Environmental Engineering, National University of Singapore.Southwell, RV. 1936. An introduction to the theory of elasticity for engineers and physicists. Oxford University Press.Sparks, CP. 1984. The influence of tension, pressure and weight on pipe and riser deformations and stresses, Transactions of the American Society of Mechanical Engineers, Vol106, March 1984, pp46-54.Sparks, CP. 2007. Pipe and riser deflections and global stability: the effective tension concept. In Fundamentals of marine riser mechanics, Pennwell, Tulsa, OK.

critical load: that is discussed in detail by Britvec (1973). The linearity will not be retained once plastic deformation begins. The results allow a three-way comparison between two independent experiments and theory, as follows:

buckling load (N) experiment, loading 1 652 experiment, loading 2 630 theory 626

A further comparison can be made with Figure 6. The agreement is good. It is consistent with the accepted effective tension theory of how to treat longitudinal force in internally pressurized pipes, and it vindicates that theory. It gives no support to those who have argued that internal pressure cannot create buckling. According to the counter-argument, there ought to be no buckling under loading 2: that is incontrovertibly not the case. Hopefully this will resolve the argument once and for all.

Andrew Palmer has divided his career equally between practice as a consulting engineer and university teaching. In 1975 he joined RJ Brown & associates, and in 1985 he founded andrew Palmer & associates. In 1996 he became research professor in petroleum engineering at cambridge University. He is currently Keppel Professor at the National University of Singapore. Prof Palmer

is the author of three books and more than 200 papers on pipelines, offshore engineering, geotechnics and ice.

Figure 7.

Loading 1 – Southwell plot

OE

Loading 2 – Southwell plot

Measured midpoint deflection, u (mm)Measured midpoint deflection, u (mm)

u/P

(x10

-2m

m/N

)

u/P

(x10

-2m

m/N

)

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TheDP3Lewek Connectoriscapableofoperatingin3000mwaterdepthandhastwoturntableswithatotalpayloadcapacityof9000te.Italsohasamobilereeldrivesystemforupto4x300tereels.Ithasa2100m2deckareaandcranecoveragetoenableHVcablesplicing.Lengthoverallis156.9mandbreadth32m.Transitspeedis16knots.Thevesselalsohasbundle-laycapability,whichallowsforthelayingofseveralcablessimultaneously. ‘Thelargepayloadcapacityincreasestheefficiencyofcable-layingoperationsbyavoidingthetime-consumingsplicingofcablesandreducingtheneedtoreloadproducts,’explainedSveinHaug,regionalheadforEmasAMCEuropeandAfrica.‘Fittedwithbundle-laycapability,theLewek Connectorisoneofthemostefficientandcompleteinstallationvesselsinthemarket.’ UpcomingsistervesselLewek Constellation,alargeiceclassedmulti-layvesselwithheavyliftcapabilities,willalsobeequippedwithDP3andratedfor3000m-pluswaterdepthoperations.AccordingtoEmasAMC,itwilloffersuperiormanoeuvrabilityandahightransitspeedwithamulti-laysystemthatcansupportbothrigidandnon-rigidpipelines.Thevesselwillhavea3000teheavy

programmepossiblystretchingtheseasonintoNovemberisunderdiscussionwithStatoil. Lookingaheadto2014,EmasAMCwasawardedacontractbyABBlastmonthforcableinstallationbetweenStatoil’sTrollAplatformandthelandstationatKollsnes,toprovideadditionalpowertoruntwocompressordrivesystems.Thecompanycurrentlyhasalong-termagreementwithABBfortheLewek Connectorinconnectionwiththeinstallationofpowercablesandrelatedservices.

assignments,Lewek Connector hasbeenfullyemployedwithnotechnicaldowntimesincedelivery,reportedEmasAMCvicepresidentstrategicprojectsBjarneBirkeland.‘Wehavenothadasinglehouroftechnicaldowntimeonabrandnewvessel,asaconsequence,Ithink,ofagoodprojectteam,goodintegrationwiththeyard,andgoodtechnicalpeople.’ Thevessel’sfirstjobwasriserreplacementforStatoilonSnorreB,followedbyhigh-voltagecableinstallationbetweenWalesandIrelandforABBinlateApril/May,thenasecondriserreplacementcampaignforStatoilfromMayuntilAugust.ItiscurrentlycarryingoutcableinstallationfortheGermansectorDolWinoffshorewindfarm.NextyearitalreadyhascableinstallationforStatoilonGudrunandforEniontheBarentsSeaGoliatproject.Afurtherriserinstallation

SURF sistersEmasAMC,formedlastyearwhenEmasacquiredAkerMarineContractorsfromAkerSolutions,tookdeliveryofitsfirstnewbuilddeepwater,multi-purpose,flexlaysubseaconstructionvesselLewek ConnectorinMarchthisyear.Asecondvessel,Lewek Constellation,currentlyunderconstructioninVietnam,isduetocomeintooperationinthesecondquarterof2014. Despitetestingweatherconditionsonitsfirsttwo

vessels in action

new or upgraded vessels have been very much in evidence lately as the subsea and deepwater vessel markets continue to grow and more renewable energy opportunities emerge. Reports by Meg Chesshyre and Russell McCulley.

LewekConstellation, a large ice classed multi-lay vessel with heavy lift capabilities, will join LewekConnector (picturedtop) in the Emas AMC fleet in 2014.

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facility in the Netherlands for the installation of a third-generation multi-lay system. There is also an option to install J-lay. Emas AMC has offices in Houston, Oslo and Singapore, plus a London consulting group concentrating on heavy lift work. The company currently has around 200 engineers, but the headcount is expected to grow as more high-end vessels join the fleet. The company is looking at establishing a marine/spool base in Norway’s Stavanger area, and has identified two sites. Birkeland said the new vessels marked the company’s entry into the SURF market. ‘Today we are not Technip or Subsea 7, but we have proved with the Statoil riser replacement programme that we can go in as an agile, fast organisation and deliver a result,’ he added.

lift crane. With a length of 178m, breadth of 46m, and deck area (without reels) of 4200m2, the vessel will have 3000te crane, a 900te hang-off clamp, two 1250te flexible pipe carousels, four 1200te rigid pipe storage reels and a 19m x 8m moonpool. Following this October’s launch from the Vietnamese yard, Lewek Constellation is scheduled for delivery late May 2013. It will then go to China for installation of the 3000te Huisman crane, then to Huisman’s Schiedam

Deep thinking: technip expects to take delivery of its big new pipelay vessel, Deep Energy (pictured above), mid-2013. the contractor claims the vessel, currently under construction by StX in Fløro, norway, will have a high transit speed of 20 knots. Designed for north Sea, Atlantic basin and inter-continental operations, Deep Energy will have the capability to handle rigid pipe up to 18in OD with a maximum coating thickness of 2in and flexible pipe and umbilicals up to 23.6inOD. it will incorporate an innovative pLet handling system. technip is also building a new pipelayer, Deep Orient, at Spain’s Metalships yard. Due for completion late next year, it will be deployed in the Far east.

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really is proud of the ship.’ As of late summer, the Grand Canyon’s first mission was ‘up in the air’, Aylmer said, although it would likely involve trenching or construction in the North Sea. Next up would probably be a job installing inter-array

for trenching and renewable energy Gary Aylmer enthused: ‘I went to see the boat in February, and I was impressed that the captain and chief engineer were standing by the boat then, and they’d been on there a long time. Volstad, being a family owned business,

under a five-year fixed-rate charter with owner Volstad Maritime. The 125m x 25m DP3 Skipsteknisk design vessel will operate out of Ålesund, the Norwegian port from where a good many of its marine crew hail. Canyon Offshore VP

Versatile vessel Norway’s Bergen Group Fosen shipyard, just outside Trondheim, was the last stop for Canyon Offshore’s Grand Canyon offshore construction vessel as the newbuild was readied for North Sea service

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Poised for pipelay McDermott International is building a new high-capacity reeled pipelay vessel with top-tier payload capacity, tentatively named Lay Vessel 108 (LV108). The vessel will be a sister ship to the recently completed subsea construction vessel North Ocean 105 (LV105), and is to be built to similar specifications at the Metalships & Docks yard in Vigo, Spain. Outfitting of the custom-designed lay system will begin following delivery of LV108 around 3Q 2014. ‘LV108 is another milestone in our vessel renewal programme focusing

on the subsea construction market for flexible and rigid product installation,’ said Stephen Johnson, chairman, president and CEO of McDermott. ‘Market analysis indicates that the subsea and deepwater construction market is expected to continue to grow and there is demand for more tonnage in both the rigid reel lay and flexible lay markets. The LV108 is expected to meet this need.’ The 132.4m long DP2 vessel, with a nominal 2500te reel payload, will target pipe diameters in the 4-16in range. Equipped with a high-capacity tower with 400te tensioner and tilting angles

from 28-90° for rigid and flexible pipelay, LV108 will have accommodation for 120 and a 450te/150te A&R system rated for pipe abandonment or subsea lowering to 3000m water depth. Other features include two portside AHC main cranes – 100te and 400te – for subsea lifts and construction support. McDermott said anticipated transit speed is 15 knots. Outfitting of sister reel pipelay vessel LV105 was completed in May and it is booked for a maiden assignment in Asia in water depths up to 4430ft. ‘We look forward to LV108 joining the LV105 and other vessels in our fleet in 2014,’ said Johnson.

Artist’s impression of the new reeled pipelay vessel LV108. The recently completed LV105.

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easily between oil & gas or renewable energy operations. ‘Because of its size, the beam, the under-deck stiffening we put in, it’s a very versatile vessel.’ And a rather plush one: accommodating a crew of 108, Grand Canyon’s amenities include carefully detailed rooms, large picture windows in some common areas and a small swimming pool on a side deck. ‘It’s setting the bar high,’ Aylmer observed. Canyon Offshore and parent company Helix Energy Solutions Group have reached agreements with Volstad Maritime and Bergen Group Fosen for the construction and chartering of an identical sister vessel. According to Volstad Maritime, the contract for delivery of Grand Canyon 2 is worth more than $800 million. The new OCV is scheduled for delivery in 3Q 2013 and is earmarked for service in the Gulf of Mexico. A third sister vessel is also in the works.

cables for the UK’s major London Array wind farm development. The 175-turbine project in the Thames estuary is expected to occupy the new vessel for more than 100 days. The Grand Canyon (OE October 2011) is well suited to this kind of shallow-water operation because it has no azimuth thrusters forward, Aylmer explained. Rather, the ship maintains position with four tunnel thrusters, allowing it to work in depths as shallow as 10m and to hold station ‘comfortably’ in 3 knot currents with thrusters running at 50% power. The vessel will accommodate the new T1200 jet trencher and two 200HP XLX ROV systems and is equipped with a 250t crane, moonpool and a reinforced deck that can support not only the trenching system but a reeled lay system and carousel. ‘I don’t think we want to pigeonhole the vessel,’ Aylmer said, noting that it can switch

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PRODUCTS IN ACTION


stroke, without depressurizing the valve and releasing hydrocarbons; a powerful dual-coil spring package is capable of shearing standard 7/32in braided cable, allowing valve closure, and a captured spring design that prevents release of the preloaded spring during repair or actuator removal. The CHA series offers two

Expanding its portfolio of hydraulic actuators for the surface drilling sector, GE Oil & Gas launched a CHA hydraulic actuator series at ONS that accepts supply pressures up to a maximum of 6000psi. The company’s earlier cost-effective RA series could manage supply pressures up to 3500psi. Ian Milne, president of the GE Oil & Gas Pressure Control business, said the new actuator line is more robust and increases the company’s market competitiveness, as well as offering improved safety features including: a quick-disconnect design that enables removal of the actuator from the bonnet within the valve operating

section with the potential for several hole-related issues. For flexibility in handling borehole instability, the operator required on-demand capability to close reamer flow to the annulus. The Rhino XC was run, allowing cycling of the reamer multiple times during the course of the run, simply by changing the pump flow rate in a predetermined sequence. According to Schlumberger, the resulting 9283ft run was completed in just over 300 circulating hours, a new run-length record for the client.

Robust actuators pile on the pounds

Rhino reamer delivers on-demandThe Rhino XC on-demand reamer, released at ONS by Schlumberger, is a next-generation reaming tool that provides unlimited activation of the flow actuation system to reliably enlarge boreholes. Building on Rhino XS hydraulically expandable reamer technology, the Rhino XC is designed to provide complete control of reamer cutter-block deployment, regardless of well-inclination angle. Its flow activation system eliminates the need for time-consuming pumpdown device activation, allowing the reamer to be placed below inner diameter-restricted bottomhole assembly components resulting in a reduced pilot-hole interval at total depth. ‘With its on-demand capabilities and unlimited activations and deactivations of the cutter blocks, customers can optimize their underreaming program in real time,’ noted Dean Watson, president, Schlumberger Drilling Tools & Remedial. ‘In deepwater environments, this provides huge savings for our customers by enabling faster and reliable activation.’ Offshore Norway, one North Sea customer undertook a long and challenging 91/2in x 101/4in

products in action

Hydraulic oil shows Arctic promiseRecent tests on Mobil Industrial Lubricants’ Arctic performance hydraulic oil have reportedly shown that it can help reduce hydraulic system energy consumption by up to 6.2%, when compared with standard mineral hydraulic oils. Given pride of place in ExxonMobil’s ONS display in Stavanger this summer, the Mobil SHC 500 series has been engineered to help protect hydraulic equipment operating on offshore and onshore oil & gas rigs and platforms located in extremely cold climates such as the Arctic, Russia and the Nordic countries. At –400°C, SHC 500 is said to be four times thinner than similar viscosity index conventional mineral hydraulic oils, allowing it to circulate around the hydraulic system faster at start up, ensuring the lubricant is in place to protect machine components. For hydraulic equipment operating in even colder conditions, specialised products such as Mobil Univis HVI or Mobil Aero HF-A have been developed. The hydraulic oil is part of the high performance Mobil SHC brand of synthetic lubricants, formulated to help oil & gas companies operating in extreme environments to

reduce unscheduled downtime and maximise productivity. The range includes gear, bearing, compressor, turbine and gas engine oils, which alongside their cold temperature performance and energy efficiency potential, are claimed capable of extending the service life of machine components by lasting between three-to-six times longer than mineral oil based products. ‘Safety is the number one concern for oil & gas companies and by reducing scheduled and unscheduled maintenance, you eliminate the associated safety risks that engineers face when undertaking the work,’ said Akram Reda, EAME industrial lubricants marketing advisor for ExxonMobil Lubricants & Petroleum Specialties. ‘Alongside the safety benefits, significant productivity and sustainability improvements can also be realised by extending equipment life and oil drain intervals.’ In addition to SHC 500, other Mobil high performance lubricants developed for the oil & gas industry include the SHC 600, Pegasus, Gear and Polyrex series. The company also offers a proprietary online oil analysis service, Signum, which enables operators to monitor proactively the condition of lubricants and address conditions that could potentially lead to unscheduled downtime.

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record to the high-differential ball valve, simplified slip design, anti-debris filter and conclusive pull-and-rotate release mechanism. Should well conditions prevent normal retrieval, the top section can be milled easily to release the slips, it adds.

‘Smart darts’ hit reliability target Aberdeen-based Churchill Drilling Tools had on display at ONS an innovative dart activation system now being deployed for technically challenging high-angle sections in Norwegian continental shelf wells. According to Churchill, DAV MX mechanical extrusion dart activated bypass valve deployment achieved its 100% reliability target last year. ‘The MX system allows the use of rigid Smart Darts for multi-cycle control and exploits their robustness and resilience to high pressure/high temperature (HPHT) environments to deliver greater speed, reliability and performance than with conventional ball activation through polymer extrusion,’ said the downhole tool developer. The darts are deployed with hardened landing shoulders and dual sheer points.

Radiation monitoringThe new NORM (naturally occurring radioactive material) monitor, added to Tracerco’s range of radiation monitors at ONS, was specifically developed to meet the requirements of the oil & gas industry in detecting and quantifying naturally occurring radioactive isotopes. Designated the NORM Monitor-IS, the robust and intrinsically safe portable unit can also measure contamination levels. Its dual probe option is said to optimise monitoring capability for all types of NORM including Radium and Lead-210 based scales.

large-diameter (1/2in) LP actuator ports: one for easy alignment to supply lines, minimising debris buildup, and one with an optional safety head designed to protect the actuator from over-pressurization.

Well integrity on the upgradeA new range of four gas-tight well suspension plugs, designated the Lock series, was unveiled by well integrity specialist Archer during ONS. The series comprises four application-specific products: SafeLock, for short to medium term suspension periods; TimeLock for long- term suspension or harsh conditions; StormLock for storms, extended periods or harsh conditions; and LastLock, for total security in permanent well abandonment. Rapid set and seal, easy move and reset, and a 100% retrievability record combine to provide absolute protection, with high efficiency and low operating costs, according to Rolf Haaland, VP and GM of Archer’s Oiltools division. ‘When sealing wells for suspension or abandonment, barrier failure can prove disastrous – for rig teams, the local environment and an operator’s reputation. The advanced technology behind our new Lock series of well suspension plugs provides the assurance and protection the industry needs.’ According to Archer, the combination of advanced seal engineering, pressure testing from below and pre-set seal surface cleaning takes Lock seal assurance to ISO 14310 V0 level. The company attributes Lock’s impressive retrieval

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FIRMS & FACES

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impact as projects move into deeper waters further from shore.’

Forum Energy Technologies is planning to build a new 150,000ft2 facility in St Martin Parish, Louisiana to produce onshore and offshore drilling equipment for global customers. The $19 million

on the Åsgard subsea gas compression system (OE April). Aker CTO Åsmund Bøe commented: ‘This technology has the potential to change offshore gas field developments worldwide. With the forecast growth of subsea developments, subsea compression will become widespread, having even more

Technip has completed the acquisition of Stone & Webster process technologies and associated oil and gas engineering capabilities from Canada’s Shaw Group.

Aker Solutions and Statoil were jointly awarded the ONS Innovation Award in Stavanger for their work

Amec is acquiring a 50% stake in Kromav Engenharia, a privately owned Brazilian engineering firm with over 400 marine and offshore projects to its credit. Based in Rio de Janeiro, Kromav has a team of some 200 people specialising in engineering services for offshore platforms, FPSOs and other marine applications.

firms

OFFSHORE ACHIEVERSFollowing a successful re-launch last year, the Society of Petroleum Engineers Aberdeen Section is again hosting the Offshore Achievement Awards with the support of main sponsor Taqa Bratani. Anticipating an even bigger turnout this year, the organisers are switching the 21 March 2013 black tie awards ceremony to the Aberdeen Exhibition &

Conference Centre. The 27th Offshore

Achievement Awards

are open to entries until 1 December from UK-registered companies in both the offshore oil & gas and renewables sectors, reflecting the growing reach of the North Sea industry. In addition to recognising exceptional business growth, the awards will focus on particular innovations, safety breakthroughs and collaborative efforts, as well as individual success. The titles of two categories have changed this year, however criteria remain the same. The 2013

categories are: Export Achievement; Offshore Renewables; Safety Innovations; Emerging Technology (previously New Idea); The Innovator; Great Small Company;

Great Large Company; Working Together; Young Professional, and Significant Contribution (previously Lifetime Achievement). Over 70 entries were received for the 2012 awards, and the winners included Amec, the Expro Group, 3sun and Professor Alex Kemp. Ian Phillips, director of CO2DeepStore and the SPE board member responsible for organising the OAAs, said: ‘The success we saw after re-launching the awards last year was hugely positive and demonstrated that the awards have a firm place in the energy sector calendar.’ Describing the awards, originally run by Scottish Enterprise, as the ‘premier forum for celebrating the very best in the offshore industry’, Phillips said it was vital that the talent responsible for shaping today’s industry, as well as the high performers and pioneers who will develop tomorrow’s cutting edge solutions and innovations, be recognised. Leo Koot, managing director of main sponsor Taqa Bratani, said: ‘I’m particularly pleased that we’re supporting the 2013 Offshore Achievement Awards, not only because they celebrate success throughout the industry, but because they recognise innovation. Taqa recognises that it’s going to take innovative commercial solutions to maximise the potential of the UKCS, so it’s important that companies with a creative approach to doing business are awarded.’ Further details of the awards and how to enter can be found at www.spe-oaa.org

BRAZIL BERTH: Dutch offshore lifting and drilling solutions provider Huisman has begun the landfill works for a 15,000m2 production facility in southern Brazil alongside the Itajai-Açu river in Navegantes, Santa Catarina state. It is expected to be operational in 2Q 2013. Subsequent

investment plans include construction of a 200m long quayside with an artificial bay to protect against the river’s high currents and allow fast access to the new facility for seagoing vessels needing to install, commission and test Huisman systems and equipment onboard.

tie awards ceremony to the Aberdeen Exhibition & The titles of two categories have changed this OAAs, said: ‘The success we saw after re-launching the awards last year was hugely positive and demonstrated that the awards have a firm place in the energy sector calendar.’ Describing the awards, originally run by Scottish Enterprise, as the ‘premier forum for celebrating the very best in the offshore industry’, Phillips said it was vital that the talent responsible for shaping today’s industry, as well as the high performers and pioneers who will develop tomorrow’s cutting edge solutions and innovations, be recognised. Leo Koot, managing director of main sponsor Taqa Bratani, said: ‘I’m particularly pleased that we’re supporting the 2013 Offshore Achievement Awards, not only because they celebrate success throughout the industry, but because they recognise innovation. Taqa recognises that it’s going to take innovative commercial solutions to maximise the potential of the UKCS, so it’s important that companies with a creative approach to doing business are awarded.’ Further details of the awards and how to enter can be found at www.spe-oaa.org

tie awards ceremony to the Aberdeen Exhibition & Conference Centre.

The 27th Offshore Achievement Awards

The titles of two categories have changed this year, however criteria remain the same. The 2013

categories are: Export Achievement; Offshore Renewables; Safety Innovations; Emerging Technology (previously New Idea); The Innovator; Great Small Company;

Busy planning an even bigger Offshore Achievement Awards ceremony in Aberdeen next March are (left to right): CO2DeepStore director and SPE board member Ian Phillips; ITF’s Anthony Onukwu, newly elected chairman of the SPE Aberdeen section, and Leo Koot, managing director of the awards’ main sponsor Taqa Bratani.

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Audubon Engineering. Roberts, a 30-year oil & gas industry veteran, will directly oversee the company’s operational business groups. He steps up from VP of Houston onshore, a post now occupied by Michael Northcott.

Ciaran O’Donnell (pictured) has been appointed CEO of subsea project and integrity

management specialist Flexlife. He was co-founder and CEO of CSL before its 2007 sale to DOF Subsea, remaining for three years afterwards mainly in the role of Atlantic region EVP.

Gertjan van Mechelen has joined ERHC Energy as exploration manager. Previously with ConocoPhillips and TransAtlantic Petroleum, he will oversee the company’s Africa-focused exploration activities.

Shyamal Bhattacharya (pictured) has taken over as operations director at Indian state oil company

subsidiary ONGC Videsh. An acknowledged authority on IOR, he once headed the Institute of Reservoir Studies in Ahmedabad.

Amy Myers Jaffe has joined the University of California, Davis, as executive director of energy & sustainability in a joint appointment to the UC Davis Graduate School of Management & Institute of Transportation Studies. She has spent the past 16 years at Houston’s Rice University, where she served as director of the energy forum at the James A Baker III Institute for Public Policy.

Anne Drinkwater (pictured) has become a non-executive director of Tullow Oil. She previously

served in senior posts with BP, including president of BP Indonesia.

Julian Hammond was promoted to CEO and president of

Gretchen Watkins, currently VP of International Production Operations (IPO), has taken over from the retiring Jim Bowzer as Marathon Oil’s VP North America production operations. Mitch Little, Marathon’s Norway business manager, succeeds Watkins as VP international production operations.

Carri Lockhart (pictured) is Marathon’s new UK North Sea asset team MD. Her earlier

posts include asset team manager for Marathon Alaska operations and business development director for North and South America.

Harold Kvisle (pictured), a director of Talisman Energy, has stepped up to president and CEO

of the Canada-headquartered E&P company following the departure of John Manzoni.

Jens Pace became COO of African Petroleum on 1 October. A geoscientist, he worked internationally for BP and its heritage company Amoco (UK) Exploration for over 30 years.

Mark Roberts has been promoted to EVP operations for Houston-headquartered

plant will replace an existing facility in nearby Broussard.

Gardline Geosciences and Canyon Offshore have established a three-year strategic alliance to provide seabed drilling, sampling in situ services for the offshore site investigation market.

Swagelok has acquired the assets of Erie, Pennsylvania-based Innovative Pressure Technologies. IPT manufactures high and medium pressure subsea valves, fittings and fluid control devices.

Aquaterra Energy opened an office in Aberdeen last month. The company’s team there, working on drilling riser systems, offshore platforms, subsea templates and the like, is headed by GM Eric Doyle who commented: ‘We are developing the expertise to provide high value engineering and technical support at a local level. This is backed up by the infrastructure and long-term established engineering team in Norwich and Cambridge.’

SeaRobotics Corporation has teamed with a private equity group led by Ocean Investments Capital to fund the expansion of the company’s core business, including the production of unmanned surface vessels

BRAND NEW: smit Lamnalco recently launched SL Gabon, the first tug branded under its new corporate identity, following the integration of Smit’s terminal handling activities with Lamnalco in July 2011. Built by Damen Shipyards Galati in Romania, this is the first of two newbuilds contracted for a five-year period by Total Gabon to provide support in the offshore oilfields and to assist tanker operations at the onshore terminal of Cap Lopez, at Port Gentil. The second tug, SL Libreville, was due for delivery in September. faces

(USVs), the commercialization of its Robotic Hull Cleaning systems, and the development of new product lines in the ocean sciences and survey markets.

GL Noble Denton has established a global design centre for floating structures at its offices in Brevik, Norway.

Aker Solutions is opening an engineering office in the northeast of England. The company’s drilling technologies business will be the main beneficiary of the expanded Stockton-on-Tees presence.

Swedish polymer and syntactic foam specialist Trelleborg officially opened its newly constructed facility in Macaé, Brazil, last month. The company also announced that it is planning to install ‘the largest hydrostatic pressure testing vessel in the world’ at the new facility.

GE completed its acquisition of Bergen, Norway headquartered Naxys, which supplies leak detection and condition monitoring sensors for the subsea sector, last month. The acquisition further expands GE’s portfolio of monitoring and sensing solutions and will be part of the company’s Measurement & Control business.

oe_F&F.indd 70 28/09/2012 13:46


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Chor How Jat, executive director of Singapore’s Keppel Shipyard has assumed the role of acting MD of the yard’s businesses and operations following the sudden death of Nelson Yeo. Rahul Dhir stepped down as MD and CEO of Cairn India, reportedly to pursue other business opportunities.

Calixto Deberaldini has been appointed BDM and strategy adviser at Brazil’s Fluke Engenharia, reporting to MD Laurent Maubré. Deberaldini joins the Acteon group business unit from GE Oil & Gas where he served as the subsea division’s Brazil sales manager.

Aimee Marsh (pictured) is the new Energy Industries Council executive director, North and Central

America, based at the EIC Houston office. She previously worked for Canyon Offshore and Saipem America.

a director of London Marine Consultants, now part of Singapore-based Ezra Holdings, Coates is tasked with developing Sigma’s presence in London having just opened a new office there.

Pat Haggerty (pictured) has joined Modus Seabed Intervention as head of projects, a newly created

post. He was with Subsea 7 for seven years, latterly as Aberdeen-based GM of Europe & West Africa ROV operations in its iTech division, and prior to that spent more than a decade with Oceaneering International Services.

John Hunter (pictured) has been appointed project engineering manager at Divex’s Westhill, Scotland headquarters. Greg Hewitt (pictured) becomes the saturation diving systems supplier’s

Asia Pacific region GM.

Apache. Brady Parish joined the company as VP investor relations.

David Hunt (pictured left) and Faris Lutfy (below) head up an expanded engineering division at Aberdeen-based Ecosse Subsea Systems. Both are chartered engineers, Hunt hailing from

Flexlife and Acergy and Lutfy from Subsea 7 and DOF Subsea UK.

John Lindsay has been promoted to president and COO of Helmerich & Payne. He joined the company in 1987 as a drilling engineer and most recently served as EVP and COO.

Bob Coates (pictured) has been named COO of Aberdeen-headquartered FPSO moorings and marine

engineering services company Sigma Offshore. Previously

Tethys Petroleum following the resignation of David Robson on health grounds. Peter Lilley took over as non-executive chairman.

Gregory Navarre (pictured) has stepped up from COO to president of Horton Wison Deepwater

following the departure of Jim Maher to pursue other interests. Navarre previously served in various positions with Global Marine and Horton Wison Deepwater’s sister company Wison Offshore & Marine (USA).

Åge Landro (pictured) has rejoined Norway’s AGR Group after a short break. Previously

with the group’s field operations unit for seven years, he returns as EVP of its global Petroleum Services division.

Alfonso Leon has been promoted to SVP and chief of staff at

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the company’s Houston office. He recently retired from ExxonMobil.

R Michael Haney (pictured) has joined Douglas-Westwood to head up its new office in Houston’s central

business district. He was previously with Accenture, Arthur D Little and Booz Allen Hamilton.

Phil Keating has been appointed energy sector BDM for pneumatic motion and fluid control technology provider Norgren.

Eddie Moore has joined Zenith Oilfield Technology, recently acquired by Lufkin Industries, as manager of sales and operations for the Middle East and Africa,

working out of Oman. Peter Smith (pictured), previously with Weatherford, has joined Zenith in

a similar capacity covering the Asia-Pacific region.

he served most recently as Amec’s operations director for West Africa.

David Hayden has stepped up from technical manager to MD of Harris Pye UK, with Steve Blake slotting in to Hayden’s former role.

Chris Peeters has been appointed EMEA region director of Schlumberger Business Consulting, based in Paris. Previously with McKinsey, he will manage SBC’s utilities practice.

Doyle Boutwell (pictured) has been named as manager, technology and business development

– rental & products, at Greene’s Energy Group, based in Houston. He was previously with Weatherford International as director of global quality and training, tubular running services.

Jon Robertson has taken over the role of MD at ROV supplier

David Kirk became CEO of Australian geosciences and well engineering consultancy AWT International on 1 October. Kirk, who previously acted as Woodside’s Pluto LNG project development manager, replaces AWT founder Cameron Manifold who will continue to advise the Perth-based company in a strategic capacity.

Kevin Revere (pictured) has joined the Acteon group as VP, based in Kuala Lumpur. Previously VP

operations in Wasco Energy’s pipe coating division, he will initially support Acteon’s Asia-based Cape business unit as it expands its subsea pipeline sector product and service offering.

Richard Jenkins (pictured) has joined Claxton Engineering as VP operations. Previously with

Hamworthy, Baker Hughes and Seaweld Engineering,

Saab Seaeye following the departure of Dave Grant to pursue other interests.

Chris Charman (pictured) takes over from the retiring Hugh Williams as CEO

of the International Marine Contractors Association (IMCA) in December. Since leaving the Navy he has worked as a loss adjuster and held various risk management and risk financing posts.

Karen Christie (pictured) has joined Aberdeen consultancy Maxoil Solutions as global

business development director. She was previously with Wood Group Integrity Management.

Tom Trigg (pictured) has been appointed global technical advisor for drilling waste management

specialist TWMA, based at

Jumbo Offshore transports and installs heavy subsea structures and mooring systems in water depths up to 3,000m. Lifting capacity on our DP2 vessels is achieved with two 900t mast cranes. Versatility is enhanced with the addition of dedicated project equipment such as; 50 man accommodation block; deep sea winches; heave compensation devices; pile driving hammers; etc. Over the last 10 years Jumbo has built up a solid and reliable reputation as a safe transport and offshore installation contractor. Our concept

“Lift. Ship. Install. All in one go.” continues to provide an extremely effi cient solution.

www.jumbo-offshore.nl

A versatile partner

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even

ts

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28/29 Offshore wind economics & finance. Conference, London. www.wplgroup.com

December3-5 Arctic technology. Conference & exhibition, Houston. www.arctictechnology conference.org3-5 Sustainable ocean summit. Conference, Washington DC. www.oceancouncil.org7 Subsea pipelines integrity management. Conference, London. www.subseauk.com

January 201315-17 Underwater intervention. Conference & exhibition, New Orleans. www.underwaterintervention.com15-17 World future energy summit. Conference & exhibition, Abu Dhabi. www.worldfuture energysummit.com21-23 Offshore Middle East. Conference & exhibition, Doha. www.offshoremiddleeast.com 22/23 Produced water management. Conference, Stavanger. www.tekna.no/intconf

February 20135/6 HSE & training. IADC conference & exhibition, Houston. www.iadc.org/events 18-20 Pipeline coating. Conference & exhibition, Vienna. www.amiplastics.com/events/ 20-22 Australian oil & gas. Conference & exhibition, Perth. www.aogexpo.com.au

March 20134-8 CERAWeek. Conference, Houston. www.ceraweek.org 5-7 Drilling. SPE/IADC conference & exhibition, Amsterdam. www.spe.org18-20 MCE deepwater development. Conference & exhibition, The Hague. www.mcedd.com20-22 OMC. Conference & exhibition, Ravenna. www.omc.it

23-25 Oilfield engineering with polymers. MERL conference, London. [email protected] 24/25 Drilling Africa. IADC conference & exhibition, Lisbon. www.iadc.org 29-2 Nov Africa oil week. Conference & exhibition, Cape Town. www.petro21.com

November4-9 Society of Exporation Geophysicists annual meeting. Conference, Las Vegas. www.seg.org5-8 Subsea survey IRM. Conference & exhibition, Galveston TX. www.subseasurvey.com6-8 OilComm. Conference & exhibition, Houston. www.oilcomm.com7-9 IADC AGM. Meeting, Scotsdale AZ. www.iadc.org9-15 International mechanical engineering. ASME congress & exposition, Houston. www.asmeconferences.org11-14 ADIPEC. Conference & exhibition, Abu Dhabi. www.adipec.com13/14 European autumn gas conference. Conference, Vienna. www.theeagc.com14/15 European well intervention. SPE/ICoTA conference & exhibition, Aberdeen. [email protected] Global safety and competence. OPITO conference, Abu Dhabi. www.opito-oscc.com 20/21 Critical issues Middle East. IADC conference, Dubai. www.iadc.org21/22 North Sea decommissioning. Conference 7 exhibition, Aberdeen. www.decomworld.com21-31 Gulf oil & gas cruise. Conference & exhibition, Persian Gulf. www.oilgascruise.com27-30 OSEA. Conference & exhibition, Singapore. www.osea-asia.com28/29 IMCA annual seminar. Meeting, Amsterdam. www.imca-int.com

October3-5 Subsea Asia. Conference & exhibition, Kuala Lumpur. www.subseaasia.org8-10 ATCE. SPE conference & exhibition, San Antonio TX. www.spe.org8-11 Gastech. Conference & exhibition, London. www.gastech.co.uk9/10 Dynamic positioning. Conference & exhibition, Houston. www.dynamic-positioning.com15-18 Lessons learnt from recent oil spills. NOSCA seminar, Rio de Janeiro. www.nosca.no16/17 Contracts & risk management. IADC conference, Houston. www.iadc.org16/18 Russian oil & gas exploration & production. SPE conference & exhibition, Moscow. www.russianoilgas.ru/en/Home 16-19 Santos offshore. Conference, Sao Paulo, Brazil. www.santosoffshore.com.br 17-19 Geo India. Conference & exhibition, New Delhi. www.aeminfo.com.bh/geo2012 22-24 Asia Pacific oil & gas. SPE conference & exhibition, Perth. www.spe.org 23/24 Offshore energy. Conference & exhibition, Amsterdam. www.offshore-energy.biz23/24 Oil & gas Africa upstream logistics and supply shairn. Conference & exhibition, Johannesburg. www.fairconsultants.com23-25 Drilling & completing trouble zones. Conference & exhibition, Galveston TX. www.drillingtroublezones.com

diary

Please send conference, exhibition and meeting entries, and also calls for papers to:[email protected]

Looking aheadl The Abu Dhabi International Petroleum Exhibition & Conference (ADIPEC), the largest industry event in the Middle East, takes place 11-14 November. More than 45,000 attendees and 1500 exhibitors are expected at this year’s gathering, which focuses on core issues affecting the industry. Scheduled panel sessions cover topics including growth and sustainability, technology deployment, human capital, and the future of the role of gas. The technical program covers topics relating to geosciences, drilling, field development, projects, HSE and asset integrity. For further details, go to www.adipec.coml The European chapter of the Intervention & Coiled Tubing Association (ICoTA) will host the SPE ICoTA European Well Intervention Conference in Aberdeen 14/15 November. Conversations on and off the floor will zero in on the latest developments and best practices in well completion and intervention. For further details, go to www.icota-europe.coml The Arctic Technology Conference will be held 3-5 December in Houston. Scheduled speakers include Jostein Mykletun, Consul General of Norway, Infield Systems senior analyst Jamie Balmer, Total SVP Michael Borrell and Robert Blaauw, a senior advisor at Shell. Technical sessions cover the spectrum of challenges facing companies as they move further into northern climes. For further details, go to www.arctictechnology conference.org

Call for papers18-20 March 2013 MCE deepwater development. The Hague. Abstracts by 19 October.l www.iptcnet.org/20123-6 September 2013 SPE Offshore Europe. Aberdeen.Abstracts by 14 January 2013. l www.offshore-europe.co.uk

30 Sept-2 October 2013 SPE ATCE. New Orleans. Abstracts by 28 January 2013. l www.spe.org/atce/2013/22-24 October 2013 Asia Pacific Oil & Gas. Jakarta.Abstracts by 3 December. l www.offshore-europe.co.uk

oe_diaryOCT.indd 74 28/09/2012 13:55


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The premier meeting place for the Russian Oil and Gas industry

16 – 18 OCTOBER 2012ALL RUSSIA EXHIBITION CENTRE, PAVILION 75, MOSCOW, RUSSIA

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SPE Russian Oil & Gas Exploration & Production Technical Conference and Exhibition 2012

Energy & Marine

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Industry-leading Committee Join Victor A. Saveliev, NGK Slavneft and Sergey Kolbikov, Novatek, Programme Commitee Co-chairs to discuss all major issues in the area of hydrocarbon exploration and production.

Registration Open www.russianoilgas.com

A Focused, High-Calibre International Event Visit the exhibition hosting over 80 companies showcasing leading-edge technology, including a dedicated Knowledge and Science Zone and Technology Incubator - new for 2012

Technical Conference Programme Discover the 18 technical and 3 plenary sessions which make up the 2012 conference programme, featuring key industry speakers from BP, Rosneft, Shell, TNK-BP, Weatherford and more.

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Ebb

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Ow

78

substantive gas supplier. More recently, Putin and Gazprom have pursued a flurry of new developments aimed at making Russia a ‘more open’ proposition to foreign investors. In March, France’s Total acquired a 20% stake in another Russian gas venture in the Arctic. In April, Putin flagged new tax breaks for offshore oil and gas to make far-flung projects more viable. Meanwhile, Russia has ramped up its militarization of the Arctic in support of its energy claims there. And in recent weeks, Russia’s gas giant Rosneft, has cut Arctic exploration deals with Norway’s Statoil and with Italy’s Eni. Potential partnerships between Gazprom and Shell are also in the offing. But there is now a new kid on the block that could pose a very clear and present threat to Russia’s vital European market: Israel along with Cyprus and their upcoming potential status as gas exporting energy superpowers. Here is a fascinating new play in the Israel-Iran nuclear saga. Development of the eastern Mediterranean’s newfound natural gas wealth could well end up reaching the European market. In recent days, an Israeli news report quotes a senior Israeli gas executive as saying: ‘The Russians have been poking around here for a while. Everyone knows about the Russian interest in controlling the European energy market. Do they want to buy from us, or delay our efforts? I don’t know. But they are here.’ The same report also cites Israeli energy website Tashtiot as claiming that during Putin’s recent visit to Israel, he and Israeli prime minister Netanyahu agreed a deal to form a junior company to Gazprom that would help develop Israel’s Leviathan gas field in the eastern Mediterranean. In the same week that Putin visited Jerusalem, Eurasia Monitor reported that ‘the government agency that oversees Russia’s arms exports and imports . . . confirmed that Iran is suing Russia for damages to the tune of some $4 billion in the Court of Arbitration in Geneva for cancelling . . . a contract to sell five divisions of the S-300 long-range anti-aircraft missile system worth an estimated $800 million to $1 billion.’ It seems that Putin’s Russia is playing a long game of its own. Many observers assume that Russia, having helped construct Iran’s nuclear plant at Bushehr as part of a long-standing relationship with Tehran, would be likely to become embroiled directly in support of its Middle East allies in an Israel-Iran conflict. However, the Kremlin appears to have higher economic and political priorities. Chief among them: ensuring its vast energy resources help it to remain a global superpower. So what Russia would do if Iran was attacked? Intriguingly, the answer may have been settled with Putin’s Russia having already sold out its Iranian ‘partners’ for an attempted hand into Israeli gas. l Michael J Economides is a professor at the Cullen College of Engineering, University of Houston, and editor-in-chief of the Energy Tribune, where Peter Glover is the Europe editor. The views expressed in this column do not necessarily reflect OE’s position.

As the tension between Israel and Iran ratchets up, an interesting sub-text has developed over the role of Iran’s traditional backer, Russia. While many Western

observers continue to raise the spectre of a ‘wider Middle East conflagration’, and one that could drag in Russia, a whole new, higher value, game chip is now in play: Moscow’s interest in Israeli energy. Israel, and neighbouring and potential partner EU-member Cyprus, of course must be quite aware that Gazprom, Russia’s battering ram, can easily prove to be a Trojan Horse in any major future natural gas development. It will try to affect a project that could certainly lessen its energy stranglehold over Europe. A 20 million tonnes per year liquid natural gas (LNG) export from the eastern Mediterranean into Europe would amount to about one third of current Russian exports. Whatever one thinks of Vladimir Putin’s politics, one thing is clear: he is a shrewd, often ruthless, operator on the global stage. But Putin’s Kremlin is clearly rattled by the threat of decline for that which underpins Russia’s entire economy: its energy hegemony. Putin is only too aware of the triple whammy of falling domestic energy productivity, surging global shale development in the wake of the transforming US shale revolution, and a new threat posed to a European market still dependent on Russian gas imports – the significant potential of Israeli and Cypriot gas exports. According to reports, while publicly playing down the impact that shale gas and oil is likely to have, Putin is privately urging Russia’s energy majors to learn all they can about hydraulic fracturing techniques. Meanwhile, in a bid to retain a key stake in its European export market – Russia supplies a quarter of all Europe’s (rising) natural gas demand – Moscow is set on doing all in its power to protect its ‘captive’ market. With the looming threat to the economy all too real, Putin and Russia’s energy giants are not idly awaiting the vicissitudes of the market place. Last year saw Russia outmanoeuvre the EU once again when its Nord Stream pipeline came online way ahead of the EU’s ‘great pipe hope’ to help it diversify away from Russian gas dependency, the Nabucco project. Designed to pipe Caspian region gas to Europe avoiding crossing Russian soil along the way, Nabucco is developing at a glacial pace and still lacks a

Why Russia toys with new partnerships

by Professor Michael J Economides and Peter Glover

OE

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‘whatever one thinks of Vladimir Putin’s politics, one thing is clear: he is a shrewd, often ruthless, operator on the global stage.’

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