Offshore Feb.2016

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February 201

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

World Trends and Technology for Offshore Oil and Gas Operations

For continuous news & analysiswww.offshore-mag.com

Drillingmarketreview

DeepStar Q&A

Eastern Canadaoutlook

Proposed wellcontrol rule

ROV update

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International Edition Volume 76, Number 2

February 2016

CON T E N T S

Offshore® (ISSN 0030-0608). Offshore is published 12 times a year, monthly, by PennWell® Corporation, 1421 S. Sheridan, Tulsa, OK 74112. Periodicals postage paid at Tulsa, OK 74112 and atadditional mailing offices. SUBSCRIPTION PRICES: US $123.00 per year, Canada/Mexico $145.00 per year, All other countries $202.00 per year (Airmail delivery $283.00). Worldwide digitalsubscriptions: $123.00 per year. POSTMASTER: Send address corrections to Offshore, P.O. Box 3264, Northbrook, IL 60065-3264. Offshore® is a registered trademark. © PennWell Corporation2016. All rights reserved. Reproduction in whole or in part without permission is prohibited. Permission, however, is granted for employees of corporations licensed under the Annual Authoriza-tion Service offered by the Copyright Clearance Center Inc. (CCC), 222 Rosewood Drive, Danvers, Mass. 01923, or by calling CCC’s Customer Relations Department at 978-750-8400 prior tocopying. We make portions of our subscriber list available to carefully screened companies that offer products and services that may be important for your work. If you do not want to receivethose offers and/or information via direct mail, please let us know by contacting us at List Services Offshore, 1421 S. Sheridan Rd., Tulsa, OK, 74112. Printed in the USA. GST No. 126813153.Publications Mail Agreement no. 40612608.

Celebrating 60 Years of Trends, Tools, and Technology

TOP 10 DRILLING CONTRACTORS

Drilling contractors face changing market ............................ 28 After years of growth, the offshore rig supply, including rigs under

construction, declined in 2015 by 43 units to a total of 1,145 drill barges,

drillships, jackups, semisubmersibles, submersibles, tender-assist units,

and Arctic rigs.

GULF OF MEXICO

DeepStar evolves to meetnew deepwater challenges .....................................................31Recently, Offshore met with Chevron Energy Technology Co.’s Dr. Greg

Kusinski, who serves as DeepStar director, and John Allen, co-chair

of DeepStar Contributors Committee, to discuss the program’s latest

activities, recent accomplishments, and goals for the upcoming year

and beyond.

EASTERN CANADA

Operators remain interestedin offshore Canada ..................................................................34Oil and gas production offshore Canada may not represent a significant

part of global offshore production, but it does play an important role for

the country’s energy future.

GEOLOGY & GEOPHYSICS

Database integration improveshydrocarbon seep evaluation ..................................................36Exploration programs can be improved by bringing together disparate

datasets into a single coherent database, with a consistent ranking

scheme. To that end, a new reference library is available which stan-dardizes all existing onshore and offshore data under a single product

suite.

DRILLING & COMPLETION

Monitoring systems help improvemooring integrity, performance ..............................................38Inspecting deepwater mooring systems is a difficult task, but because

these systems are safety-critical, understanding their performance and

degradation is essential to safe operations.

Deepwater MPD system aidsdrilling operations offshore Angola ........................................40

Inspired by an accelerating learning curve and ongoing efforts toestablish distinctive integration protocols for floating drilling rigs, key

industry players are increasingly recognizing pressure control tech-

nologies and techniques, including managed pressure drilling, as safe

and cost-effective approaches to drilling deepwater wells.

Legacy BOP design could beapproaching design limitations ..............................................41

The Presidential Commission that studied the Deepwater Horizon

tragedy described BOPs as the “last line of defense” in preventing a

catastrophic release of hydrocarbons into the environment. However,

when it comes to this critical barrier that protects the rig and its crew,

the industry is still using 90-year-old technology that has significantly

increased in size, weight, and complexity over time.

Proposed rule seeks stricter well control regulations ...........43On April 17, 2015, the Bureau of Safety and Environmental Enforce-

ment announced its new proposed BOP and well control requirements

rule for the outer continental shelf federal waters.

PRODUCTION OPERATIONS

Riserless light well interventionincreases production, operating efficiency ............................45

With oil prices expected to remain depressed for an extended period,

riserless light well intervention is the most cost-effective and proven

method to unlock additional production, raising overall recovery rates

and improving the economics of existing fields.

BOP skids on ROVs providebackup for wellhead control ...................................................46New standards are emerging to ensure that BOP rams lock in a well as

fast as possible. As a double safeguard, rig operators are considering

stationing ROVs on support vessels to undertake blowout prevention if

the rig crew are unable to activate the BOP at the wellhead.

Enhanced satellite imagery supportsoffshore oil spill, security monitoring .....................................47Observations using satellites orbiting thousands of meters above the

Earth allow energy companies to regularly monitor sites for oil spills

and leaks, without the costs associated with conventional monitoring

techniques.

43


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Offshore February 2016 • www.offshore-mag.com

International Edition Volume 76, Number 2

February 2016

SUBSEA

ROV technological advances allow for more precision, efficiency ...........................48 The ROV industry is poised to make a significant step change thanks to advances in automation

control, machine vision technology, and new algorithms in artificial intelligence.

Forsys Subsea aims for life-of-field partnerships with deepwater operators .........51Officially launched last June, a new joint venture combines FMC Technologies’ strengths insubsea production and processing systems with Technip’s capabilities in engineering and instal-

lation of subsea umbilicals, risers, and flowline systems.

FLOWLINES & PIPELINES

Novel subsea configuration setto free stranded gas offshore west of Shetland ........................................................52Located 140 km (86 mi) northwest of the Shetland Islands, the Laggan-Tormore development

on the UK Atlantic Frontier has suffered several delays. Only through relatively new technology

and techniques, including a long-distance subsea tieback, could Total E&P UK Ltd. enable its

commercial viabil ity.

Online .................................................... 6

Comment ............................................... 8

Data ..................................................... 10

Global E&P .......................................... 12

Offshore Europe .................................. 16

Gulf of Mexico ..................................... 18

Subsea Systems ................................. 20

Vessels, Rigs, & Surface Systems ...... 22

Drilling & Production .......................... 24

Geosciences ........................................ 26

Business Briefs ................................... 62

Advertisers’ Index ............................... 67

Beyond the Horizon ............................ 68

COVER: With oil prices continu-

ing to fall, offshore drilling contrac-

tors are facing a challenging year.

The expectation is that by the end

of 2016, many rigs will have been

scrapped and very few new orders

will have been placed. Still, work

is ongoing in several offshore oil

and gas markets. For example,

Transocean’s ultra-deepwater drill-

ship Deepwater Thalassa (cover)

recently left Cape Town, South

Africa, on its way to the US Gulf of

Mexico, where it will commence a

10-year contract with Shell in early2016. (Photo by Virtual Media)

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COMMENT David Paganie • Houston

Top 10 drilling contractors surveysignals more changes ahead

This year’s edition of Offshore and IHS’s annual survey of the Top 10 drilling contrac-tors finds some compelling results. Chief among them is the strong possibility that themost profound changes to the sector are yet to come. Indeed, the drilling contractorsegment of the industry is arguably taking the greatest hit of all sectors during thisdownturn. But, the one significant change that has been anticipated for some time buthas not yet occurred is consolidation.

The author of the accompanying articleto the Top 10 survey inside this issue, Cin-namon Odell with IHS Petrodata , pointsto declining rig demand as a primary fac-tor. She says that in 2017/2018, the off-shore rig industry “should begin seeingmore consolidation among rig contractorsas sales of both individual rig and entirecompanies will become necessary due tosustained low demand in response to con-tinued low oil prices, and those contractors

with cash on hand will be able to take advantage of the market and its competitors.”

In reviewing this year’s survey results, it is interesting to note that the only change tothe listing of companies that made this year’s Top 10 is their order.

Odell also expects that by the end of this year, many more rigs will have been scrappedand very few new orders will have been placed. Since the beginning of 2014, 66 unitshave been removed from the fleet for various reasons.

Perhaps the biggest change from last year’s survey is the number of rigs working, asoperators terminated charters and new contracting declined. Since the end of 2014, thetotal number of rigs working has dropped by 161 units to 519. This year’s Top 10 drill-ing contractors witnessed only a marginal share of that decline. Its fleet of working rigsdropped from 47.8% to 45.3% year-over-year.

Odell’s full market analysis with regional highlights begins on page 28.

New regulations Another relevant change to come in the drilling sector is the impending release of

a new BSEE rule for BOPs and well control requirements. The rule aims to enhance well control and equipment reliability, and includes a suite of reforms in well design, well control, casing, cementing, real-time well monitoring, and subsea containment. Also included in the new rule are several post-Macondo industry standards to establishminimum requirements for the design, manufacture, repair, and maintenance of BOPs.Following BSEE’s in-house review, the proposed rule will go before the US Office ofInformation and Regulatory Affairs in the US Office of Management and Budget. Off-shore Editor Sarah Parker Musarra reviews the details of the proposed rule and itsstatus beginning on page 43. Musarra’s comprehensive report includes a conversation

with BSEE of ficials: Dough Morris, Chief of Offshore Regulatory Programs; and Ally-

son K. Anderson, Associate Director.Meanwhile, one equipment supplier believes that the 90-year-old BOP technology has

reached its design limit, and that a next generation is required to further mitigate thepossibility of another Macondo-type incident from happening again. The case for newBOP technology begins on page 41.

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Worldwide offshore rig count & utilization rate

January 2014 – December 2015

1,000

900

800

700

600

500

100

90

80

70

60

50

N o . o f r i g s

F l e e t u t i l i z a t i onr a t e %

J a n 1 4

A p r i l

1 4

J u l y

1 4

O c t 1

4

J a n 1 5

A p r i l

1 5

J u l y

1 5

O c t 1

5

Contracted fleet utilization Total supply Total contracted Working

S o u r c e : I H S R

i g B a s e

Worldwide day rates

Year/Month Minimum Average Maximum

Drillship

2015 Jan $151,000 $500,890 $735,000

2015 Feb $151,000 $506,862 $735,000

2015 Mar $151,000 $505,472 $735,000

2015 Apr $97,000 $501,962 $735,000

2015 May $97,000 $502,177 $708,000

2015 June $97,000 $508,568 $670,000

2015 July $97,000 $504,288 $670,000

2015 Aug $97,000 $493,466 $670,000

2015 Sept $97,000 $496,661 $670,000

2015 Oct $97,000 $501,820 $670,000

2015 Nov $166,860 $510,979 $670,000

2015 Dec $166,860 $507,581 $660,000

Jackup

2015 Jan $51,405 $143,235 $389,000

2015 Feb $51,405 $143,871 $389,000

2015 Mar $51,405 $144,389 $389,000

2015 Apr $38,000 $142,068 $389,000

2015 May $51,405 $141,803 $389,0002015 June $51,405 $140,569 $414,000

2015 July $51,405 $137,539 $414,000

2015 Aug $35,000 $136,126 $414,000

2015 Sept $50,000 $134,912 $414,000

2015 Oct $38,000 $135,571 $414,000

2015 Nov $38,000 $136,017 $414,000

2015 Dec $35,000 $136,572 $414,000

Semi

2015 Jan $145,000 $396,493 $641,000

2015 Feb $145,000 $396,860 $641,000

2015 Mar $145,000 $402,003 $641,000

2015 Apr $145,000 $400,804 $641,000

2015 May $115,000 $401,125 $605,000

2015 June $115,000 $401,210 $605,000

2015 July $115,000 $397,567 $624,000

2015 Aug $115,000 $398,551 $624,000

2015 Sept $115,000 $397,667 $624,000

2015 Oct $75,000 $399,894 $615,000

2015 Nov $75,000 $392,017 $615,000

2015 Dec $75,000 $395,875 $615,0002

Source: Rigzone.com


GLOBAL D ATA

US offshore drilling permits and development plansIn its US Drilling Permit Monthly of January 2016, Evercore ISI reports that a total of 15 new permits

were issued in the US Gulf of Mexico in December, down from 21 in November and down from 25 a year

ago. Five permits were issued for new wells, including one deepwater, three midwater, and one shallow

water. Six permits were issued for sidetracks while four were issued for bypasses. A total of 220 new per-

mits were issued in 2015, down 31% versus 2014, driven primarily by sharply lower bypass and new well

permits. Only 81 new well permits were issued in 2015 compared to 133 during 2014. While the number

of ultra-deepwater and midwater new well permits were relatively robust over the past year, deepwaternew well permits fell 17% to 25 and shallow water new well permits dropped 78% to just 14 (from 65).

Meanwhile, the number of new exploration plans filed in the Gulf last month fell to two (from seven) and

operators filed plans to drill a total of just 10 wells, down from 11 in November. Only one development plan

was filed to drill during December; development of the Lower Tertiary appears to remain a long ways off as

the industry has filed few development plans year-to-date. With pricing having contracted sharply, Evercore

says it expects development activity to accelerate slightly in the coming months and years and believes that

the Gulf of Mexico will be the only relative bright spot for deepwater activity in 2016-2017.

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14/7212 Offshore February 2016 • www.offshore-mag.com

G L O B A L E & P Jeremy Beckman • London

Market caution lifts drilling servicesMobile offshore drilling unit day rates will likely continue to fall

into 2017, according to a repor t by Douglas-Westwood, as more rigscome off long-term contracts. The “World Oilfield Services MarketForecast” also foresees limited rig demand post-2017 with so fewprojects currently being sanctioned, particularly in the Brazil presalt

and West African deepwater plays. Instead, the analyst expects oper-ators to focus more on complex completions and longer lateral wellsand raising production from existing assets. This should benefit sup-pliers of directional drilling, coiled tubing, and stimulation services.

Another analyst, Wood Mackenzie, expects upstream oil and gasdeal activity to ramp up after a sluggish 2015. Depressed prices willforce more companies to sell or merge businesses in order to sur-

vive, with some capital-intensive development assets having to besold almost regardless of price. If oil prices recover later this year tomore than $65/bbl, as Wood Mackenzie anticipates, the main play-ers will move quickly to take advantage of any opportunities in orderto catch the next upward-cycle.

North AmericaHusky Energy has contracted the harsh environment semisub-

mersible Henry Goodrich for a two-year program offshore New-foundland, starting in mid-2016. This includes development drillingat the North Amethyst field and South White Rose Extension andnear-field exploration.

•••Mexico plans to invite bids later this year for exploration licenses

over 10 deepwater areas. Four in the Perdido Fault Belt are thoughtto be prospective for light crude. The Energy Ministry is also set toopen more shallow-water blocks.

US independent Fieldwood Energy has signed a production-shar-ing contract for Area 4 in the Bay of Campeche which includes theundeveloped Ichalkil and Pokoch fields in 100-150 ft (30-45 m) of

water. This is one of the latest awards under Mexico’s Round 1 Call2 bid process. Fieldwood’s partner in the permit is PetroBal.

South America The newly-completed FPSO Cidade de Maricá should have depart-

ed the Brasa shipyard for duty on the Petrobras-operated Lula field inthe Santos basin offshore Brazil. Sister ship Cidade de Saquarema wasthen due to enter the yard for topsides module integration before alsoheading out to Lula. Contractor SBM Offshore says both vessels areof the same design as the Cidade de Ilhabela, which started produc-tion for Petrobras in November 2014.

Elsewhere in the Santos basin, Petrobras has completed forma-tion testing of a well on the ultra-deepwater Carcará Norte structure

which delivered good-quality 31° API oil. Analysis indicates that thisand the previous Carcará and Caracará Noroeste discoveries are thesame oil accumulation.

•••ExxonMobil has contracted Fugro to conduct a multi-beam ba-

thymetry, side-scan sonar and geotechnical survey offshore Guyana

over the site of the planned deepwater Liza oil field development.Liza was discovered last May in the Stabroek block in the Guyana-Suriname basin.

Guyana’s government has approved an extension to the spuddate for a first commitment exploration well on CGX’s Corentyneoffshore block until July 1. CGX requested the deferral in light ofcurrent oil prices.

•••Officials from Eni and PDVSA have discussed future options for

the Perla gas field in the Gulf of Venezuela which came onstreamlast summer, and which was recently producing 14 MMcm/d. Pro-duction under a second phase could rise to more than 23 MMcf/d,

with the potential for some of the gas to be exported.

West Africa The first appraisal well on the deepwater SNE oil discovery off-shore Senegal fulfilled expectations, according to operator CairnEnergy. SNE-2, drilled in 1,200 m (3,937 ft) of water in the SangomaOffshore block, 3 km (1.8 mi) nor th of SNE-1, flowed up to 8,000 b/dfrom a 12-m (39-ft) interval during a drillstem test and up to 1,000b/d from a 15-m (49-ft) inter val of lower-quality pay. Results suggestthe reservoirs can produce at commercial rates.

•••Ophir Energy has become operator of the CI-513 license area off-

shore Côte d’Ivoire after acquiring a 45% stake from African Petro-leum. The concession carries a commitment to drill an exploratory

well by mid-2017.•••

Yinson Production (West Africa) has commissioned Keppel Ship-

yard to convert an FPSO to operate on Eni’s Offshore Cape ThreePoints block offshore Ghana.

••• Total has started production from the Moho Phase 1b project, 75

km (47 mi) offshore Pointe Noire, Republic of Congo. The develop-ment, in water depths of 750-1,200 m (2,460-3,937 ft) involves drilling11 subsea wells and installing two subsea multiphase pumps. Pro-duction, which should eventually reach 40,000 boe/d, is tied back tothe FPU on the Moho Bilondo field. Work continues on the nearbyMoho Nord development, targeting a further 100,000 boe/d.

In addition, Total has signed an agreement with Sonangol to joint-ly explore Angola’s ultra-deepwater concessions and to implementan adjustment addendum for the Kaombo project in ultra-deepwaterblock 32.

Mediterranean SeaItaly’s government has approved legislation that reimposes restric-

tions on offshore oil and gas activity within 12 nautical miles of thecountry’s coasts. These measures were first implemented in 2010 fol-lowing the Deepwater Horizon incident, but were rescinded in 2012. TheOmbrina Mare oil field development in the Adriatic Sea could be one ofthe projects impacted by the ruling, according to operator Rockhopper.

•••Energean Oil & Gas has brought onstream the first of 15 new de-

velopment wells from its fields in the Gulf of Kavala offshore westernGreece. The company’s tender-assist barge Energean Force drilledthe PA-35A well at the Prinos field. The campaign, which also takesin Epsilon and Prinos North, is targeting 30 MMbbl of reserves.

•••FPSO Cidade de Maricá at Brasa shipyard. (Photo courtesy SBM Offshore)

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PROBLEM 03

How can a trade-off between

geotechnical soil sample quality,

depth accuracy and operational

efficiency be avoided, especially insoft and highly variable formations?

If you want to know how

#AskFugro

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G L O B A L E & P

Petroceltic, which was one of the success-ful bidders for the recent Greek offshorelicensing round, has offloaded its interestin the Patraikos concession to the remain-ing partners. The Irish independent hasalso agreed to sell its stakes in the deepwa-

ter North Theka and adjacent North PortFouad exploration license offshore Egypt topartner Edison for $9.5 million.

•••Cyprus’ government has reportedly ap-

proved a request by the Eni-KOGAS consor-tium to extend the exploration license foroffshore blocks 2, 3, and 9 to February 2018.

The partners wanted more time to assessthe resource potential, particularly in lightof Eni’s recent deepwater Zohr discoveryin the Egyptian sector, 6 km (3.7 mi) fromCyprus’ block 11. This may involve applyingthe same model used for Zohr to track po-tential carbonate reservoirs.

•••Noble Energy has applauded Israel’s

government’s implementation of a naturalgas framework which it says introducesregulatory certainty and stability, and pro-

vides transparency for domestic pricing andnatural gas competition. This should allowthe partners in the deepwater Leviathan

gas field to proceed with development. Ac-cording to Delek Drilling, parent companyfor two of the partners, the basic plan is toproduce 1.6-1.8 bcf/d from the field to sup-ply customers in Israel, Egypt (mainly BG),

Jordan and the Palestinian Authority, in ac-

cordance with signed letters of intent.

Asia/PacificONGC has contracted McDermott Inter-

national and L&T Hydrocarbon Engineer-ing to supply and install subsea facilities forthe Vashista and S1 development offshoreeastern India. The fields are in 250-700 m(820-2,296 ft) of water off the Amalapuramcoast. Workscope includes 30 mi (48 km) ofumbilicals and 64 mi (103 km) of dual rigidpipelines extending from the shore line outto 2,300 ft (701 m) of water, which will likelybe installed by McDermott’s DB30 and NO105 vessels.

•••ExxonMobil has started operations at

the onshore processing facility serving theBanyu Urip oil field in the Java Sea off In-donesia. The company expects productionto build to a peak later this year of morethan 130,000 b/d. Banyu Urip, which cameonstream in 2008, has been developed via 45

wells producing from three well pads, a 60-mi (96-km) offshore/onshore pipeline, andan FSO offloading to tankers.

INPEX has signed a heads of agreement with Pertamina and Total concerning thefuture of Indonesia’s offshore Mahakamblock. Once the current production-sharingcontract (PSC) expires, operatorship would

The offshore Mahakam block and its discoveries.

(Image courtesy INPEX)

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ENHANCING SUBSEA TIEBACK TECHNOLOGY THROUGH

AWARD WINNING ENGINEERING

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G L O B A L E & P

transfer to Pertamina although the other twoparties would remain as partners managingactivities post-2018. Since signing the initialPSC in 1996, INPEX and Total have discov-ered seven fields which have produced oiland gas for more than 40 years, with the gas

exported to Indonesia’s LNG complex on-shore at Bontang.

••• Woodside Energy has discovered gas

with its first exploration well off Myanmar.Shwe Yee Htun-1 was drilled in the deep-

water western of fshore area in the Rakhinebasin. The well, targeting one of numer-ous channel complexes identified over theSaung Anticline, encountered a 129-m (423-ft) gross gas column. Woodside is joint op-erator with MPRL E&P.

•••PTTEP has budgeted $2.09 billion for ca-

pex and $1.35 billion for opex this year, withfields in Thailand accounting for 55% of thetotal. The company’s main focus will be onsustaining production levels at the Arthit,Bongkot, Contract 4 and MTJDA projects,

with a further 27% of the budgeted commit-ted to producing fields and the M3 projectoffshore Myanmar.

Australasia

The Woodside-led par tners in the North West Shelf (NWS) project offshore northwest Australia have approved the $2-billionGreater West Flank Phase 2 development.

This will deliver 1.6 tcf of gas from eight

wells on the Dockrell, Keast, Lady Nora,Pemberton, Rankin, and Sculptor fields vianew subsea facilities and a 35-km (21.7-mi),16-in. pipeline connected to the Goodwyn

A platform. It will be the fourth large-scaleNWS development in the past seven years.

Woodside anticipates start-up in 2019.•••

In the Browse basin, Wood Group Kennyhas secured two front-end engineering and de-sign contracts for the proposed Browse floatingLNG development, 300 km (186 mi) from theKimberly coast. One involves flow assuranceand process integration studies for the Brec-

knock, Calliance, and Torosa gas condensatefields, to be developed using Shell’s FLNG tech-nology. The other contract concerns the con-figuration of the flexible risers and umbilicals.

•••Quadrant Energy has discovered conden-

sate-rich gas in the Roc-1 well in the WA-437-P permit offshore Western Australia.

The location is 150 km (93 mi) north of PortHedland. Sampling revealed a condensate-gas ratio of 20-40 bbl/MMcf. Previous oper-ator Apache had discovered oil 20 km (12.4mi) to the northwest in 2014 on the PhoenixSouth structure. Partner Carnarvon Petro-leum said another well may be drilled to test

Roc’s potential crest.•••

New Zealand’s Energy and Resources Min-istry has issued nine new exploration permits.Four offshore concessions in the Taranaki ba-sin went to OMV, in partnership with Mitsui.

Two others in the same basin were awarded to Todd Exploration and to Mont D’Or.

•••OMV and its partners in the Maari oil field

offshore New Zealand have commissionedDOF Subsea to upgrade the mooring sys-tem on the FPSO Raroa. The $NZ60-million($39-million) program was due to start thismonth, and is designed to future-proof thesystem for the next decade. The eight moor-

ing lines are anchored to the seafloor in 100m (328 ft) of water and connected to the ves-sel via a swivel, allowing it to rotate freely inprevailing winds and currents.

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UK, Norway level in well returnsDrilling activity has stayed strong offshore Norway despite the

oil price slump, according to analyst Hannon Westwood (HW). Incontrast, UK well numbers have fallen back to a level last seen in theearly days of North Sea exploration in the 1960s. Yet returns from

wells drilled across both sectors last year were broadly comparable.

HW identified 45 exploratory and appraisal (E&A) well spuds off-shore Norway, only one down on the previous year’s total. These ledto 16 discoveries, with the best returns as before in the NorwegianSea (a success rate of 50%), followed by the North Sea at 47.6%. Oneof the largest new finds was Statoil’s 45.5-MMboe Julius gas/con-densate accumulation, close to the undeveloped King Lear field inthe southern Norwegian sector.

Lundin encountered sub-commercial gas in the Ørnen structurein the Barents Sea in December, while one other well in this region

was temporarily suspended. However, total discovered volumes were only 268 MMboe as against 838 MMboe discovered with 18 wells the previous year.

Offshore the UK, HW counted a mere 13 E&A well spuds in 2015,10 of which targeted prospects in the generally more prolific UKcentral North Sea. At least one of these led to a discovery (Barto-li) for Shell near the Shearwater high-pressure/high-temperaturecomplex. There were also finds in the UK northern North Sea atBoatswain, K Prospect (Callater), and Corona; another for Chrysaoron the Mustard structure west of Shetland; and at Sillimanite in thesouthern gas basin. Including results from a re-entered appraisal

well on the Seagull field (100 MMboe), the commercial success rate was 46%, the highest since 2002, HW said, with discovered reserves just short of the Nor wegian total at 265 MMboe. This year numer-

ous high-impact wells will likely be drilled in UK waters, the analystadded.

Another positive indicator for the UK was the anticipated 7% risein production for 2015, the first in the sector for more than 15 years.Seven fields came onstream, completed at year-end by TAQA’s Clad-han tieback to the Tern complex northeast of the Shetlands. How-

ever, the oil price reduced tax receipts from UK production to £130million ($189 million), against £2.2 billion ($3.2 billion) in 2014.

Steam flood an option for UK heavy oilIndependents, seen as the saviours of the UK North Sea, continue

to fall by the wayside as cashflow evaporates in current conditions. Yet others appear willing to take their place. One of the more ambi-tious is The Steam Oil Production Co. (SOPC), which has agreed ona deal (subject to ratification by Britain’s Oil & Gas Authority) to ac-quire license P1996 in the northern UK sector from EnQuest, cover-ing blocks 28/2b and 28/3b. These include the undeveloped heavy-oil fields Narwhal and Elke, discovered respectively by Arco andMurphy, in Tay sandstone reservoirs. Oil gravity ranges from 12-15°

API, with combined in-place reserves estimated at 226 MMbbl.Elsewhere in the license area are numerous untested Tay sand

and Jurassic prospects, while a short distance to the northwest arethe Pilot Main, Pilot Harbour, and Harbour discoveries. All takentogether offer a potential resource of 500 MMbbl that appear to besuited to a steam flood development: SOPC claims it could producemore than 250 MMbbl, making this potentially one of the largestremaining UK North Sea projects.

The company points out that heated heavy oil can be much less viscous than a cold light crude, and for this reason steam flooding

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O F F S H O R E E U R O P E

should be viable. Although more commonly applied onshore, thetechnique has been implemented in Congo’s offshore Emeraudefield, in Bohai Bay of fshore China, and in the shallow waters of LakeMaracaibo. Experience suggests long horizontal wells are most ef-fective for offshore steam flooding, SOPC says, leading to bettersweep patterns. And if the formation has a high permeability, injec-

tion rates into the wells can be raised to counteract heat losses in the wellbore and to the sea.

SOPC expects to be able to recover about 60% of in-place oil inthe Pilot reservoir via steam flood, after optimizing issues such as

well placements relative to the oil/water contact. It will also evaluateco-injection of steam and propane to further increase recovery and

improve the steam oil ratio, thereby limiting fuel requirements. Thecompany believes the process could recover an additional 2 Bbbl ofheavy oil from fields around the UK shelf.

Minimal platform chosenfor next phase of Osebreg

Statoil has submitted a development plan for Oseberg Vestflan-ken 2, designed to recover a further 110 MMboe from the Osebergarea in the Norwegian North Sea and sustain the current produc-tion level beyond 2030. The project takes in the Alpha, Gamma,and Kappa structures 8 km (4.9 mi) northwest of the Oseberg fieldcenter. Statoil plans a 10-slot unmanned wellhead facility remotelycontrolled from the field center, with two of the slots occupied byinjectors importing gas through a new pipeline from the existing gasinjection system in the area. One of the company’s new Cat J jackups

will drill the wells, with production slated to start in spring 2018.Minimal wellhead platforms with no helidecks or lifeboats oper-

ate in the Dutch and Danish sectors, but this scheme is a first forNorway. Part of Statoil’s reasoning in following this route was thetripling of costs for subsea templates over the past decade. Since set-tling on the fixed steel jacket alternative early last year, the companyclaims to have reduced the costs for this project by around NOK1billion ($112 million).

Offshore run-out for Quad 204 floaterThe newbuild FPSO for BP’s Quad 204 project west of

Shetland underwent sea trials late last year, and should reach

the North Sea this spring, docking initially at a Norwegian yardfor inshore commissioning. Glen Lyon, built by Hyundai HeavyIndustries in South Korea, will replace the decommissioned

floater originally installed to develop the Schiehallion and Loyaloil fields in the late 1990s. BP expects the new vessel to extend

production from these fields to 2035 or beyond. The 270-m(886-ft) long, 52-m (170-ft) wide ship will be able to process andexport up to 130,000 b/d of oil and store up to 800,000 bbl.

The Glen Lyon FPSO leaves

the HHI yard in Ulsan, South

Korea. (Photo courtesy BP)



G U L F O F M E X I C O Bruce Beaubouef • Houston

Even as low oil prices continue to form ablack cloud over the industry, some operat-ing companies and developers are movingforward with new commitments to E&Pactivities, both in the US Gulf of Mexico andin the Mexican GoM.

BHP Billiton recently announced a renewedcommitment to the E&P activities in the USGulf as part of its allocated total capex of $1.5billion for various offshore programs in 2016.

The company says it will focus on poten-tially high-return infill drilling opportunitiesin the Gulf of Mexico and Western Australia,and on life extension projects at its fields in

the Bass Strait off southeast Australia and theNorth West Shelf. The main targets for exploration (total bud-

get $600 million) are oil plays in the deepwaterGoM, the Caribbean, and the Beagle sub-ba-sin off Western Australia.

Since last August, the company has acquired26 blocks in the Western Gulf of Mexico LeaseSale, each with a 100% working interest.

Elsewhere in the Gulf, work is moving for- ward on the Hummer exploration prospectin Main Pass block 270. The project is beingdeveloped by Castex Offshore Inc. and Pet-sec Energy Ltd. Petsec has reported that aplatform jacket will be fabricated and installed

over the Main Pass block 270 #3 BP 1 well thissummer.

Jacket installation is scheduled to begin in June, and the cost for fabrication and instal-lation has been estimated at $1.08 million.

The anticipated timeframe for the fabrication,installation, well completion, and testing is ap-proximately six to seven months.

The well, which was drilled and mud-linesuspended at 14,300 ft TVD/14,342 ft MD(4,358/4,371 m), will be completed and testedafter the jacket has been fabricated and in-stalled.

Operator Castex began drilling the Main Pass

270 #3 BP 1 well in July 2015 utilizing the EN- SCO 87 jackup drilling rig. The well is located inUS federal waters, approximately 50 mi (80 km)southeast of Venice, Louisiana. Water depth atthe prospect location is about 215 ft (65 m).

Meanwhile, Anadarko Petroleum Corp. saysoil has begun to flow on its Heidelberg project,located in Green Canyon block 859 in the ultra-deepwater Gulf. The Heidelberg field is situat-ed in 5,300 ft (1,615 m) of water and has 200-400MMbbl of recoverable resources.

Development consists of a truss spar witha capacity of more than 80,000 b/d of oil and2.3 MMcm/d (81 MMcf/d) of natural gas,six production wells, two drill centers, dual

looped 8-in. flowlines, and 16-in. oil and gasexport lines.

The Heidelberg truss spar is 605 ft (184 m)in length, 110 ft (33.5 m) in diameter, a top-sides operating weight of 16,000 tons, and ahull weight of 23,000 tons.

This is Anadarko’s second major truss spardevelopment in the deepwater Gulf of Mexi-co in the last two years. The company imple-mented its “Design one, build two” approachto the field development by constructing areplica of the Lucius spar.

To the south, activity in the Mexican por-tion of the GoM is progressing despite the lowoil price environment. In early January, Hous-ton-based Fieldwood Energy announced thatit had signed a production-sharing contract for

Area 4 of fshore Mexico, which was awardedin the Round 1 Call 2 bid process.

Area 4 comprises the proven but undevel-oped Ichalkil and Pokoch fields and is locatedin the Bay of Campeche at water depths of 100to 150 ft (30 to 45 m). Fieldwood Energy E&PMexico will serve as operator of Area 4 and haspartnered with PetroBal, S.A.P.I. de C.V., a sub-sidiary of Grupo Bal, a Mexican conglomerate.

The signing of the Area 4 contract repre-sents the company’s inaugural investmentin Mexico. The company will commence anapproximate two-year appraisal period begin-ning early this year, during which time it in-tends to conduct a limited drilling programand technical evaluation process.

And there was more news in mid-January,as Mexico’s oil regulator voted to approve

plans by PEMEX to drill two new deepwater wells near the maritime border with the Unit-ed States. According to a Reuters report, these

wells are expected to be drilled later this year.Both wells are expected to yield light or

super light crude, and are within the Mexicanextension of the Perdido Fold Belt, which hasproved highly productive in adjacent US wa-ters but has represented a major challenge forPEMEX.

The National Hydrocarbons Commissionapproved PEMEX’s request to drill the Vas-to-1001 and Nobilis-1 wells, both off the coastof northeastern Tamaulipas state.

Vasto-1001 will be drilled at a depth of 23,717ft (7,229 m), costing an estimated 3.4 billion pe-sos ($190 million); it is believed to hold prospec-tive resources of about 203 MMboe in mostlylight crude.

The nearby Nobilis-1 well will be 19,619 ft(5,980 m) deep and cost about 2.73 billion pe-sos ($152.7 million). The deposit that the well

will explore is believed to hold prospective re-sources of about 161 MMboe in mostly superlight crude.

The location of the Nobilis-1 well is just over4 mi (7 km) from PEMEX’s Maximino-1 well,one of the company’s most promising deepwa-ter discoveries in recent years.

The Heidelberg truss spar has a

capacity of more than 80,000 b/d of

oil and 2.3 MMcm/d (81 MMcf/d) of

natural gas. (Courtesy Anadarko)

Operators make new commitmentsamidst market downturn



21/72

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S U B S E A S Y S T E M S Sarah Parker Musarra • Houston

DeepStar announceslong-distance tieback study

Over the last 50 years, technological ad- vancements have spurred the evolution ofsubsea production systems. For example,long-distance subsea tiebacks have allowed

these systems to move from operating inshallow-water close to the shore or a plat-form to producing in deepwater locationsmore than 60 mi (100 km) from supportinginfrastructure.

Although not very commonplace in theindustry today, DeepStar says that it expectsto see the number of long-distance subseatiebacks to increase as the industry venturesinto deeper waters and harsher climates.

To this end, the industry body launched anew study in November 2015 to identifynew subsea system architecture for fieldslocated more than 50 mi (80 km) from theirhost facilities. This new system would thenserve as a first step in developing a more ro-bust solution for future long-distance subseafields.

DeepStar selected INTECSEAto perform the desktop configura-tion study, which is projected toconclude in March.

The study aims to review andclarify the operating require-ments of a representative subseafield configuration while identify-ing and evaluating key advancedtechnologies for integration. It willalso look to summarize the status

of additional technologies for in-tegration, both existing and to bedeveloped.

It will also define a path forwardfor eventual deployment, includ-ing plans to address technologygaps as well as engagement plansfor strategic partners and stan-dardization entities.

DeepStar considers that techno-logical advances are key to the economies ofscale necessary to ensuring that these long-distance fields remain economically viable.Deepwater subsea developments require

sizeable capital investments, which are typi-cally repaid a few years after start-up, whilethe field still has a long operating life.

The study intends to identify economiesof scale that could reduce capital investmentenough to make long-distance tiebackseconomically viable where conventionalmethods would not be, enabling significantreturns on investments.

The strategic value of an investment inthis study is clear, DeepStar said. Beyond areduction in capital, technological advancescould also reduce potential risk and increasein operational flexibility and performance.

The advanced technologies considered

in this study will consist of three main com-ponents: all-electric subsea and downholesystems; fiber optic networked communica-tions for control and data acquisition; andsubsea processing. In defining the elementsof the new architecture for the subsea sys-

tem, the study assumes that the technologyis 10 years out from field deployment, soboth existing and emerging technologies

will be considered.

FMC delivers anothertree for TEN project

FMC Technologies has delivered theeighth subsea tree for the Tullow Oil-oper-ated TEN field development offshore Ghanafour weeks ahead of schedule.

FMC Technologies is assembling andtesting all subsea trees for the project atits recently expanded facility in Takoradi.

Awarded in 2013, the contract has led totraining and development of Ghanaians whorepresent 76% of the local workforce.

Weighing around 40 tons (36 metric tons),the subsea trees are vital pieces of equipment

which control the flow of fluids into and outof the oil and gas wells. A total of 22 subsea

trees will be installed as part of the project -one for each well.

Ramboll to assess integrityof Zakum subsea pipelines

Zakum Development Co. (ZADCO) hasawarded Ramboll Oil & Gas an inspectioncontract offshore Abu Dhabi. This involvesan integrity study of 15 subsea pipelinesserving the Zakum oil field, allowing ZAD-CO to plan future maintenance and potentialequipment replacement needs.

Ramboll’s scope includes a review ofavailable pipeline data, assessment of cur-rent and future pipeline integrity for future

operations, and calculation and prediction ofthe corrosion growth rate.

Production from Zakum started in 1983. The goal of this project is to extend the de-sign and service life of selected pipelines byan additional 20 years.

Bibby Offshore securesinfrastructure project

Bibby Offshore was granted a multi-mil-lion pound contract by BP to replace subseainfrastructure in the UK central North Seaas part of the $1-billion Eastern Trough

Area Project (ETAP) Life Extension Project.ETAP comprises six fields operated by BP(Marnock, Mungo, Machar, Monan, Mir-ren, and Madoes) and a further three byShell (Heron, Skua, and Egret). The ETAPLife Extension Project (ELXP) will help se-cure the future of the fields until 2030 andbeyond.

The Bibby Offshore ELXP contract involvesinstalling new subsea control system infrastruc-

ture to safeguard power and com-munication links to ETAP’s Machar,Madoes, and Mirren fields, some150 mi (241 km) east of Aberdeen.

From April 2016, the company will provide dive support and con-struction support vessels from itsinternational fleet to deliver ser-

vices including; umbilical installa-tion, trenching, structure installa-tion and commissioning, throughto final survey of the completed

work scopes.

DNV GL advancescodes program

Aquatic Engineering & Constr-uction is assisting DNV GL and othersubsea organizations on guidelinesfor “The Development of Codes forOffshore Equipment for Cable andPipe Laying – Phase 1.” These will

be incorporated into new or existing DNVGL offshore standards or recommendedpractices.

The work will see engineering and techni-

cal experts from contractors and equipmentmanufacturers collaborating to establish jointindustry guidelines for cable and pipelayequipment. Subject to satisfactory comple-tion of the first two phases, a third phase un-dertaken by DNV GL will result in the publi-cation of an offshore standard or recommendpractice for cable/pipelaying equipment.

Other Phase 1 participants are AllseasEngineering; Amclyde Norson Engineer-ing; IHC Engineering Business; IHC SAS;MAATS Tech; NLI Offshore & Marine Prod-ucts; Parkburn Precision Handling Systems;Reel SAS (IMECA); Saipem Group; Subsea7; and Technip UK.

A total of 22 trees will be delivered to the TEN field, with each weighing

around 40 tons (36 metric tons). (Image courtesy FMC Technologies)



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Integrate subsurface and subsea engineering domains

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V E S S E L S , R I G S , & S U R F A C E S Y S T E M S Robin Dupre • Houston

Eni terminates Ocean RigOlympia contract

Eni has terminated its contract with OceanRig UDW Inc. for the ultra-deepwater Ocean Rig Olympia drillship. The rig provider saidthat the Italian company had reassessed its

drilling activities and moved to terminate thecontract “due to the dramatic fall of the crudeoil price and the volatile market context.”

Ocean Rig announced in May 2015 that Ocean Rig Olympia had entered into a new contract with Eni to drill offshore Angola. Work was tobegin in 3Q 2015 for a minimum of eight months

with a total contract backlog of about $91 million. The DP-3 class Ocean Rig Olympia was

built at Samsung Heavy Industries’ South Ko-rean shipyard. The 2011-build is designed andequipped for drilling in water depths from 500-3,000 m (1,640-10,000 ft).

According to an update on the transactionprovided by Evercore ISI’s Oilfield Services,Equipment & Drilling group, Eni’s decisionreduces Ocean Rig’s backlog by an estimated$49 million.

Noble Drillingto stack more rigs

Noble Corp. has issued a status update forits drilling rig fleet. Last month Shell terminat-ed the Noble Discoverer ’s contract. A paymentto Noble was made for the remaining term atabout 90% of the operating day rate, ad-

justed for certain other items. The rig isbeing mobilized to Singapore where it isexpected to be stacked.

The Noble Sam Croft and Noble Tom Madden remain under contract with Free-port-McMoran into July 2017 and Novem-ber 2017, respectively. The company hasannounced plans to reduce the number ofrigs it uses in the US Gulf of Mexico.

As for the Noble Scott Marks, Noble Rog- er Lewis, Noble Joe Beall , and Noble Gene House rigs, Noble said that its Saudi Aram-co contract rates were adjusted downwardfor 2015.

Atwood defersdelivery of two ultra-

deepwater drillships Atwood Oceanics has deferred deliv-ery of two remaining newbuilds. Lastmonth the company entered anotherdelay agreement to defer the deliver-ies of the Atwood Admiral until 2017,and the Atwood Archer until 2018. Theagreement with Daewoo Shipbuilding& Marine Engineering Co. postponesthe milestone payments of $93.9 mil-lion for the Admiral and $305 millionfor the Archer to their delivery dates inexchange for $50 million payments foreach rig on Dec. 31, 2015. This defer-ral builds on the company’s April 2015

choice to delay rig delivery for one year toreduce its near-term capex spending in lightof the challenging offshore drilling market.

Atwood signed a letter of intent for one ofthe newbuilds to commence a drilling pro-gram offshore Brazil in 3Q 2017.

Two new vessels launchedfor Otto Offshore

The sister vessels Go Matilda andGo Munda- ra, platform supply vessels under constructionat the Wuchang Shipbuilding Industry Co. forOtto Offshore, were recently launched.

The vessels are number two and three ina series of four, with the first vessel being Go Michigan.

The PX121 vessels are capable of support-ing offshore activities. In addition to tanks for

various contents such as oil, water, and drill-ing fluids, they have four stainless steel tanksfor flammable liquids or corrosive chemicals.

The vessels are certified by DNV and carr ythe ‘Clean Design’ notation. They can accom-modate 30 persons and keep a speed of ap-proximately 14.5 knots.

A vessel of the PX121 design has an over-all length of 274 ft (83.4 m), a beam of 59 ft(18 m), and a load capacity of about 4,000metric tons. The vessels are equipped withthe most modern solutions for DP-2 dynam-ic positioning, oil recovery, and fire-fighting.

The contract with Ulstein includes the deliv-eries of design, engineering and main equip-ment. An extensive delivery from UlsteinPower & Control includes integrated controlsystems, bridge (radio, navigation), switch-board, diesel electric propulsion and frequen-

cy converters, and communication systems. The vessels will be prepared for offshore

crane and a mezzanine deck for ROV.

Bisso Marine acquires newderrick/pipelay barge

Bisso Marine has acquired the offshorepipelay industry’s stalwart derrick/pipelay

barge Global Iroquois. The 400 ft x 100 ft x 30 ft (122 m x 30 m x 9 m) laybarge hasperformed pipelay operations worldwideand will be renamed Bisso Iroquois.

The central part of the barge’s stationkeeping system are the 10 single drum

winches with 320 kips of pulling forceand 744 kip holding force each. Each sin-gle drum winch holds 5,300 ft (1,615 m)of a 2.5-in. wire rope. The barge’s maintub mounted dynamic revolving cranehas a 250-ton capacity and the deckcrane is a Manitowoc 4100W Series 2.

The pipe handing system is designedto handle 40-ft (12-m) pipe joints but canaccommodate 60-ft (18-m) joints withsome modifications. The pipe handlingsystem can handle pipe joints weighing

up to 38 tons each. Through a series ofconveyors, pipe is fed into a fully en-closed ready rack, line up station andfiring line.

The Bisso Iroquois can accommodate256 persons and features a large galleyand dining area, a large theater, severalconference rooms, ample client officespace, a gym, and a three bed hospital.During the last decade, the barge hasbeen reconfigured and received signifi-cant capacity, technology, and ef ficiencyupgrades to enable it to perform inter-nationally in very harsh environmentsfor long durations.

Bisso Marine has acquired the offshore pipelay

industry’s stalwart derrick/pipelay barge Global

Iroquois. (Image courtesy Bisso Marine)

Above: Go Matilda, a PX121 vessel is capable of supporting

offshore activities. (Image courtesy Otto Offshore)

Below: Go Mundara, a platform supply vessel, was recently

launched. (Image courtesy Otto Offshore)



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D R I L L I N G & P R O D U C T I O N Robin Dupre • Houston

A return to lean and mean?Last year was a tough one for the oil and gas industry, as spending

and headcounts were slashed and the specter of bankruptcy becamean impending concern for some. Recent trends in commodity priceshave not helped, says Andy Jenkins of Douglas-Westwood. He notesthat late December saw Moody’s downgrade its price forecast for

2016 by 17% and a further dip in the price of oil, with Brent crudefalling to the lowest level since 2004.

Producers have continued to produce and new Iranian output mayresult in even more oversupply. By all accounts, 2016 is shaping upto be just as challenging as 2015.

If prices remain low, one thing is clear, says Jenkins: 2016 is linedup to be a year of consolidation. Cost savings are required to en-sure that future developments are economically viable. Project op-timization and supply chain improvements will be key in reducingcosts. However – at current prices – industry consolidation will playa large part in ensuring the cost-effective development of projects.

In all likelihood, 2016 will see the completion of two E&P and OFSdeals – with Shell and Halliburton acquiring BG Group and BakerHughes, respectively. Further M&A activity is expected – those

with strong balance sheets are in line to benefit from a wealth of dis-tressed assets. This is particularly clear in the drilling sector – since2014’s drop, firms have relied on credit markets to keep rigs going.

With prices below $40, this option will dry up, forcing a search forpartners. This year looks to be a difficult one for all involved. Yet,for those companies that are well positioned, there is likely to be aplethora of opportunities, Jenkins commented.

Sandbox to purchase distressed assets John Fredriksen, owner of offshore drilling company Seadrill, has

created a new firm called Sandbox to purchase distressed rig as-sets from shipyards. With rising numbers of canceled and delayednewbuilds sitting at shipyards as offshore drillers focus on de-risk-ing their balance sheets, Raymond James stated the new companyshould be able to acquire floaters and jackups at a discount.

The firm intends to take advantage of the downturn to makesmart investments that may pay off when the offshore drilling mar-ket recovers. Raymond James stated: Sandbox is one of the firstfirms to vocally declare its intentions to invest in distressed rigs inthe near term. Though many firms within Raymond James coveragehave expressed interest in the acquisition of distressed assets, theygenerally believe the bid/ask spread is too wide.

North Sea decline expected to endProduction from the North Sea is expected to remain constant

over the next five years as operators focus on redeveloping maturediscoveries and reversing the production decline of the last decade,says Olga Kerimova, analyst, and Theodora Batoudaki, analyst, Rys-tad Energy. From 2020, Johan Sverdrup will play a significant role in

maintaining this trend.Norway and the UK make up about 90% of the region’s produc-tion; however, production has been declining historically due tonatural decline of mature fields, such as the Norwegian fields Gull-faks (Statoil-operated), Ekofisk (ConocoPhillips), Sleipner (Statoil),and Oseberg (Statoil). In 2015, production is expected to increase.

The main drivers for this growth are the mature fields Oseberg andGudrun that produced more than expected, partly as a result of areduction in maintenance during the summer months of 2015. Ad-ditionally, operators have focused on extension projects on alreadyproducing fields such as Ekofisk South and Valhall. From 2016 on,production is expected to stabilize at around 4.2 MMboe/d. Thecontribution of Johan Sverdrup, the largest discovery of the last de-cade, is visible in 2020, when the field is expected to start producing.From 2020 on, Johan Sverdrup is estimated to be the field with the

second most significant contribution to production, after the giantNorwegian field, Troll.

Spending levels have increased significantly from $50 billion in2010, peaking at almost $80 billion last year, followed by a significantdrop expected in 2015 and into 2016 due to the fall in the oil price.Capex reached around $21 billion in 2010, with an expected growthto approximately $34 billion by 2020. The increase in spending overthe last five years is primarily from mature fields in the NorwegianNorth Sea, such as Troll, Ekofisk and Gullfaks, as well as the recentEdvard Grieg and Jasmine discoveries, Rystad Energy commented.

Future growth is expected mainly from the development of dis-covered resources, primarily the first phase of the Johan Sverdrup

field, as well as the Culzean field, both of which are expected to startproducing around 2020. Most of the development costs for the firstphase of Johan Sverdrup are expected to be incurred by 2019, lead-ing to overall lower spending levels in 2019, before picking up againin 2020. The operating costs are expected to remain around $27-30billion per year, accounting for inflation.

In 2015, an increase in North Sea production is expected, partlyas a result of lower maintenance throughout the year and as newdevelopment projects come online. Production is estimated to re-main stable until the end of the decade. Investments are expectedto start increasing again from 2017, as the development of the majordiscoveries Johan Sverdrup (2010) and Culzean (2008) progresses.No significant increase is expected in exploration activity in the re-gion, validating the focus on stable growth from developing existingdiscoveries and mature fields.

Total North Sea production split by hydrocarbon.

Total North Sea discovered volumes by lifecycle.

(Graphs courtesy UCube from Rystad Energy)



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GEOSC IENCES Sarah Parker Musarra • Houston

New software releasesRecently, the industry has seen several new or updated suites of

seismic-related software hit the market.

Paradigm 15.5: Paradigm has released its Paradigm 15.5 suite,aimed at extending its high-definition subsurface workflows and en-

hancing user productivity. The software aims to help users resolvestratigraphic details and recover the subsurface features that con-trol hydrocarbon accumulation and recover y.

Paradigm 15.5 includes memory-efficient multi-volume, multi-ho-rizon, and multi-survey flattening. Its horizon-fault contacts are cal-culated and editable on-the-fly. It also features multi-volume attributeextraction and blending with geometric attributes in 3D Canvas.

Additionally, the Paradigm Quantitative Interpretation solutionfor recovering rock properties from seismic and well data has beenupdated with a Wedge Modeling application that analyzes the effectof bed thickness on seismic amplitudes, and provides the option toeasily test “what if” scenarios.

Paradigm 15.5 includes the recently released Geolog 7.4 formationevaluation suite, which expands the solution’s reach into the engineer-ing domain with new well integrity and geomechanics modules, to eval-uate casing integrity and help assess mechanical conditions around the

wellbore, to provide a better understanding of the reservoir. Additional efficiency enhancements provided with the Paradigm

15.5 release are enabled by new and expanded interdisciplinary work-flows, including:

• An extension of the cross-domain integration between Paradigm ve-locity determination and earth modeling solutions, enabling struc-turally and stratigraphically constrained velocity model updating

• Enhanced integration between geologic modeling and interpreta-tion applications through the loading and display of time-stampedproduction data

• The inclusion of Paradigm Epos-based well display and mappingcapabilities with certain Geolog configurations.

This release also expands connectivity between Paradigm and oth-er G&G platforms, including Petrel seismic-to-simulation software,to provide users with additional options for accessing Paradigm’sadvanced technologies while maintaining value from existing invest-ments in other software platforms.

ImaCore 3017: MR Solutions, of Guildford, UK, in partnership with Green Imaging Technologies, based in New Brunswick, Can-ada, have combined technologies to bring ImaCore 3017, a new 3Dmagnetic resonance imaging (MRI) solution.

The partners said that the ImaCore 3017 will lessen resolution limi-tations by allowing customers to bolster the theoretical with actual im-

ages of all the fluid present in the rock core sample, and thus the porenetwork. The cryogen-free MRI imaging technology is versatile, as themagnet field can be adjusted depending on image requirements. Sam-ple sizes can range from 1-in. to 4-in. diameters and space is providedfor pressure and flow cells, allowing users to make measurements atreservoir conditions and to perform high resolution flow studies.

PerGeos: FEI has released PerGeos, a software that aides in in-terpreting and modeling digital rock imagery. Using PerGeos, coreanalysts, geologists and petrophysicists can integrate data from mul-tiple sources and share descriptions and statistics using a commonplatform. It features automated workflows, high-powered image pro-cessing algorithms and a user-friendly interface. The initial PerGeosrelease consists of three modules: petrophysics, pore statistics and

core profile. Each module is designed to help users make statisticalobservations about the sample as it relates to their specific function,and then allows them to transfer this knowledge to a digital environ-ment for interactive assessment by the entire asset team.

Fugro to assess seabedconditions off Australia

Hess Exploration Australia has commissioned Fugro to conduct acombined geophysical and geotechnical project in the northern Car-narvon basin offshore northwest Australia. The program, due to startin the current quarter, will include seabed and shallow geological in-

vestigations, some in areas of difficult terrain. For the first phase, thecompany will employ a Hugin 1000 AUV to map the seabed. The data

will help optimize planning for the subsequent sediment samplingphase where a variety of techniques will be applied.

Multi-volume, multi-horizon, multi-survey volume flattening offerings are

available in Paradigm SeisEarth. (Image courtesy Paradigm)

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1 1

t h

L I C

E NSIN G

R O U N

D

GABONDEEP WATER

11th Gabon Deep Water Licensing Round

Until 31st March 2016, bids will be acceptedfor the new Gabon 11th Licensing Round whichhas a special focus on five blocks covering

some of the country’s key deep water acreage.

CGG is advising the Gabonese Republic’sMinistry of Petroleum and Hydrocarbons on thepromotion of this licensing round and, workingwith the Ministry, has acquired more than25,000 km2 of new 3D BroadSeis™ multi-clientseismic data over the area. The fast-track datais available now.

Visit www.gabon11thround.com to find out more.

www.gabon11thround.com

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Drilling contractors face changing market

Many rigs expected to be scrapped in 2016

A fter years of growth, the offshore rigsupply, including rigs under construc-tion, declined in 2015 by 43 units to atotal of 1,145 drill barges, drillships,

jackups, semisubmersibles, submers-ibles, tender-assist units, and Arctic rigs. This was a direct resultof an oversupply problem that began to show itself even before oilprices collapsed in the second half of 2014. New rig orders droppedoff steeply, while attrition became a hot topic.

Since the beginning of 2014, 66 units have been removed from thefleet for various reasons, such as scrapping, conversion to a non-drill-ing unit like a mobile offshore production unit, or simply being retiredfrom the active fleet. Of these 66, 25 were removed in 2014, and therest occurred in 2015. However, this is not expected to be the end

of the scrapping session, as a delicate balance between supply anddemand in a relatively stable oil price environment has not yet beenachieved. With many oil analysts in agreement that the crude pricehas not yet reached bottom, it makes it tougher on rig contractorsto determine how many rigs need to be culled from their portfolios.

At the end of 2014, 180 rigs were under construction. Fast for- ward one year and 184 units were under construction at the endof the year. As rigs generally take multiple years to build, many ofthese were rollovers from the year before. A total of 29 rigs weredelivered in 2015. Many more were previously scheduled for deliv-ery last year, but due to worsening market conditions throughoutthe year, several had their delivery dates renegotiated and delayed.Still others that were either finished or nearly finished had theirshipyard contracts canceled by rig contractors unable or unwillingto accept delivery. However, as these rigs were built to completion

and remain part of the active fleet, albeit with-out a dedicated rig owner and manager, theirshipyard contract cancellations do not affectthe overall numbers in the accompanying table,except that the totals for specific managers that

canceled rigs will not be as high as they would have been otherwise. The biggest drop from the table is the working count, as opera-

tors not only terminated charters, but also failed to sign as manycontracts as had been expected. Numerous rigs rolled off contract

without follow-up jobs in hand and most of these remain idle as thenew year began. Since the end of last year, the working count hasdropped by 161 units to 519. That being said, as a whole, the 10 larg-est contractors went from having 47.8% of the working rigs to 45.3%,maintaining their dominance, as at present there are over 170 differ-

ent rig managers worldwide. As expected, the rig manager with the biggest drop in its fleet is

also the largest manager – Transocean. The company downsizedfrom a fleet of 86 in 2014 to 74 by the end of 2015. In terms of fleetpercentage though, Diamond Offshore slimmed down nearly 20%from 2014, while Transocean’s drop amounted to about 14% from itsrig portfolio. Of the other top 10 managers, only one did not haveany change – Shelf Drilling stayed at 39 units, while China OilfieldServices Ltd. (COSL) is the only manager to have increased the sizeof its fleet, going from 46 to 47 units following the change of managerfor the rig Nanhai VI . COSL has been the owner of this rig since 2003,but Maersk was acting as manager while it worked off Australia.

While there were no changes to the companies that made it ontothe top 10 list this year, the biggest shake-ups are the fall of Dia-mond from fifth to seventh place following its rig reductions, switch-

Cinnamon Odell

IHS Petrodata

Night time view of a support vessel

next to the illuminated BP-operated

ENSCO DS-3 drillship at sea in the

Gulf of Mexico. (Courtesy BP)



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When the Hydrocarbon Journey originates

offshore, a whole new set of challenges opens

up that puts increased pressure on values such

as safety, efficiency and time savings.

That is where Cameron experience and

technology are vital. From more traditional

Documents

Offshore Feb.2016