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International Edition Volume 75, Number 12
December 2015 Celebrating 60 Years of Trends, Tools, and Technology
CONTENTS
MIDDLE EAST AND NORTH AFRICA
34
National interest projects sustain Middle East’s offshore rig count .............................................37 Against a backdrop of low oil prices and spending cutbacks in the upstream E&P industry, the Middle East is the only major region in the world yet to register sizeable decreases in the number of offshore drilling rigs holding current or future contracts.
Mellitah details plans to unlock dormant discoveries offshore Libya ....................................... 39 Over the next seven years, Mellitah Oil & Gas is looking to develop three Libyan offshore oil, condensate, and gas discoveries. Total costs will likely exceed $7 billion, according to Khalifa Daw Musa, general manager of geosciences and reser voir engineering.
TOP 5 PROJECTS
Chevron advances deepwater frontier with Jack/St. Malo project ......................................................28 With first oil produced late last year, Chevron has advanced the boundaries of of fshore exploration and production with its Jack/St. Malo project in the deepwater Gulf of Mexico.
GEOLOGY & GEOPHYSICS
Somalia, East Black Sea opening up for exploration ............. 40 Frontier seismic surveys were due to start this fall offshore Somalia and in the eastern Black Sea. For dif ferent reasons, the industry has largely shunned both regions over the past two decades, but new developments are altering perceptions.
Spar platform proves successful for Anadarko once again .........................................................32 Following the September 2014 decommissioning of its one-of-a-kind DRILLING & COMPLETION cell spar, Red Hawk, in the Gulf of Mexico, Anadarko Petroleum Corp. New fracturing tool improves wasted no time before it made yet another mark in the Gulf. Moored extended-reach drilling efficiency ..........................................41 in more than 7,100 ft (2,164 m) of water, the Lucius spar is Anadarko’s Weatherford recently introduced a new system for stimulating the biggest and most technically advanced to date, producing from multiple open-hole section to the completion toe in extended-reach wells. The resource-rich fields. system operates lower-completion tools remotely to minimize intervention and milling requirements and costs.
Delta House FPS is a first of its kind ......................................34 Heralded as one of the most ef ficient production systems in the Gulf of Mexico, the Delta House development taps three Mississippi Canyon fields where the average water depth is around 4,500 ft (1,372 m) and reservoirs range from 12,000 to 18,500 ft (3,658 to 5,486 m).
ENGINEERING, CONSTRUCTION, & INSTALLATION
Subsea compression prolongs gas production at Åsgard offshore Norway ...........................35
Technip assessing fatigue, weight issues as subsea installations go deeper ..........................................43
In mid-September, the world’s first subsea compression station began operating at the Åsgard production complex in the Norwegian Sea. The technology is designed to boost pressure at the Midgard and Mikkel fields that export gas and condensate to the Åsgard B semisubmersible processing platform nearly 40 km (25 mi) away.
At a recent presentation in London, Technip outlined some of the technologies it is working on to extend the lives of producing subsea facilities and to extend development to deeper water.
Perla marks first gas field to enter production off Venezuela ........................................................36
Understanding the causes of equipment schedule delay is essential in order to mitigate future delays in supply chain activities of major offshore projects.
Cardón IV S.A., a 50/50 joint operating company between Repsol and Eni, started production from the Perla gas field in the Gulf of Venezuela in July 2015.
Vendor partnerships key to optimizing supply chain management ......................................................44
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Industry project seeks to update pipeline repair standards ....................................47
• Engage visitors on website
Loss of production time due to repair operations offshore can equate to millions of dollars per day in lost revenue. As a result, pipeline “live” repair is an attractive option for operators, and is often preferred since it yields considerable flexibility and is highly opex-efficient. It is however, technically challenging.
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FLOWLINES & PIPELINES
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Asphaltene inhibitor prevents deposition in deepwater GoM tieback .....................48
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Safely controlling and treating asphaltene deposition is a major flow assurance challenge in the offshore environment, where consequences and remediation can be far more involved and costly than onshore.
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Vessels, Rigs, & Surface Systems ...... 22 Drilling & Production .......................... 24 Geosciences ........................................ 26 Business Briefs ................................... 61 Advertisers’ Index ............................... 63 Beyond the Horizon ............................ 64
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COMMENT
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Select projects earn special recognition The editors of Offshore magazine have selected five projects that exemplify best-in-class among those that recently achieved first production. Offshore’s Top 5 Projects for 2015 were selected on the basis of best use of innovation in production method, application of technology, and resolution of challenges, along with safety, environmental protection, and project execution. Interestingly, two of the projects employ a variation of the “design one, build two” approach, which is rapidly gaining momentum as project developers seek to improve efficiencies. In no particular order, the winners are:
Jack/St. Malo
Chevron and partners produced first oil late last year from the Jack/St. Malo project in the deepwater Gulf of Mexico. The Jack and St. Malo fields are among the largest in the GoM, and are part of its Lower Tertiary Trend. The fields were developed with subsea completions tied back to a single host, semisubmersible floating production unit (FPU) moored between the fields. The FPU is the largest of its kind in the GoM. It is fitted with capacity to process 170,000 b/d of oil and 42 MMcf/d of natural gas, with the potential for future expansion. The successful completion of the project was the result of the collaboration of hundreds of suppliers and contractors and thousands of workers across nine countries over a ten-year period.
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Lucius
Anadarko and partners achieved first oil from Lucius in the Gulf of Mexico in January of this year, about three years from project sanction. The full cycle time from discovery to first production was five years, about 10 months faster than the industr y average of spar projects. Moored in 7,100 ft (2,164 m) of water, Lucius is Anadarko’s largest spar to-date. It produces from multiple resource-rich fields spanning Keathley Canyon blocks 874, 875, 918, and 919. The Anadarko-led consortium made several decisions throughout the project development cycle that resulted in sizeable savings in both time and money.
Delta House
The LLOG-operated Delta House development in the deepwater Gulf of Mexico flowed first oil in the second quarter of this year. Prompted by an expiring lease, the privately held operator initiated platform design even before a discovery was made. And it was based on its “one-size-fits-most” approach, which would enable it to work within a range of reservoir characteristics. The Delta House host semisubmersible floating production platform is moored in about 4,500 ft (1,372 m) of water. It is designed with capacity to handle 100,000 b/d of oil, 240 MMcf/d of gas, and 40,000 b/d of water.
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In mid-September of this year, the world’s first subsea compression station began operating at the Åsgard production complex in the Norwegian Sea. The technology is designed to boost pressure at the Midgard and Mikkel fields that export gas and condensate to the Åsgard B semisubmersible processing platform nearly 40 km (25 mi) away. In the process, Statoil expects to extend the fields’ lives out to 2032, thereby extracting a further 306 MMboe of production.
Perla
Cardón IV SA., a 50/50 joint operating company between Repsol and Eni, started production from the Perla gas field in the Gulf of Venezuela in July of this year. Located in the Cardón IV block 50 km (31 mi) offshore in 60 m (197 ft) water depth, Perla is estimated to hold up to 17 tcf of gas in place, or 3.1 Bboe. The project partners believe Perla represents the largest offshore gas field in Latin America, and also the first gas field to be brought to production offshore Venezuela. For more information on the award-winning projects, start on page 28 inside this issue and see the Top 5 webcast hosted on Offshore magazine’s homepage: www.offshore-mag.com.
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GLOBAL
D A TA
Worldwide day rates Year/Month
Worldwide offshore rig count & utilization rate
Minimum
Average
Maximum
$151,000 $151,000 $151,000 $151,000 $151,000 $97,000 $97,000 $97,000 $97,000 $97,000 $97,000 $97,000
$507,429 $506,413 $502,106 $508,094 $506,715 $503,214 $503,730 $509,781 $505,880 $495,020 $498,335 $503,369
$735,000 $735,000 $735,000 $735,000 $735,000 $735,000 $708,000 $670,000 $670,000 $670,000 $670,000 $670,000
$43,300 $43,300 $51,405 $51,405 $51,405 $38,000 $51,405 $51,405 $51,405 $35,000 $50,000 $38,000
$143,063 $144,122 $143,069 $143,729 $144,310 $142,288 $142,218 $141,371 $137,549 $136,938 $136,295 $137,623
$389,000 $389,000 $389,000 $389,000 $389,000 $389,000 $389,000 $414,000 $414,000 $414,000 $414,000 $414,000
$145,000 $145,000 $145,000 $145,000 $145,000 $145,000 $115,000 $115,000 $115,000 $115,000 $115,000 $75,000
$390,906 $389,010 $396,352 $397,375 $403,528 $401,818 $401,733 $402,479 $399,640 $401,004 $399,262 $401,968
$641,000 $641,000 $641,000 $641,000 $641,000 $641,000 $605,000 $605,000 $624,000 $624,000 $624,000 $615,000
Drillship
2014 Nov 2014 Dec 2015 Jan 2015 Feb 2015 Mar 2015 Apr 2015 May 2015 June 2015 July 2015 Aug 2015 Sept 2015 Oct Jackup
2014 Nov 2014 Dec 2015 Jan 2015 Feb 2015 Mar 2015 Apr 2015 May 2015 June 2015 July 2015 Aug 2015 Sept 2015 Oct Semi
2014 Nov 2014 Dec 2015 Jan 2015 Feb 2015 Mar 2015 Apr 2015 May 2015 June 2015 July 2015 Aug 2015 Sept 2015 Oct Source: Rigzone.com
This month Infield Systems takes a brief look at the West African deepwater market (> 500 m/1,640 ft) up to 2020. The number of deepwater fields anticipated to come onstream over the next five years is expected to increase in comparison to the historic period (2011-2015). Increasing deepwater activity within the region will undoubtedly have a positive impact on the subsea market, with Infield Systems projecting subsea capex to increase by 59% period on period. Key deepwater markets over the next five years in West Africa include Angola, Nigeria, and Ghana. Together all three are anticipated to account for about 86% of West African deepwater capex during the period of analysis, with Angola being the main demand driver. In Angola, French supermajor Total could see the largest number of deepwater fields enter production during the forecast period, mainly related to oil fields associated with its giant Kaombo project located in 10 Offshore December 2015 • www.offshore-mag.com
November 2013 – October 2015 Contracted fleet utilization
Total supply
Total contracted
Working
100
1,000
90
900
s g i r f o . o N
e s a B g i R S H I : e c r u o S
800
80
700
70
600
60
500
3 v 1 o N
4 4 y 1 b 1 a e F M
4 4 5 5 5 v 1 y 1 u g 1 g 1 b 1 o a u e F A A N M
F l e e t u t i l i z a t i o n r a t e %
50
Number of projected deepwater developments in Africa entering production 2011-2020 West Africa
North Africa
South & East Africa
100 90
) % ( 80 s t n 70 e m 60 p o l e 50 v e d 40 m a e r 30 t s - 20 n O
10 0 2011
2012
2013
2014
2015
2016
2017
2018
2019
2020
Source: Infield Systems Market Modeling & Forecasting Database
block 32. The project is situated in water depths averaging about 1,667 m (5,469 ft). Eni is also anticipated to be a key driver of deepwater developments in the country, mostly related with fields linked with its West Hub Development project located in block 15/06. Three of the nine fields associated with the project are already in production. In Nigeria, Total is expected to see the largest of a number of deepwater developments enter production over the timeframe. Its ultra-deepwater Egina project in Offshore Mining Lease 130 is a notable example, with the field expected to start production during 2017. In Ghana, Tullow Oil is expected to be a key contributor to the country’s deepwater market, largely associated with the TEN development that consists of the Tweneboa, Enyenra and Ntomme oil fields. Situated in water depths of about 1,259 m (4,131 ft), production is expected to start in 2016. – George Griffiths, Senior Energy Researcher, Infield Systems
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DW downgrades floating production capex Capex on new floating production systems (FPSs) will likely total $4.5 billion this year, according to projections from analyst Douglas Westwood (DW). This is 72% down on the figure for 2014, and reflects operators’ continuing difficulties in the lower oil price era. By early November, only four FPSs had been ordered for new projects: Appomattox in the Gulf of Mexico, Sankofa of fshore Ghana, South Pars in the Persian Gulf, and the Brotojoyo field redevelopment off Indonesia. As a result, DW has downgraded its projections of FPS capex during 2015-19 from $81 billion to $68 billion, although it does foresee a recover y in the market next year as various projects go forward that had been put on hold.
North America The US Department of the Interior has canceled two Arctic offshore lease sales tentatively scheduled for 2016-17 in the Chukchi and Beaufort seas. This follows Shell’s decision to cease exploration off Alaska after disappointing results from its well on the Burger prospect in the Chukchi Sea. Additionally, the Bureau of Safety and Environmental Enforcement turned down requests from Shell and Statoil to retain their leases in these regions beyond their primary 10-year terms, citing inadequate evidence of forward exploration and development programs. ••• Shell has approval from the Canada-Nova Scotia Offshore Petroleum Board for its Shelburne basin offshore drilling. This requires a response of no more than 12-13 days to contain a subsea blowout. Shell’s initial capping stack would come from Stavanger, Norway, with a second contingency stack to be deployed from Brazil.
Jeremy Beckman • London
••• Jacka Resources expects first oil to flow early next year from the Aje field in the OML 113 license offshore Nigeria via the FPSO Front Puffin , recently refurbished in Singapore. Lekoil is the new operator of the Nigerian OPL 325 lease after buying the interest previously held by Ashbert Oil and Gas. The concession is in the offshore Dahomey basin wrench zone that straddles the western Niger Delta. Lumina Geophysical’s recent review based on existing seismic has identified various large prospects with associated channel complexes and potential in-place oil totalling 5.7 Bbbl. ••• Equatorial Guinea’s Ministry of Mines, Industry and Energy plans a new bid round next year for all the country’s remaining deep and ultra-deepwater blocks. However, the Ministry has decided not to extend the production-sharing contract for the offshore Zafiro field, operated by ExxonMobil. Noble Energy expects to install a new gas compression platform at its offshore Alba field during 1Q 2016. The facility should start operating later in the year. •••
Latin America State-owned Cuban company Cupet could partner with PDVSA and Sonangol in a new round of exploratory drilling offshore Cuba, Reuters reported. They are looking at an oil-prospective deepwater area northwest of the island and could begin their program in late 2016. This would be Cuba’s first offshore well since 2012 when Repsol pulled out of the country following a dry hole. ••• Anadarko has been drilling its second deepwater prospect offshore Colombia’s Pacific coast, following the earlier Kronos gas discovery to the south. The Calasu-1 well was targeting a large four way structure. ••• ExxonMobil is reportedly looking to develop its deepwater Liza oil discovery offshore Guyana, thought to hold more than 200 MMbbl recoverable, via an FPSO. Development should benefit from recent decreases in FPSO leasing costs and drillship day rates, claims consultant GlobalData. ••• Petrobras has completed drilling a fourth exploratory well on the Libra oil field in the presalt Santos basin offshore Brazil, in the central part of the block. Operations recently started on another well to the north. The par tners have also invited tenders for a second FPSO to conduct extended well tests for the Li bra Pilot Project: this would have a capacity of 180 b/d of oil and 12 MMcm/d of gas.
West Africa Foxtrot International has brought online a second platform in block CI-27 offshore Cote d’Ivoire as par t of $1-billion, four-year program to develop the Marlin oil and gas and Manta gas fields. The new facility, in 100 m (328 ft) of water, should double the block’s hydrocarbons treatment capability. The existing platform, in ser vice since 1999, handles production from the Foxtrot and Mahi fields. 12 Offshore December 2015 • www.offshore-mag.com
The Tugela license offshore South Africa. (Map courtesy Statoil)
Statoil has farmed into its first exploration concession offshore South Africa, acquiring a 35% stake in the ER 12/3/154 Tugela South Exploration Right, operated by ExxonMobil. The 9,054-sq km (3,496-sq mi) permit is offshore eastern South Africa in water depths up to 1,800 m (5,905 ft). Commitments include shooting 3D seismic and geology/geophysics studies. ••• Galp Energia and Kosmos Energy have been assigned equal 45% stakes in block 6 in the Sao Tome and Principe Exclusive Economic Zone. This spans 5,024 sq km (1,940 sq mi) in water depths up to 2,500 m (8,202 ft). The partners have committed to seismic acquisition during the first four-year exploration term. ••• CGG is helping to promote Gabon’s 11th licensing round which features five deepwater blocks and which will open for bids from Feb.
GLOBAL E&P
15 to March 31, 2016. New 3D BroadSeis data should improve imaging of areas downdip of and adjacent to various recent deepwater pre Aptian salt discoveries, CGG said. ••• Eni has added 250-350 MMboe of gascondensates to its reserves pool in the Marine XII block offshore Congo following its Nkala Marine discovery. The well was drilled 3 km (1.86 mi) from the Nene Marine field which began production late last year. On test it flowed more than 300,000 cmoe/d from a lower Cretaceous interval. Eni plans appraisal drilling and will study options for a development taking in various finds on the block. ••• Chevron has produced first oil and gas from the Lianzi field within a unitized offshore zone between Republic of Congo and Angola. The field, discovered in 2004 in 3,000 ft (900 m) of water, 65 mi (105 km) offshore, has been developed via a subsea production system and a 27-mi (43-km) with a direct electrical (flowline) heating system, exporting production to Chevron’s BelizeLobito Tomboco compliant tower platform in Angola’s block 14.
Eastern Europe LOTOS Petrobaltic has delivered first oil from its B8 field development in the Polish sector of the Baltic Sea. Production came initially through an upgraded drilling rig which earlier had drilled a water injector on the field. ••• Lukoil has discovered a potential gas giant in the Romanian sector of the Black Sea. The semisubmersible Transocean Develop- ment Driller II drilled the Lira-1X well on the Trident block, 170 km (105 mi) offshore in 700 m (2,296 ft) of water. Early data from the well suggested a productive inter val with a gas-saturated thickness of 46 m (151 ft) – reserves could be more than 30 bcm, although this has to be confirmed by appraisal drilling.
••• Delek Group says the Noble Energy-led partners in deepwater block 12 offshore Cyprus have re-scheduled further test drilling until May 2016. This gives them more time to work on amendments to the development plan for the Aphrodite gas discovery.
Middle East Iran Offshore Oil Co. has increased oil output from the Salman field in the Persian
Gulf by 3,500 b/d following gas injection. Two rigs were due to drill further wells to step up injection, lifting oil volumes by a further 4,000 b/d.
East Africa Mozambique’s government has awarded four offshore exploration blocks to two consortia under the country’s fifth bidding round. ExxonMobil/Rosneft picked up the Z5-C and Z5-D contract areas in the Zambezi
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Mediterranean Sea BP has agreed to speed up development of its recent deepwater Atoll discovery in the North Damietta concession offshore Egypt. The company estimates reser ves at 1.5 tcf of gas and 31 MMbbl of condensate: under a first-phase development it plans two wells tied back to existing infrastructure. Eni has brought onstream its fasttrack Nooros gas/condensate development in the shallow-water Nile Delta region following the discovery this July, via two deviated wells drilled from an onshore location. Production is sent 25 km (15.5 mi) to the Abu Madi treatment plant. Eni planned three more exploration wells in the license area.
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GLOBAL E&P
Delta and a5-B in the Angoche basin. Eni, in par tnership with Statoil and Sasol, secured A5-A in the Angoche area of the Northern Zambezi basin. Although nearly all Mozambique’s deepwater finds to date have been gas, this area could be oil-prone, Statoil said.
Asia/Pacific The WP4 platform for the Zawtika Phase 1b gas pr oject offshore Myanmar has departed the Tanggu Fabrication yard in China, according to operator PTTEP. Last month it was due to sail to its offshore location in the Gulf of Martaban. Most of the gas from Zawtika, which started production in March 2014, heads to Thailand. ••• CNOOC has confirmed its Caofedian field in the Bohai region offshore China is a mid-sized oil discover y. A recent appraisal well was drilled in the western par t of the Shijuto Uplift in 20 m (65.6 f t) of water, flowing 5,750 b/d of light crude during testing – the highest rate achieved to date in Palaeogene clastic rocks, the company claimed. ••• Lundin Petroleum has discovered a small gas accumulation in the Mengkuang structure, 75 km (46.6 mi) north of its Bertam field offshore Pensinsular Malaysia. The well encountered 9 m (29.5 ft) of gas pay in Miocene channel sands. Early next year the company and partner Petronas plan two exploration wells offshore Sabah on the Imbok and Bambazon prospects in the SB307/308 concessions. Both are said to be on trend with three producing oil fields operated by Shell. ••• Husky Energy has started a tendering process for a floating production vessel to develop the MDA and MBH fields in the Madura
Strait, offshore Indonesia. The company has commissioned another FPSO to process gas and liquids from the BD field in the same region.
Australasia The BGP Explorer was mobilizing early last month to start shooting the Haere 2D seismic survey in the Gulf of Papua. According to Searcher Seismic – a partner in the project, along with Papua New Guinea’s PNG’s Department of Petroleum and Energy – the aim is to build a 17,000-km (10,56-mi) grid of long-offset, high-resolution broadband seismic. This should assist reinterpretation of the geology in the region and identification of prospective structural and stratigraphic trends. The area is thought to contain extensive Mesozoic and Palaeozoic sediments. ••• Saipem has finished installation of the 890-km (55 3-mi) 42-in. gas export pipeline for the Ichthys LNG project offshore northern Australia. This is the world’s third longest subsea pipeline, according to operator INPEX. It will take gas from the Ichthys gas/condensate field to new processing facilities near Darwin. Saipem’s laybarges SEMAC and Castorone began the installation in mid-2014. ••• Australia’s National Offshore Petr oleum Safety and Environmental Management Authority (Nopsema) is considering BP’s environment plan for exploratory drilling offshore South Australia. Nopsema has asked the company to provide a detailed risk assessment of its proposed program in the Great Australian Bight, with arrangements for dealing with the impact of any oil spill. �
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OFFSHORE EUROPE
Butch to head subsea to Ula
Jeremy Beckman • London
Centrica and its partners have chosen the subsea route for their Butch oil field development offshore southern Norway. Pending an investment decision late next year, the oil will be transported 13 km (8 mi) to BP’s Ula complex for processing, then transported via the Ekofisk center and the Norpipe trunkline to the Teeside terminal in northeast England. Butch’s produced gas will be injected into the Ula reservoir. This will be Centrica’s first operated de velopment project in the Nor wegian sector. To guide it along the way, the company has awarded Norwegian fabricator Aibel a five year frame agreement covering all phases of its programs offshore Nor way, from detailed engineering to construction, installation and completion. Centrica handed Subsea 7 another five-year contract encompassing all Norwegian concept engineering, front-end engineering and design (FEED), subsea The jackup Paragon C462 is undergoing inspection and modifications in the Port of Den Helder umbilicals risers and flowlines (SURF) studon the Dutch North Sea coast. This will include replacement of high-pressure pipework and ies and execution, and life of field operations. maintenance of drilling equipment. The Port authorities hope this job will serve as an offshore Initially, Subsea 7 will work on the FEED for reference, allowing it to expand it services to mooring of offshore structures at its maintenance quays. (Photo courtesy Port of Den Helder) the tieback to Ula with Granherne. The aim of this agreement, Centrica said, is to minimize complexity, cost, and risk. south of Forties, another Apache-operated sea gas compression at its Åsgard and Gull Assuming the project goes forward, it well encountered oil and gas in Triassic faks field centers. could cost up to $854 million to develop sands in block 22/29c. The company plans Butch’s recoverable reserves of up to 51 further appraisal drilling to push recover- NPD commissions MMboe. Centrica plans to use infrastruc- able resources from the three finds beyond unmanned platform study ture installed at Ula to receive hydrocarbons 70 MMboe. If proven, this will help it extend The Norwegian Petroleum Directorate from DONG’s Oselvar field, which has per- the lives of both production complexes be- (NPD) is pressing for more dry-tree unformed below expectations, and is looking to yond 2020. manned wellhead platforms for new field start production in 2019, building to a peak West of Shetland, Chrysaor has con- developments offshore Norway as an alterof 35,000 boe/d. firmed that its 205/27-3 and 205/27-3z wells native to subsea tiebacks. It has commisdrilled this summer both discovered oil in sioned Ramboll Oil & Gas to study the pros Apache proves the Mustard prospect in late Jurassic Solan and cons of these facilities, which NPD besandstone. Neither was tested, although the lieves are comparable in terms of functionalmore oil in Beryl area Apache Corp., which has revitalized the top-hole section has been retained for poten- ity and sound economics to subsea systems, Forties field complex in the UK central tial future use. but more accessible in terms of inspection North Sea since acquiring BP’s operated inand maintenance. Unmanned wellhead platterest, is now delivering results from Beryl Statoil starts up shoreforms range from relatively simple to more in the same region, formerly developed by powered Troll compressors complex structures equipped with process ExxonMobil. The company achieved discov Two new compressors have begun op- equipment. Some can be accessed from veseries with its first two exploratory wells in erating at Statoil’s Troll A platform in the sels without the need for helidecks. The rethe Beryl area, and strong results from de- Norwegian North Sea. Alongside the two port should be completed by year-end. velopment drilling. existing models, they should increase gas After its initial K discovery (well 9/18B- recovery from the field by 83 bcm and main- DONG backs field 18) in June, two side tracks followed into ad- tain the Troll field’s gas export capacity at life extension study jacent fault blocks which intersected more 120 MMcm/d. DONG Energy may apply a new technique than 1,500 ft (457 m) of good-quality oil-bear Aibel built the 3,000-ton compressor mod- to prolong production from its Siri area fields ing sands within four formations and across ules at its yards in Norway, Poland and Thai- in the Danish North Sea. The $4.2-million three fault blocks. The Corona exploratory land, while ABB supplied and installed the 70- collaborative project OPTION (Optimizing well was the company’s first test of a Tertia- km (43-mi) subsea cables bringing power to Oil Production by Novel Technology Integrary injectite prospect: it logged 225 ft (69 m) the new plant from the Norwegian mainland, tion) is working on ways to improve simulaof net pay. In July, Apache brought onstream using the company’s HCDC Light technol- tion tools for prediction and control of flow its Triassic Lewis formation Nevis Central ogy. This involves taking alternating current between horizontal wells on the reservoir, L4S oil and gas production well, followed in from Norway’s national grid, converting it with a focus on enhanced oil recovery. DONG October by first oil and gas from the Beryl to direct current and transmitting it through is contributing a subsurface dataset from the ACN development well in the Nansen and the cables to Troll A. There it is transformed Siri and Stine fields. Partners in OPTION inEirikisson formations. In both cases, Shell back to AC to run the compressors. clude LR Senergy, two Danish universities, is the sole partner. Around 80 km (50 mi) Earlier this year, Statoil also started sub- and downhole tractor specialist Welltec. � 16 Offshore December 2015 • www.offshore-mag.com
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GULF OF MEXICO
Bruce Beaubouef • Houston
Amidst storm clouds, some silver linings Even amidst the dark gloom that pervades Chevron U.S.A. Inc. is the operator of Anthe current market downturn, one can still chor, with a 55% working interest. Anchor find a few silver linings. While the number of co-owners are Cobalt International Energy, active drilling rigs in the Gulf is significantly L.P. (20%), Samson Offshore Anchor, LLC down from last year, there have been a few (12.5%), and Venari Resources, LLC (12.5%). positive metrics in recent weeks. Meanwhile, Shell announced in mid-No A total of 19 drilling permits were issued vember that it is one step closer to achievfor work in October, up from 13 in Septem- ing first oil at its Stones development, with ber, according to Evercore ISI’s US Drilling the launch of the world’s deepest floating Permit Monthly update issue in mid-Novem- production facility. The Turritella FPSO reber. Of course, that number is down from 21 cently set sail from Singapore, where it was a year ago. built at the Keppel yard, and is on its way to The Turritella FPSO recently set sail from But in October, eight permits were issued the deepwater Gulf. Singapore, where it was built at the Keppel yard, for new wells, including three deepwater, four Once it reaches the GoM, the facility will and is now on its way to the deepwater Gulf for midwater, and one ultra-deepwater. Five per- be connected to subsea infrastructure lo- Shell’s Stones project. (Courtesy Shell) mits were issued for side tracks while six were cated in the Lower Tertiary play, beneath issued for bypasses and eight for new wells. 9,500 ft (2,896 m) of water, which Shell says risers – steel pipe with in-line buoyancy that A total of 154 new permits have been issued breaks the existing water depth record for absorbs the vessel’s motion and boosts riser year to date, down 42% versus 2014, driven by an oil and gas production facility. performance at extreme depths. sharply lower bypass and new well permits. Stones is located about 200 mi (320 km) SBM Offshore was contracted to build the Only 58 new well permits have been issued southwest of New Orleans in the Walker Ridge vessel, which is a converted Suezmax FPSO. year-to-date compared to 105 as of this time area. It will have a processing facility capacity of last year. While the number of ultra-deep“The strength of Shell in deepwater is 60,000 b/d of oil and 15 MMcf/d of gas treat water and midwater new well permits have rooted in our ability to combine innovation ment and export. No water injection facilities been largely resilient over the past year, only with our strong track record for delivery,” are specified. SBM said that the Suezmax 18 deepwater and 12 shallow-water new well said Wael Sawan, executive vice president hull will be able to store 800,000 bbl of oil. permits have been issued year to date, down of Deep Water, Shell Upstream Americas. But of course, in these times, not every18% and 76% respectively from a year ago. “Achieving first oil at Stones – in this new thing is a silver lining. There are still storm Meanwhile, the number of new oil and Gulf of Mexico frontier – involves taking a clouds. This was in evidence in early Nogas exploration plans filed in the Gulf of measured and strategic approach, growing vember, when Marathon Oil Corp. agreed to Mexico held steady month-to-month, with as we learn more about the reservoir.” sell most of its GoM oil and gas assets. operators filing five plans to drill a total of The project has nearly 16 million hours of Marathon’s GoM portfolio includes its op22 wells, versus five plans to drill 14 wells work safely completed during construction. erated producing assets in the greater Ewin September. No development plans were Shell said a “safety first” mindset and a desire ing Bank area and its non-operated producfiled to drill in October. to “build something special with no harm to ing interests in the Petronius and Neptune But even with lower oil prices, Evercore people” is what led to the safety success dur- fields in the Gulf of Mexico. They are being ISI says it expects development activity to ing the construction of the Turritella. sold for $205 million. accelerate slightly in the coming months Shell says it selected this vessel design Marathon Oil operates the Arnold, Loband years, and it believes that the Gulf of to optimize field development and produce ster, and Oyster fields in Ewing Bank blocks Mexico will be the only relative bright spot this ultra-deepwater discovery in a safe and 963, 873, and 917, holding 65% working interfor deepwater activity in 2016-2017. responsible manner. Using this floating ves- est in Ewing Bank; 66.67% WI in Lobster and More good news came in late October, when sel allows Shell to address the relative lack Oyster and 62.5% WI in Arnold. It holds a Chevron announced a successful appraisal well of infrastructure, seabed complexity, and 30% non-operated WI in Neptune, and a 50% at its Anchor discovery in the Lower Tertiary unique reservoir properties. Aside from be- non-operated WI in Petronius/Perseus de Wilcox Trend. Appraisal drilling has found 694 ing the world’s deepest facility, it also features velopment in Viosca Knoll blocks 786/830. ft (211 m) of net oil pay. an industry-first application of combining Marathon Oil said it will retain its inter To date, Chevron has confirmed a hydrocar- a disconnectable buoy with steel lazy wave ests in certain other producing assets and bon column of at least 1,800 ft (549 m) in acreage in the GoM, as well as its inthe Lower Tertiary Wilcox reservoirs at terests in the Gunflint development and Anchor. Complete appraisal of the field reShenandoah discovery. quires further delineation wells and techMarathon holds a 10% non-operated nical studies, Chevron said. WI in the Shenandoah discovery, lo The original Anchor discover y well, cated in Walker Ridge block 52, and in Green Canyon block 807, approxian 18% non-operated working intermately 140 mi (225 km) off the coast est in Gunflint, located on Mississippi of Louisiana in 5,180 ft of water (1,579 Canyon blocks 948, 949, 992(N/2) and m), was drilled to a depth of 33,750 ft 993(N/2). (10,287 m) and it encountered 690 ft The unnamed buyer will assume all (210 m) of net oil pay. future abandonment obligations for the acquired assets. The effective date of the transaction is Jan. 1, 2015. Closing is Chevron assets in the Lower Tertiary in the Gulf of Mexico. (Courtesy Chevron) expected before the end of the year. � 18 Offshore December 2015 • www.offshore-mag.com
Sarah Parker Musarra • Houston
SUBSEA SYSTEMS
DW examines subsea industry Douglas-Westwood (DW) has offered new insights into the subsea oil and gas market with two new repor ts focusing on the global subsea vessel operations market and the global ROV operations market, respectively. DW estimates global subsea vessel operations expenditure will total $97.7 billion between 2016 and 2020. Mark Adeosun, author of the fifth edition of the “World Subsea Vessel Operations Market Forecast,” said: “Low hydrocarbon prices coupled with vessel oversupply will result in low utilization, impacting expenditure over the forecast period. Despite these near-term concerns, subsea vessel demand is set to recover towards the end of the forecast period. “As a result of the continued challenging market conditions, subsea vessel providers have been taking additional measures to help strengthen their financial position and stem oversupply in the market by deferring the delivery program of newly built vessels. We believe that it is unlikely that day rates have bottomed out.” Across the global subsea vessel fleet, he notes that a 2014-15 decline of at least 30% in day rates is “not unlikely before prices stabilize. However, many tier one contractors are joining forces to ensure utilization and maintain track record.” In another recently released analysis, the seventh edition of the “World ROV Operations Market Forecast,” the firm reported that it foresaw lower day rates and utilization for work-class ROVs. The market for workclass ROVs could total $14.2 billion over the period to 2019. Author Antoine Paillat said: “This represents a 19% increase on the previous five-year period, however, near term we see some difficult conditions with weaker day rates and lower levels of utilization for the work-class fleet. “We expect the global ROV market to significantly contract in value terms in 2016 (-6.3%) and then plateau in 2017, due to the current oil price downturn.”
at Bladin Point near Darwin for processing. Louis Bon, managing director Ichthys Project, said: “It means we are one step closer to physically connecting our onshore plant near Darwin to the Ichthys field where our offshore facilities will be permanently moored for the 40-year life of the project.” Saipem started the program in mid-2014, using its lay barges SEMAC and Castorone. INPEX will conduct other work on the pipeline in preparation for operational start-up.
ations on the first Catcher water injection well (CTI1) were completed with good reservoir results. The second water injector, (CCI2), has reached TD and is in the final phase of completion. Catcher remains on schedule for first oil in 2017.
Cardona well tieback complete
At the Cardona field in Mississippi Canyon block 29, the Cardona #6 well has been tied into the existing Cardona subsea infrastructure which flows into the company’s PomSubsea 7 to work pano platform. Gross production from the with Premier Oil Subsea 7 has signed a long-term partner- Cardona field is about 15,000 boe/d. Drilling ship frame agreement with Premier Oil. of the Cardona well #7 with the ENSCO 8503 The subsea contractor will provide the Lon- is expected to begin once completion of the don-based operator with concept engineering, Amethyst prospect is finished. Drilling is exfront-end engineering and design (FEED), pected to take about two months. subsea, umbilicals, risers and flowlines (SURF) In neighboring MC block 26, ENSCO 8503 project execution and life of field operations, on is performing completion operations at the a preferred supplier basis. Additionally, Subsea Amethyst discovery, where Stone holds 100% 7 may participate in Premier’s decommission- working interest. The well will be prepared ing programs. for an initial production test prior to final flow The agreement covers Premier’s activities line and umbilical hook up. First production offshore the UK, Norway, and the Falkland is expected by 1Q 2016 to the Pompano platIslands and runs for five years, with options form, located less than 5 mi (8 km) from the for an extension. discovery. Through early engagement on Premier’s projects Subsea 7 aims to develop technical GE strengthens solutions with realistic cost evaluations. Cur- intervention capability rently the contractor is supporting the operaGE Oil & Gas has agreed to acquire subtor’s Catcher development in the UK central sea intervention specialist Advantec. The acNorth Sea. At Catcher, this year’s subsea in- quisition is part of GE’s strategy to address isstallation schedule has been completed with sues affecting the growing number of mature the pipeline end manifold and tow templates subsea fields, and to strengthen its position in place at the Burgman and Varadero ac- as a provider of subsea production equipment cumulations. The 60-km (37-mi) gas export and solutions for full life-of-field management. pipeline was laid during July. Advantec, formed in 2005, will operate unFabrication of the subsea flowline bundles der the existing name and management team and associate towheads, the buoy and the mid as part of GE’s Subsea Services & Offshore water arches (riser buoyancy aids) is on sched- division, continuing to supply products and ule and these will be installed next summer. services directly to existing and new clients. In July, the Ensco 100 started development Advantec supplies and rents Installation drilling, and has to date drilled two wells. Oper- WorkOver Control Systems for subsea inter vention tasks.
Saipem completes Ichthys pipelay Saipem has completed laying the 890-km (553-mi), 42-in. gas export pipe- line serving the Ichthys LNG project offshore northern Australia. This is the longest subsea pipeline in the Southern Hemisphere and the third longest subsea pipeline in the world, according to operator INPEX. The pipeline will take gas from the offshore Ichthys gas/ condensate field to onshore facilities
Saipem’s deepwater pipelay vessel Castorone laid more than 700 km (435 mi) of the Ichthys LNG project’s 890-km (553-mi) gas export pipeline. (Courtesy INPEX)
20 Offshore December 2015 • www.offshore-mag.com
Wood Group wins BP contract BP has contracted Wood Group to provide engineering services to existing subsea infrastructure in the Gulf of Mexico, UK and Nor wegian continental shelves, and offshore Azerbaijan. Wood Group Kenny will deliver program, project and integrity management and operational support for subsea projects under the five-year contract, which is effective immediately. The contract will be delivered from WGK’s offices in Aberdeen, London, Norway, Houston, and Baku. �
Three Successful Startups, One Common Denominator
VESSELS, RIGS, & SURFACE SYSTEMS
FPS capex to grow by 49%, says DW Douglas-Westwood’s quarterly version of the World Floating Production Market Forecast 2015-2019 report states that between 2015 and 2019 $68 billion will be spent on FPS units – an increase of 49% compared to 2010-2014. Despite capex growth over the forecast, orders this year have been very weak with only four contract awards so far, the company stated. This is a result of the low oil price impacting project sanctioning activity, compounded by recent histor y of high-cost FPS projects running late and/or over-budget. In the near term, Douglas-Westwood expects improvement next year. Operators have worked hard recently to redevelop projects to make them more cost effective and their efforts should see final investment decisions made on a number of projects. One example is Mad Dog Phase 2 in the Gulf of Mexico, which was originally considered ‘uneconomic’ when oil was priced at $110 a barrel. With the major redesigns BP has undertaken (coupled with lower prices for equipment and services in the downtur n) it is likely to be sanctioned next year, despite the current low oil price. FPSOs will represent by far the largest segment of the market both in terms of numbers (67 installations) and forecast capex (79%) during 2015-2019. FPS units will account for the second largest segment of capex (9.3%), with TLPs third (9.2%).
Statoil cancels rig contract Statoil has canceled its contract with Songa Offshore for the semisubmersible drilling rig Songa Trym, four months before the expiration of the contract. Statoil previously notified Songa Of fshore that the rig would be suspended for a period, and Statoil has tried to find other assignments for the rig after the suspension period and up to the expiration of contract. “We informed the supplier earlier in October about suspending the contract after the rig has completed the drilling operation on the Tavros well on the Visund field. Statoil has hoped for further activity in the remaining contract period, but we now realize that we must cancel the contract, as we have not succeeded in finding more assignments. We regret that we need to cancel the contract before it expires,” says Tore Aarreberg, head of rig procurements in Statoil.
Maersk Drilling focuses on remaining competitive
Robin Dupre • Houston
meets the criteria required for completion of the vessel in accordance with the construction contract and its specifications. Pacific Drilling made advance payments totaling approximately $181.1 million under the contract, and will seek a refund of the installment payments.
Guardian 2 will
sail for Port Harcourt, Nigeria in December. (Photo courtesy Damen Shipyards)
Homeland takes delivery of second Damen vessel Homeland Integrated Offshore Services Ltd. will take delivery of its second Damen Fast Crew Supplier 3307 Patrol just 18 months after a sister vessel entered service in the Nigerian of fshore market. HIOSL serves the Nigerian oil and gas industry with a wide range of maritime, security and logistics services. The Lagos-headquartered company has ambitious plans to become the leading marine logistics provider in the Nigerian offshore industry. Currently undergoing sea trials in Singapore, Guardian 2 is expected to be directly employed when she arrives in Port Harcourt, Nigeria, in December. HIOSL will then have five patrol vessels in its fleet. Guardian 1 has largely been carrying out security patrol services for the IOCs, working alongside the Nigerian Navy, as well as transferring crew and supplies. “ Guardian 1 is definitely the best vessel in the field in terms of speed and intervention abilities. Furthermore, with her unique Damen Sea Axe hull, she has fantastic seakeeping ability and still provides efficient fuel economy, even in rough terrain.”
Claus V. Hemmingsen, CEO of Maersk Drilling and member of the Executive Board in the Maersk Group said: “We deliver a satisfactory third quarter result given the adverse market conditions. We continue to focus on operational perfor mance and a competitive cost Transocean delays newbuild deliveries level, which are key factors in or der to secure contracts for our rigs.” Transocean has postponed the deliver y of ultra-deepwater newIn the third quarter, Maersk Drilling signed two new contracts. builds Deepwater Pontus and Deepwater Poseidon for one year each. Maersk Resilient secured a three-year contract and Mærsk Giant re- The Deepwater Pontus was expected to start work with Shell in the ceived a contract for 150 days, both for work in the Danish sector of Gulf of Mexico in 1Q 2017, while the Deepwater Poseidon was exthe North Sea. Furthermore, Maersk Drilling signed four contract pected to start in the Gulf in 2Q 2017. extensions. A 16-month extension for Mærsk Innovator working in Though the counterparties will be compensated for the delay, Norway, a five-year extension for Heydar Aliyev working in the Cas- the 10-year duration and $519,000 day rates of the original contracts pian Sea in Azerbaijan, a 250-day extension for Maersk Resolve in the remain. The ultra-deepwater newbuild Deepwater Thalassa is curDanish sector of the North Sea, and the latest a three-year extension rently mobilizing to the Gulf of Mexico to start with Shell in 1Q 2016 for Maersk Discoverer working offshore Egypt. at $519,000/d, while the Deepwater Proteus is scheduled for delivery At the end of 3Q 2015, Maersk Drilling’s for ward contract cover- in December 2015 with operations commencing in 2Q 2016. age was 85% for the rest of 2015, 70% for 2016 and 49% for 2017. The Golar issues Cameroon FLNG update total revenue backlog by end 3Q 2015 amounted to $5.8 billion. Golar LNG Ltd. says its Cameroon FLNG project has received approval and signature of the binding tolling term sheet thereby Pacific Drilling rescinds confirming the commercial terms for the FLNG vessel Golar Hilli. construction contract Pacific Drilling has exercised its right to rescind the construction Cameroon’s state owned oil and gas company Societe Nationale des contract for ultra-deepwater drillship Pacific Zonda due to the failure by Hydrocarbures, Perenco Cameroon, and Golar are all parties to the exSamsung Heavy Industries to timely deliver a vessel that substantially ecuted agreement. Operations are scheduled to begin in 2Q 2017. � 22 Offshore December 2015 • www.offshore-mag.com
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DRILLING & PRODUCTION
Robin Dupre • Houston
Weatherford, Maersk Training partner to enhance critical well preparation Weatherford Secure Drilling Ser vices and Maersk Training have entered into a strategic partnership to enhance scenario-based training and competency for critical wells. The training will provide Weatherfor d, operator and rig-crew personnel with improved preparation and aptitude to help prevent well-control events and nonproductive time when operating in extreme drilling environments. Weatherford recently introduced the OneSync software platform, which enhances planning, simulation and control during managed pressure drilling (MPD), early kick detection, and other drilling and completions scenarios. The software platform builds on the fieldproven Microflux control system. Maersk Training will fully integrate the MPD simulator application of the OneSync platform into its drilling simulators to enable comprehensive MPD and well-control planning and scenario-based training. The Maersk Training drilling simulators wil l be available in locations including Houston, Rio de Janeiro, Dubai, and Aberdeen. The advanced simulations will enable entire rig crews — including the drilling contractor, operator, service provider and third parties — to receive hands-on rig and well-specific training. “Many of today’s easy-to-access reserves have been depleted and complex wells have become the norm, particularly in deepwater applications. As a result, advanced drilling technologies like MPD are being deployed more frequently,” said Iain Cook, vice president of Weatherford Secure Drilling Services. “Improved competencies on how to manage well-control scenarios through the application of these technologies, as well as seamless communication across multi-functional teams, are imperative to a safe and productive future.” As a part of this agreement, Maersk Training will serve as Weatherford’s preferred provider of well-control training for all MPD personnel worldwide. “We see the partnership with Weatherfor d as a game changer in the industry,” said Claus Bihl, CEO of Maersk Training. “We are combining strong technical knowledge with high-quality training to increase competence development for crews working with MPD technology. This will improve safety and operational performance on rigs.”
Halliburton achieves first installation of SmartPlex downhole control system Halliburton’s Completion Tools business line has achieved the first installation of the SmartPlex downhole control system in a six-zone multilateral well. The installation was a joint effort across functional teams within the intelligent completions group, and was the first electro-hydraulic system installed by Halliburton in the Middle East. The installation was completed with zero nonproductive time and no HSE issues. The SmartPlex downhole control system enables remote actuation of downhole control devices using electro-hydraulic control lines from the surface. The multi-drop system provides simple and reliable zonal control of up to 12 interval control valves in a single wellbore, using a minimum number of control lines.
Report reveals need for collaboration A new report reveals that while the current environment is creating opportunities for innovation, almost half of oil and gas executives admit they have fallen short of their innovation goals. The number of respondents saying they have fallen shor t has almost doubled as the oil price has gone down, with only 26% saying they had fallen short in spring 2014. These findings form part of the Technology Radar 2015 report recently launched by Lloyd’s Register Energy. “The oil and gas industry is undergoing a period of significant uncertainty,” said John Wishart, Group Energy Director of Lloyd’s Register. “The oil price slowdown is clearly impacting investment 24 Offshore December 2015 • www.offshore-mag.com
An Atwood Oceanics Inc. subsidiary has agreed to an extension and rate adjustment to its existing contract with Noble Energy Inc. for the Atwood Advantage ultra-deepwater drilling rig. The agreement is to extend the contract for the purposes of a four-well P&A program in the Gulf of Mexico. The program has an estimated duration of 120 days during the contract term and is anticipated to occur in 2016. This extension adjusts the operating day rate to about $240,000 only during the four P&A wells, and makes the new contract expiry date August 2017. (Courtesy Atwood Oceanics Inc.)
in innovation initiatives. However, our report finds that contrary to perceived wisdom, innovation has a crucial role to play in the current environment, where it creates operational efficiencies and is cost-effective.” “To innovate properly and achieve business goals companies must address a number of common challenges, including collaborating more openly, using data more effectively and changing traditional mind-sets,” continued Wishart. “Encouragingly, our findings show that overall the industry understands the need for innovation and has begun reaching out to other sectors to gain technological insight.”
Halliburton, Baker Hughes update Halliburton and Baker Hughes announced the second round of divestitures in connection with the pending transaction. In addition to the previously announced divestitures of Sperry and Drill Bits, Halliburton will also divest its expendable liner hanger business (part of its Completion & Production Division), Baker Hughes’ core completion business (which includes packers, flow control tools, subsurface safety systems, intelligent well systems, permanent monitoring, sand control tools and sand control screens), Baker Hughes’ GoM sand control business (including two stimulation vessels), and Baker Hughes’ offshore cementing businesses in Australia, Brazil, the GoM, Norway, and the UK. The combined 2013 revenue associated with all of the announced divestitures was $5.2 billion, up from $3.5 billion for Sperry and Drill Bits, which implies the assets announced had revenues of $1.7 billion. Halliburton also announced that it received bids from multiple interested parties for each business (implying multiple buyers each of Sperry, Drill Bits and the combined businesses). This marks another positive step in the process and should alleviate some concerns that arose over the past few weeks around a single-buyer theory and the rumored buyers. Evercore expects the Baker Hughes/Halliburton spread to narrow and believes the second round of divestitures will be easier to accomplish as these are more “asset sales” than sales of large, global businesses. �
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GEOSCIENCES
Exhibitors showcase new technologies at SEG 2015 The exhibit floor at the 2015 Society for Exploration Geophysicists Annual Meeting, held this year in New Orleans, was brimming with new technologies and products. While companies slash budgets and continue to search for mor e cost-effective methods of doing business, the overall focus on the floor was how seismic companies could offer high-quality imaging at a lower cost. A quick scan of the exhibition floor was testament to the fact that necessity does, in fact, beget invention. Highlighted here are just a handful of products and technologies introduced or discussed at SEG 2015.
Flying Node concept Thalassa Holdings’ Autonomous Robotics Ltd. (ARL) debuted its Flying Node concept, which the company says operates as a “swarm” of AUVs descending upon the seabed to record data. The Flying Node concept is designed to combat the cost of obtaining ocean bottom seismic data in extreme water depths or in complicated geological structures. With a maximum operating depth of 3,000 m (9,842 ft), the ARL Flying Nodes are positioned on the seabed using an ultra-short baseline acoustic navigation system mounted on an unmanned surface vessel. According The autonomous Flying Node to company representatives, the accuuses acoustic placement racy of the nodes’ positioning is comto navigate to the seabed. parable to ROV-deployed nodes. Each (Image courtesy ARL) node, which is said to have a flexible receiver geometry and an integrated acoustic transponder, can record on the seabed for up to 60 days, and is capable of both 3D and 4D seismic. Multiple receiver rows can be deployed at once, and ARL said that it foresaw the deployment of 3,500 Flying Nodes from a vessel.
Portable Modular Source System Fellow Thalassa Holdings company WGP highlighted its Por table Modular Source System and Dual Portable Modular Source Systems (PMSS / D-PMSS) as part of its permanent reservoir monitoring services. Statoil uses the system at its Snorre and Grane fields, both located in the Norwegian North Sea. BP is also a customer, utilizing WGP’s life of field seismic products in both its Valhalla field in the North Sea, and its Chirag Azeri Reservoir Seismic Project in the Caspian Sea. The PMSS is a modular, containerized system based on ISO-sized containers, designed to be both land and sea transportable. The system can be quickly, temporarily installed on a vessel of opp ortunity, even one already assigned to a field for a different application, which could help contain costs. WGP announced this summer that the permanent reservoir monitoring operations at Snorre and Grane were completed ahead of schedule. More than 6,000 km (3,728 mi) of data was shot over the two fields.
Reservoir benchmarking Cray Inc. announced it had achieved a new performance benchmark for reservoir simulations using Stone Ridge Technology’s ECHELON reservoir simulation software and the Cray CS-Storm cluster supercomputer. ECHELON models oil, water, and gas flows in a reservoir, and is specifically designed for leveraging graphics processing units (GPUs) computer architectures. It also has scalability across multiple GPUs. With ECHELON running on Cray’s CS-Storm system, it can deliver speed that can be used by reser voir engineers to study many mor e realizations of their models and run large, high-resolution cases, said Vincent Natoli, founder/CEO, Stone Ridge Technology. 26 Offshore December 2015 • www.offshore-mag.com
Magseis’ docking robot operates onboard the research/survey vessel Artemis Athene.(Image courtesy Magseis)
MASS Present in Magseis’ booth to demonstrate its Marine Autonomous Seismic System (MASS) was a smaller version of the Lysaker, Nor way-based company’s automated industrial robot technology. Magseis’ MASS sees small, autonomous sensors inser ted into steel cables. As part of that process, the robotic “arm” handles the sensor capsules, data downloading, and battery management aspects of the system. Following the show, in mid-November, Magseis announced an agreement with Shell for the further joint development of a system to deploy the MASS technology in ultra-deepwater. The agreement regulates the fur ther work leading up to a full-scale pilot test which is planned for completion in early 1Q 2016 and through to the commercial deployment of the system which is planned for early 2017. The project will be jointly financed by Shell and Magseis with a significant contribution from Innovation Nor way.
New geotech collaboration Halliburton’s Landmark software provider and CGG agreed to a geosciences technology collaboration. The collaboration aims to allow seamless access to interpretation and reservoir characterization technologies and geoscience data from both companies using Landmark’s DecisionSpace. A series of workflows enabled by the platform will be delivered through connectivity of geoscience applications and data, the companies said. Additionally, Landmark and CGG will engage with customers to develop a new class of E&P workflows to meet existing and emerging industry challenges.
FlexNode Seabed Geosolutions introduced FlexNode, a scalable node deployment solution. An express seabed seismic service, FlexNode has completed two successful projects for different operators, with one located offshore West Africa and the other in the North Sea. Through its transportable, modular solution, nodes can be deployed using existing support vessels already on site, optimizing vessel usage. The FlexNode service solution is designed for deepwater projects up to 3,000 m (9,842 ft) under tight time constraints, and projects where targets are obstructed by platforms and seafloor infrastructure. While the number of nodes to be deployed can be flexible, Seabed Geosolutions said that between 200-500 nodes are typically needed, as FlexNode offers sparse node geometry with a high-density shot point coverage. Currently, customers could employ Seabed Geosolutions’ existing Trilobit in using FlexNode, a four-component broadband seabed node which already offered prolonged recording times and flexibility in deployment methods. However, the company representative explained, by 2H 2016, IT is planning for its new fully-autonomous Manta node to be available. This model could also be used in the FlexNode ser vice. �
TOP 5 PROJECTS
Chevron advances deepwater frontier with Jack/St. Malo project Deep draft semisubmersible to serve as hub for the 43 subsea wells Bruce Beaubouef
Managing Editor ith first oil produced late last year, Chevron has advanced the boundaries of offshore exploration and production with its Jack/St. Malo project in the deepwater Gulf of Mexico. The Jack and St. Malo fields are among the largest in the Gulf of Mexico, and are part of the Gulf of Mexico’s Lower Tertiary trend, the play that has proved both tempting and vexing for many developers. The fields were co-developed with subsea completions flowing back to a single host, semisubmersible floating production unit (FPU) located between the fields. The FPU is the largest of its kind in the GoM and has a production capacity of 170,000 b/d of oil and 42 MMcf/d of gas, with the potential for future expansion. The Jack/St. Malo semisubmersible floating production unit began its journey from the fabrication With a planned production life of more yard in Ingleside, Texas, to its mooring location in the Walker Ridge area in November 2013 (Images than 30 years, current technologies are an- courtesy Chevron Corp.) ticipated to recover in excess of 500 MMboe. The successful completion of the project ners include Petrobras (25%), Statoil (21.50%), site by the Crowley ocean-class tugs Ocean was the result of the collaboration of hundreds ExxonMobil (1.25%), and Eni (1.25%). Wind and Ocean Sun, and the contracted of suppliers and contractors and thousands of The St. Malo field was discovered in Octo- tugboat Harvey War Horse II . These vessels workers across nine countries over a ten-year ber 2003 by a discovery well drilled by Trans- moored the FPU and made it storm safe. period. With the project now onstream, Chev- ocean’s Discoverer Spirit drillship. The well The Jack/St. Malo FPU is now accessing ron says that Jack/St. Malo is a key part of its struck a net oil pay of 1,400 ft. The Jack field reservoirs beginning at 19,500 ft (5,944 m) upstream projects program, and was delivered was discovered in July 2004 with the explora- beneath the seafloor—representing a total on time and on budget. tion well Jack-1. The well was drilled by Trans- depth of 26,500 ft (8,077 m), or roughly the Successive development phases, which ocean’s Discoverer Deep Seas drillship to a same height as the last base camp a climber could employ enhanced recovery technolo- depth of 29,000 ft. It struck 350 ft of net oil pay. reaches before summiting Mount Everest. gies, may substantially increase recovery at The project was approved by the partners the fields. in October 2010. An investment of $7.5 bil- Technology advances lion was made in the initial development To locate and produce resources from phase, which called for three subsea centers these depths, Chevron took on some exProject infrastructure The Jack and St. Malo fields are about 25 tied back to a production hub. Production is treme conditions with technological breakmi (40 km) apart, and are around 280 mi (450 expected to be ramped up to 94,000 b/d of throughs that it says are game-changers for km) south of New Orleans in about 7,000 ft oil and 21 MMcf/d of gas in coming years. the industry. The project has delivered a (2,100 m) of water, at its greatest depth. The The hull of the deep draft semisubmers- number of new technology applications, inproject infrastructure covers an area nearly ible production platform was constructed at cluding the industry’s largest seafloor boostas wide as the state of Rhode Island. the Samsung Heavy Industries yard in Geo- ing system and Chevron’s first application The Jack field lies in Walker Ridge blocks 758 je, South Korea, and was transported by the of deepwater ocean bottom node seismic and 759 at a water depth of 7,000 ft (2,134 m). Dockwise Vanguard from Korea to Corpus technology in the Gulf of Mexico, providing Chevron owns a 50% interest in the field while Christi, Texas, from February to April 2013. images of subsurface layers nearly 30,000 ft Maersk and Statoil hold 25% each. The topsides facilities were fabricated at the below the ocean floor. The St. Malo field lies in Walker Ridge block Kiewit yard in Ingleside, Texas, and mated Chevron deployed the ocean bottom nodes 678 at a water depth of 2,100 ft (640 m). Chevron to the hull in May. as part of its seismic survey program. Remotely is the operator with a 51% interest. Other part The assembled FPU was then towed out to operated vehicles positioned 100-pound receiv-
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28 Offshore December 2015 • www.offshore-mag.com
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TOP 5 PROJECTS
ers, or nodes, in a grid directly on the seafloor, which enabled survey crews to collect highquality seismic data without the distortion of the water column. The Jack/St. Malo fields are about 25 mi At each of the Jack/St. Malo fields, 1,100 (40 km) apart in about 7,000 ft (2,100 m) of nodes were placed on the seafl oor. The backwater, and were co-developed with subsea to-back surveys lasted 10 months, involving completions flowing back to a single host, 100 people and two ships. The surveys also semisubmersible floating production unit broke several records: number of nodes, the located between the fields. longest acquisition schedule, the deepest water and the largest source area. At low-permeability reser voirs like Jack and St. Malo, engineers often pump proppant into the reservoir to allow oil to flow more easily into the well. This process, called frac-packing, can be time- and cost-intensive because of the size of the producing rock formations. At Jack and St. Malo, some of these rocks are more than 1,000 ft thick (305 m), requiring large volumes of proppant to be pumped at high pressure. Typically, it can take five days to frac-pack yon block 19. The pipeline is the first large-diMcDermott International Inc. received each zone, but Chevron helped develop a ameter, ultra-deepwater pipeline in the Walker a contract to transport and install jumpers, new single-trip, multi-zone technology, which Ridge area of the Lower Tertiary trend. The subsea pump stations, and 30 mi (48.3 km) allowed it to stimulate multiple zones of the combination of extreme water depths, large of umbilicals and associated flying leads. reservoir in a single run of the equipment diameter, high-pressure design, and pipeline McDermott also performed the subsea downhole, cutting the time to 18 to 20 hours structures have set new milestones for the landing of some of the industry’s largest and per zone. With a cost of about $1.2 million/ Gulf of Mexico. most complex umbilical end terminations. day of rig time, improving completion time InterMoor designed and fabricated 11 resulted in major cost savings. suction piles for the Jack/St. Malo developOther key vendors At one well in the Jack field, Chevron Some of the other key vendors, suppliers, ment. The 11 suction piles are 18 ft (5 m) in stimulated a record-breaking six zones and and contractors on the Jack/St. Malo project diameter, ranging from 55 to 75 ft (17 to 23 pumped more than 2 million pounds of prop- are detailed below. m) in length and weighing up to 115 tons. pant in just a few days instead of the normal Wood Group Mustang performed front-end Bardex supplied the linear chain jacks for 30. Chevron also successfully tested the engineering design (FEED) and then detailed the 16-line mooring system that secures the technology in an open-hole well (a well that engineering design for the topsides facilities. Jack/St. Malo FPU on location. had not been cased and sealed) for the first KBR performed the detailed design engineerBMT Scientific Marine Services provided time in the industry. ing for the FPU’s hull, deck box, accommoda- an environmental and facilities monitoring Although the Jack and St. Malo reservoirs tions, appurtenances, equipment foundations, system that was installed on the FPU. The are currently high pressure, the pressure is ex- mooring system and anchor suction piles. system is designed to monitor, log, and dispected to decrease over time due to production. Wood Group also provided the plan- play in real time local environmental and fa A powerful pumping system was installed on ning, managing and field execution of the cility motions. the ocean floor to help boost the oil to the FPU. commissioning of the Jack/St. Malo FPU. MyCelx designed and delivered a produced Jack/St. Malo’s three subsea pumps are Work was perfor med by DSI, Wood Group water treatment system that removes oil and built to withstand 13,000 lbs/psi, are in- PSN’s commissioning services business. water soluble organics to below 10 ppm. stalled in 7,000 ft (2,134 m) of water; and OneSubsea, through one of its predecessor Saipem installed the 137-mi, 24-in. Jack/ consume three megawatts of power – a new companies, was awarded a subsea produc- St. Malo crude oil export pipeline using its industry record, representing a significant tion systems contract in 2010. The scope pipelay vessel Castorone; it was the first inimprovement over previous models. Prior included the delivery of 12 15,000-psi sub- stallation project for this newbuild vessel. to this project, industry maximums were at sea wellhead trees, production controls, JP Kenny performed the detail design work 5,000 psi pressure, 5,500 ft (1,524 m) water four manifolds and associated connection for the pipeline, which addressed routing of depth, and required 2.7 megawatts of power systems, engineering and project manage- the pipeline to minimize spans; design for prefor pumps of similar configuration. ment. In 2011, through another of its prede- and post-installation vortex-induced vibration With regard to the FPU, the Jack/St. cessor companies, OneSubsea was awarded and stress spans; collapse testing of the pipe; Malo platform is one the largest semisub- the subsea processing systems contract for and installation of in-line valves and sleds. mersible production platforms in the world, three pump stations, three subsea pump and is the first semisubmersible floating control modules, and associated control and Future plans production unit designed and built as a low- instrumentation equipment. Jack/St. Malo will act as a hub for 43 submotion unit for the Gulf of Mexico. Technip received a contract for the engi- sea wells, including pumps and other equipCrude oil from the FPU will be moved neering, fabrication, and subsea installation ment on the seafloor. Future developments through the Jack/St. Malo oil export pipeline, of more than 53 mi of 1.75-in. outer diameter for the Jack/St. Malo fields will likely include which runs approximately 137 mi from the flowlines, steel catenary risers, pipeline end an option for water injection; production exproduction hub in Walker Ridge block 718 to terminations, manifolds, pump stations and pansion; increased power generation; and the Shell Boxer A fixed platform at Green Can- tie-in skids. multi-phase seafloor pumps. � 30 Offshore December 2015 • www.offshore-mag.com
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TOP 5 PROJECTS
Spar platform proves successful for Anadarko once again
Innovative design for Lucius helps mitigate potential risks Sarah Parker Musarra
Editor
ollowing the September 2014 decommissioning of its one-ofa-kind cell spar, Red Hawk, in the Gulf of Mexico, Anadarko Petroleum Corp. wasted no time before it made yet another mark in the Gulf. Moored in more than 7,100 ft (2,164 m) of water, the Lucius spar is Anadarko’s biggest and most technically advanced to date, producing from multiple resource-ri ch fields. Located about 235 mi (378 km) off Port Fourchon, Louisiana and spanning Keathley Canyon blocks 874, 875, 918 and 919, Lucius was discovered in December 2009. An appraisal well, dri lled 3,200 ft (975 m) from the discovery well that encountered 200 ft (61 m) net of oil pay, was completed about 13 months later. Throughout Lucius’ lifecycle, the Anadarko-led consortium made several decisions that resulted in sizeable savings in both time and money. Also notable are the wild fluctuations in oil prices that have lasted through Lucius’ discovery, to first oil, and even present-day. According to historical data from the US Energy Information Administration, at the time of Lucius’ 2009 discovery, WTI had fallen to an average of $61.95/bbl from $99.67 in 2008 due to the US financial crisis occurring at that time. Prices began to climb between 2009 and 2013 before diving again just before first oil was produced in 2015. In December 2014, WTI fell to $59.29 from a high of $105.79 months earlier, in June. By the time Lucius produced first oil, the industry experienced panic as WTI settled at $47.22. To manage this price cycle and positively affect project economics, Anadarko signed an agreement in July 2012 with Inpex to enter into a joint-venture capital carry arrangement. Under its terms, Anadarko would be carried for the company’s share of the estimated
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32 Offshore December 2015 • www.offshore-mag.com
Part of Anadarko’s ‘design one, build two’ philosophy, the Lucius spar is the company’s biggest to date. (Images courtesy Anadarko Petroleum Corp.)
capital cost until first production: $556 million. This agreement allowed the company to mitigate the risks associated with a long-term megaproject, and limit its exposure to capital burden. Anadarko first successfully carried out the capital-carry model onshore, and the Lucius project marked the first time that the operator applied the concept offshore.
Project development In January 2010, at the time of appraisal drilling, Anadarko said that the up-dip side track was drilled about 20,600 ft (6,278 m) TD in water depths reaching about 7,100 ft (2,164 m). It encountered almost 600 ft net (183 m) of high-quality oil pay with additional gas-condensate pay in thick subsalt Pliocene and Miocene sands, confirming to the Houston-based company that it now had another major oil and gas discovery in its books. Resources for the development were estimated to be in excess of 300 MMboe. The project was sanctioned in December 2011. At that time, it was announced that Technip was constructing the Lucius truss spar at its Pori, Finland facility, marking the seventh spar constructed by Technip for Anadarko. The 605 ft (184 m) high spar has a hull weighing 23,000 tons (20,865 metric tons) and a topsides weighing 14,000 tons, with a nameplate capacity of more than 80,000 b/d and 450 MMcf/d (127 MMcm/d) of natural gas. It set sail from Pori for the Gulf of Mexico in April 2013. Matt Lamey, Anadarko’s facilities project manager for Lucius, said that Technip and Anadarko’s combined experience in the design and construction of spars minimized the challenges normally
TOP 5 PROJECTS
associated with scaling a design up to Lucius’ propor tions. “We have a really good relationship with Technip,” Lamey said. “Our history with them, and the people that we have here [in Anadarko] that are experienced in building spars made it a very smooth process to build this larger spar.” The spar’s size also allowed for a larger scope of production. “The topsides are about 14,000 tons (12,700 metric tons), [whereas] our other topsides were around 10,000 tons (9,071 metric tons),” Lamey explained. “That gives you an idea of the scale up that we have done there. The other thing is, the productive capacity is a bit above the prior spars that we’ve done. The volumes themselves are pretty significant and that required a bit bigger spar.” In keeping with the speedy development cycle maintained since discovery, Anadarko achieved first oil with Lucius on Jan. 16, 2015, about three years after sanction. Lamey said that the quick cycle from discovery to appraisal was astounding, especially given the size and remoteness of the project. “It is probably the fastest I’ve ever seen anywhere,” Lamey said. The full cycle time from discover y to our first production was five years. I think for a mega-project, where you’re talking several billion dollars, that’s pretty astounding, when most other projects of this size I see go for probably about twice that length of time.” Lucius has been operating steadily since first oil. “The project is going exceptionally well; we are producing right at capacity of the facility,” said Anadarko’s General Manager of the Lucius project Danny Hart. “We have had a run time of about 98% since we brought the project on. We were able to ramp the wells up initially and have been able to sustain right at capacity of the spar since that initial ramp up.”
The Lucius truss spar measures 605 ft (184 m) high, with the hull weighing 23,000 tons (20,865 metric tons). It has a nameplate capacity of more than 80,000 bo/d and 450 MMcf/d (127 MMcm/d) of natural gas.
Constructing the long export lines necessary for remote, deepwater projects can greatly impact a pr oject’s budget. Anadarko and the Lucius consortium chose Enterprise to handle the oil export line, and Lamey explained that the economics of the project were gre atly improved by re-utilizing the line.
Production hub
Design choice
One reason for the steady production are the development’s reservoirs, which Hart characterized as extremely prolific. The Lucius spar pulls from six wells, totaling approximately 80,000 b/d of oil. Hart said that the reservoirs were “some of the highest productivity indexes seen in the Gulf of Mexico.” The Lucius spar also produces for other neighboring fields. Shortly after sanction, Anadarko finalized a unitization agreement with ExxonMobil. Gas from Hadrian South, located in Keathley Can yon blocks 963 and 964, would be processed through the Lucius spar, which reduced the need for new infrastructure. On March 30, 2015, Hadrian South achieved first production, with daily gross volumes expected to reach around 300 MMcf/d (850 MMcm/d) of gas and 3,000 bbl of liquids from two wells. Hart said that Hadrian South contributes most of the current natural gas production of about 400 MMcf/d. Also in March, Anadarko signed a production-handling agreement with Chevron for its Buckskin/Moccasin discoveries, located in Keathley Canyon blocks 785, 872, and 736, through the Lucius spar as well. “Obviously, this is a very remote location…We tied up to South Hadrian right off the bat to help to offset some of the costs and to put a hub out there,” Hart said. “We’ve already signed other agreements to tie other fields back through the spar. That hub is providing another income, and the source is allowed to produce significant resources through the spar out in this remote area.” In another example of how Anadarko worked to save money against the bottom line is evident in Lucius’ infrastructure. A gas line that had served the now-decommissioned Red Hawk cell spar was repurposed into Lucius’ export pipeline. Lamey said that the decision was made prior to sanction while Anadarko was negotiating the oil and gas gathering agreements. “That is a unique use that we have not seen much in the Gulf of Mexico,” Lamey said, of the decision to re-utilize existing infrastructure by converting the gas line into oil service.
Both Lamey and Hart expressed that a spar was a natural design choice when installing in waters as deep as the waters at Lucius (7,000 ft). By design, Lamey said, the spar is more adaptable and therefore needed less bespoke design work. “It works very well in a variety of metocean conditions,” Lamey said. “It’s got a very low center of gravity and provides very good motion, even in elevated conditions of wind, wave, and current. It provides low impact to the steel risers… It gives you a good design life, with low impact, fatigue, and stress on all those elements that are connected to the spar that make it work.” A tension leg platform was immediately r uled out, due to the water depth. That left Anadarko and the Lucius consortium with the choice of a spar or a semisubmersible. One issue that factored into the decision was the amount of mooring points needed for that area of the Gulf of Mexico. “One of the things that made this spar so useful here is that you have a three-point mooring system,” Hart said. “The bathymetry of the ocean floor was very challenging. You have a three-point mooring system as opposed to semis, which would be a four-point mooring system. Finding three mooring points was [already] somewhat of a challenge, so the spar fit really well in this environment.” Lamey said it was a hallmark of Anadarko’s philosophy that the company would avoid re-inventing the wheel when it was unnecessary, and that is evident in the company’s “design one, build two” philosophy. The truss spar for the Heidelberg development, located in Green Canyon 859 and slated to enter production in 2Q 2016, will be based on the Lucius spar. Anadarko operates the Lucius spar with a 23.82% interest. Its partners are Freeport-McMoRan (25.123%); ExxonMobil (23.295%); Petrobras (11.500%); Inpex (7.753%); and Eni (8.500%). Eni (12.5%), ExxonMobil (9.375%) and Freeport-McMoran (12.5%) also partner with operator Anadarko (31.5%) on Heidelberg, along with Statoil (12%), Marubeni (12.74%), and Cobalt (9.375%). � www.offshore-mag.com • December 2015 Offshore 33
TOP 5 PROJECTS
Delta House FPS is a first of its kind Robin Dupre
Senior Technology Editor eralded as one of the most efficient production systems in the Gulf of Mexico, the Delta House development taps three Mississippi Canyon fields where the average water depth is around 4,500 ft (1,372 m) and reservoirs range from 12,000 to 18,500 ft (3,658 to 5,486 m). From fasttrack development to inking a significant deal to fund the host platform to being pri vately-owned, Delta House’s develo pment is a game changer in the deepwater sector of the oil and gas industry. When LLOG initially planned the development of the area, it knew that the Delta House FPS would serve as a host facility for future fields, with at least four fields tying into the platform. Designed for 25 years of continuous production, the facility initially called for seven wells to connect followed by seven additional wells as exploration activity continued. It is considered a water independent, semisubmersible floating production system (FPS) with a production handling capacity of 100,000 b/d of oil, 240 MMcf/d of gas, and 40,000 b/d of water. LLOG Exploration, both operator and par tial owner of the facility, commenced production in the second quarter of this year.
H
Fasttrack development LLOG had less than 36 months to drill wells in the Mississippi Can yon lease before it expired. The partnership was granted a “Suspensions of Operation,” which granted the consortium a one-time ‘presidential lease’ “Suspension of Operations” due to the drilling moratorium that was enacted because of the Macondo incident. This period gave the partners time to study the leases and then commence drilling. “We were very transparent in our presentations to the BSEE, and since then, we’ve done everything we said we were going to do,” said Mike Altobelli, LLOG vice president, land, in a Del ta House supplement, A New Hub in Mississippi Canyon . “It was a pretty dynamic time. I’ve never been involved in a project with that much going on in such a condensed period of time. The lease expiration dates were staring us in the face. We had to get out there and drill wells.” Once drilling started, two discoveries were made, allowing for development of the project to begin. With financing secured through an in vestment group and due to the financing terms in the contract, it paved the way for the project to be sanctioned sooner rather than later, cutting the development time of the entire project by around two years. The original plan for development called for at least three deep water wells, plus the infrastructure to connect them to the FPS. That plan grew to include seven wells during the star tup period for a total investment of $1.2 billion. Oil from Delta House flows through some 35 mi (56 km) of newly-constructed 12-in. pipe that connects to the Shell-operated Odyssey oil pipeline. Gas from Delta House is delivered through 31 mi (50 km) of new 16-in. line that links the FPS to the BP Pipelines-operated Destin Pipeline Co.’s 24-in. gas pipeline. While the second exploration well was being drilled on the Who Dat field, which is a part of the Delta House project, LLOG’s de velopment team was beginning to order the subsea infrastr ucture. Nine trees, along with the wellheads, casing and downhole systems were planned for its development long before it was needed in the field, according to the exploration company. The team was sure it could use the ordered equipment for Delta House, mainly because the company has standardized its wells, it said. Most of the company’s deepwater developments use the same horizontal trees, and 34 Offshore December 2015 • www.offshore-mag.com
Dockwise Treasure transported
the hull from South Korea to Texas. (Photo courtesy LLOG Exploration)
any that were not needed for Delta House could be used for other developments. The company also has standardized its subsea manifolds, LLOG added, so if the development calls for more than four wells, a second manifold can be bolted to the first. By the end of 2014, six of the proposed 14 Delta House wells had been drilled. Of the first six wells, two were drilled by the Ensco 8502 in 2012-2013, and two were drilled by the Noble Amos Runner in 20112012. The Ensco 8503 drilled the sixth well in late 2014, followed by the initial two subsea completions for the field. The Sevan Louisiana then drilled wells 7, 8 and 9 in 2015, followed by Seadrill’s West Neptune that completed the remaining wells in the field.
Contracts As for the Delta House FPS, it is designed and customized to LLOG specifications, in a first in what the company envisioned as a series of floating production systems all with the same basic Delta House plan. The four-column semisubmersible floating production system, based on Exmar’s Opti-Ex hull design is similar to LLOG’s successful Who Dat platform but 40% larger. The hull is optimized to increase the amount of payload it can carry relative to the weight of the steel in its hull. Consider ed lighter and more buoyant than most conventional four-column hulls, due to the columns being square on the other corners where structural loads are the greatest, saves steel, the company added. With the risers attaching to the FPS, it provides another weight saving feature. “The way the hull is designed, we swap off risers for ballast,” said Craig Mullet, project manager for the hull and topsides. “If we tension the risers at the top of the hull, we sacrifice weight capacity. By fastening our risers to the bottom of the hull instead, we save the weight.” Delta House’s opti-11,000, situated on the Who Dat field in Mississippi Canyon block 547, is suitable for water depths from 1,500 to 10,000 ft (457 to 3,048 m). By October 2014, the FPS was moored. Once ballasted down to working depth, the underside of the main deck was 72 ft (22 m) above the water line, with 98 ft (30 m) of the hull below the waves. Production commenced shortly after. �
TOP 5 PROJECTS
Subsea compression prolongs gas production at Åsgard offshore Norway Jeremy Beckman n mid-September, the world’s first subton power/control module for installation on Editor–Europe sea compression station began operating the vessel, with ABB providing the associat the Åsgard production complex in the ated drives and transformer (the total installed Norwegian Sea. The technology is depower system, according to analyst ScanBoss, signed to boost pressure at the Midgard is around 25 MW), and Apply Sørco performand Mikkel fields that export gas and coning the topsides modifications. Each of the densate to the Åsgard B semisubmersible trains is supplied with power via an umbilical, processing platform nearly 40 km (25 mi) manufactured by Nexans, with Deutsch, Exaway. In the process, Statoil expects to extend pro and GE providing the high-voltage subsea the fields’ lives out to 2032, thereby extractconnectors and Schneider Electric the subsea ing a further 306 MMboe of production. control power distribution unit. MPM manu According to a paper presented by Statoil’s factured the subsea wet gas meters. Simon Davies and Rune Mode Ramberg at Well stream from the three Midgard subsea DOT in Houston in October, the industry templates, one of which also receives Mikkel’s began working on developing subsea comproduction, enters the compression station via pression technology in the late 1980s. Gas a 900-ton manifold. This arrangement necessiproduction through Åsgard B started in late tated reconfiguration offshore of the flowlines 2000, although Statoil and its partners were between the two fields: Technip handled this aware from the outset that compression would assignment, also installing the umbilicals and be needed at some point to counter declining power cables. In 2013, Technip’s subsea conpressure at Midgard and Mikkel. Lack of availstruction vessel North Sea Giant installed 12 able space on Åsgard B meant the only alterpipeline end manifolds and a riser base, both native would have been adding a much cost- Artist’s impression of the Midgard/Mikkel subfabricated by Rosenborg Worley Parsons. lier, dedicated compression platform. In July the same year, Saipem’s crane sea compression train. (Image courtesy Work on qualifying the components need- Aker Solutions) barge installed the 1,800-ton compressor staed for subsea compression started in 2005, tion template and manifold station, both built and during 2007-13, Statoil and its team of ter. Each train would comprise a scrubber, by Aker in Egersund, at the Midgard location, equipment suppliers implemented a program a condensate pump, and a compressor with and also the topsides power/control module. for testing and qualifying nearly 50 compo- an inlet and outlet cooler. The focus was on a The 20 modules for the compressor station nents divided into three main categories: compact design, with motor and compressor underwent a system integration test at Egerprocess modules, power system and control housed in the same casing, and with cooling sund in mid-2014 and were installed offshore system. Testing of the prototype compressor of the motor achieved using the process gas. by North Sea Giant during April to September began at Statoil’s K-lab facility near StavanMAN Diesel and Turbo, also involved in this year. The vessel performed nine trips to ger in 2008 with a series of endurance trials, the qualification program, designed and man- install all 20 modules, most including installasome with different quantities of liquids. Be- ufactured the HOFIM motor-compressors tion of one large module such as a comprestween 2008 and 2013 the compressor and mo- for integration into the compression station sor, scrubber or outlet cooler. These were tor rating was increased from 8 MW to 11.5 provided by the main equipment contrac- lowered over the side of the vessel using a MW, with verification testing conducted of tor Aker Solutions. The four HOFIM units, specially designed handling system, which the 11.5-MW compressor design from 2012. adapted for harsh subsea conditions, are included a 420-metric ton (463-ton) crane and During 2011-13, K-lab was upgraded to in- hermetically sealed and remotely controlled, guide frame equipment, to allow installation clude a shallow-water test pit for testing of a with casings designed to withstand 220 bar through the splash zone in significant wave complete compressor module, with one of (3,191 psi) pressure, and a 7-axes active heights of up to 4.5 m (14.7 ft). the compressor units undergoing successful magnetic bearing system integrated inside Each complete train, weighing 1,500 tons submerged testing in 2014. Further tests were the casings to prevent gas leakage. Accord- in total, is secured to a 400-ton base frame. In performed at the facility on the motor and top- ing SKF, supplier of the magnetic bearings, 2013, Allseas’ Lorelay laid the new 37-km (23side variable-speed drive using a cable simula- these are designed to simplify the system by mi), 20-in. pipeline that runs from the comtor to confirm electrical stability over the long removing the need for components such as pression station to the Åsgard B gas platform. step-out for a range of operating conditions. lubricating oil, seals and gearbox. In addi- One of the existing Midgard/Mikkel export In March 2012, Statoil and partners Eni, tion, the bearings are friction-less, leading to pipelines has been retained – this is conExxonMobil, Petoro, and Statoil got the go- higher rotation speeds, which in turn allows nected to another line from the compression ahead from Norway’s Parliament to proceed use of smaller compressor modules. station via a hot tap connection, performed by with the full-scale development, which would Power for the subsea station is supplied Technip’s Skandi Arctic vessel. involve installation of a two-train subsea from the Åsgard A production ship. Under a Statoil estimates the overall project cost compression station in 300 m (984 ft) of wa- separate contract, Aker Solutions built a 900- at just over NOK19 billion ($2.19 billion). �
I
www.offshore-mag.com • December 2015 Offshore 35
TOP 5 PROJECTS
Perla marks first gas field to enter production off Venezuela
C
Jessica Tippee
Assistant Editor
ardón IV S.A., a 50/50 joint operating neering and Construction Group for pre-front- construction of the equipment and materials company between Repsol and Eni, end engineering and design and FEED for at module and jacket fabrication yards, and started production from the Perla the field’s production facilities: offshore struc- for site installation. gas field in the Gulf of Venezuela in tures, trees, controls, offshore processing, Valerus won an engineering, procurement, July 2015. Located in the Cardón IV subsea flowlines, export pipelines, the shore and construction contract for the natural gas block 50 km (31 mi) offshore in 60 m (197 approach and utilities facilities from the well- conditioning and condensate stabilization faft) water depth, Perla is estimated to hold up heads to an onshore gas plant, and tie-in to an cility. The company performed the process to 17 tcf of gas in place, or 3.1 Bboe. Accord- existing gas and condensate pipeline system. design and fabricated the process equipment. ing to Repsol, this is the largest gas discov As part of FEED in April 2011, Trident Construction of the facility was executed by ery in the company’s history and the largest Risk Management was hired for reliability, Consorcio La Perla, a consortium between offshore gas field in Latin America. Eni says availability, and maintainability analysis; a Valerus Venezuela and Lindsay Venezuela. Perla is the first gas field to be brought to marine vessel collision risk assessment; an The Minister of Petroleum and Mines of production offshore Venezuela. infield flowline risk assessment; and layers Venezuela and President of PDVSA Rafael Discovered in 2009, the Perla 1X well encoun- of protection analysis for offshore and on- Ramírez, Eni’s CEO Claudio Descalzi, and tered a 240-m (775-ft) hydrocarbon column. shore facilities. Repsol’s President Antonio Brufau signed During production testing, it produced high In April 2013, Saipem was commissioned strategic agreements in June 2014. The first quality gas with a capacity of 600,000 cu m/d to transport and install a hub platform and agreement is a memorandum of understand(approximately 3,700 boe/d) and 500 b/d of two satellite platforms; a 67-km (41.6-mi), 30- ing to create a new company (mixed entercondensate. Perla 2, drilled in 60 m (198 ft) in. offshore export pipeline; two 14-in. clad prise) to develop and produce Perla’s conof water, found 260 m (840 ft) of net pay in infield flowlines and other infie ld cables; and densate reserves. a carbonate sequence with good reservoir related tie-in operations. Most of the work The new company will be jointly run by characteristics. During production testing it was performed by the Saipem 3000 and Cas- CVP (PDVSA’s affiliate) with 60%, Eni with flowed 50 MMcf/d plus 1,500 b/d of conden- toro 7 vessels between 3Q 2013 and 2Q 2014. 20%, and Repsol with 20%. The second agreesate. Perla 3, drilled in 70 m (230 ft) of water, Seadrill received a $222-million contract ment establishes the key elements for up to encountered 210 m (675 ft) of net pay carbon- for the LT-Super 116E jackup drilling rig West $1 billion investment structure to finance ate sequence with the same hydraulic regime Freedom in July 2013. The 30-month charter CVP’s share in the Perla development. Eni as the discovery well and with excellent res- began in late September 2013. At first produc- and Repsol will contribute with up to $500 ervoir characteristics. The well flowed 68 tion, seven of the 26 planned wells had been million each. Both agreements are subject MMcf/d of gas and 1,350 b/d of condensate drilled. to final contracts being signed and approved during the production test. According to Eni, Foster Wheeler was contracted to provide by local authorities. the third shallow-water well confirms Perla as project management for the new producPDVSA exercised its 35% back-in right, “a world-class supergiant gas discovery, one tion facilities in August 2013. The company and, after the signature of a sale and purof the most significant in recent years, and supervised the engineering, procurement, chase agreement, it will get its ownership the largest ever in Venezuela.” The Perla 4 ap- and construction contractors, and the pro- stake in Cardón IV S.A., which will be jointly praisal well flowed 17 MMcf/d of gas and 560 curement of long-lead equipment, from operated. Eni and Repsol will each keep a b/d of condensate during the production test. engineering centers in Houston, Madrid, 32.5% interest. The three-phase development involves four London, and Rijeka, Croatia. According to In April 2015, Seaway Heavy Lifting was relatively light platforms connected to 26 wells, Foster Wheeler, contractors in more than 15 contracted to transport and install the gas with gas exported through a 30-in. subsea pipe- countries were involved in fabrication and production platforms and tie-in to various line to a new two-train central processing fainter-field pipelines that were already cility onshore at Punto Fijo. The first phase installed. The crane vessel Stanislav Yu- is estimated to cost $1.5 billion. din executed the lifting and installation The project was officially sanctioned work, and was outfitted with a saturation in December 2011 when Eni and Repsol dive system to perform the tie-ins. The signed the gas sales agreement with Vencompany handled project management ezuelan national oil company Petróleos and engineering from the Netherlands de Venezuela SA (PDVSA) and the Minisand its new project office in The Woodter of Petroleum and Mines of Venezuela. lands, Texas. By the end of 2015, Repsol expects gas Perla is part of the Rafael Urdaneta gas production to increase to 450 MMcf/d. project, which spans about 30,000 sq km Production should reach 1.2 bcf/d in (11,580 sq mi). It consists of 29 blocks: 18 2020. PDVSA has contracted the gas for in the Gulf of Venezuela and 11 in northall three phases until 2036. east Falcon state. According to PDVSA, In October 2010, Cardón IV S.A. con- The Perla gas field is in the Cardón IV block 50 km (31 mi) the project aims to meet the domestic tracted Foster Wheeler AG’s Global Engi- offshore. (Map courtesy Repsol) market’s demand for natural gas. � 36 Offshore December 2015 • www.offshore-mag.com
MIDDLE EAST AND NORTH AFRICA
National interest projects sustain Middle East’s offshore rig count Dr. Rina Samsudin
IHS
Marketed and contracted offshore rigs by region (October 23, 2015) US Gulf of Mexico
gainst a backdrop of low oil prices and spending cutbacks in the upstream E&P industry, the Middle East is the only ma jor region in the world yet to register sizeable decreases in the number of offshore drilling rigs (jackups, semisubmersibles, and drillships) holding current or future contracts. The number of contracted rigs – typically jackups in this part of the world – stood at over 130 as of late October, only slightly lower compared to a year ago. In comparison, the contracted fleet in other key regions such as Southeast Asia, West Africa, and the US Gulf of Mexico shrank significantly, between 20% and 40%. The global average was a net 20% decrease, with the number of contracted units dropping from around 730 to less than 600 between October 2014 and October 2015. Why has the Middle East’s contracted rig count managed to hold steady when contracted numbers have wavered elsewhere? In this region of high levels of state participation in the oil and gas industry, countries such as Saudi Arabia, Iran and the United Arab Emirates (UAE) are largely maintaining – or even increasing – their working rig populations to ensure that projects or goals of national interest are met. These plans are facilitated by lower development costs compared to those in areas such as offshore northwest Europe and West Africa. Saudi Aramco – with over 45 jackups under contract – is the top employer of offshore drilling rigs in the Middle East and the second worldwide, after Petrobras. When oil prices plummeted during the 2008/2009 global financial crisis, the national oil company (NOC) chose to scale down its operated rig fleet. However, in the subsequent years, Saudi Aramco ramped up offshore activity again and effectively doubled its rig count between 2011 and 2014. Despite the current environment of low oil prices (with OPEC deciding to maintain production levels) and pressure to reduce spending, it is understood that Saudi Aramco is not planning to significantly downsize its fleet of jackups, as it did in 2008/2009. Rather, in this buyer’s market, the influential NOC is using its bargaining power to negotiate day rate discounts in old and new contracts, not only for drilling rigs but for other services also. Saudi Aramco renegotiated a good number of jackup contracts earlier this year and renewed most that were expiring. Iran, the second biggest jackup market in the Middle East, has managed to secure drilling rigs over the years in the face of sanctions that have prevented many foreign operators, service providers, and other companies from engaging in business with the country. It is estimated that more than 25 jackups are currently operating in the Iranian sector of the Persian Gulf, compared to 10 or so a decade ago. In spite of sanctions, Iran has been able to buy and/or lease jackups from abroad; many of these rigs have been deployed to work on the giant South Pars gas development, from which production is being brought onstream in phases. The republic’s economic activity and government revenues are heavily dependent on petroleum revenues, yet weaker crude prices seem to have hardly made a dent in Iran’s offshore rig count. It is thought that many of the rigs deployed off Iran are operating under relatively long contracts for critical development projects that will carry on nonetheless. In the coming years, Iranian demand for offshore drilling
A
This Week
Last Week
Last Month
Last Year
Total Supply
118
117
118
116
Marketed Supply
72
73
75
89
Marketed Contracted
55
54
54
72
76.4
74.0
72.0
80.9
Marketed Utilization (%) South America
This Week
Last Week
Last Month
Last Year
Total Supply
68
68
69
78
Marketed Supply
64
64
65
74
Marketed Contracted
58
58
59
74
Marketed Utilization (%)
90.6
90.6
90.8
100.0
This Week
Last Week
Last Month
Last Year
Total Supply
103
103
103
98
Marketed Supply
96
96
96
96
Marketed Contracted
79
79
79
93
Northwest Europe
Marketed Utilization (%)
82.3
82.3
82.3
96.9
West Africa
This Week
Last Week
Last Month
Last Year
Total Supply
74
74
74
88
Marketed Supply
69
69
69
79
Marketed Contracted
48
48
49
69
69.6
69.6
71.0
87.3
Middle East
This Week
Last Week
Last Month
Last Year
Total Supply
159
159
161
151
Marketed Supply
153
153
155
146
Marketed Utilization (%)
Marketed Contracted
132
133
136
135
Marketed Utilization (%)
86.3
86.9
87.7
92.5
This Week
Last Week
Last Month
Last Year
Total Supply
96
97
98
102
Marketed Supply
88
88
90
92
Southeast Asia
Marketed Contracted
50
50
53
80
56.8
56.8
58.9
87.0
This Week
Last Week
Last Month
Last Year
Total Supply
849
851
852
863
Marketed Supply
755
759
764
798
Marketed Contracted
595
598
606
732
Marketed Utilization (%)
78.8
78.8
79.3
91.7
Marketed Utilization (%) Worldwide
Source: IHS
rigs has the potential to grow by some significant degree with the anticipated lifting of sanctions. The country has already begun discussions with external parties regarding future development projects. Meanwhile, the UAE is arguably the top growth area in the Middle East this year. The National Drilling Co. (NDC) of the Emirate of Abu Dhabi has said that its (land and offshore) rig count is not likely to be dampened by low oil prices as the UAE strives to meet its production target of 3.5 MMb/d by 2017/2018 and be able to sustain these levels. Abu Dhabi is to invest in some $2.5 billion in offshore drilling activities as part of the investment plans and the www.offshore-mag.com • December 2015 Offshore 37
MIDDLE EAST AND NORTH AFRICA
Working demand for jackups in the Middle East: Top 5 Countries.
Abu Dhabi National Oil Co. (ADNOC) plans to drill around 160 wells per year in the next couple of years. Earlier this year, NDC chartered eight additional jackups on behalf of operators in Abu Dhabi. Two of the rigs were already based in the region while the remaining six were mobilized from abroad. Most of these new contracts commenced during the second half of the year. Compared to other parts of the world, especially given the current circumstances, the hiring of eight incremental off-
shore rigs in one sweep by a single country is impressive, particularly considering the backlog of work that these units have been hired for: over 20 years firm plus potentially more than 10 years in the form of options. Moreover, Abu Dhabi’s jackup fleet is set to expand further. The emirate has three LeTourneau Super 116E Class units under construction at the Lamprell yard in the Emirate of Sharjah. These are scheduled to be delivered in 2016/2017. Elsewhere in the Middle East, working
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rig numbers have come down. In Qatar, the rig count rose from 2013 to 2014, but the market is experiencing some softness during the second half of 2015 as rigs become idle. In the offshore Neutral Zone, a joint development area between Saudi Arabia and Kuwait, production has been shut down as a result of disagreements between the parties involved and the jackup count there has dropped from four to two units. As for Oman, no rigs have been deployed offshore since early 2014 following a brief spurt of e xploration/workover activity. On aggregate, working jackup levels in the Middle East this year are expected to remain relatively flat compared to last year as growth in the UAE is anticipated to balance out declines elsewhere. Jackup day rates, though, have come down significantly as competition intensifies in an oversupplied market. For the time being, the Middle East’s top jackup operators – namely the NOCs – are anticipated to have enough work in the pipeline to maintain existing working levels for the next year or two. In the most optimistic scenario, rig demand in the region may even increase, if various planned exploratory drilling programs by some of the region’s smaller/ newer players go ahead. �
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MIDDLE EAST AND NORTH AFRICA
Mellitah details plans to unlock dormant discoveries offshore Libya Program starts with expansion of Bahr Essalam Jeremy Beckman
Editor–Europe
O
ver the next seven years, Mellitah Oil & Gas is looking to develop three Libyan offshore oil, condensate, and gas discoveries. Total costs will likely exceed $7 billion, according to Khalifa Daw Musa, general manager of geosciences and reservoir engineering. Musa, speaking at the recent 4 th New Libya Oil & Gas Forum hosted by IRN in London, said the three fields were designated the A, C, and E structures. “C” is actually a second-phase development of the producing Bahr Essalam field in concession NC41, 110 km (68.4 mi) offshore in around 200 m (656 ft) of water. Bahr Essalam comprises a 50-km (31-mi) long and 4-km (2.5-mi) wide series of anticlines. Mellitah – a joint venture between the Libyan National Oil Company (NOC) and Eni – has subdivided the field into the Western, Central A, Central B, and Eastern areas, with varying Proposed E structure development offshore Libya. (Schematic courtesy internal pressures, fluid contacts, and fluid properties. The western Mellitah Oil & Gas) parts are more heavily faulted. The reservoir is mainly gas condensate, with a small oil rim beneath the gas zone in the Central B and (8.7 mi) long and 3 km (1.87 mi) wide. To date, four wells have been Eastern areas, respectively 80 ft (24 m) and 35 ft (10.7 m) thick. drilled and tested, encountering hydrocarbons in Metlaoui formation Phase 1 production comes from the 15 wells in the Central B area, carbonates, with a large gas cap and a 96-ft (29-m) column of 39°API drilled from the Sabratha platform, and from two subsea clusters of wells oil. Estimated reserves are 671 bcf of gas, 32.2 MMbbl of condensate, (11 in total) on the Western part. The current Phase II development is and 5.9 MMbbl of oil. All four wells will feature in the development targeting a further 1,185 tcf of gas, 51 MMbbl of condensate and 188 – Mellitah plans to drill another eight, Musa said, comprising seven MMbbl of oil via two more subsea clusters (10 wells in total) on C-East; platform wells and one subsea. The proposed $1.49-billion project, detwo wells in the Central A area; and another on the Central B area. signed to deliver 160 MMcf/d of gas, could start up in spring 2021. Drilling was due to start before year-end, Musa said, and the proDeepwater potential gram should take around 720 days to complete, with Phase II set to come onstream during summer 2017. The total drilling and completion BP is the second largest IOC operating in North Africa, said Jasper budget is $772 million, while the full cost of the Phase II project is esti- Peijis, VP exploration, Africa at the same conference. Its exploration mated at $2 billion. acreage in Libya includes the 30,000-sq km (11,583-sq mi) Area C in To the east of Bahr Essalam is the E structure, a rounded, flat anticline the offshore Sirte basin in water depths up to 2,000 m (6,561 ft). This with two culminations separated by a saddle. The field is 126 km (78.3 mi) is north of Hess’ 2009 reportedly commercial deepwater Arous Al Baoffshore in water depths of 205-235 m (672-771 ft) and extends into the adhar discovery. BP has identified three plays – carbonate flank, basinal jacent NC35 concession. Since the initial discovery in 1977 on the northern clastics and marginal clastics – and sees analogies with Eni’s recent part of the structure, five appraisal wells have been drilled. Hydrocarbons mammoth Zohr gas find to the east in the deepwater Egyptian sector. are present in the Metlaoui carbonates formation, and comprise a thick The company has acquired 17,000 sq km (6,564 sq mi) of 3D gas-condensate column and a thin oil column. Reserves are estimated at seismic over the central and eastern part of Area C, and was only 1,838 tcf of gas, 65.5 MMbbl of condensate, and 82 MMbbl of oil. months away from spudding its first exploration well before growing Mellitah plans to install a platform in the central part of the str ucture instability in Libya forced it to declare Force Majeure in February housing 15 gas and five oil wells, with two subsea wells in the western 2011. Fifteen months later, BP lifted Force Majeure, only to re-depart exporting gas to the platform via a 16.3-km (10-mi), 8-in. pipeline clare it in August 2014 as Libya’s situation deteriorated further. and another cluster of four subsea wells in the north exporting gas to Peijis said BP is waiting for the moment to begin safely executing the same facility via two parallel 7.5-km (4.67-mi) pipelines. All gas, oil, its offshore drilling program, starting with a long-planned well on the and condensate produced at the platform will be expor ted via two paral- Trelia prospect in the Carbonate Flank play. However, even if proposlel 126.2-km (78.4-mi) pipelines to an onshore plant (32-in. diameter for als for forming a new unity government succeed, certain issues still gas, 14-in. for oil and condensate). The $3.62-billion project is currently have to be addressed before operations can start offshore, Peijis said. slated to start up in spring 2022, initially producing 600 MMcf/d of gas. One is the need to implement procedures to deal with any resultant The A structure is southwest of Bahr Essalam, 75 km (46.6 mi) oil spills; another is the safety risk posed by boats carrying refugees offshore in 125 m (410 ft) of water. This is a faulted anticline, 14 km passing close to areas of offshore activity. � www.offshore-mag.com • December 2015 Offshore 39
GEOLOGY & GEOPHYSICS
Somalia, East Black Sea opening up for exploration
Jeremy Beckman
Editor–Europe
F
rontier seismic surveys were due to start this fall offshore Somalia and in the eastern Black Sea. For different reasons, the industry has largely shunned both regions over the past two decades, but new developments are altering per ceptions. Spectrum Geo is directing both operations. The company has an agreement with the federal government in Somalia to acquire around 28,000 km (17,398 mi) of new 2D data in the Indian Ocean off the southern half of the country in water depths of 30 m -4,000 m (98-13,123 ft). This is designed to complement and infill a survey acquired last year closer to the shore off the same coastline. Part of the contract area includes an offshore concession assigned to Shell and Exxon in 1988. The new data will provide the first in-depth view of the country’s offshore prospectivity, which is attracting new interest following the recent discoveries along the East African Margin, including BG’s Sunbird oil find offshore neighboring Kenya. Streamer lengths of 10,050 m (32,972 ft) will be used in the current campaign to record information at all offsets, assisting imaging of the underlying syn-rift geometries. Spectrum will then apply modern processing algorithms to optimize imaging of known steeply dipping extensional and compressional features and to highlight amplitude anomalies. On completion, the company will have sole marketing rights for the dataset, which will provide coverage over the shelf, slope and basin floor. Somalia is known to have three main oil-producing basins: the Permo-Triassic, Jurassic, and Cretaceous. Various international oil companies explored intermittently onshore Somalia before withdrawing as security deteriorated. According to Abdulkadir Abikar Hussein, the geological survey head at the Ministry of Petroleum and Mineral Resources – speaking at a recent Spectrum seminar in London – much of the country is know to have sediments 3-5 km (1.86-3.1 mi) thick, but historically, the wells drilled were too far apart. Following the installation of the federal gover nment, stability has improved, leading to the renewed interest from the oil and gas sector. The Ministry itself was created in 2 011 and has been working on a legal and regulatory framework to finalize terms for a competitive production-sharing agreement linked to a future bid round, which could be staged in 2018. Spectrum’s data will be available for this round, as will old legacy data, much of which CGG is managing and marketing on the Ministry’s behalf. For security reasons the Ministry is ignoring onshore Somalia for the time being, Hussein said. “We need to first focus on the Indian Ocean, followed by a Gulf of Aden bid round in the north – if we can reach a settlement with the northern separatists.” Once the new framework and datasets are in place, he added, “we can show that Somalia means business, that the country has come back to the international community and that it is ready for really serious oil and gas exploration.”
Black Sea oil quest Spectrum’s other frontier sur vey should be under way in the East Black Sea basin. Although the basin is similar in size to the Gulf of Mexico, only three exploration wells have been drilled to date, and there are large areas of open acreage with only sparse modern data coverage. However, the Maykop formation in the Black Sea area is a proven source rock that has also generated large oilfields to the east in the Caspian Sea. 40 Offshore December 2015 • www.offshore-mag.com
The area offshore southern Somalia covered by the latest 2D survey. (Map courtesy Spectrum Geo)
In total, the current survey will acquire 14,000 km (8,700 mi) of long offset 2D data in a 10 x 10 grid over the southeastern part of the sea using 12,000-m (39,370-ft) long streamers, with broadband processing. Acquisition should finish during 1Q 2016, with the first processed prestack time migration (PSTM) data set to be released a few months later. Recent spectacular drilling results in the Romanian sector suggest the west side of the Black Sea is largely gas-prone, especially in deep water Palaeo-Danube plays, said Dr. Neil Hodgson, Spectrum Geo’s executive VP Multi-client, Mediterranean and Middle East. “However, we believe the east will be oil-prone. The region is the location for a past collision between two thrust zones, the Greater Caucasus North and the Lesser Caucasus systems.” This part of the Black Sea has very little existing multi-client seismic data to draw on for establishing hydrocarbon plays. Spectrum has therefore scanned and vectorized Russian academic data from the 1980s to build a basic overview, although not of the quality needed “to chase the play,” Hodgson said. “This was a rift basin opened in the early Cretaceous, subsequently infilled by clastics thought to have stemmed from the Georgian delta system. That created a set of understandings of the basin that we aim to challenge with our new data set.” Typical perceptions are of poor-quality reservoir, based on overpressure encountered by the few wells drilled (two of which drilled through targeted Tertiary clastics). The East Black Sea basin was once part of a giant inland sea system that extended to the Caspian Sea, Hodsgon continued. Satellite images have revealed oil seeps, some originating from Georgia, confirmed as thermogenic by subsequent sampling. “We also took our own satellite images and spotted more seeps on the margins of the basin just offshore Turkey and on the maritime border between Turkey and Georgia.” These seeps show that oil is sloshing and trying to find a reser voir to migrate to, he suggested. TPAO, the Turkish state oil company, has also mapped from its data sands coming from western Georgia’s Rioni River Delta in the east to the Pliocene in deepwater, he added. �
DRILLING & COMPLETION
New fracturing tool improves extended-reach drilling efficiency Bruce Robertson • Euan Murdoch
Weatherford ith thousands of feet of seawater between surface and wellbore, harsh and unpredictable environments, and difficult-to-access equipment placed far below the seabed, offshore reservoirs magnify the typical challenges associated with well completions. Extreme environments demand lower-completion technologies that mitigate risks, lower costs, and save rig time. Lower-completion interventions that require tripping thousands of feet in and out of wells mid-operation can incur at least $1 million per intervention and significant delays. These complex operating conditions combined with the current economic climate leave no margin for error. In extended-reach applications, conventional proppant stimulation allows little to no flexibility in the event of unplanned scenarios, such as premature screen-outs or poor injection into zones. In these circumstances, additional milling runs are required to continue operations, and conversion to a less efficient completion technique may be necessary. This significantly increases nonproductive time between fracture cycles and the associated costs. To address these concerns, operators have long sought lower-completion technology that reduces intervention during stimulation, avoids time-consuming mill-outs, minimizes exposure to abnormally stressed formations, and provides contingencies for unanticipated events. Weatherford recently introduced the AutoFrac system as an effective option for stimulating the open-hole section to the completion toe in extended-reach wells. The system operates lower-completion tools remotely to minimize intervention and milling requirements and costs, and it reduces time between fracture cycles. The system can be fully customized for specific well conditions. The new system provides several options for tool communication without reliance on control lines or mechanical actuation: ra-
W
Setting depth and run-in order for each AutoFrac tool. Zone 1 2 3 4 5 6 7
AutoFrac tool
Setting depth
AutoStim Valve 1
20,764 ft (6,329 m)
ARID Sleeve 1
20,689 ft (6,306 m)
dio frequency identification device (RFID) technology, frequencymodulated pressure pulses, ACTiFRAC pressure pulses, timers, or a combination of these options. RFID actuation involves dropping preprogrammed electronic tags downhole. As the tags pass by the tools, they transmit commands to built-in tool antennae, and the tools respond by opening or closing. When it is not possible to drop RFID tags downhole, a sequence of pressure cycles can actuate tools. ACTiFRAC pulses adopt algorithms within the tool software that enable the recognition of pressure pulses in circulation mode, which enhances flexibility. For operational updates, the Weatherford downhole i-Rabbit system (DRS) is a memory logging tool that retrieves temperature and pressure data and that provides valuable information regarding the status of tools in situ. The new system incorporates one or more of the following tools: the advanced reservoir isolation device (ARID) stimulation sleeve, the AutoStim flapper valve, and the reser voir isolation valve (RIV). The ARID sleeve isolates the tubing from the open hole and provides on-demand
Operational summary of commands delivered to each tool and the actions taken. AutoFrac tool
Commands
Action
AutoStim Valve 1
RFID tag
Closed during installation
ARID Sleeve 1
3-minute pressure pulse
Opened
AutoStim Valve 2
ARID Sleeve 2
AutoStim Valve 3 ARID Sleeve 3 AutoStim Valve 4
ARID Sleeve 4
3-minute pressure pulse
Switched to RFID mode
RFID tag
Closed for pressure test
ACTiFRAC Pulse
Re-opened
3-minute pressure pulse
Switch to RFID mode
RFID tag
Switch to pressure-pulse mode
3-minute pressure pulse
Opened
RFID tag
Close for pressure test
ACTiFRAC Pulse
Re-opened
5-minute pressure pulse
Opened
5-minute pressure pulse
Switch to RFID mode
RFID tag
Closed for pressure test
ACTiFRAC Pulse
Re-opened
5-minute pressure pulse
Switch to RFID mode
RFID Tag
Switch to pressure-pulse mode
3-minute pressure pulse
Failed to open
5-minute pressure pulse
Switch to RFID mode
RFID tag
Closed
AutoStim Valve 2
20,148 ft (6,141 m)
ARID Sleeve 2
20,089 ft (6,123 m)
AutoStim Valve 3
19,547 ft (5,958 m)
ARID Sleeve 3
19,485 ft (5,939 m)
ARID Sleeve 5
7-minute pressure pulse
Opened
AutoStim Valve 4
18,944 ft (5,774 m)
AutoStim Valve 6
7-minute pressure pulse
Switch to RFID mode
ARID Sleeve 4
18,885 ft (5,756 m)
7-minute pressure pulse
Switch to RFID mode
AutoStim Valve 5
18,340 ft (5,590 m)
RFID tag
Switch to pressure-pulse mode
ARID Sleeve 5
18,274 ft (5,570 m)
3-minute pressure pulse
Opened
AutoStim Valve 6
17,257 ft (5,260 m)
7-minute pressure pulse
Switch to RFID mode
ARID Sleeve 6
17,198 ft (5,242 m)
AutoStim Valve 7
16,765 ft (5,110 m)
ARID Sleeve 7
16,706 ft (5,092 m)
AutoStim Valve 5
ARID Sleeve 6 AutoStim Valve 7 ARID Sleeve 7
7-minute pressure pulse
Switch to RFID mode
RFID tag
Switch to pressure-pulse mode
3-minute pressure pulse
Opened
www.offshore-mag.com • December 2015 Offshore 41
DRILLING & COMPLETION
reservoir access. Upon remote actuation, the sleeve autonomously shifts its ports into the open position for proppant fracturing. Depending on specific well needs, operators can use either AutoStim flapper valves or reservoir isolation valves to isolate previously fractured zones and to divert stimulation fluids through open ARID sleeves in the next inter val. The valves close and open, on command, when actuated. The flapper valve, which enables unidirectional flow of stimulation fluids, holds pressures from above up to 10,700 psi (73.8 MPa). The RIV uses the same design as the flapper valve, but also includes a mechanical locking mechanism that enables the RIV to hold differential pressures from both above and below. With this added functionality, the RIV is typically used at the toe of the well and provides an ISO 28781 V1 (Gas)-rated well barrier.
Case study Recently, Weatherford deployed the AutoFrac system in a tight-gas well in the North Sea. The client sought to develop the Leman Sandstone reservoir—while minimizing intervention runs and costs—by performing six stimulations in seven horizontal zones. Other systems that the operator had used previously lacked contingencies for screenouts. Because relatively little hydraulic fracturing is performed in this type of reservoir and the formation could contain high-permeability streaks, much uncertainty existed about reservoir response to stimulation treatments. This greatly increased the risk of a screen-out. The lower-completion string included seven 4½-in. AutoStim flapper valves and seven 4½-in. ARID sleeves, which were inspected, function tested, and programmed to meet operational parameters upon arrival at the job site. In March 2015, Weatherford set the lower-completion string at a total depth of 20,862 ft (6,359 m).
SEASON PASS
Once the lower-completion string was run to depth, the team added RFID tags into the fluid stream and circulated them downhole through the liner-hanger running tool. The RFID tags commanded the flapper valve at the completion toe to close, which provided a deep-set barrier. Pressure testing indicated positive valve integrity. Hydraulic stimulation of the zones occurred in June 2015. The stimulation operation used a combination of RFID tags, pressure pulses, and ACTiFRAC pulses to actuate the AutoFrac system. Six of the seven ARID sleeves opened successfully with a command-response rate of 93%. An isolated electronic failure in ARID Sleeve 4 necessitated a shifting-tool run to mechanically open the sleeve, which resulted in the sleeve opening and achieving a good injection rate during stimulation. All AutoStim valves successfully closed and re-opened with a 100% command-response rate. The new fracturing system also demonstrated a high level of flexibility during stimulation. Injection was not possible in one zone; however, the system presented several viable options for continuing the operation cost-effectively, minimizing intervention runs, maintaining remote operation of tools, completing all planned stimulations, and maximizing production. Additionally, the system functioned cor rectly in a screen-out that occurred during the flush stage of Zone 1, with proppant up to an estimated depth of 9,843 ft (3,000 m). An indication from the bottomhole gauge and collected data from subsequent pressure testing revealed that AutoStim Valve 2, though filled with 9 ppg of proppant, had closed per instructions from an RFID tag. This provided a closed system for a hydrocarbon-free clean-out run. Following the completion of the stimulation program, it was confirme d that all AutoStim valves had re-opened as intended. �
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ENGINEERING, CONSTRUCTION, & INSTALLATION
Technip assessing fatigue, weight issues as subsea installations go deeper
A
lthough deepwater activity has slowed over the past year, subsea contractors continue to prepare for the upturn. At a recent presentation in London, Technip outlined some of the technologies it is working on to extend the lives of producing subsea facilities and to extend development to deeper water. According to Laurent Décoret, Group Senior VP Innovation & Technology, the challenges preoccupying offshore operators include aging infrastructure; the need for life-of-field monitoring and inspection systems; flow assurance and recovery from complex reservoirs that are more difficult to produce, with a requirement for active heating to put energy into the fluid; and problematic reservoir conditions such as high pressure/high temperature, with carbon dioxide (CO2 ) or hydrogen sulfide (H2S) in the fluids, and the requirement for products that can accommodate these components. For ultra-deepwater developments such as the presalt fields off Brazil, the design life can be 30 years-plus, Décoret pointed out. “Our products must sustain production without the need for intervention over this period,” he said. “And increasingly, new technology must generate cost savings for clients.” In October, Technip USA signed an agreement with 3D at Depth, based in Boulder, Colorado, to jointly develop the LIDAR (Light Detection and Ranging) laser scanning technology for new types of subsea metrology and inspection applications. LIDAR can be used to build precise 3D models of subsea structures, including in deepwater where data collection and imaging is typically more difficult. The technique can be applied to more accurately assess requirements for connecting pipelines to wells and manifolds prior to fabricating spools, speeding the operation and minimizing any work that might subsequently need to be re-done. Another issue Technip has been working on is an improved methodology for assessing riser fatigue, particularly in the presalt plays where risers can typically be suspended up to 2,500 m (8,203 ft) from an FPSO to the seafloor. “To minimize top-section tension, buoyancy modules have to be fitted along the riser,” Décoret explained. “These have to be pro-
Jeremy Beckman
ancy altogether. The result would be a free-hanging riser that is slightly shorter. And although composites cost more to manufacture than steel, without buoyancy this solution would be easier to install, and therefore cost-effective.” The company has qualified the first generacured and they then take time to install. It would tion of carbon armor. “There is a limit on the be better to be able to unreel a flexible riser with maximum temperature it can withstand, but nothing on it and reduce significantly the num- we are working on second and third-generaber of buoyancy modules. This is a challenge the tion versions to address this. And we are also company is addressing to provide flexible pipes studying use of composite materials for umon the Libra field in the Santos basin, notably for bilical and rigid pipeline systems as well as to the high pressure gas injection application.” replace other layers within the flexible pipe.” Technip’s longest established flexible manu Another ongoing development is Morphofacturing plant is in Le Trait, northern France. pipe, which involves inserting microelectronic Here it has introduced Cowbot (CObot for sensors in the top section of risers or umbili Wire Bending Operation at Technip), a ma- cals to provide life of service performance chine designed to improve the wire bending feedback. This could include the curvature process during end-fitting mounting opera- of the riser at the connection point to the offtions, reducing effort for the machine opera- shore production facility for fatigue monitortors and ensuring better repeatability. As the ing. “Bending of the pipe creates the most industry moves ever deeper toward production fatigue,” Décoret said. “With this technology, in 4,000 m (13,123 ft) water depth, with the at- it could be possible to determine whether the tendant higher pressures, this will add to the pipe’s service can be extended beyond its destrains imposed on the riser by the movement sign life, or if it has reached maximum capacof the FPSO. That can be partly addressed via ity and therefore has to be removed.” adding reliability during the end fitting mountDecoret said Technip’s In-Service Riser ing process, Décoret said. Inspection (IRIS) system could provide a step At the same time, there is a general recogni- change in monitoring of in-service risers, and tion that composites will be needed to replace also umbilicals and rigid pipelines. This is a steel sections for risers to withstand the stresses crawler module equipped with various different of deeper-water service. Technip has been work- Non-Destructve Testing (NDT) technologies ing on carbon fiber armor that would provide that would be deployed by an ROV. After clamphigher mechanical strength than flexible pipes ing onto the riser, the crawler would perform with tensile steel armors while reducing weight tests to determine possible ingress of water or by up to 50%. “That would be significant for a breakage of armor wire, supervised remotely riser in 4,000 m of water,” Décoret pointed out, from a control room. The crawler would send “and with this armor, we could get rid of buoyout a unique (according to Décoret) combination of ultrasonic signals and elecTechnip’s carbon fiber tromagnetic impulses that would armor could allow a be matched against what the consimpler configuration trol room operator would expect for deepwater risers to receive to determine if there is without the need for a problem. added buoyancy. (Im Another technique under age courtesy Technip) development involves use of Xray inspection to create a true 3D picture of an in-situ flexible riser, similar to the service provided by a hospital scanner. This could be applied to the top 200 m (656 ft) of the riser to determine whether any breakages, cracks or corrosion are taking place. �
Editor–Europe
www.offshore-mag.com • December 2015 Offshore 43
ENGINEERING, CONSTRUCTION, & INSTALLATION
Vendor partnerships key to optimizing supply chain management
I
n 2013, Douglas-Westwood published a study that found 30 of 45 FPSOs installed worldwide between 2008 and 2012 suffered schedule delay. Reasons cited include project complexity, difficult regulatory requirements, an imbalance of risk in favor of project owners at the expense of contractors, organizational learning issues, and supply chain issues. While the author’s company can provide data to illustrate a different, more positive trend, this article is written to address the negative perception of schedule slippage that afflicts the entire industry, including both project owners and contractors. Understanding the causes of equipment schedule delay is essential in order to establish plans to mitigate future delays in supply chain activities of major offshore projects.
Equipment supply chain complexity The three equipment supply chains that serve the major project sector are segmented to match the main components of the offshore production facility: hull, mooring, and topsides. The vendors to each of these main
Bryan Kendig
SBM Offshore components exist in different environments. These environments are characterized by differences in the variety of industries served by a vendor’s products, level of customization of a vendor’s products, and the way in which vendors relate to their customers (buyers). The key message is that the equipment supply chain for manufacturing an offshore oil and gas facility is complex, not simple. This complexity calls for a certain degree of specialization to be present within a supply chain management organization. Specialization enables supply chain management to better anticipate and mitigate the risks that are associated with the complexity. The equipment supply chain can behave differently depending on whether the buying organization is mainly in the engineering, procurement, and construction (EPC) business or mainly in the production operations business (operator). This can be seen in the behaviors of equipment vendors. For ex-
ample, when a vendor is bidding to multiple EPC companies, and each EPC is competing for the same project, it is not unusual for the vendor to save significant bidding costs by initially, only lightly reviewing specifications, offering a generic bid to all EPCs. The vendor may then delay a thorough review of the specification until the market reveals the EPC winner. This package bidding model is likely an unintended consequence of the contracting model employed by project owners with their EPCs. It has led vendors to expect that they will be given another chance to bid the project. Such a model can inhibit the vendor’s understanding of the specification requirements, manifesting in a quality, cost, or schedule impact at a later date. It is also detrimental to a front-end engineering and design (FEED) effort that is supposed to result in approval ready, draft purchase orders for packages of equipment. Supply chain management should develop vendor partnerships. Early vendor involvement, and measuring vendor performance/ holding them accountable over the long term, can be more beneficial than risking the
Reasons for schedule delay. (Courtesy SBM Offshore) 8
120
7 100 6 80
s 5 e c n e r 4 u c c O
60
3 40 2 20 1
–
Quantity Cum % % of total
Vendor Vendor’s delay to poor understand control of specification subvendors 7 18% 18%
6 33% 15%
Vendor quality issue 6 49% 15%
Company’s Insufficient Insufficient Company’s Vendor’s design capacity staffing design dishonest change (not at vendor levelchange progress HAZOP) workshop vendor (HAZOP) reporting 5 62% 13%
4 72% 10%
44 Offshore December 2015 • www.offshore-mag.com
2 77% 5%
2 82% 5%
1 85% 3%
Vendor Vendor Scope document capability added by delay and capacity company assessment inadequate 1 1 1 87% 90% 92% 3% 3% 3%
Intentional delay by company
Delayed vendor decision
Delayed company decision
All other
1 95% 3%
1 97% 3%
1 100% 3%
0 100% 0%
0
% e v i t a l u m u C
ENGINEERING, CONSTRUCTION, & INSTALLATION
accuracy of vendor proposals in the traditional, adversarial bidding process.
Specification development The amount of time scheduled to advance through the stages of an offshore project development typically ranges from three to seven years. During this period, various EPC companies are engaged to help define the offshore oil and gas facility. The supply chain management within the EPC provider is likely to be engaged throughout various stages. The supply chain team may be called upon to secure firm bids from vendors, including scope, price, and schedule. The bids will be based on specifications, and the specifications will be based on the maturity level of engineering existing at the time. Further, the maturity of engineering will be a function of the maturity of input data made available by the project owner. The process for specification development can introduce schedule risk to supply chain management. One such risk element, prevalent during later stages of the process, is the risk of receiving an accurate technical specification from the engineering effort in time for the request for quotation (RFQ) that must be sent to vendors. Unfortunately, almost every project has some RFQs that must be issued quickly due to anticipated long manufacturing lead times that could potentially upset the fixed project schedule. In these cases, supply chain management may have no choice but to issue RFQs (and subsequent purchase orders) to secure limited manufacturing slots, while expecting that necessary refinement of the specification will occur after the purchase order award. In a normal bidding process, technical specifications will be reasonably mature and sufficient for the RFQ. However, even in the normal bidding process, some vendors claim that specifications have become unnecessarily more voluminous and overly complicated. There is some empirical evidence that vendors are struggling to understand specifications. An analysis of schedule slippage among a selection of purchase orders suggests that the vendor’s delay in understanding specification requirements can represent up to ~20% of the reasons associated with delay. Root causes for failure to understand specifications can be traced to both the vendor and the buyer sides of the supply chain. A vendor cause relates to vendor sales organizations that transpose specification requirements to in-house data sheets, giving the vendor’s manufacturing organization a work instruction according to the vendor’s own standards, but at the expense of having lost in translation some of the client requirements. A buyer cause relates to a specific case in which more than 200 pages of interesting, yet non-essential specifications were included in the RFQ
package as zip files, for a simple orifice plate. Later investigation found that the RFQ could have been reduced to a mere few data sheets. Both project owners and EPC contractors should keep package specifications simple and standardized. Supply chain management (SCM) should work with engineering business partners to ensure that project specifications are simple, fit for purpose, and that they maximize the opportunity for vendors to bid as per vendor standards, as an alternate to the specifying company’s standards. Specific goals for the effort should be to strike out specified items that are clearly not applicable to the subject equipment including: specific clauses, specific requests for documentation, and specific reference standards that are stated within the main specifications. The industry of manufacturing offshore oil and gas facilities is unique in that it brings together diverse bodies of engineering such as marine/naval architecture, process, mechanical equipment, piping, electrical and instrumentation, automation, and construction. The engineering disciplines will work both independently and collaboratively to produce a listing of materials (equipment list) that will be purchased, inspected, and shipped to a construction yard for assembly into the offshore facility by a construction team. Each discipline is an internal client to the part of the company responsible for managing the company’s supply chain, supply chain management, and each discipline has inherent differences that need to be recognized in order to achieve an accurate, timely RFQ that can be sent to vendors. For example, marine/naval architecture can require use of vendors who are specialized, small companies, and who are asked to participate in a process whereby designs are proven in a gated process. It is important for SCM to recognize the partnership style of relationship that can be required with such vendors, while ensuring that the partnerships honor schedule requirements, and also ensuring that the partnerships do not overstep the boundaries required for a healthy, competitive relationship. SCM should have early involvement with its internal business partners and with specific, prospective vendors. This involvement may require a level of product or specific supply chain specialization (hull, mooring, topsides) within SCM. Early SCM involvement can help engineers minimize commercial obstacles that can be associated with extremely long specification development periods, and sole source vendor arrangements. Early SCM involvement can also help to recognize and satisfy timing needs of interdependent specification development across the company’s various engineering disciplines (i.e. the dependency that electrical, instrumentation, and automation has on many other disciplines).
Defining equipment packages Ideally, SCM will have worked as a catalyst with engineering such that engineering produces the equipment list and specifications to enable the RFQ in a timely fashion. However, another step is often taken before the RFQ is issued. SCM will work with engineering management to rationalize the equipment list against the capabilities of the vendors, and the efficiency of managing the various purchase orders that will result from the equipment list. There are different terms used to describe the outcome of this process. One such term is the “package list.” The package list represents a bundling of equipment intended for purchase from a single vendor. It is a key activity to get right because it can make or break the best, most perfect engineering effort. In some companies, the package list not only determines the equipment to be bundled, but it also impacts the listing of vendors who are qualified to bid, the level of equipment inspection, and the personnel resources that will be assigned to manage the package, assuring its cost, schedule, and quality. Transferring an equipment list to a package list requires frequent, healthy exchange between SCM and engineering in order to avoid bundling of packages for administrative convenience at the expense of a vendor’s true ability to provide all elements of the bundle on schedule and on budget. Perfor m a sanity check on plans to bundle equipment that will be sourced from a single vendor. Use a system that gathers input from a collection of experts most familiar with the technology and the potential vendors’ current capabilities and current shop capacities (engineering, drafting, machining, assembly, and testing). Make an effort to obtain feedback from someone with construction expertise, especially if a bundled component might be better sourced from a construction yard rather than from a manufacturer.
Risk assessment Risk assessments within both the EPC contractor and the project owner environments are often “owned” at very high levels within the major project teams, with SCM, among others, taking specific actions to mitigate the risk. This is a good practice, but can be flawed if the ownership of risk assessment is not sufficiently pushed down into the project. When ownership is pushed down into the project organization the assessment of risk becomes more of a continuous assessment rather than a snapshot of risk at a given point in time. In addition, it can drive the correct behaviors within the people who are closest to the point of being able to identify and mitigate the risk. In fact, when risk management is not pushed sufficiently down into the project organization, it may not be apparent to those on the project www.offshore-mag.com • December 2015 Offshore 45
ENGINEERING, CONSTRUCTION, & INSTALLATION
that everyone should be a risk manager, rather than an incident responder. Vendor qualification systems can have the same effect as high level risk assessments. They are risk snapshots of the vendor at a specific point in time, but may not be entirely effective at identifying risk changes to the vendor which occur after the snapshot. For example, has the vendor recently decided to sub-contract major components as a result of a “make-buy” decision? If so, what float is in the vendor’s schedule to make repairs resulting from having to “train” a new sub-vendor? Also, many supply chain organizations separate the individuals responsible for “qualifying” the vendor from those who are responsible for managing the vendor during the execution of a purchase order. Again, this is a separation of time and responsibility that can be a threat to the schedule and budget for the equipment package. Push ownership of risk assessments sufficiently down into the project organization, inclusive of the supply chain organization. Risk assessments within supply chain should not be complex nor require special tools. Addressing basic risk oriented questions about the vendor during specific stages within the procurement process can be sufficient. The key is to recognize the need, and institutionalize a process.
the agencies will provide much of the inspection man-power for the 2,000-plus inspections. When there are problems, they often can be traced back to a miscommunication (quality of information and timing), mismatch of an inspector’s skill set to the inspection requirement, or a deficiency in upholding a professional responsibility. The value of using third-party agencies for vendor surveillance, given practical limits on project resources, is undeniable. However, the challenge of thoroughly educating the third parties about the package inspection needs, and instilling just a small sense of “ownership” so the inspector might look beyond what is described in the work order is a major flaw in any process that relies totally upon third-party inspectors. It is prudent to develop an in-house inspections team. In addition, supplement the in-house team with processes that develop continuous improvement with the third-party inspectors. The positive schedule impact of an in-house inspections team is that the team will minimize the number of quality defects that would other wise need to be fixed in a construction yard. Control of vendor and sub-vendor quality. Vendor surveillance involves more than simply inspecting equipment when the EPC contractor or project owner is given notification by the vendor. Quality issues It is essential to visit the vendor’s workshop in Quality issues abound in the oil and gas order to positively identify schedule progress, equipment industry and their resolution can investigate vulnerabilities, and ensure that the occupy a lot of time for the supply chain pro- vendor has sufficient contingency to deal with fessional, both internally and externally. The unexpected problems. following areas should be examined and reFrequent factory visits are essential to viewed closely. check progress at both vendor and sub-ven Hazardous area electrical issues. Recent proj- dor locations. The person given responsibility ects have provided quality challenges in terms of for managing the vendor schedule within the package compliance to electrical and hazardous EPC or project owner companies should make area standards (explosion proof “EX” require- the visits, and ideally, such visits should not ments). Nearly half of quality defects found on be delegated to others. When done properly, equipment packages were related to EX issues. there is no substitute for the value of visiting These defects require remediation, and will like- the vendor and sub-vendors. Also, there is no ly delay the package schedule. substitute for the value of knowing what to Put additional focus on packages that will look for and how to conduct one-self while visrequire hazardous area certification. Require iting a vendor factory. vendors to incorporate hazardous area inspec Where there are package schedule delays, tion within the inspection and test plan. The a significant number of the delay occurrences hazardous area inspection should be per- are due to quality defects from sub-vendors. formed by a qualified COMPEX (competency An analysis of schedule slippage among a sein explosion proof) inspector. Also, require the lection of purchase orders suggests that the vendor to train shop floor personnel to prop- vendor’s poor control of the sub-vendor can erly construct a cable gland connection. represent up to 15% of the reasons associated Inspection. A typical project might involve with delay. Gathering early intelligence of submore than 500 purchase orders for major vendor progress is required. equipment. The inspection and test plans asEnsure that vendor progress reports (insociated with these packages might total more cluding standard templates) provide sufficient than 2,000 inspections to occur at vendor facili- visibility of sub-vendor activity. Vendors subties. Independent inspectors reside in various contract many components. Quality control at global locations and typically avail themselves the sub-vendor level is often poor, and visibility of to the market via third-party inspections agen- sub-vendor problems can arrive late. The person cies. Both EPC companies and project owners given responsibility for managing the vendor will contract with the third-party agencies, and schedule within the EPC or project owner com46 Offshore December 2015 • www.offshore-mag.com
panies should work closely with schedule planners to decompose/analyze vendor schedules and spotlight vulnerabilities before they occur. Recognize that the person given responsibility for managing the vendor schedule within the EPC or project owner companies may, in fact, need to manage the schedules of multiple, corresponding sub-vendors. Projects need to plan for sufficient numbers of personnel to perform this deep level of vendor/sub-vendor management.
The right people The final recommendation is arguably the most important, because heeding the other recommendations could be ineffective without the last recommendation. The final recommendation relates to the qualifications of the people who are given responsibility for managing the vendor schedules within the EPC or project owner companies. Those who are most successful in the role do not necessarily have identical backgrounds in terms of roles/industries previously worked, or educational achievement. Rather, the majority of them possess the knowledge, skills and behaviors of good project managers. Specifically, the following traits are important: • Establishes credibility with stakeholders • Accepts and continually establishes ownership of the package • Completely knowledgeable of the purchase order or contract • Influential • During negotiations, continually advocates for the buyer organization, but is fair with vendors • Maintains healthy relationships at multiple levels within the vendor organization, but maintains professional distance to ensure objectivity • Knowledgeable of the package and/or vendor sufficient to anticipate and manage changes • Vigilant in r egards to questioning the vendor’s schedule • Communicates package progress to supporting staff and to the project management team • Resilient to handle the high pressure, demanding environment of a major project • Inspires others and recognizes their contributions. It is the author’s hope that the topics presented here will generate discussions and actions that will improve the offshore industry’s reputation for schedule achievement. �
Acknowledgment Based on a paper presented at the Society of Petroleum Engineers Annual Technical Conference and Exhibi- tion held on Sept. 28-30, 2015, in Houston.
SUBSEA
Industry project seeks to update pipeline repair standards Junkan Wang Ali Mirzaee-Sisan
Jens Petter Tronskar Dag Øyvind Askheim
DNV GL
L
oss of production time due to repair operations offshore can equate to millions of dollars per day in lost revenue. As a result, pipeline “live” repair, i.e. repair operations without any downtime, is an attractive option for operators, and is often preferred since it yields considerable flexibility and is highly opex-efficient. It is however, technically challenging. Offshore pipelines are designed to last for more than 20 years, but damage can prevent them from reaching their optimal design life. Damage to oil and gas pipelines can occur during installation or during the operational stages. The Pipeline and Riser Loss of Containment (PARLOC) report published in March 2015 presents loss of containment incidents that occurred on pipelines and risers on the UK continental shelf (UKCS) during the 12-year period 2001 to 2012. The PARLOC report mentions 183 loss of containment incidents of which 160 happened during operation. According to PARLOC, full descriptions of all incidents are not available due to missing reported anonymous data. These statistics differ in other parts of the world, but nevertheless highlight the importance of of fshore asset integrity, and the need to access the latest repair technology to respond when required. During operation, damage can be caused by internal and exter nal corrosion, hydrogen-induced stress cracking (HISC), environmental factors such as unstable seabed conditions or seismic related damage, and third-party impacts such as anchors and other dropped objects. The risk of damage depends on many factors, but typically includes the design of the pipeline, the environmental conditions, and the intensity of adjacent human activities. Additional logistical challenges also apply if the off shore repair operations involve isolating topsides on a production platform. The extent of possible damage can vary from insignificant to a fully buckled or parted pipeline, and governs the repair preparedness strategy. For extensive damage of large sections of the pipeline, repair options are usually limited to cut and replacement using hot tap and bypass technology with substantial opex implications due to lost production time. For most local damage, such as external or internal cor rosion and mechanical damage on a local scale (i.e. dents, wrinkles, buckles or girth weld defects), repair methods that involve minimal or no lost production time can be viable. These re pair methods are collectively referred to as “live” repair. Most subsea pipeline re pair technologies involve fittings that can be connected to the pipeline via mechanical means, such as couplings, clamps, T-branch connections, or by welding. Isolation plugs are used to limit emptying volume of internal fluid and sea water filling of the pipeline during the repair. Offshore repairs can also be challenging and costly in terms of logistics. Most shallow-water repairs (down to 180 m/591 ft water depth in Nor wegian waters) have historically been performed by divers. In deeper waters, pipeline repairs have to be conducted via remotely controlled technologies. Qualification of such technologies and equipment requires in-depth knowledge of the pipeline design parameters and operational experi-
Damage to oil and gas pipelines can occur during installation or during the operational stages. (Courtesy DNV GL)
ence. To date, there are very few options for deep and ultra-deepwater pipeline re pair. DNV GL has served as an independent technical advisor on several pipeline repair projects in the past few decades, to enable “live” pipeline repair without compromising on safety and integrity. The company has developed a number of practical repair procedures and a range of “live” repair solutions. These include plugging and grouted repair clamps for pipelines, and in-ser vice welding of split-sleeves and stand-off sleeves with internal gas containment for repairs on leaking lines, grouted sleeves, and tees for pipelines. Responsible for 170 world leading offshore standards and recommended practices (RPs), DNV GL is currently updating one of its leading RPs for offshore pipeline repair – DNV-RP-F113 – through a fasttrack joint industry project (JIP). The RP is widely referenced for the qualification of fittings and systems used for pipeline subsea repair and/or modifications and tie-ins. The guidelines include aspects relating to the design, manufacture, installation, and operation of such fittings and systems. However, the latest version of this RP was published eight years ago and a number of new technologies have been developed since then. This new JIP aims to capture the latest best practices, experiences, and expertise from the main providers and operators of pipeline repair equipment and tools, and to formalize pipeline subsea repair criteria and procedures into an internationally recognized standard. The new edition of the RP will be harmonized with the latest re vision of the Offshore Standard, DNV-OS-F101, on subsea pipelines, and will extend coverage to repair of clad and lined pipe, surface pipeline recovery, damage assessment, including root cause assessments, inspection methods, criticality assessment, selection of mitigations and repair methods for given damage levels, and lifecycle management of pipeline repair operations. The new edition will also provide more guidelines on the safety (including topside and landfall) and barrier philosophy related to offshore pipeline repairs, and will provide further assistance on considerations for post-lay ovality of the pipe, and test requirements after the repair operation. Other improved design and qualification guidelines will relate to pipeline isolation plugs; sour service; high temperature/high pressure (HT/HP) pipeline repair; the lifetime performance of elastomeric seals; and acceptance criteria for possible effects on the pipeline surface from coating removal tools. It will also address updated guidelines and acceptance criteria on hyperbaric welding, burst capacity check for welding on in-service pipelines, and installation aspects such as longitudinal seam weld removal. � www.offshore-mag.com • December 2015 Offshore 47
FLOWLINES & PIPELINES
Asphaltene inhibitor prevents deposition in long-distance tieback Tim Garza
Baker Hughes
S
afely controlling and treating asphaltene deposition is a major flow assurance challenge in the offshore environment, where consequences and remediation can be far more involved and costly than onshore. For example, umbilical failures in a subsea system can lead to unacceptable health; safety; environmental and operational risks; unnecessary delays and downtime; costly repair and replacement expenses; and deferred production. These potential risks make it imperative that deepwater fields be properly evaluated for asphaltene deposition risks. If the risks are properly identified, effective prevention programs can be implemented.
Selecting an inhibitor Key performance indicators (KPI) for the successful chemical inhibition of asphaltenes are the reliability, deliverability, and compatibility of the chemical application and its ability to provide uninterrupted production for the operator. First, the type of deposition must be properly identified to determine what steps need to be taken to inhibit the deposits before they can damage the wellbore, flowlines, or other equipment or facilities. Following deposition identification, a stringent qualification process is followed to select the optimal chemical solution, based around the KPIs. Use of qualified production chemicals is critical to maintaining safe, efficient operations and to protecting many aspects of producing assets—including personnel, the environment, facilities, and financial investment. To develop a set of standards for subsea chemical injection systems, Baker Hughes collaborated with several operators, chemicals and fluids vendors, and industry trade groups in the Blockage Avoidance in Subsea Injection and Control Systems joint industry project (JIP). The service company’s deep water-subsea certification process, which includes a rigorous 16-test protocol to qualify chemistries for use in subsea umbilical applications, was built upon Specification 17TR6. Two American Petroleum Institute (API) standards were issued as outcomes of the JIP. Recommended practices for the avoidance of blockages in subsea chemical injection systems were published in API specification
Baker Hughes says its subsea-certified chemicals go through a rigorous 16-test deepwater subseacertification process to be qualified for use in subsea applications. (Courtesy Baker Hughes)
17TR5, Avoidance of Blockages in Subsea Production Control and Chemical Injection Systems. Qualification standards for chemicals to be used in subsea chemical injection systems were published in API Specification 17TR6, Attributes of Production Chemicals in Subsea Production Systems. Reliability of each chemical is substantiated by performing various stability tests, which confirm that there will be no phase separation, gelling, or precipitation of the chemical under given thermal and pressure conditions throughout the application lifetime. Low-temperature stability of the chemical is tested to mimic the temperatures often seen in the cold seabed environment, while hightemperature stability testing is performed to demonstrate the upper temperature capabilities of a chemical. Extreme temperature fluctuations can occur during the transportation and storage of chemicals to deepwater assets. To further confirm a chemical’s temperature cycling and stability, both short- and longterm, studies are performed to determine the resistance of a chemical to phase separation during thermal cycle stress over long periods of time. The effect of pressure on the stability of the chemical is also investigated under both low and high temperatures to simulate lowtemperature umbilical and high-temperature capillary deployment. This combination of tests can provide a holistic view of subsea-certified chemical reliability under harsh deepwater temperature and pressure conditions.
Deepwater remediation Recently, close collaboration between an operator working in the deepwater Gulf of Mex-
48 Offshore December 2015 • www.offshore-mag.com
ico and Baker Hughes prevented asphaltene deposition in subsea equipment, flowlines, and surface equipment in a long tieback system. The deepwater operator was faced with potential asphaltene deposition in its subsea equipment, flowlines, and surface equipment from a well located in approximately 3,800 ft (1,158 m) of water and tied-back to the host, a tension leg platform approximately 16 mi (25 km) away. The well had a bottomhole pressure of approximately 10,000 psi (690 bar) and produced a 38°API gravity crude oil. Oil samples were collected and sent to a technology center in Sugar Land, Texas, where saturates, aromatics, resins, and asphaltenes (SARA) analysis was conducted. The percentages of these deposits in the crude oil sample were determined using a modified version of the Institute of Petroleum Standards IP143/57 method. Results indicated that the oil contained approximately 1.3% asphaltenes. From the SARA analysis, the colloidal instability index of the crude oil was calculated to be 1.27, indicating unstable oil and validating deposition concerns. Once the potential risks for asphaltene deposition were understood, the process of designing an appropriate asphaltene inhibition program began. This included selecting an asphaltene inhibitor to be continuously injected via a 5/8-in. capillary line through an uninsulated umbilical along the 16-mi tieback, where the seabed water temperature was approximately 40°F (4.4°C). To achieve optimal inhibition, the inhibitor would be injected down the capillary string before the fluids could reach the asphaltene onset pressure. After extensive laboratory testing and modeling, Baker Hughes’ FATHOM XT deepwater subsea-certified asphaltene inhibitor was selected. A topsides plant trial was conducted to confirm that the asphaltene inhibitor would not negatively impact the emulsion tendency of the crude or water quality of the overboard water. Following the successful plant trial, a full-scale field trial was initiated. Continuous injection of the inhibitor was introduced into the system at an initial dose of 400 ppm. After treatment had been established throughout the production system, production volumes increased to an average of 5,000 b/d of oil. Emulsion tendency and water quality remained in spec, and the system pressure profiles indicated that asphaltene deposition had been prevented with no signs of deposition occurring. �
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Mark Peters, Vice President and Publisher, Offshore Mark F. Peters is a Vice President of PennWell Publishing and Group Publisher of Offshore and Oil & Gas Financial Journal. He has over 30 years of industry-related experience having been a publisher of a refining, petrochemical, gas processing publication and a pipeline and gas industry publication. He is a frequent speaker addressing oil, gas, refining and offshore issues and trends at seminars, conferences and users groups. His extensive travel schedule includes attendance at major upstream and downstream meetings around the world. He holds a BA degree in psychology from Brown University University..
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Alec Johnson, Advisory Board Chairman,
Senior Mechanical Engineer, Petrobras America Inc. Alec Johnson earned a Bachelor of Science degree in Industrial Engineering in 1992 and a Master of Science degree in Mechanical Engineering in 1994, both from Mississippi State University. Since 2007, Alec has worked for Petrobras as the lead mechanical engineer on the Cascade & Chinook FPSO project team. He has more than 20 years of experience in the oil and gas industry working for various offshore engineering companies, OEM’s, and major oil and gas production companies.
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CHALLENGES OF DESIGNING, FABRICATING, AND INSTALLING DEEPWATER FIXED JACKETS Gary Epperson, Structural Engineer, Oil Field Development Engineering
MAJOR MAINTENANCE FROM FLOTELS Marc Wagner, Civil Engineer, Shell
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CRUDE OIL SEPARATORS, LATE LIFE DEBOTTLENECKING Wally Georgie, Principal Consultant, Maxoil Solutions Inc
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CHAIR: Carlos Mastrangelo, Sr. Vice President, Projects and Technical Development, SBM Offshore CO-CHAIR: Ross Hancock, Topsides Facilities GOM, Anadarko Petroleum Corporation RISERS FOR FPSO IN HARSH ENVIRONMENT Sherry Xiang, Principal Lead Engineer, SBM Offshore USA, Inc
DEEPSTAR® QUALIFICATION PROGRAM OF SLWR TECHNOLOGY Peimin Cao, Manager, Mooring & Riser Systems, SBM Offshore
PHILOSOPHY OF RISER CONCEPT SELECTION FOR AN FPSO APPLICATION: AN OPERATOR’S PERSPECTIVE Dr. Ruxin (Rex) Song, Staff Riser Engineer, ConocoPhillips
Alternate: DEEPWATER RISER OPTIMIZATION DESIGN FOR FLOATING PRODUCTION SYSTEMS Lixin Xu, Vice President of Floating Systems and Risers, Univ ersalPegasus International
4:30 P.M. – 5:45 P.M.
NETWORKING RECEPTION – EXHIBIT HALL Sponsored by:
TOPSIDES, PLATFORMS & HULLS CONFERENCE & EXHIBITION 2016 PRELIMINARY EVENT GUIDE
Preliminary Conference Program THURSDAY, FEBRUARY 11, 2016 7:00 A.M. – 8:00 A.M.
CONTINENTAL BREAKFAST – FLORAL BALLROOM Sponsored by:
8:00 A.M. – 9:30 A.M.
SESSION 4: OFFSHORE CONSTRUCTION – MOODY BALLROOM
CHAIR: Mark Meunier, Vice President, Kiewit Offshore Services CO-CHAIR: Scott Key, Vice President, Manager of Projects, WorleyParsons CURRENT CHANGES IN RIG TIE DOWN REQUIREMENTS Ramesh Maini, President/CEO, Zentech, Inc.
NEW TLP TENDON INTERMEDIATE CONNECTOR - DESIGN AND TEST Alpha Mahatvaraj, Offshore Products Manager, GMC Inc.
PLATFORM LIFE EXTENSION Eleni Beyko, Director, Technip
9:30 A.M. – 10:15 A.M.
COFFEE BREAK - EXHIBIT HALL
10:15 A.M. – 11:45 A.M.
SESSION 5: COST REDUCTION AND VALUE CREATION OPPORTUNITIES – MOODY BALLROOM
CHAIR: James Deaver, Engineering Advisor, Oil Field Development Engineering, LLC CO-CHAIR: David Castle, Project Advisor, Hess Corporation COST REDUCTIONS USING INTERNATIONAL CODES AND STANDARDS Matthew Hill, Principal Facilities Engineer, Statoil Gulf Services LLC
EXMAR OPTI ® FPS - EXMAR’S EXPERIENCE WITH OPTIMIZED FPS DEVELOPMENT PROJECTS David Lim, Managing Director, Exmar Offshore
AN OVERVIEW OF THE CURRENT ECONOMY Richard Westney, Founder/Director, Westney Consulting Group
11:45 A.M. - 1:15 P.M.
LUNCH – FLORAL BALLROOM
1:00 P.M.
HARLEY-DAVIDSON EXHIBIT FLOOR GIVEAWAY
1:15 P.M. - 2:45 P.M.
SESSION 6: PANEL DISCUSSION COST REDUCTION AND VALUE CREATION OPPORTUNITIES – MOODY BALLROOM
MODERATOR: Renard Falcon, Facilities Manager, Chevron CO-MODERATOR: Murray Burns, Consultant PANELISTS: Matt Hill, Principal Facilities Engineer, Statoil Maria Pena, Stones Business Opportunity Manager, Shell Richard Westney, Founder/Director, Westney Consulting Group PRESENTATION OF SPEAKER AWARDS 2:45 P.M. - 3:00 P.M.
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TOPSIDES, PLATFORMS & HULLS CONFERENCE & EXHIBITION 2016 PRELIMINARY EVENT GUIDE
2016 Exhibitor List
AIMS INTERNATIONAL, INC.
626
AKER SOLUTIONS
615
ALE
421
ALFRED CONHAGEN INC ALLOY METALS AND TUBES INTERNATIONAL, INC.
as of 10/12/2015
FREUDENBERG OIL & GAS TECHNOLOGIES
914
QUALITY PRODUCT FINISHING, INC.
1015
FZV AMERICAS
1110
RAMBOLL OIL & GAS US, INC.
917
1010
GALPERTI ENGINEERING AND FLOW CONTROL USA INC.
1115
RAYTEC SYSTEMS
827
SAACKE MARINE SYSTEMS
927
621
GATE, LLC
314
GEORG SCHÜNEMANN GMBH
1111
SAFEZONE SAFETY SYSTEMS, LLC
701
GIL AUTOMATIONS
112
SEATRAX
1009
GLAMOX AQUA SIGNAL CORPORATION
921
SEAWAY HEAVY LIFTING
1211
SIEMENS WATER SOLUTIONS
919
GMC INC
1016
STI MARINE FIRESTOP
200
HB RENTALS
902
STRAIGHTPOINT INC
628
HELIDEX OFFSHORE LLC
209
HOLLOWAY HOUSTON
721
STRATEGY ENGINEERING & CONSULTING, LLC
215
AMEC FOSTER WHEELER
715
ANTLER SUPPLY SERVICES
1028
APPLETON MARINE, INC.
202
APPLY CAPNOR US, INC.
509
APPLY EMTUNGA
426
AUDUBON ENGINEERING
415
AVEVA INC
709
BAKER HUGHES
802
BAYARDS USA LLC
1114
HOUSTON OFFSHORE ENGINEERING
221
STRESS ENGINEERING SERVICES
819
BECHTEL OIL, GAS & CHEMICALS
1119
INTERGRAPH
309
TECHNIP
301
INTERNATIONAL PAINT LLC
115
TIGER OFFSHORE RENTALS
328
BERARD TRANSPORTATION INC.
901
INTERTEK HI-CAD
1001
TRELLEBORG OFFSHORE
915
BLUEBEAM SOFTWARE
210
JACOBS
315
620
KBR
403
UNIVERSALPEGASUS INTERNATIONAL, INC
KEYSTONE ENGINEERING
922
UTEC SURVEY INC.
800
LEECYN COMPANY
1008
VERSABAR INC.
609
LONESTAR MARINE SHELTERS
327
VIEGA
214
LTS ENERGY
801
W&O
908
M&H ENERGY SERVICES.
820
WILLIAMS
809
MACGREGOR
1014
WOOD GROUP MUSTANG
601
MACTECH OFFSHORE
1101
MAMMOET
409
MCDERMOTT
308
BOA MARINE SERVICES INC.
909
CAMERON
300
CANAL BARGE COMPANY INC.
900
CIVEO
1007
CLA-VAL
1006
CORTEC
720
COUGAR FUEL SYSTEMS
821
DANOS
321
DEANSTEEL MANUFACTURING COMPANY
427
DEKKER VACUUM TECHNOLOGIES, INC.
916
MECH-TOOL ENGINEERING LIMITED
201
DK-LOK
1104
MECO
306
DYNAMIC INDUSTRIES, INC.
515
NORTH AMERICAN GRATING
1022
ECL
320
228
EDG, INC.
805
NOV COMPLETION & PRODUCTION SOLUTIONS
ENDURO
318
OGLAEND SYSTEM US LLC
322
ENERSYS
1011
OIL STATES INDUSTRIES, INC.
815
ENVIRO-TECH SYSTEMS
823
PENNWELL
1230
ESGARD, INC
923
PHAROS MARINE AUTOMATIC POWER
828
ESP SAFETY INC.
904
POLE STAR MARITIME, LLC
217
EVOQUA WATER TECHNOLOGIES LLC
727
PREFERRED ELECTRIC INC
826
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TOPSIDES, PLATFORMS & HULLS CONFERENCE & EXHIBITION 2016 PRELIMINARY EVENT GUIDE
BUSINESS BRIEFS
People The Electromagnetic Geoser vices ASA board of directors has appointed Christiaan A. Vermeijden as CEO. Kevin Gallagher has resigned as CEO and managing director of Clough. Jeremy D. Thigpen, Transocean’s president and CEO, has been elected to the company’s board of directors. Ziebel has named Francis Neill as CEO. Anadarko Petroleum Corp. has appointed Mitchell W. Ingram as executive vice president, Global LNG. Wood Group Mustang has promoted Kent McAllister to president, Offshore Business Unit. Royal Dutch Shell plc has appointed Maarten Wetselaar as Integrated Gas director, effective Jan. 1, 2016. Le Béon Asia Singapore has appointed Edmund Chik as CEO. Saudi Total, a joint venture Chik between Zahid Group and Total, has named Hisham Atalla as general manager. R. Bradley Forth has joined Norther n Offshore as senior vice president and CFO. KBR has appointed Ann Pickard to its board of direcForth tors. Kongsberg Maritime has appointed David Wilson as business manager for the Offshore Production division. Sonardyne International Ltd. has named Robin Bjorøy its new managing director. He succeeds John Ramsden who leaves the position after six years in charge to return to Singapore Bjorøy following a transition period. Robert E. Beauchamp has resigned from the National Oilwell Varco board of directors. William R. Thomas has been appointed to the company’s board of directors Sir Patrick Brown , chairman of the Oil and Gas Authority, has confirmed the appointment of three non-executive directors to the OGA board: Mary Hardy , Frances Morris Jones, and Robert Armour . ACE Winches has appointed Richard Wilson as COO and Hayley Yule as marketing and communications director. Antony Croston, drilling and wells manager for Wood Group Kenny in the Americas, has received the title of Institution of Mechanical Engineers Fellow. Exova has hired Paul Barr y as managing director for Europe and a member of its Group Executive Committee.
In Memoriam Peter Cantu, a PennWell Petroleum Events, exhibit and sponsorship sales manager, passed away on Oct. 26, 2015. He was 49. Peter worked at PennWell for eight years. Survivors include his mother, Olga Perez Cantu; four siblings; nine nieces and nephews; and his beloved dogs, Jack and JJ Cantu. He was a member of Our Lady of Guadalupe Catholic Church in Rosenberg, Texas. His hob bies included playing go lf, traveling, hunting in South Texas, participating in the Porsche Car Club, spending time at his property in Kendleton, and supporting his nieces and nephews in their endeavors.
Forum Subsea Rentals has promoted Nicki Nicholls to global business director. Christian Blinkenberg has been appointed global sales and marketing director of the company’s Global Services division. Oilgen has hired Bruce Blanche and Richard Bunt as independent consultants.
Company News Weatherford International plc has launched its Production Optimization Consulting group. Its services integrate cyclical optimization solutions to enable proactive well, reservoir and asset management. Beach Energy Ltd. and Drillsearch Energy Ltd. have entered into a binding merger implementation agreement whereby Beach has agreed to acquire all of the shares in Drillsearch that it does not already own. In combination, the merger creates an oil and gas company on the ASX, with a market capitalization of approximately $1,169 million. The transaction is subject to the approval of Drillsearch shareholders at a shareholder meeting expected to occur in late January 2016, as well as court approval and other conditions. Energy Software Intelligence Analytics has acquired Richmond Energy Partners Ltd. Global Tubing LLC has delivered its second record-breaking coiled tubing string to the Port of Houston where it awaits transport to the Middle East. The new 2.375-in. (60.325mm) diameter string weighs more than 136,000 lb (61,700 kg) at a continuous length of more than 30,000 ft (9,144 m). JDR has expanded its facilities with PD Ports in Hartlepool, UK. The company’s presence now includes three adjoining warehouses for manufacture and storage at the port, totaling more than 280,000 sq ft (26,013 sq
m). The space will house a new high-capacity horizontal helix lay-up machine to manufacture umbilicals. It also will provide storage for 6,000 metric tons f equipment. The TGS Geological Products division has purchased Digital Petrodata LLC . Sandvik has opened its South American hub in Rio de Janeiro. The new Sandvik Materials Technology facility consists of a control lines service center, sales hub, and warehouse. Eni has agreed to sell a 12.5% stake in Saipem to Fondo Strategico Italiano (FSI). At the same time, Eni and FSI entered into a shareholders’ agreement defining the term of engagement governing the relations between parties as shareholders of Saipem. In addition, Eni acknowledged Saipem’s intention to achieve financial independence. Unique Group has acquired Oceanwide Safety at Sea . Royal IHC has acquired Fraser Hydraulic Power , a designer and builder of equipment for laying subsea cables and umbilicals. FHP, based in Newcastle, northeast England, de velops tracked engines and tensioners, cable carousels, and drum handling systems. The company recently opened 28,000-sq ft (8,534sq m) premises at the Neptune Energy Park in Walker, Newcastle. Harris CapRock Communications has received a contract extension for satellite and remote communications ser vices. The contract includes the transition to Harris CapRock’s Ad vanced VSAT network for three oil production platform sites in the Gulf of Mexico. Sparrows Group and Norwegian firm OptiLift have formed a strategic partnership to deliver robot vision laser technology that aims to improve the up-time of lifting operations. As part of the agreement, Sparrows Group will distribute, install, and maintain the Motion Reporter on behalf of OptiLift. Following a year-long collaboration between Saudi Aramco, Huawei, and King Fahd University of Petroleum and Minerals , the Huawei Oil and Gas Joint Innovation Center has been established at Dhahran Techno Valley. Verisk Analytics has acquired Infield Systems Ltd. The analyst firm will become part of Wood Mackenzie, which Verisk acquired in March. Hansen Protection will supply Statoil several thousand survival suits for its operations offshore Norway over the next seven years. The agreement carries an optional extension until 2026. The suits will be used at all Statoil’s helicopter bases in Norway. Coretrax has opened its fifth Middle East base within four years, in the Al Rai area of Kuwait. Le Béon Manufacturing has opened a new branch in Singapore: Le Béon Asia Singapore. www.offshore-mag.com • December 2015 Offshore 61
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1455 West Loop South, Suite 400, Houston, TX 77027 PHONE +1 713 621 9720 • FAX +1 713 963 6228 David Davis (Worldwide Sales Manager)
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A Aker Solutions .......................................... 9 www.akersolutions.com Arc Advisory Group................................ 27 www.arcweb.com B Baker Hughes ........................................... 7 www.bakerhughes.com
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D Dril-Quip ................................................. C3 www.dril-quip.com G GE Oil & Gas ........................................... 11 www.geoilandgas.com K KBR......................................................... C4 www.kbr.com Kobelco / Kobe Steel Ltd .......................25 www.kobelcocompressors.com M M&D Industries of LA, Inc. ..................... 19 DrillLab.com
P PennWell Offshore West Africa Conference & Exhibition ................... 14 www.offshorewestafrica.com PennWell Books............................. 8, 38 www.PennWellBooks.com Subsea Tieback Forum & Exhibition............................ 62 www.subseatiebackforum.com Topsides, Platforms & Hulls Conference & Exhibition ..............49-60 www.topsidesevent.com S Schlumberger ........................................... 3 www.slb.com Shaw Pipeline Services..........................29 www.shawpipeline.com T T.D. Williamson....................................... C2 www.tdwilliamson.com Thermamax GmbH.................................. 15 www.thermamax.com V Vallourec..................................................17 www.vallourec.com Variable Bore Rams, Inc. ........................13 www.vbri.com
N National Oilwell Varco ............................23 www.nov.com
W Weatherford...............................................5 weatherford.com
National Oilwell Varco ............................31 www.nov.com
Wood Group Mustang ............................ 21 www.mustangeng.com
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BEYOND THE HORIZON
Market downturn presents opportunity to break down silos The cyclic nature of the upstream oil and gas industry is nothing new. When the supply/demand balance is favorable and drilling and production activity is robust, it is a great business to be in. However, during a global upheaval, the industry contraction can be devastating in disrupting careers, lives, and families. Like Sarah Connor in the Terminator movie, we have to believe there is ‘No Fate’ that a company has to be vulnerable to the vicissitudes of the market. Companies in our industry can take action to stay strong, and weather the storm. In 1987, in the midst of what would be a decade-long downturn, this author joined with two like-minded colleagues to form Mustang Engineering (now Wood Group Mustang). At the time, we were all employed but had witnessed how owners, engineering, construction and service companies were shrinking severely. They were dismissing experienced, dedicated, and talented employees who had been instrumental in building their company’s reputation and success. It was not easy even for those who remained, as they were constantly assessing their position and facing the uncertainty of continuing project work. There was little trust among management and employees as profit margins tr umped loyalty. During the past year, the industry has been suf fering from a global market downturn which bears strong similarities to the situation that existed in the ‘80s. Whereas, the earlier contraction caused one-half million or more workers to relocate from Texas back to the north, at last count, the industry has decreased its workforce by almost 200,000 people this time. While it is true that there are, perhaps, more global influences, extreme technological breakthroughs, and competitive factors today than there were back then, the dynamics of operating in this climate still revolve around the same need – people and teams. The impact of this cyclicality begs the question, “How can we strengthen our industry so that it will protect its future during volatile times?” The industry is made up of many silos including workers, management, the company, clients, suppliers and contractors. In downturns, each silo becomes focused on its own survival and tends to look at every situation as “win-lose” because there is not enough space left for “win win” relationships. For through-cycle growth, we have to make space for win-win treatment of each other during the cycles, by busting these natural silos and working together. A downturn means there is a lot of change and change means there is opportunity to use silo-busting skills to improve relationships and create a culture for better work execution. We created a “silo-busting” culture based on communication, teambuilding, transparency, and trust built on performance. The bedrock this culture was built upon was creating win-win relationships between these potential silos and welding them into high-performance integrated teams. This same “hero-making” culture helped move the upstream industry from shallow-water fixed platforms to the spaceage technologies required for deepwater development worldwide in the short span of 12 years. This culture had four key components. Taking care of people. Companies can employ all the slogans they
want. They can tout their quality and innovation. If they cannot retain their key employees, though, their reputation and competitive capabilities will surely suf fer. A way we found to be highly successful was to create a clan. Each Mustanger was treated fairly and their family members were included in our many teambuilding activities and events. We did not lose people in the good times, and we did our best to retain every productive worker during the slow times by taking on different types of projects or creating new innovations. We also created projects by showing clients how much they could save by doing a project during a downturn when quality resources were available…essentially “out of cycle” projects. We pulled together as a tighter team to chase work with more people, and worked on innovative ways to be more competitive. One key step here was to eliminate the waste that inevitably builds up through the hundreds of handoffs, in the typical engineer-procure-construct schedule. Creating a win-win environment . Tr ust is imperative in building relations between client and contractor. Our philosophy was based on demonstrating project performance that was efficient and innovative, while at the same time passing cost savings onto the client. We helped move the industry from lump-sum/win-lose contracting to reimbursable time and material contracts awarded based on solid project definition. We went out of our way to quantify value on every project and avoid surprises. In tough times when everyone is looking for an edge, it is even more critical to have worked with the client on the same side of the table in a reimbursable fashion. Capabilities in the industry change quickly in downturns as resources disappear, and the team has to figure out the best way to deliver the project in the cur rent industry environment. Building a talent base. The oil and gas industry is still rebounding from the dearth of petroleum engineering graduates in the ‘90s who eschewed that discipline after recognizing its vulnerabilities. Today, there are many opportunities to fill the void between knowledgeable experts and novice engineers. We initiated a “Young Guns” program in the mid-nineties which gave recent graduate engineers immediate chances to contribute on a project under the tutelage of a seasoned veteran. This proved to be highly successful in increasing productivity while grooming future leaders. A high percentage of “Young Gun” grads have gone on to hold key leadership roles within the company. They continue to drive the culture. Making heroes. Nothing creates close bonds better than successful results. By setting up positive experiences with vendors and other project partners, close relationships are formed. Heroes are created in the clients’ eyes, realizing that they have a proven team that can be counted on to work together on future projects. Repeat work creates stronger teams across all silos, and has to be the goal.
William G. Higgs
Author, Mustang: The Story Founder, Mustang Engineering, Inc.
This page reflects viewpoints on the political, economic, cultural, technological, and environmental issues that shape the future of the petroleum industry. Offshore Magazine invites you to share your thoughts. Email your Beyond the Horizon manuscript to David Paganie at
[email protected].
64 Offshore December 2015 • www.offshore-mag.com
Realize Peace Of Mind
When you choose a DRIL-QUIP Wellhead System Setting the standards for safe, reliable and fully validated subsea wellhead systems enables DRIL-Q UIP to deliver peace of mind. We are committed to providing the most dependable subsea wellheads in the industry. The company utilizes technologically advanced design practices consistent with industry standards for design verification and system level analysis. We have taken the process one step further − our design integrity check includes physical system validation testing in accordance with API Technical Report 1PER15K-1 recommendations. Our subsea wellhead systems are compliant to the latest editions of API 17D and API 6A (PR2). DRIL-QUIP’S BigBore™ II-H subsea wellhead casing hanger and seal arrangement is now qualified to API 6A Appendix F Group 4 dynamic test requirements. The knowledge obtained through this process enabled us to develop the next generation 35-inch mandrel wellhead system, suitable for HPHT applications. This wellhead system, with a new and highly engineered wellhead profile, provides sufficient structural capacity and fatigue resistance to meet industry needs for future decades of drilling and production. Our Quality Management System utilizes Advanced Product Quality Planning (APQP) methodology to ensure design and process tasks produce reliable, quality wellhead components each and every time. For more information please contact your local DRIL-QUIP representative.
setting industry standards
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Validation testing of a subsea wellhead system in DRIL-QUIP ’ S horizontal test machine
