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Offshore magazineTRANSCRIPT
Houston London Paris Stavanger Aberdeen Singapore Moscow Baku Perth Rio de Janeiro Lagos Luanda
World Trends and Technology for Of
echnology for Offshore Oil and Gas Operations
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OS60Yrs_PetroRM_i_140108 1 1/8/14 11:16 AM
March 2014
Houston London Paris Stavanger Aberdeen Singapore Moscow Baku Perth Rio de Janeiro Lagos Luanda
World Trends and Technology for Offshore Oil and Gas Operations
For continuous news & analysiswww.offshore-mag.com
INSID
E:
Subsea b
oostin
g &
proce
ssin
g post
er
Seismic vessels adapt to changing demands
Asia/Pacific shipyard review
Coiled tubing case study
Dual gradient drilling update
1403OFF_C1 1 2/28/14 5:03 PM
| bakerhughes.com
We can sit around and debate what’s possible.
Or we can invent the first multizone single-trip completion system
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© 2014 Baker Hughes Incorporated. All Rights Reserved. 38682 01/2014
1403OFF_C2 2 2/28/14 5:03 PM
1403OFF_1 1 2/28/14 4:50 PM
42
38
International EditionVolume 74, Number 3
March 2014
C O N T E N T S
Offshore (ISSN 0030-0608) is published 12 times a year, monthly by PennWell, 1421 S. Sheridan Road, Tulsa, OK 74112. Periodicals class postage paid at Tulsa, OK, and additional offices. Copyright 2014 by PennWell. (Registered in U.S. Patent Trademark Office.) All rights reserved. Permission, however, is granted for libraries and others registered with the Copyright Clearance Center, Inc. (CCC), 222 Rosewood Drive, Danvers, MA 01923, Phone (508) 750-8400, Fax (508) 750-4744 to photocopy articles for a base fee of $1 per copy of the article plus 35¢ per page. Payment should be sent directly to the CCC. Requests for bulk orders should be addressed to the Editor. Subscription prices: US $112.00 per year, Canada/Mexico $ 145.00 per year, All other countries $184.00 per year (Airmail delivery: $257.00). Worldwide digital subscriptions: $112.00 per year. Single copy sales: US $11.00 per issue, Canada/Mexico $13.00 per issue, All other countries $15.00 per issue (Airmail delivery: $24.00). Return Undeliverable Canadian Addresses to: P.O. Box 122, Niagara Falls, ON L2E 6S4. Back issues are available upon request. POSTMASTER send form 3579 to Offshore, P.O. Box 3264, Northbrook, IL 60065-3264. To receive this magazine in digital format, go to www.offshoresubscribe.com.
Celebrating 60 Years of Trends, Tools, and Technology
ASIA/PACIFIC
Sembcorp to integrate Singapore yards at new ‘mega’ shipyard ........................................................... 38Sembcorp Marine has set up a “mega” shipyard in Singapore to service
the global oil and gas and marine sectors, and to maintain a competitive
edge in the construction of exploration rig and production platforms, ship
conversion, repairs, and maintenance. Prime Minister Lee Hsien Loong
opened the frst phase of Sembmarine Integrated Yard @ Tuas on Nov.
6, 2013, 50 years after the industry began in 1963 as part of Singapore’s
industrialization program to support its then fedgling economy.
Innovation keeps Keppel at the forefront of rig design ................................................... 42 Singapore rig builder Keppel continues to take on the challenges of
operating in a high-risk offshore oil and gas sector by using innovative
designs, effciency-driven capabilities, and close working relationships
with its customers. “Pressure is always felt. And we treat all our com-
petitors, including the Chinese shipyards, very seriously,” says Tong
Chong Heong, CEO of Keppel Offshore & Marine. But he is quick to
point out the advantage of being strategically located in the world’s
major hydrocarbon producing regions such as Brazil, the US, Caspian
Sea, and Southeast Asia, as well as China.
60 YEARS OF OFFSHORE
From the archives: U.S. rig makes a gas strike in the North Sea ................................................... 48Selected from the July 1964 issue of Offshore, the article describes
how, after making a historic gas strike in the North Sea, Reading &
Bates’ mobile drilling unit Mr. Louie was forced to abandon the location
because of gas cratering the seafoor near the Nordsee B-1 well.
1403OFF_2 2 2/28/14 4:50 PM
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50
20
62
International EditionVolume 74, Number 3
March 2014
C O N T E N T S
4 Offshore March 2014 • www.offshore-mag.com
Celebrating 60 Years of Trends, Tools, and Technology
GEOLOGY & GEOPHYSICS
Seismic vessel survey expands to include additional vessel types .......................................... 50The 2014 Worldwide Seismic Vessel Survey lists 179 vessels. This is
an increase if directly compared to the 2013 tally, but that is deceiving.
There are two signifcant changes this year. The listing adds Geokinet-
ics and its 43 transition zone/shallow water/OBC vessels for the frst
time, and the two electromagnetic survey vessels of EMGS.
2014 Worldwide seismic vessel survey .................................. 52Get the latest comprehensive listing of the capabilities and features of
the worldwide seismic vessel feet.
Seismic LWD reduces time, risk in remote ultra-deepwater well .............................................. 58The Schlumberger seismicVISION seismic-while-drilling service used
real-time measurements to update the velocity model in a wildcat well
off the coast of West Africa and enabled the well target objectives to be
achieved with confdence while reducing risk and time to drill the well. In
one well section with a challenging mud weight window, SWD was used
alongside the Schlumberger StethoScope FPWD service to more accu-
rately calibrate the pre-drill pore pressure model. The acquired formation
pressures, coupled with while-drilling petrophysical data, facilitated cali-
bration of a velocity-to-pore-pressure transform and normal compaction
trend lines, providing reduced uncertainty in the pore pressure model.
DRILLING & COMPLETION
Advances in dual gradient drilling will facilitate deepwater development ................................... 62When drilling conventionally, the column of wellbore annulus returns
(mud and cuttings) presents a single depth-versus-pressure gradient. Dual
gradient drilling technology involves creating two or more depths versus
pressure gradients in the returns path. DGD is particularly suitable for ad-
dressing a number of offshore drilling challenges because it enables a well-
bore pressure profle to more closely match the pressures presented by
nature, reducing or eliminating the impact of water depth on well design.
1403OFF_4 4 2/28/14 4:50 PM
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6 Offshore March 2014 • www.offshore-mag.com
International EditionVolume 74, Number 3
March 2014
PRODUCTION OPERATIONS
Compact coiled tubing unit makes small facility completion interventions feasible ....................................................... 66Baker Hughes has developed Micro CT Coiled Tubing service, a more compact, lighter weight,
and modular system using a combination of equipment and proprietary intervention modeling
software to circumvent the deployment challenges of larger CT equipment. The unit effectively
bridges the gap between traditional capillary and CT services to allow operators to economically
service wells that might otherwise have to be shut in or abandoned.
SUBSEA
Subsea processing retains innovation, moves toward standardization .................. 68This issue of Offshore contains the 2014 Worldwide Survey of Subsea Processing Systems, the
seventh installment of this industry resource, a joint effort between INTECSEA and Offshore
magazine. The primary aims of this poster are to chronicle the development and the developers
of these systems, and to document the continued commitment of oil companies to the applica-
tion of these technologies.
Online .................................................... 8
Comment ............................................. 10
Data ..................................................... 12
Global E&P .......................................... 14
Offshore Europe .................................. 20
Gulf of Mexico ..................................... 22
Subsea Systems ................................. 24
Vessels, Rigs, & Surface Systems ...... 26
Drilling & Production .......................... 28
Geosciences ........................................ 30
Offshore Automation Solutions .......... 32
Regulatory Perspectives ..................... 34
Business Briefs ................................... 70
Advertisers’ Index ............................... 71
Beyond the Horizon ............................ 72
COVER: Seismic data acquisi-
tion on the open seas has evolved,
as work moves into deeper waters
and remote, and often harsh, environ-
ments. Purpose-built, high-capacity
seismic vessels will be sailing out of
shipyards over the next few years to
meet demand for increasingly complex
data acquisition techniques. Many of
those vessels will be powered by hy-
brid propulsion systems, as geophysi-
cal companies focus on fuel effciency.
In the photo, a worker unhooks a
workboat from a CGG mother vessel,
which is shown towing a seismic array.
(Image courtesy CGG)
1403OFF_6 6 2/28/14 4:50 PM
1403OFF_7 7 2/28/14 4:50 PM
PennWell1455 West Loop South, Suite 400, Houston, TX 77027 U.S.A.
Tel: (01) 713 621-9720 • Fax: (01) 713 963-6296
SALES
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To start a free subscription, visit www.offshoresubscribe.com. Contact us for subscription questions,
address changes and back issues
Tel: (847) 763-9540 • Fax: (847) 763-9607
Email: [email protected]
OFFSHORE EVENTSDavid Paganie (Houston) [email protected]
Russell McCulley (Houston) [email protected] Gail Killough (Houston) [email protected] Niki Vrettos (London) [email protected]
Jenny Phillips (London) [email protected]
CORPORATE HEADQUARTERSPennWell; 1421 S. Sheridan Rd., Tulsa, OK 74112
MemberAll Rights reserved
Offshore ISSN-0030-0608Printed in the U.S.A. GST No. 126813153
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CONTRIBUTING EDITORS Dick Ghiselin (Houston)
Doug Gray (Rio de Janeiro) Nick Terdre (London)
Gurdip Singh (Singapore)Wendy Laursen (Australia)
TECHNOLOGY EDITOR,SUBSEA & SEISMIC
Gene [email protected]
EDITOR-EUROPE Jeremy Beckman
ASSISTANT EDITOR Jessica Tippee
SENIOR TECHNICAL EDITOR/DOMESTIC CONFERENCES
EDITORIAL DIRECTORRussell McCulley
POSTER EDITORE. Kurt Albaugh, P.E.
PRESENTATION EDITORJosh Troutman
VICE PRESIDENT and GROUP PUBLISHERMark Peters
CHIEF EDITOR/CONFERENCES EDITORIAL DIRECTORDavid Paganie
®
MANAGING EDITORBruce A. Beaubouef
8 Offshore March 2014 • www.offshore-mag.com
Latest newsThe latest news is posted daily for the offshore oil and gas industry covering
technology, companies, personnel moves, and products.
New maps, posters, surveys • 2014 Worldwide Seismic Vessel Survey• Top 10 Offshore Drilling Contractors Survey• 2014 Survey of Arctic & Cold Region Technology for Offshore Field
Development Poster• 2014 Gulf of Mexico Map• 2014 Deepwater Gulf of Mexico Discoveries Survey
Download: http://www.offshore-mag.com/maps-posters.html
New white papers➤ Design Considerations for Real-Time
Operating Centers: Best Practices for Asset Integrity and Secure Information Management for the Oil and Gas Industry
This white paper examines best practices for the design of the underlying system to securely control, manage, and distribute the fow of information to, from, and within the real-time operations center.
http://www.offshore-mag.com/whitepapers/offshore/ 2014/january/design-considerations-for-real-time-operating-
centers-best-practices-for-asset-integrity-and-secure- information-management-for-the-oil-and-gas-industry.html
➤ Don’t Buy…Make Your Own! Dedicated Nitrogen Generation Systems in Offshore E&P
The use of nitrogen in the offshore oil and gas industry has a decades-long history, and continues to play an integral role in the day-to-day operations aboard mobile offshore drilling units, FPSOs, and drillships around the world. Without nitrogen, completing tasks would come at increased operational risk and result in greater costs for operators.
http://www.offshore-mag.com/whitepapers/offshore/ 2014/don-t-buy-make-your-own-dedicated-nitrogen-
generation-systems-in-offshore-e-p.html
New video➤ Kashagan
In September 2013, the North Caspian Operating Co. offcially tapped the super-giant offshore oilfeld Kashagan in the Kazakhstan sector of the Caspian Sea. It is Kazakhstan’s frst offshore oil development, and has an estimated 13 Bbbl of proved and recoverable reserves. Named after a 19th century Kazakh poet from Mangistau, Kashagan is the largest oil feld to be discovered in the past 35 years.
http://www.offshore-mag.com/topics/video-index
Browse Offshore magazinePeruse the cover issue and archives back to 1995.
www.offshore-mag.com
Available at
Offshore-mag.com
1403OFF_8 8 2/28/14 4:51 PM
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To respond to articles in Offshore, or to offer articles for publication,
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COMMENT David Paganie • Houston
Setting the standard for subsea processing
The possible benefts of subsea processing and boosting are well known, yet the industry has been slow to adopt the technology. While slow adoption indeed is stan-dard protocol in this industry, a common explanation I hear from industry operators is the lack of a standardized approach to system supply and integrity management. Recently formed API Committee 17x aims to flls this void for the boosting element of the process.
Chaired by John Vicic, Technology Program Manager of Deepwater & Arctic for ConocoPhillips, the committee is tasked to develop a guide to enable operators, contractors, and suppliers to reach a common goal for the design of subsea pumps, thereby standardizing the design process. It will provide specifc guidance on the design, qualifca-tion, and factory testing of subsea pumping systems. A draft Recom-mended Practice is expected to be available by the end of this year, with the fnal version slated for late 2015.
The formation of this committee is timely in that the industry is ag-gressively pursuing new methods to improve the viability of deepwa-ter development. Rising costs are stretching project economics, and it is thought that the implementa-tion of subsea boosting could improve recovery to a point that justifes the investment.
The developers of the World-wide Survey of Subsea Processing Systems poster in their annual technology review highlight the trending focus on technology implementation. “Sub-sea boosting is more of a matter of course for many operators, and efforts have shifted towards effective implementation,” they suggest.
The evolution of separator technology is another noteworthy trend identifed by the poster team. Concerns over cost, size and weight continue to drive interest in alterna-tives to the conventional technology. The full report by INTECSEA’s Larry Forster, Mac McKee, and John Allen begins on page 68.
The 7th edition of the poster, inside this issue, chronicles the evolution of subsea processing technologies and their respective applications. For online access to view and download all seven posters, please visit www.offshore-mag.com/maps-posters.
Meanwhile, Statoil is closing in on implementation of the world’s frst subsea gas compression system (compressor pictured above, courtesy MAN Diesel & Turbo), slated for the Åsgard feld in the Norwegian Sea. Subsea compression on Åsgard is expected to improve recovery from the Mikkel and Midgard felds by about 280 MMboe, beginning in 2015. Proving subsea gas compression would mark an important milestone in the application of a complete subsea processing and boosting system.
Still, other elements of subsea processing require further qualifcation. These include advanced manifolds for multi-feld tie-ins, storage for oil and chemicals, more sophisticated separation and processing equipment, and ft-for-purpose IMR concepts.
1403OFF_10 10 2/28/14 4:51 PM
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1403OFF_11 11 2/28/14 4:51 PM
Worldwide offshore rig count & utilization rate
December 2011 – January 2014
950
850
750
650
550
450
350
100
90
80
70
60
50
40
No
. o
f ri
gs
Fle
et u
tiliza
tion
rate
%
Dec
11
Marc
h 12
June 1
2
Sept 12
Dec
12
Marc
h 13
June 1
3
Sept 13
Dec
13
Contracted fleet utilization Total fleet Contracted Working
Sourc
e: IH
S
Operator capex share (%) in Asia/Pacifc 2009-2018
100
90
80
70
60
50
40
30
20
10
0
Others
Reliance
Inpex
ExxonMobil
PTTEP
Woodside
Shell
ONGC
CNOOC
Chevron
Petronas
2009
Source: Infield Systems
2010 2011 2012 2013 2014 2015 2016 2017 2018
Op
era
tor
cap
ex (
%)
Worldwide day rates
Year/Month Minimum Average Maximum
Drillship
2013 Feb $50,000 $451,005 $678,000
2013 Mar $50,000 $446,902 $678,000
2013 Apr $50,000 $454,798 $678,000
2013 May $50,000 $459,773 $678,000
2013 June $50,000 $464,803 $678,000
2013 July $151,000 $466,410 $678,000
2013 Aug $151,000 $465,170 $678,000
2013 Sept $151,000 $459,947 $678,000
2013 Oct $151,000 $464,995 $678,000
2013 Nov $151,000 $472,646 $678,000
2013 Dec $151,000 $477,618 $678,000
2014 Jan $151,000 $480,302 $678,000
Jackup
2013 Feb $30,000 $120,170 $361,000
2013 Mar $30,000 $121,039 $361,000
2013 Apr $30,000 $120,186 $361,000
2013 May $30,000 $122,553 $361,000
2013 June $30,000 $123,140 $361,000
2013 July $30,000 $123,997 $361,000
2013 Aug $30,000 $125,495 $361,000
2013 Sept $30,000 $126,438 $361,000
2013 Oct $30,000 $128,141 $361,000
2013 Nov $30,000 $127,766 $361,000
2013 Dec $30,000 $130,269 $361,000
2014 Jan $30,000 $132,719 $361,000
Semi
2013 Feb $145,000 $362,730 $656,662
2013 Mar $145,000 $364,283 $656,662
2013 Apr $145,000 $373,919 $656,662
2013 May $145,000 $381,672 $656,662
2013 June $145,000 $380,276 $656,662
2013 July $145,000 $384,420 $656,662
2013 Aug $145,000 $386,314 $656,662
2013 Sept $145,000 $386,531 $656,662
2013 Oct $145,000 $382,071 $656,662
2013 Nov $145,000 $395,145 $656,662
2013 Dec $145,000 $394,124 $656,662
2014 Jan $145,000 $394,016 $656,662
Source: Rigzone.com
G L O B A L D ATA
12 Offshore March 2014 • www.offshore-mag.com
Asia/Pacific is one of the most diverse regions in the world; stretching from Pakistan and India in the west to South Korea and Russia’s Sakhalin Island in the far east and north, and Australia and New Zealand in the south. While much of the region is dominated by shallow-water development, recent years have seen an increase in deepwater activity, driven by Malaysia and India. Going forward Chevron is expected to lead deepwater invest-ment across the region, followed by India’s ONGC and Reliance.
The top two operators in terms of total forecast capex, Petronas and Chevron, are each expected to account for just over 9% of the market, while Shell, in third place, is expected to command a 7% share of regional investment across the 2014-2018 timeframe. In contrast to other regions, capex spend in Asia/Pacific is characterized by a variety of smaller operators. Outside of the top 10 operators, an additional 100 operators, equating to 42% of regional spend, are expected to invest in the region
between 2014 and 2018. However, despite the presence of many relatively small operators, it is still the supermajors and national oil companies that make it into the top nine companies, with Petronas, CNOOC, ONGC, and PTTEP all present, while Chevron, Shell, and ExxonMobil are also expected to direct significant expenditure toward the region. While Asia/Pacific’s national oil companies focus primarily on their respective home countries, the other large oil companies vary. Chevron is expected to direct the greatest proportion of expenditure toward Australia and Indonesia, where key projects include Wheatstone and the Gendalo-Gehem developments. Shell is expected to continue to focus on projects offshore Malaysia and Australia where capital intensive developments such as Malikai and the giant Prelude are expected to drive the operator’s investment demand. Northwest Australia is expected to remain a major area of investment going forward for several operators, with a number large of gas projects in the planning stages.
– Catarina Podevyn, Analyst, Infield Systems Ltd.
1403OFF_12 12 2/28/14 4:51 PM
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G L O B A L E & P Jeremy Beckman • London
14 Offshore March 2014 • www.offshore-mag.com
AmericasStatoil has opted to exit a license agree-
ment offshore the Bahamas that started in May 2009. The applications for the Falcones, Islamadores, and Zapata offshore conces-sions will now revert solely to Bahamas Pe-troleum. Recently the islands’ government issued a mandate to proceed with explora-tion drilling on existing licenses. Bahamas Petroleum plans to drill its frst well on its southern licenses by April 2015, if it can se-cure fnancing via a farm-out.
•••
Range Resources has completed a farm-in to Niko Resources’ Guayaguayare block on-shore/offshore Trinidad. Exploration plans include an offshore well drilled from the shore, followed by appraisal drilling if the outcome is successful.
•••
BG Group expects approval from Colom-bia’s government to farm into 30% of the Gu-ajira Offshore 3 block. A 3D seismic survey is planned this year.
•••
SAExploration has signed a three-year stra-tegic cooperation agreement with COMESA to jointly source, acquire, and process 2D and 3D seismic data. SAE and COMESA will source and conduct new transition-zone and shallow-water projects in Mexico, along with developing data-processing opportunities in South America.
Under the terms of the agreement, both companies will share expertise, resources, and technologies to pursue and fulfll new seismic projects in the region. All project awards will be contracted separately from this agreement on a project-by-project basis.
Seadrill has executed the fnal contracts with a total value of $1.8 billion with PEMEX for the jackup drilling units West Oberon, West Intrep-id, West Defender, and West Courageous.
•••
Brazil’s frst tension leg wellhead platform (TLWP), P-61, has sailed from the BrasFels shipyard to the Papa-Terra feld in the Cam-pos basin. It will operate with the P-63 FPSO which began producing oil in November. In tandem, the platforms will be able to pro-duce up to 140,000 b/d from 18 wells. P-61 is also designed to compress 1 MMcm/d (35 MMcf/d) of natural gas. Some will be used on the two facilities, with the remainder injected into the reservoir. The TLWP re-sembles a semisubmersible, but is moored to the seafoor via vertical anchors. The ar-rangement is designed to suppress the plat-form’s range of motions, allowing the use of dry christmas trees.
•••
Premier Oil and partner Rockhopper Ex-ploration have selected a TLP for Sea Lion, the frst planned development project off-
shore the Falkland Islands. Front-end engi-neering design is due to start soon, with a f-nal investment decision to follow during the frst half of next year. The aim is to achieve frst oil within four years of project sanction. Phase 1 of the project, designed to recover 293 MMbbl over 25 years, will likely cost around $5.2 billion.
West AfricaVaalco Energy says two new production
platforms remain on schedule for installa-tion later this year on the Etam Marine block offshore Gabon. One will go on the Etame feld and the other between the Southeast Etame and North Tchibala felds. Recently the company resumed exploration drilling on the area with a well on the Dimba prospect, designed to evaluate the Gamba and deeper syn-rift formations.
•••
All wells have been P&Ad at the decom-missioned Azurite feld off Republic of Congo (Brazzaville), according to partner PA Resourc-es. Demobilization has started of the foating drilling, production, storage, and offoading vessel, which is expected to sail away before mid-year. Operator Murphy Oil is negotiating a termination of the vessel’s contract.
•••
Cobalt International Energy has discov-ered hydrocarbons with its latest presalt deepwater exploratory well offshore Ango-la. Bicuar #1 on block 21 intersected 56 m (184 ft) of net pay from multiple intervals. It was also the frst discovery in the deeper presalt syn-rift reservoir.
In offshore block 15/06, Total has sold its 15% stake to Sonangol E&P for $750 million. A frst production hub is expected to start up next year, but Total says it prefers to focus its resources on its operated block 17, which includes the current CLOV development and ultra-deepwater block 32.
In Cabinda offshore northern Angola, Bos-kalis subsidiary SMIT Salvage will start work in 2Q to raise the Saipem jackup Perro Negro 6 from the seafoor. The rig sank last July after
suffering a punch-through close to a pigging platform while under contract to CABGOC.
Mediterranean SeaDNO has completed a farm-in to two con-
cessions offshore Tunisia held by Eurogas International and Atlas Petroleum Explora-tion Worldwide. DNO has taken an 87.5% op-erated interest in the Sfaz and Ras El Besh permits, both in mostly shallow waters in the Gulf of Gabes. They include three small oil discoveries, with 29 other prospects that could collectively contain 500-700 MMbbl.
•••
Croatia reportedly plans to open acreage over the southern Adriatic Sea to bidders, possibly this spring. Spectrum Geo recently completed a fve-month multi-client seismic survey providing the country’s frst modern long-offset 2D data. This will be connected to Spectrum’s reprocessed seismic from the Italian side of the Adriatic.
•••
Woodside Energy has reached a complex agreement with Noble Energy and its partners in the deepwater Leviathan gas feld offshore Israel. The company hoped to conclude nego-tiations by the end of this month – if ratifed, it would acquire 25% of petroleum licenses 349/Rachel and 350/Amit containing Leviathan, and would operate any LNG development. Noble would remain upstream operator.
Last year’s Tamar SW discovery could hold up to 917 bcf (26 bcm), according to partner Delek Group. Costs of a tie-in to the Tamar in-frastructure will be high – possibly more than $132 million – due to the distance of the well from Tamar’s subsea manifold and timing is-sues for development drilling.
Eastern EuropeNord Stream AG has completed a feasibility
study for expanding capacity of the twin-Nord Stream gas trunklines through the Baltic Sea. Results suggest one or two more lines would be technically and economically viable. Addition-ally, the study assessed several potential routes that will serve as the basis for further research.
Activity offshore Namibia has taken a step upShell has taken over exploration blocks 2913A and 2914B in the Orange basin off-
shore Namibia from Signet Petroleum, with the Anglo-Dutch group acquiring a 90% stake in the two blocks and Namibian national oil company, Namcor, keeping its 10% carried interest.
Investment company Polo Resources Ltd. reports that Signet Petroleum Ltd. intends to implement a share buyback under which funds not required for ongoing operations and new business opportunities would be returned to shareholders.
Polo says the investment in Signet Petroleum is a central part it strategy to increase its exposure to the oil and gas sector. The last 12 months have been a trans-formative period for Signet in which the company has acquired and interpreted 3D seismic data over Mnazi Bay (Tanzania), which has confirmed the up-dip extension of the BG/Ophir Chaza-1 discovery well, acquired 2D seismic over block 2914B in Namibia, demonstrating significant prospectivity, and launched a process to examine strategic alternatives, which is being led by First Energy Capital LLP.
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Gazprom, supplier of the gas, says South Stream Transport has awarded frst pipe supply contracts for the South Stream gas line sys-tem through the southern Black Sea. This will eventually comprise four 93-km (58-mi) offshore pipelines between the Russkaya com-pressor station on the Russian coast and a landfall on the Bulgarian side. Each line will be 32-in. diameter, with a wall thickness of 1.5-in., and made from X65 steel to withstand extreme operating pressure of 28.45 MPa (4,126 psi) during installation. Germany’s Europipe and Russia’s United Metallurgical Co. and Severstal will manufacture all pipes for the frst line, with construction offshore due to start this fall.
Caspian SeaRamboll Group is performing winterization studies for a planned off-
shore drilling complex and living quarters for Lukoil’s Yuri S. Kuvykin gas/condensate feld in the Russian sector. The northern part of the Caspian Sea is prone to severe ice build-up in winter, when temperatures often dip to -21°C (-6°F). Lukoil is targeting produc-tion of 4 bcm/yr (141 bcf/yr) of gas and 385,000 tons/yr of condensate.
•••
Oil production has started through the BP-operated West Chirag platform in the Azeri sector, the centerpiece of the $6-billion Chirag oil project. The platform, fabricated entirely in Azerbaijan, has been installed in 170 m (558 ft) of water between the Chirag
and Deepwater Gunashli platforms. It can process up to 183,000 b/d of oil, exported to the Sangachal terminal via a new pipeline linked to the existing subsea trunkline system. Its gas export capacity is 285 MMcf/d (8 MMcm/d).
BP and its partners in the Shah Deniz gas feld in the same sector have awarded the AMEC Tefken Azfen consortium a $974-million contract for the two new Stage 2 production/risers and quarters/utilities platforms. Both of the topsides will be built at the ATA yard in Bibi-Heybat near Baku.
Middle EastAbu Dhabi’s government has extended the Upper Zakum offshore
oilfeld concession to the end of 2041. State oil company ADNOC oper-ates in partnership with ExxonMobil and Japan Oil Development Co. The feld came onstream in 1982, and the partners have progressively added new facilities to raise production. Current development involves
use of artifcial islands to raise throughput capacity to 750,000 b/d, and the partners are looking at ways to raise the threshold to 1 MMb/d.
•••
Dubai Petroleum has awarded Technip an engineering, procurement, construction, and installation contract for the Jalilah B feld development in 60 m (197 ft) of water, 90 km (56 mi) offshore Dubai. Technip will build and install a new platform comprising a 900-ton deck and a 500-ton jacket; install 13 new risers on existing platforms; and lay 110 km (68 mi) of pipelines in diameters from 6- to 24-in. using three vessels.
The new West Chirag platform offshore
Azerbaijan. (Photo courtesy BP)
1403OFF_16 16 2/28/14 4:51 PM
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A new ultra-lightweight conductor-supported tripod platform is in place on the same operator’s Fateh feld in 50 m (164 ft) water depth. 2H offshore designed the T-02 facility for installation from a jackup. The minimal topside/subsea structure will host an upcoming exploration drilling/well test campaign.
•••
Masirah Oil’s second well in block 50 offshore Oman has discovered oil. Cantilever jackup Aban VII drilled the well to a depth of 3,000 m (9,842 ft) in the Cambrian formation, encountering hydrocarbons in various intervals. This was the frst-ever discovery east of Oman, the company claimed.
IndiaIndia’s government expects to offer 29 offshore blocks under the NELP-
10 licensing round. Fifteen will be in shallow water and 14 in deepwater.BG Exploration has awarded Larsen & Toubro a $114-million EPCI
contract for a new wellhead platform and subsea pipelines for the Panna-Mukta felds off northwest India. The project should be complete by March 2015.
On the east coast, Vessel Gasifcation Services has commissioned from Wison Offshore & Marine a barge-based foating LNG regasifcation unit designed to export 1 bcf/d of gas. It will be moored on a jetty structure 8 km (4.97 mi) offshore Andrha Pradesh alongside a permanent foating storage unit, which will serve as the LNG offoading station for tankers.
Asia/PacifcCNOOC has started production from the Liuhua 19-5 gas feld in the
Pearl River Mouth basin in the South China Sea. The two-well develop-ment, in 185 m (607 ft) of water, is linked to the production facility on the Panyu 30-1 gas feld. At peak Liuhua 19-5 will deliver 29 MMcf/d.
•••
Mubadala Petroleum has commissioned production facilities for its Nong Yao oil feld development in block G11/48 in the Gulf of Thailand, designed to produce up to 15,000 b/d. Nippon Steel and Sumikin Engi-neering have started fabrication at a yard close to Bangkok. Develop-ment calls for a wellhead platform, a processing platform, and intercon-necting sealines to an FSO, with 23 wells during the initial phase.
Elsewhere in the Gulf, Mubadala has extended its lease of Petro-fac’s FPSO on the Jasmine feld by an additional four years. However, the company has decided to sell its 60% operated interest in northern area block G3/48 to KrisEnergy.
•••
Dragon Oil has agreed to farm into Service Contract 63 in the northwest Palawan basin offshore the Philippines. Initially, the com-pany will take 40% of Nido Petroleum’s 50% stake in the concession, with Nido later hoping to recover an extra 10% through another farm-in deal with PNOC-Exploration. Nido would remain technical opera-tor for the planned Baragatan-1 exploration well.
•••
Lundin Petroleum aims to drill at least six exploratory wells in South-east Asia this year. In block 307 off Peninsular Malaysia, the company plans to appraise its 2012 Tembakau gas discovery, with another well targeting oil in the Rengas structure. Offshore Sabah, Lundin has com-pleted processing of the 500-sq km (193-sq mi) 3D Emerald seismic survey in block SB307 and plans to drill two of the covered prospects, Kitabu and Maligan.
AustraliaShell, which has reported lower profts like numerous other majors,
is looking to cut costs via asset sales. One already agreed sale is the company’s equity interests in the Wheatstone-Iago Joint Venture and the Wheatstone LNG project offshore Western Australia to KUFPEC for $1.135 billion. Shell CEO Ben van Beurden insisted that the company intended to remain a major player in Australia’s energy industry. •
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O F F S H O R E E U R O P E Jeremy Beckman • London
20 Offshore March 2014 • www.offshore-mag.com
Phased approach for Johan Sverdrup
Statoil and its partners have agreed on a development concept for Johan Sverdrup in the central Norwegian North Sea. The project, potentially Norway’s largest since the 1980s, will deliver production of 550,000 boe/d at peak and the facilities could remain in service for 50 years.
Under the proposed frst phase – the fnal development plan will be submitted to Nor-way’s parliament next year – the partners will commission a four-platform feld center to be installed in 120 m (393 ft) of water, with design capacity of 315,000 boe/d. According to Lundin Petroleum, 45 production and in-jection wells will be drilled in Phase 1, with a semisubmersible rig drilling 11-17 wells pri-or to frst oil in late 2019. New long-distance subsea trunklines will take the oil and gas respectively to Mongstad and Kaarstø on Norway’s southwest coast.
The complex’s 80-MW power supply will come from a shore-based transformer at Kaarstø delivering direct current to a con-verter on the riser platform. Over later phas-es, power from shore could be extended to other feld developments in the area, once requirements have been established.
Statoil estimates frst-phase investments in the range $16.4-19.8 billion, although work continues to fnd ways to lower costs. The partners have not yet addressed the scope and costs of future phases, although their long-term goal is to achieve a 70% recovery rate from the feld.
Johan Sverdrup extends over 200 sq km (77 mi) in licenses PL265, PL501, and PL502.
Reserves boost for SkarfjellWintershall has doubled the potential
resources at the Skarfjell feld in the Nor-wegian North Sea to 120-230 MMboe. This follows analysis of an appraisal well and side track which proved oil and gas in Jurassic sandstones a short distance south of the dis-covery well. No further drilling should be needed, the company said, and studies have started for a development. Options include a
standalone project and a tieback to the GDF Suez-operated Gjoa platform 15 km (9.3 mi) to the northeast.
Last year, exploration activity offshore Norway was highest in the North Sea, ac-cording to the Norwegian Petroleum Direc-torate (NPD). Wells proved seven oil and gas accumulations, with seven discoveries in the Norwegian Sea and fve in the Barents Sea. NPD estimates cumulative recoverable reserves at 50-106 MMcm of oil and 30-58 bcm of gas.
Currently 13 Norwegian felds are under development and NPD expects operators to submit plans for a further 13 projects over the next two years. Investments across the Norwegian shelf could rise by $487 million this year to $28.5 billion, it adds.
Norway allocates more blocksNorway’s government has offered 65
new production licenses to a total of 48 com-panies under the 2013 Pre-defned Areas (APA) licensing round. Of these, 38 are in the North Sea, 19 in the Norwegian Sea and eight in the Barents Sea. Seventeen rank as acreage additional to existing licenses.
NPD says interest was greatest in the northern Norwegian North Sea and in the central Norwegian Sea. This was probably down to familiarity with the geology in the area, said exploration director Sissel Erik-sen, and a general desire to maximize tie-ins of resources to offshore infrastructure.
Britain has opened the bidding for the UK’s 28th offshore licensing round, with Energy Minister Michael Fallon reaffrm-ing the government’s goal to fully extract remaining reserves of potentially up to 20 Bbbl. Oonagh Werngren, operations direc-tor of Oil & Gas UK, hopes that more new applicants would participate, alongside the established players, with the sector in need of a revival. UK offshore production con-tinues to slide, and reserves are not being replaced. A mere 15 exploration wells were drilled in UK waters last year, Werngren said, and less than 100 MMboe have been discovered over the past two years.
ATP UK back in businessAlpha Petroleum, a subsidiary of Petroleum
Equity, has acquired ATP Oil & Gas UK for $133 million. Parent company ATP Corp. fled for protection in 2012 under Chapter 11 of the US Bankruptcy Code and had been looking to sell the UK business, which includes operated gasfelds in the southern North Sea.
The deal clears ATP UK of all debts and leaves the company free to resume work on undeveloped assets. One of these is the Chev-iot feld in the northern UK North Sea, which has in-place oil of over 200 MMbbl. Manage-ment had commissioned an Octabuoy semi-submersible drilling, production, and storage
platform designed by Moss Maritime to ac-commodate dry wellheads. Cosco in China had started construction, but the program has been cancelled due to the high costs. Instead, ATP UK and its new owners will examine al-ternatives, most likely an FPSO, and will seek to reduce costs via a farm-out of the license.
Another troubled North American indepen-dent, Antrim Energy, is selling its UK North Sea subsidiary to First Oil Expro for $53 mil-lion. This follows problems related to fnanc-ing of the Causeway feld subsea tieback to the North Cormorant platform, which were com-pounded when the platform had to be shut down last September.
First oil fows from AmstelGDF Suez has started production from
Amstel, its frst oilfeld development in the Dutch North Sea. Oil is produced through the Q13a-A platform and transported through a new 25-km (15.5-mi) subsea pipeline to TAQA’s P15 platform to the northwest. At peak, Amstel should deliver 15,000 b/d of oil, with a production life estimated at 10 years. •
Location of the Cheviot field in the UK northern
North Sea. (Courtesy Petroleum Equity)
Johan Sverdrup will be developed with four platforms. (Image courtesy Statoil)
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G U L F O F M E X I C O Bruce Beaubouef • Houston
22 Offshore March 2014 • www.offshore-mag.com
BOEM outlines Gulf of Mexico lease sale offer
The US Department of the Interior will of-fer more than 40 million acres for oil and gas exploration and development in the Gulf of Mexico in March lease sales.
Secretary of the Interior Sally Jewell and Bu-reau of Ocean Energy Management (BOEM) Director Tommy P. Beaudreau say Lease Sale 231 in the Central Planning Area and Lease Sale 225 in the Eastern Planning Area will be held consecutively in New Orleans, Louisiana, on March 19. The sales will be the fourth and ffth offshore auctions under the Administration’s Outer Continental Shelf Oil and Gas Leasing Program for 2012-2017 (Five-Year Program).
Sale 231 encompasses about 7,507 unleased blocks, covering 39.6 million acres, located from three to 230 nautical miles offshore Louisiana, Mississippi, and Alabama, in water depths ranging from 9 ft (3 m) to than 11,115 ft (3,400 m). BOEM estimates the proposed sale could result in the production of approximate-ly 1 Bbbl of oil and 4 tcf of natural gas.
Sale 225 is the frst of only two lease sales pro-posed for the Eastern Planning Area under the Five-Year Program, and it is the frst sale offer-ing acreage in that area since Sale 224 in March of 2008. The sale encompasses 134 whole or partial unleased blocks covering about 465,200 acres in the Eastern Planning Area. The blocks are at least 125 mi. (201 km) offshore in water depths ranging from 2,657 ft (810 m) to 10,213 ft (3,113 m). The area is south of eastern Alabama and western Florida. BOEM estimates the sale could result in the production of 71 MMbbl of oil and 162 bcf of natural gas.
In addition to opening bids for these two sales, BOEM will open any pending bids sub-mitted in Western Planning Area Sale 233 for blocks located or partially located within three statute miles of the maritime and continental shelf boundary with Mexico (the Boundary Area). Any leases awarded as a result of these bids will be subject to the terms of the US-Mex-ico Transboundary Hydrocarbons Agreement.
Lucius spar installation completed
Anadarko has completed installation of the 80,000 b/d oil capacity Lucius spar in deepwa-ter Gulf of Mexico. The topsides are expected to be towed to location in 1Q 2014.
Lucius is on schedule toward frst oil produc-tion in the second half of 2014, said Anadarko, and construction on the Lucius-look-alike Hei-delberg spar is more than 70% complete. Hei-delberg is on schedule for frst oil production in 2016.
Anadarko’s 2013 deepwater GoM success was highlighted by the emergence of the Shenandoah basin. Following the Anadarko-operated Shenan-doah-2 appraisal well, which encountered more than 1,000 net feet of oil pay, and oil discoveries
at the nearby Coronado and Yucatan prospects, Anadarko enhanced its ownership position in, and will become the operator of Coronado.
Anadarko is the only company with owner-ship in all three discoveries in the Shenandoah basin. In addition, Anadarko and its partners are accelerating appraisal activity in the basin with appraisal wells under way at Coronado and Yucatan, and a rig committed to drill a delinea-tion well at Shenandoah beginning in 2Q 2014
Shell starts second Mars production
Shell has started producing from the deep-water Mars B platform in the Gulf of Mexico. Production is going through the Olympus installation, making this the frst deepwater GoM project to expand an existing oil and gas feld with signifcant new infrastructure.
Shell said this should extend the life of the greater Mars basin production to 2050 or be-yond. When added to future Olympus produc-tion, the original Mars platform is expected to deliver a total of 1 Bboe.
“We safely completed construction and in-stallation of the Olympus platform more than six months ahead of schedule, allowing us to begin production early from the develop-
ment’s frst well,” said John Hollowell, execu-tive VP for Deep Water, Shell Upstream Ameri-cas. “Olympus is the latest successful start-up of our strong portfolio of deepwater projects, which we expect to generate substantial value in the coming years. Deepwater will continue to be a core growth opportunity for Shell.”
In addition to the Olympus drilling and pro-duction platform, the Shell Mars B develop-ment includes subsea wells at the West Boreas and South Deimos felds, export pipelines, and a shallow-water platform at West Delta 143. Olympus is in approximately 945 m (3,100 ft) of water.
Using the Olympus platform drilling rig and a foating drill rig, additional development drill-ing will enable ramp up to an estimated peak of 100,000 boe/d in 2016. Mars feld produced an average of over 60,000 boe/d in 2013. Partners in the development are operator Shell, 71.5%; and BP, 28.5%.
BSEE, Coast Guard respond to well control incident
On Jan. 31, the Bureau of Safety and Environ-mental Enforcement (BSEE) announced that along with the US Coast Guard it was respond-ing to a loss of well control in Vermilion block 356. Vermilion block 356 is located about 108 mi (174 km) southwest of Lafayette, Louisiana.
EnVen Energy Ventures LLC reported a natural gas fow while drilling from the Rowan Louisiana, at the A production platform. The gas was diverted overboard and work began immediately to shut in the well. No visible sheen was reported. Personnel were evacu-ated, no injuries were reported, and all oil and gas production at the platform was shut in.
BSEE approved EnVen’s plan to kill the well with mud, and pumping began the afternoon of Jan. 31. By Feb. 3, the well control incident had been resolved. The BSEE reported that weighted drilling fuids had been pumped into well A-7 to stop the uncontrolled fow. The agency said that it will require additional work at the site, including setting of barriers to en-sure no further gas release. •
Shell says production from the deepwater Mars B platform has begun, marking the first deepwa-
ter GoM project to expand an existing oil and gas field with significant new infrastructure. (Photo
courtesy Shell)
Anadarko says it has completed installation of
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Last year, Dockwise transported the spar on
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S U B S E A S Y S T E M S Gene Kliewer • Houston
24 Offshore March 2014 • www.offshore-mag.com
Åsgard gets power distribution units Schneider Electric has delivered to Aker Solutions three control
power distribution units (CPDU) for the Åsgard subsea compres-sion station project. Two CPDUs will be installed on the subsea tem-plate, with the third being a spare. The Åsgard CPDUs will provide fully redundant low voltage power for the world’s frst subsea gas compression station.
The three CPDUs have been delivered to Egersund, Norway, where the mechanical, electrical, and automation integration and fnal testing of the complete subsea unit are being performed.
Åsgard feld, in 300 m (984 ft) water depth offshore Norway, is op-erated by Statoil with partners Eni, ExxonMobil, Petoro, and Total.
Ceona to install umbilicals for Bennu in Gulf of Mexico
Bennu Oil and Gas has contracted Ceona to work on the Clipper Contingency Umbilical Installation Project in the Gulf of Mexico. The project is to install 1.1 mi (1.77 km) of dymanic umbilical and two 15-mi (24-km) electrical quad cables in more than 3,000 ft (914 m) of water.
Offshore work is planned to commence in May 2014 using the Normand Pacifc. The vessel is chartered by Ceona and, once de-livered in April 2014, it will be ftted with a 75 metric ton (82 ton) vertical lay tower and two new high-specifcation Work Class ROVs for deepwater fexible installation and subsea construction. The ves-sel is 122 m (400 ft) long by 23 m (75 ft) in beam and also has a 200 ton knuckle boom crane.
Delta SubSea buys ROVs from Schilling Robotics
As part of Delta SubSea’s frame agreement with FMC Schilling Robotics, DSS has fnalized an order to receive an additional feet of four work-class ROV systems to be delivered in February-to-April.
Schilling Robotics is to supply two additional Schilling HD 150-hp work-class ROV systems and two Schilling UHD 200-hp work-class ROV systems.
DSS will add the new ROVs to its feet to service the global oil and gas offshore drilling support, construction, and inspection, mainte-nance, and repair (IMR) markets.
Shell agrees to sell interest in BC-10 offshore Brazil
Shell has agreed to sell a 23% interest in the BC-10 deepwater devel-opment offshore Brazil to Qatar Petroleum International for $1 billion. Shell will continue to operate BC-10 with a 50% working interest.
The transaction is subject to approval by the National Petroleum and Gas Agency (ANP) and the Administrative Council for Econom-ic Defense (Brazil’s anti-trust authority).
BC-10 produces approximately 50,000 boe/d. Since coming on-stream in 2009, BC-10 has produced more than 80 MMboe. Phase 2 of the project, to tie-in the Argonauta O-North feld, came online on Oct. 1, 2013, with an expected peak production of 35,000 boe/d. The fnal investment decision for Phase 3 of the BC-10 project was taken in July 2013 and once online is expected to reach a peak production of 28,000 boe/d.
Martin Linge platform hookup awarded
Technip has awarded Rosenberg WorleyParsons a hookup and commissioning contract for Total’s Martin Linge platform in the Norwegian North Sea.
Estimated value of the contract is $92 million.Onshore preparations start with mobilization to France and sub-
sequently South Korea, with a project team to be established at
some point at Rosenberg WorleyParsons’ facilities in Stavanger.The contractor expects main offshore activity to be executed dur-
ing mid-2016.Ågotnes-based Atlantic Offshore’s newest offshore support ves-
sel Ocean Marlin will operate at the Martin Linge feld.The hull recently was launched at the Astilleros Zamakona Pasaia
shipyard in San Sebastian, northern Spain. Currently the vessel is undergoing painting, drydocking, and out-
ftting. It is expected to be delivered by end-July.The Martin Linge development will consist of a production fxed
platform, a foating storage offoading vessel, 50 MW AC electric power from shore through a 160-km (100-mi) subsea cable, a 24-in. gas export pipeline, and an offshore control center in Stavanger.
Martin Linge is 180 km (112 mi) west of Bergen, Norway, in a water depth of 115 m (377 ft). •
MAN Diesel & Turbo is installing its first-ever hermetically sealed compressor on an offshore production platform. The HOFIM (High-Speed, Oil Free, Integrated Motor) compressor is going onto Det norske oljeselskap’s Ivar Aasen develop-ment in the North Sea. The Ivar Aasen installation comprises a multi-stage radial compressor (1x100%) arranged in tandem around a centrally positioned 9.5 MW high-speed electrical motor. The compressor is used to export produced gas into a subsea pipeline to shore.
Deepwater spending to grow 130%Deepwater expenditure is expected to increase by 130%,
compared to the preceding five-year period, reaching $260 bil-lion from 2014 to 2018, forecasts Douglas-Westwood.
As production from mature onshore basins and in shal-low water declines, development of deepwater reserves has become increasingly vital. Robust oil prices support the in-vestment as sustained high oil prices over the past few years increase confidence in the sector.
Africa and the Americas continue to dominate deepwater capex, with $213 billion to be spent over the next five years. Africa is forecast to experience the greatest growth among the three regions, as East African natural gas developments begin production and become more prominent in the latter years of the forecast period. Latin America will remain the largest market and North America is expected to experience the least growth.
Douglas-Westwood has identified a temporary trough in global expenditure in 2015 primarily driven by delays to deliv-ery of FPS units in Latin America. African projects have also experienced delays resulting in a surge in capex from 2016 onward.
1403OFF_24 24 2/28/14 4:51 PM
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V E S S E L S , R I G S , & S U R FA C E S Y S T E M S Russell McCulley • Houston
26 Offshore March 2014 • www.offshore-mag.com
Fecon taps Keppel for frst jackupsKeppel FELS has won contracts worth $650 million to build three
high-specifcation jackups for startup Fecon International Corp. The KFELS B Class rigs are scheduled for delivery in 2H 2016. Fecon, a new offshore player with Russian roots, is targeting markets in Africa, the Middle East, and Southeast Asia, “and has identifed off-shore drilling in Russia as a strategic market with good growth op-portunities,” Keppel said.
Keppel FELS also reported a $218-million contract with UMW Drilling 8 for a KFELS B Class rig to be delivered in 3Q 2015. The shipyard has another jackup, UMW NAGA 5, under construction for the Malaysian driller, and in early 2013 delivered they UMW NAGA 4, which is currently working offshore Malaysia.
CIMC builds backlog Yantai CIMC Raffes Offshore Ltd. has secured orders for a new-
build drillship and a harsh environment semisubmersible, with op-tions for an additional four drilling rigs. The drillship, for Norwegian drilling contractor Norshore, will be a small multi-purpose vessel designed for riserless drilling and well intervention. Delivery is scheduled for 2H 2016. Norshore has options to build up to three similar drillships.
CIMC also received an order from Beacon Holdings Group Ltd. for an ice class semisubmersible based on the GM4-D design. Dubbed the Beacon Atlantic, the rig will be capable of drilling to 8,000 m (26,247 ft) in water depths up to 500 m (1,640 ft). The con-tract carries an option for one additional semisub. CIMC has sched-uled delivery of the Beacon Atlantic in 4Q 2016.
Ensco divests idle rigsEnsco has sold its two remaining cold-stacked jackups for $33
million. The rigs, ENSCO 69 and Wisconsin, both date to 1976. The London-based company has been undergoing a feet upgrade over the past four years, having sold 13 older rigs and taken delivery of 12 high-performance units, including fve ultra-deepwater drillships, fve ENSCO 8500 series semisubmersibles, and two harsh-environ-
ment jackups. Ensco has three more drillships and three premium jackups under construction.
Wison to build second foating regas unitEXMAR and Pacifc Rubiales have placed an order with Wison
Offshore & Marine for a barge-based foating LNG regasifcation unit, to be delivered in 4Q 2015. Wison will build the unit at its Nan-tong, China, shipyard. The companies have collaborated on the Pa-cifc Rubiales-operated Caribbean FLNG project offshore Colombia, which is scheduled to begin processing gas from an onshore feld in 2Q 2015. In January, Wison announced that it will supply a barge-based regasifcation unit to VGS for an LNG import project offshore Andhra Pradesh, India.
Seadrill inks Pemex contracts
Seadrill has fnalized a set of contracts with Mexico’s Pemex for the West Oberon, West Intrepid, West Defender and West Courageous jackup drilling units. A ffth contract for the recently acquired Pros-pector 3 jackup, renamed West Titania, is expected to be fnalized in 2Q 2014. Each contract is for about six years. Seadrill said the total value of the Pemex deal could exceed $1.8 billion.
The company also announced that it had formed a 50/50 joint venture with investment company Fintech Advisory. The new part-nership, SeaMex Ltd., was formed to own and manage the jackups working for Pemex and “to develop and pursue further opportuni-ties in Mexico and other Latin American countries,” Seadrill said.
Kraken contract inkedDeltamarin will provide basic design for the FPSO to be installed
at EnQuest’s Kraken feld in the UK North Sea. EnQuest approved the £4-billion ($6-billion) project in November 2013, and announced that Malaysia’s Bumi Armada would supply the FPSO. Deltamarin had earlier provided Bumi Armada with technical support during the tanker conversion’s front-end engineering and design stage. The turret-moored FPSO will have a storage capacity of 600,000 bbl and measure more than 285 m (935 ft) in length. Production is sched-uled to begin in 2016 or 2017 and peak at a daily rate of more than 50,000 bbl. •
Maersk Drilling held a naming ceremony at the Samsung Heavy
Industries yard in South Korea for the company’s second and third
ultra-deepwater drillships, Maersk Valiant and Maersk Venturer. Maersk
has invested roughly $2.6 billion in four ultra-deepwater drillships to
be delivered by SHI by the end of this year. Maersk Valiant will go to
work for ConocoPhillips and Marathon Oil in the Gulf of Mexico under a
three-year, $694-million contract with an option to extend for two years.
Maersk Venturer and the fourth rig, which is scheduled for delivery in
3Q 2014, are not yet under contract.
Boskalis subsidiary Dockwise landed a contract with Statoil for the
transportation of two Cat-J jackup drilling rigs from South Korea to Nor-
way. Dockwise plans to deploy the Blue Marlin transport vessel (pictured
delivering the Noble Jim Day in 2010) and sister vessel White Marlin,
which Dockwise plans to put into service this year. The Statoil rigs are
scheduled to leave the Samsung Heavy Industries yard in late 2016 or
early 2017, and will be deployed to the Gullfaks and Oseberg fields.
1403OFF_26 26 2/28/14 4:52 PM
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28 Offshore March 2014 • www.offshore-mag.com
Over the last several months, the offshore industry has taken delivery of quite a few drilling units rated for 12,000-ft (3,659-m) water depth. Since to date the deepest water well measured in at 10,411 ft (3,174 m), the world’s ultra-deepwater drilling contractors must have visions of still deeper frontiers. And judging by the number of units boasting 12,000-ft capability, the contractors must en-visage quite a deepwater boom approaching.
For foating drilling units, deepwater capac-ity is mainly limited by variable deck load. This is the sum of the weights of all movable equip-ment on deck from tubulars, to BOP stacks, to drilling and completion fuids. Another lim-iting consideration is hoisting power, but this more a function of total well depth than water depth.
But for oil and gas well drilling, operators have concerns other than water depth. To en-sure that wells actually reach their intended targets requires formation evaluation, and therein lies a challenge.
The deeper the water, the higher the overall drilling and completion risk. Typically, verti-cal or slightly deviated wells have been evalu-ated by wireline logging measurements. The service companies have done quite a lot of engineering to make the logging process as safe and effcient as possible. Downhole tools are now combinable so almost all needed ser-vices, including fuid samples and formation pressure measurements, can be made in a sin-gle trip, saving considerable time and greatly reducing risk. Schlumberger has launched its new TUFFline extra strength logging cable to address the ultra-deep challenge. When bot-tomhole conditions are considered, wireline
logging has a big advantage. The tool string must be able to withstand the heat and pres-sure at total depth for only a short time.
Operators of high-profle drilling programs value the real-time aspects provided by log-ging-while-drilling (LWD) tools. Incorporat-ed in the drillstring and close to the bit, LWD tool strings provide quality formation evalua-tion, including formation fuid and pressure sampling, with data transmitted to surface in real-time. This enables engineers to “geo-steer” the wellbore into reservoir “sweet spots” while avoiding geohazards. This great-ly reduces drilling risk, so much so that many opt for LWD despite its cost premium.
However, since the LWD instruments must remain at total depth for the entire bit run, they may be exposed to harsh environment condi-tions of pressure and temperature for quite a long time. They are also subject to severe shock and vibration from the drill bit. Rotary steerable systems (RSS) are the preferred method of geo-steering the wellbore because they can make trajectory adjustments faster, and because they eliminate the sliding mode that can hamper drilling performance when mud motors and bent subs are used to direct the drilling. Unfor-tunately today’s RSS typically have temperature ratings below 350°F (175°C).
No matter which formation evaluation type is used, concluding ultra-deepwater drilling operations safely ushers-in a new series of en-vironmental concerns—completions. To im-prove well performance and avoid production risks, operators are investing in sophisticated completions. Besides the obvious desire to maximize production, they must consider fow assurance, sand management, and cor-
rosion. Other concerns focus on cementing and perforating. To cost-effectively mitigate these issues, or perform these services, re-quires accurate measurements of downhole conditions. Later, during production, opera-tors need the ability to make downhole fow adjustments. Downhole pressure and tem-perature gauges, which are at the heart of most production measurements, also have environmental limits. The current tempera-ture record-holder for a downhole pressure gauge is 15 days at 410°F (210°C). Unfortu-nately, the gauge recorded this temperature several hundred meters above total depth, forcing the operator to make correlations to estimate actual reservoir temperature at the completion.
In addition to instrumentation, sealing technology must keep pace with the drillers. Standard elastomeric seals are stressed by el-evated temperatures and pressures. Metal-to-metal seals can deform under pressure; then fail when the pressure is relieved.
For the past few years, good news has been coming ashore from many ultra deep-water projects. Many, if not most, discoveries boast of massive reservoirs, hundreds of feet thick and containing millions of barrels of high-quality crude oil. The prize more than justifes the investment.
But if the industry is going to be successful in drilling, completing, and producing ultra-deep wells in ultra-deepwater, greater strides must be made to develop reliable downhole in-strumentation that can withstand bottomhole conditions for the life of the reservoir. What good are drillships that can drill in 12,000 ft of water and 40,000 ft (12,192 m) of rock if log-ging and production tools cannot perform un-der those conditions? •
How deep can the industry go?
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30 Offshore March 2014 • www.offshore-mag.com
3D seismic survey underway off Namibia
A 3D seismic survey has commenced in license area EL 0037 offshore Namibia, says Pancontinental Oil & Gas. The 3D acquisition will cover 3,000 sq km (1,158 sq mi) and a sec-ond acquisition phase of 2D data will cover ap-proximately 1,000 line km (386 mi). The total acquisition is expected to take up to 120 days.
The survey is managed by the EL0037 joint venture operator Tullow Oil, using the seismic acquisition vessel Polarcus Asima.
Tullow Oil farmed-in to EL 0037 in Sep-tember 2013 and subsequently identifed a number of geological leads to be covered by the 3D survey.
Pancontinental retains a 30% free-carried interest through the surveys and one op-tional well to be drilled by Tullow, for Tullow to retain its 65% interest. Pancontinental esti-mates that Tullow’s farm-in expenditure may be up to $130 million for the full program.
Eco (Atlantic) Oil & Gas has an updated re-source report on block 2012A (Cooper) in the Walvis basin offshore Namibia.
According to Colorado-based Gustavson As-sociates, the P50 best estimate is 4.5 Bboe of gross prospective oil over the existing targets.
The report evaluated an additional 700 km (435 mi) of recently acquired 2D seismic data. Eco retained PGS in the UK to work with its in-ternal team to complete a new detailed geolog-ical and geophysical interpretation of Cooper.
Overall, the report is based on interpretation of more than 1,450 line km (901 mi) of 2D data and an analysis of PGS’s study on the block.
The Namibian Ministry of Mines and Ener-gy has granted a one-year extension to March 2016 of the initial exploration period for the license.
Elsewhere offshore Africa
SeaBird Exploration will work with part-ner Acorn Geophysical on an additional 3D seismic acquisition project offshore West Africa in the Gulf of Guinea.
The 1,100-sq km (425-sq mi) survey is an extension of a 1,500-sq km (579-sq mi) 3D proj-ect announced earlier this year. Pre-funding for the two programs totals around $8 million. The survey vessel Geo Pacifc will acquire the added data.
Marathon Oil says evaluation continues of last year’s Diaman-1B exploration well on the Diaba license G4-223 offshore Gabon, operated by Total.
Marathon announced in August that the well encountered 160-180 net ft (48.7-55 m) of hydrocarbon pay in the deepwater presalt play. Early analysis suggests the hydrocar-bons are natural gas with condensate con-tent, although this remains to be confrmed.
Marathon, which holds a 21.25% interest
in the license, says the partners have identi-fed numerous other presalt prospects.
Last October, the company was the high bidder as operator of two deepwater blocks in the presalt. Gabon’s government has since withdrawn one of the blocks. Award of the other block is pending government ap-proval and negotiation of an exploration and production-sharing contract.
Ophir Energy plc has begun drilling on the Padouck Deep-1 well on the Ntsina block, offshore Gabon, using the Vantage Drilling Titanium Explorer drillship.
The Padouck Deep-1 well is the frst well targeting the presalt play offshore in the North Gabon basin, and is located in a water depth of 835 m (2,740 ft) and has a planned TD of 3,500 m (11,483 ft). Operations are ex-pected to take approximately 45 days.
Afren claims its Ogo discovery offshore Nigeria is one of the largest worldwide, with potential recoverable resources of 774 MM-boe. Ogo is in license PL 310 in the Upper Cretaceous fairway that runs along the West African transform margin.
Afren says the syn‐rift play that delivered a 280-ft (85-m) gross hydrocarbon column in the Ogo well also exists on the company’s ad-jacent OML 113 license. The company plans to acquire 3D seismic ahead of appraisal and additional exploration drilling.
This year Afren and its partners will start development of three more shallow-water Nigerian discoveries, namely the Okoro Further Field Development, the Ebok North Fault block, and Okwok.
Foz do Amazonas 3D survey ongoing
CGG and Spectrum say acquisition of the BroadSeis 3D multi-client survey program offshore Brazil in the Foz do Amazonas ba-sin is going as planned. The two companies
are equal partners on this project which has received high prefunding.
The 11,330-sq km (4,378-sq mi) survey is being acquired by the Oceanic Endeavour deploying Sercel’s new-generation Sentinel RD solid streamer. The data set will be pro-cessed in CGG’s Rio de Janeiro subsurface imaging center.
CNOOC wins Iceland license
Orkustofnun, Iceland’s National Energy Authority, has granted its third license in the offshore Dreki area.
CNOOC Iceland will operate with 60% interest, in partnership with Eykon Energy (15%) and Petoro Iceland (25%).
Applications for the third licensing round for the Dreki area between Iceland and Nor-way closed last April.
The other successful consortia were Itha-ca Petroleum, Kolvetni and Petoro Iceland; and Faroe Petroleum Norge, Íslenskt kol-vetni, and Petoro Iceland.
Norway’s oil ministry said that Norway teamed last year with CNOOC to explore for oil offshore Iceland. Under a 1981 treaty, Norway has a right to take a 25% stake in Iceland’s oil licenses, and the Norwegian government decided to exercise this right to join an exploration license with CNOOC in the waters between Iceland and Norway’s Jan Mayen Island.
The Dreki Area is part of the Jan Mayen ridge micro-continent, thought to have sepa-rated from the continental shelf of Green-land and Norway via plate tectonic move-ments 45-60 million years ago. A Strategic Environmental Assessment of the Dreki Area, and research on the marine biosphere, climate and sea conditions, suggest there is no danger of sea ice and wave heights are lower than off Norway’s west coast. •
SEAM data publicly availableThe SEG Advanced Modeling Program (SEAM) Earth Models and synthetic data
sets from the Phase I project are now publicly available to license. The license fees are based on distribution media of external USB drives or, for smaller sets, DVDs or flash drives.
The SEAM data provides benchmarking tools to test imaging and inversion algo-rithms; better understand features and artifacts in real image; and explore trade-offs in acquisition methodologies. The SEAM data also provides teaching tools for aca-demia to train the next generation of seismic processing and imaging experts.
Five earth models were generated in SEAM Phase I to simulate a realistic earth model of a salt canopy region of the Gulf of Mexico. The models range in size from 3 GB to 426 GB. The data sets are available ranging in size from approximately 4 GB to 1.6 TB. The majority of the data sets are compressed, and decompression codes are included with each set.
The Phase I project was initiated in March 2007 with the primary goal of designing and generating synthetic model 3D geophysical data that represents exploration and subsurface characterization challenges to the consortium members.
Following SEAM Phase I, SEAM launched Phase II, Land Seismic Challenges, which is currently under way. A SEAM Phase III, Pressure Prediction and Hazard Avoidance, is planned for 2014-2016.
1403OFF_30 30 2/28/14 4:52 PM
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O F F S H O R E A U T O M AT I O N S O L U T I O N S
32 Offshore March 2014 • www.offshore-mag.com
Ian VerhappenIndustrial Automation Networks Inc.
All of us are aware that we are being inundated with data at an ever increasing rate. But how often are we able to use all this infor-mation to make informed decisions? Getting from data to action is a multi-step process in several dimensions.
The key to managing all this data is standards. Without standards to defne the format in which the information is to be converted from bits into a signal – light (fber optic), frequency (wireless), volt-age or current (cable) – so that it can be transmitted and received as packets of information, it would all simply be noise. It is likely that a single packet of information moves from a feld sensor in an offshore facility to the control room and then eventually to the cor-porate MES (manufacturing execution system) or ERP (enterprise resource planning) system.
Due to space limitations and to avoid becoming overly technical, the focus here will be on the data fow side of the equation.
The four levels of transformation when moving from data to action are: data (raw data collected from feld sensors, operators, purchase
orders, inventory levels, etc.), information (putting this information into context of place, time, relative amounts), knowledge (how the change in information affects the stability of the operation), and ac-tion (doing something to maintain equilibrium in the system). Let’s take a look at each of these levels in more detail from the perspec-tive of feld devices.
Today’s feld sensors and actuators, including motor drives, all sup-port some form of digital communication technology, whether it is HART, one of the all-digital protocols such as Modbus, or one of the many feldbuses. In addition to the process signal, these devices can convey more than 300 parameters used to determine the health of the device, and hence not only the reliability of the signal itself but also the ability to predict when and what form of maintenance will be re-quired to keep the signal within acceptable levels of tolerance. Taking advantage of this information means you will only operate your facility on information that you know is good, and with a bit more work allows you to better manage your spare parts and equipment maintenance.
Using the single status byte converts the data into information. However, to move the balance of the data from these feld devices requires more work, typically in the form of intelligent device man-agement. The International Society of Automation has a committee, ISA-108, working on standards for data fow and work practices in this area, so that data can consistently be used for more reliable operation of feld devices and control systems.
Once it has been identifed that device maintenance is required, the technicians then have to connect to the device. In the case of most process industries and hence offshore platforms, that will mean an EDDL (electronic device description language)-based de-vice. However, the connection to that device or other devices such as motors may use other protocols to identify the problem, and then take corrective action without having to physically go into the feld, thus reducing exposure hours of personnel. FDT technology is a widely used tool to provide a graphical interface to view and in some cases change the information in the device for a wide range of pro-
tocols with a common “look and feel” as defned in the ANSI/ISA-62453 (103) documents based on the IEC 62453 series of standards.
Field device data is also being used in control systems to maintain steady operations – and in the case of some advanced applications, to identify patterns of measurements indicating anomalies in the opera-tion of other equipment such as separation vessels, heat exchangers, and pumps. The information indicates when equipment is not operat-ing within or is approaching the limits of its design envelope.
Experienced operators know that when they see a pattern of read-ings, or hear a certain noise from a piece of equipment, that they have to respond in a certain way. This represents the knowledge that we are striving to capture with automated systems as represented by an-other ISA standard, ISA-106 (“Procedure Automation for Continuous Process Operations”), as well as at the higher levels of the enterprise ERP and CMM (continuous maintenance management) systems.
There are two primary organizations working to integrate the control system with enterprise systems: the ISA-95 Best Practices Working Group (“Enterprise-Control System Integration”) and the Manufacturing Enterprise Solutions Association (MESA). They are defning the methods by which data can be consistently trans-
ferred between the various levels of an enterprise so that it can be integrated with business data points such as inventory, pricing, and workforce availability/planning.
Each of these systems is integrating ever more data into models that convert it into a form from which the systems themselves – through knowledge coded into them as rules, procedures, and al-gorithms – can automatically take action, or alert a person about the situation so that they can take the appropriate action in a timely manner, whether they are in an offce in Houston, on a rig in the Gulf of Mexico, or on a deep sea production facility.
Reliable deepwater installation requires tight integration with all levels of the enterprise to manage the logistics of keeping the fa-cility operating with spare parts, food and water, and maintenance. Integrating data from weather satellites and GPS signals with the rig controls keep the platform stable and properly oriented in the right location over the drilling or production site.
The tools and processes used to turn data to information, informa-tion to knowledge, and knowledge to action, are in many cases what separate the successful offshore companies in all facets of operation – drilling, production, safety, and environment – from their peers. Each of us, therefore, needs to answer the question of where are we in this hierarchy of integrated business operations. Our role as engi-neers and managers is to enable people to make the right decisions and take the actions that will maximize return on investment while being sure that everyone gets home safe at the end of the day. •
The AuthorIan Verhappen, P.Eng., is an ISA Fellow, ISA Certifed Automation Professional
(CAP), Automation Hall of Fame member, and a recognized authority on process
analyzer sample systems, Foundation Fieldbus, and industrial communications tech-
nologies. Verhappen provides consulting services in the areas of feld level industrial
communications, process analytics and hydrocarbon facility automation. Feedback is
always welcome via e-mail at [email protected].
Turning data into actions Effective data integration essential to safe and effcient operations
Reliable deepwater installation requires
tight integration with all levels of the enterprise.
1403OFF_32 32 2/28/14 4:52 PM
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R E G U L AT O R Y P E R S P E C T I V E S
Kenneth HurwitzHaynes and Boone, LLP
No one knows for certain what will turn up when a drill bit reaches target depth, but seis-mic data allow robust estimates of the prob-ability of success. This has never been truer than today as a result of dramatic technologi-cal advances in seismic surveying and com-puter modeling. But scientifc understanding of the environmental impacts of seismic ac-tivities has not kept pace, and the regulatory state of the art is relatively unsophisticated. These issues are now coming to a head in the US, where future seismic activities and leasing in the mid-Atlantic and South Atlantic areas may hang in the balance.
The basics of seismic exploration can be simply explained. A seismic survey uses sound energy to map geological structures under the seabed. Specialized vessels tow air guns that use compressed air to produce pulses of high-energy, low-frequency sound waves that travel through rock layers beneath the seabed and bounce back to hydrophones that measure the strength of the waves and their return time. Computer modeling of these measurements produces a detailed picture of the structures
and rock formations in the survey area.Rudimentary aspects of the impacts of air
guns on marine mammals and fsh are well understood. It is generally agreed that for a seismic sound to result in auditory impair-ment or other physical harm to marine mam-mals, animals must be located within a short distance from the sound source. Most marine mammals, including certain types of whales, generally avoid active seismic vessels and swim away when one is in the vicinity. Some marine mammals, on the other hand, such as dolphins, are known to “bow ride” (ride in the wake at the vessel’s bow) with no apparent harmful impacts. Also, there is evidence that, if seismic surveys were to occur when a large aggrega-tion of marine mammals, fsh, or sea turtles were present, they could result in the displace-ment of breeding, feeding, or nursing activities, dispersion of fsh in spawning areas, and diver-sion from migration routes. In other words, there are potentially detrimental consequences. But the risks are poorly quantifed or unknown.
It is not yet possible to establish unequivo-cal criteria for determining the zone of in-fuence around a noise source. Sound infu-ences different species differently, based on physiological variations and conditions of the
environment, and experimental data are lim-ited. For example, determining the energy levels that could cause temporary threshold shift (temporary hearing loss) in whales is extremely diffcult because of challenges in replicating real-world conditions and in accu-mulating data from adequately sized sample populations. Moreover, it is impossible to ex-trapolate reliably from one species to another. The gaps in scientifc research are wide, and they will not be eliminated any time soon.
Faced with these challenges, regulators seem to have coalesced around several ba-sic mitigation measures intended to reduce the risk to marine mammals and fsh. The frst of these is a prohibition against night-time activities and the establishment and monitoring of safety zones by a trained ma-rine mammal observer. If a whale, dolphin, porpoise, or sea turtle is spotted within the safety zone, the air source array must be shut down or postponed until the animal leaves (although continued release of a minimum amount of sound is allowed in some cases to deter entry by others). In addition, seismic operators are required to take advantage of the characteristic avoidance behavior of most marine species by using a start-up technique
Proposed offshore seismic rules appear to lack scientifc rigor
1403OFF_34 34 2/28/14 4:52 PM
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whereby activation of air source arrays takes place gradually over a fxed period of time. Reporting requirements for survey activities and sightings are also common. Finally, pas-sive acoustic monitoring is required by some regulatory regimes to assist in mitigation ef-forts. This technique can detect sound waves generated by species that propagate noise in mating behavior or for echolocation. All of these measures, except the last are, under a 2012 Notice to Lessees, required of all US les-sees that wish to conduct seismic survey op-erations in waters deeper than 200 m (656 ft) throughout the Gulf of Mexico, and in waters of any depth east of 88° longitude.
While the above mitigation measures are commonly required around the globe, no one knows how effective they really are. The problem is coming to a head in the US, where the draft Programmatic Environmental Impact Statement for Proposed Geological and Geophysi-cal Activities in the Mid-Atlantic and South Atlan-tic Planning Areas, a document mandated by Congress in 2010, will soon be issued in fnal form by the Bureau of Ocean Energy Manage-ment. The terms under which future seismic activities will be conducted in these areas will be heavily infuenced by its content. These ac-tivities, in turn, will determine whether the re-gion’s hydrocarbon resources are suffciently robust to support future leasing.
Intended as a tool for decision making by regulators, the draft statement is an unfortu-nately blunt and unwieldy instrument. It consid-ers two different sets of mitigation measures, Alternative A and Alternative B, distinguished by the relative level of protection they afford, and Alternative C, which would ban seismic air gun surveys in the area. Alternative B would require passive acoustical monitoring, impose a 25-mi (40-km) distance between simultaneous-ly operating deep-penetration seismic air gun surveys, ban air gun surveys in near-coastal waters offshore Brevard County, Florida, dur-ing sea turtle nesting season, and create an expanded zone off the Atlantic coast adjacent to the right whale critical habitat area, where surveys would be banned from Nov. 15 through April 15. Alternative A contains none of these measures; it roughly corresponds to the mea-sures in the Notice to Lessees described above.
The draft statement, while lengthy, appears to lack scientifc rigor. It merely estimates that the “expanded time-area closure” would reduce ves-sel strikes and acoustic impacts on right whales and other marine mammals by approximately 13%, a fgure whose origins seem unclear, and that the expanded Brevard offshore time-area closure would substantially reduce the impact on sea turtles. Furthermore, the statement is silent on the critical issue of how the additional restrictions would affect industry. Whether they would hurt the economics and predictive utility of seismic surveys is simply not addressed.
In light of the defects of the draft state-ment, industry is taking the position that the fnal version must be buttressed with the lat-est research data, and that the analysis must be expanded to address the impact of addi-tional restrictions on industry’s ability to con-duct seismic exploration. If improvements are not made, regulators would simply not be in a position to balance the benefts of addi-tional restrictions against the costs. In effect, they would be shooting in the dark. •
The author Ken Hurwitz is a partner at Haynes
and Boone, LLP, an international law
frm headquartered in Texas. A gradu-
ate of the University of Pennsylvania
Law School and the Wharton School,
Hurwitz is an energy and environ-
mental regulatory lawyer representing
clients in the oil and gas production,
transportation, and marketing sectors. He is a recog-
nized authority on offshore safety, operational, and
environmental regulation.
1403OFF_35 35 2/28/14 4:52 PM
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38 Offshore March 2014 • www.offshore-mag.com
A S I A / PA C I F I C
Sembcorp to integrate Singapore yards
at new ‘mega’ shipyardGovernment support helps local industry maintain competitive edge
Sembcorp Marine has set up a mega-shipyard in Singapore to service the global oil and gas and marine sectors, and to maintain a competitive edge in the construction of explora-tion rig and production platforms, ship conversion, repairs, and maintenance.
Prime Minister Lee Hsien Loong opened the frst phase of Semb-marine Integrated Yard @ Tuas on Nov. 6, 2013, 50 years after the industry began in 1963 as part of Singapore’s industrialization pro-gram to support its then fedgling economy.
Lee applauded the shipyard-based marine and offshore industries survival through the vagaries of economic cycles, but warned of ever-increasing competition from China and South Korea.
Jurong Shipyard, now one of several facilities owned by Semb-corp, launched the national industry with a joint venture between Singapore’s state-owned Economic Development Board (EDB) and Ishikawajima-Harima Heavy Industries (IHI) of Japan in 1963. As Singapore’s frst commercial shipyard offering ship repair services, Jurong Shipyard was part of the government’s effort to develop the marine and offshore industry as one of the key elements of indus-trialization. It offcially opened in March 1972, and incorporated a fshing islet of Samulun with a wooden pontoon bridge over a short water rivulet.
Sembawang Shipyard, the second of the Sembcorp Marine’s yards, was started when the British pulled out of the city state and the Far East, leaving behind a vast, unused naval base. Sembawang started operations from the Royal Navy Dockyard in late 1968 under the management of Swan Hunter Group, the biggest and most fa-mous ship repair group at the time.
Today, Sembcorp Marine and Keppel Marine & Offshore, the sec-ond shipyard-based group, have thriving operations in major mar-kets across the globe.
“These industries have come through the diffcult times of the 1970s and severe recessions of the 1980s,” Lee pointed out.
He also recalled how many had doubted the industry’s long-term viability in those challenging years.
“Our marine and offshore industry has established a leading posi-tion in the world, even though Singapore does not have enough land and indigenous oil and gas production,” Lee noted.
“Two of the world’s top companies in this industry are from Singa-pore – Sembcorp Marine and Keppel Offshore & Marine. And both are thriving today, starting from humble beginnings,” he said.
Lee assured more government support for the industry, having reclaimed the Tuas site on the west coast of Singapore for Sembcorp yards, and pledged support for infrastructure to keep the industry vibrant.
“We’ve got to keep upgrading ourselves,” he said.He noted a goal of Sembcorp’s former president, K.K. Tan, to
consolidate the group’s yards at one site for overall effciency. Lee pointed out that it took over a decade to achieve that goal. Tan has retired after more than 50 years in the industry and now is an ad-viser to Sembcorp.
Government supportThe prime minister said the government would support the indus-
try with manpower training and continue to work on talent and skills development for the marine and offshore sector.
Gurdip SinghContributing Editor
(Above) The Sembmarine Integrated Yard @ Tuas will eventually cover
more than 200 hectares. By 2024, Sembcorp plans to consolidate its
five Singapore shipyards at the site.
1403OFF_38 38 2/28/14 4:56 PM
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Elaborating on Lee’s comments, Singa-pore Minister of Trade and Industry Lim Hng Kiang stressed the need for the indus-try to continue its progress.
“Notwithstanding the current global leader-ship position, the industry needs to continue to innovate and to transform itself to stay ahead of the competition,” said Lim. “This is especially important as land and manpower become increasingly valuable in our resource-scarce Singapore.”
Lim highlighted Sembcorp’s investment in the integrated yard at Tuas and the com-pany’s collaboration with Palfnger Systems to jointly develop the hull treatment system.
“This fully automated (hull treatment) system integrates the washing, blasting, and coating processes. Apart from cost, material, and manpower savings, this system will also result in the reduction of dust emissions,” noted Lim.
Lim said the government would partner with and support the marine and offshore industry in its transformation efforts.
“First, we will help companies to increase their design and engineering capabilities through the public research infrastructure
such as the Singapore Maritime Institute and ocean basin test facility,” he said.
“Second, we will work with companies to look for ways to improve overall productivity through new production technologies, train-ing, equipment, and machinery.
Singapore’s Prime Minister Lee Hsien Loong,
second from left, views a model of the new
consolidated shipyard.
1403OFF_40 40 2/28/14 4:56 PM
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“Third, we will help the industry attract and develop talent by partnering the rel-evant educational institutes to introduce programs focused on offshore engineering, petroleum engineering, naval architecture, and marine engineering.”
Lim continued: “While we look forward to a bright future for the marine and offshore industry in Singapore, industry leaders such as Sembcorp Marine need to continue to forge ahead to develop innovative solu-tions for the needs of tomorrow.”
At the same time, Lim noted that “the supporting ecosystem of industry partners, suppliers, and sub-contractors also needs to continually transform and upgrade so as to keep pace with the changing needs of the world.”
Integrated yardSembcorp’s Singapore shipyards – Jurong
Shipyard, Sembawang Shipyard, Sembawang Marine and Offshore Engineering (SMOE), rig builder PPL Shipyard, and vessel repair company Jurong SML – will be consolidated at the new Sembmarine Integrated Yard @ Tuas by 2024. The 73.3-hectare Phase 1 be-gan operations on Aug. 5, 2013, while yard de-velopment work continues on the other two phases at the 206-hectare site.
Phase 1 of the new yard has four very large crude carrier (VLCC) drydocks with a total dock capacity of 1.55 million deadweight metric tons, as well as fnger piers and basin lengths totaling 3.9 km (2.4 mi).
The facilities include a drydock, YST D2, measuring 360 m (1,181 ft) in length by 89 m (292 ft) in width, with a draft of 8.5 m (28 ft). Billed as the widest drydock in Singa-pore, it is designed to accommodate jackup and semisubmersible rigs. Another drydock, YST D3, measures 412 m (1,352 ft) long by 66 m (217 ft) wide, with a draft of 11 m (36 ft), making it what Sembcorp claims is the lon-gest and deepest ship repair drydock in Asia. It is equipped with an innovative intermediate dock gate system and is capable of docking containerships of up to 18,000 TEU (one TEU is equivalent to the measurements of a stan-dard container used on ships). The design provides the fexibility to confgure the dock to allow smaller ships to dock in front while other works are carried out at the rear. There is also a special reinforced load-out area for offshore platforms of up to 20,000 metric tons (22,046 tons). The natural deepwaters at the new yard also enable the installation of thrusters for semisubmersibles without tow-ing the rig to sea, providing signifcant sav-ings for customers.
To maximize the waterfront coverage in land-scarce Singapore, the yard is confgured with three fnger piers and a basin ranging from 201 to 400 m (659 to 1,312 ft) with maxi-mum draft of 9-15 m (30-49 ft), allowing for ultra-deepwater semisubmersible rigs and passenger vessels to be berthed without re-strictions in the new yard.
The 34.5-hectare Phase 2 yard is expected to begin operations in the next three to four years. The site is located adjacent to and north of the Phase 1 development. The yard features the latest in production technologies, processes, and equipment, and represents a major step forward in the marine and off-shore industry’s efforts to transform itself for sustainable long-term growth. It will enhance the Singapore industry’s competitiveness and productivity, and reaffrm Singapore’s position as a global offshore and marine hub, Sembcorp said.
“We are confdent that it will contribute to the further success of Sembcorp Marine in Singapore,” said company chairman Goh Geok Ling. “The new yard is an apt symbol of our growth and expansion. This next-gen-eration yard is a testament of the efforts and strategic investments of our pioneers and leaders who have paved the way to our suc-cess today.” •
1403OFF_41 41 2/28/14 4:56 PM
42 Offshore March 2014 • www.offshore-mag.com
A S I A / PA C I F I C
Innovation keeps Keppel
at the forefront of rig design
New drillship aims for operations offshore Brazil, West Africa
Singapore rig builder Keppel continues to take on the challenges of operating in a high-risk offshore oil and gas sec-tor by using innovative designs, eff-ciency-driven capabilities, and close
working relationships with its customers.“Pressure is always felt. And we treat all our
competitors, including the Chinese shipyards, very seriously,” says Tong Chong Heong, CEO of Keppel Offshore & Marine. But he is quick to point out the advantage of being stra-tegically located in the world’s major hydro-carbon producing regions such as Brazil, the US, Caspian Sea, and Southeast Asia, as well as China.
“Additionally, our policy of being where our customers want us to be, and where the market is, has also helped us. Being close to the customers means…that if it is a re-quirement to be built there, that they (the competitors) would have no advantage com-
pared to us,” Tong says.He also sees the potential of venturing
into more regional yards within the Associa-tion of South East Asian Nations (ASEAN), especially in Malaysia and Thailand. It will be a way to expand its shipyard network outside of its expertise base but land-short Singapore facility.
Keppel, he says, is driven by innovations to meet the ever increasing demand for eff-ciency from international hydrocarbon pros-pecting companies. The company will have to continue to strategize business across the globe, especially given the strong competi-tion from China-based shipyards. “Obvious-
ly, competition from China is a big threat,” he says, noting China’s low-cost funding support to projects implemented at Chinese yards. “But we have been in this business long enough. We have clientele loyal to us, and they know that we will deliver reliably on time and with the quality expected. Own-ers who build rigs with us will not have to have the contingency set in to overcome surprises.” By this he means any delay in completion of capital-intensive project at a shipyard would result in costly disruption to businesses, especially the production from offshore oil and gas felds.
“Risks are always looked at very carefully at Keppel. But then there is a risk and a re-ward we should also be mindful of,” Tong points out. “The capabilities and effciency in the newly built rigs are higher at 10%, 20%, and 30% in terms of time required, in terms of ability to drill deeper, in harsher environ-ment, and more complicated wells.”
Engineering centersWith engineering centers in Singapore, Bul-
garia, Mumbai, Shenzhen, and Houston, the company offers its customers 24 hours a day, seven days a week engineering services. “Our engineering offces in Singapore and around the world collaborate seamlessly through an advanced web-based environment offering 3D design tools and data management functions,” he says.
“This state-of-the-art system enables our engineering centers operating in different time zones to work on projects with high ef-fciency, around-the-clock,” says Tong, who retired in February 2014, leaving behind a legacy of managing multi-billion dollar proj-ects.
The company secured S$7 billion ($5.48 billion) worth of orders in 2013, taking its total order book to S$14.2 billion ($11.12 bil-lion), which will keep the group’s shipyards
Gurdip SinghContributing Editor
The CAN-DO drillship will feature
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(Image courtesy Keppel Offshore & Marine)
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busy through to 2019. It delivered a record 21 rigs in 2013. Keppel remains the world’s leading jackup drilling rig builder, but is also an established semisubmersible rig builder.
Its latest drillship is designed specifcally to do development and completion drilling as well as exploration drilling, particularly in the deepwater hydrocarbon-rich regions such as offshore West Africa and the presalt basin of Brazil, where supporting infrastruc-ture is less developed.
The drillship, CAN-DO, has increased deck space so companies can drill more wells more effciently. Comparatively, the present drillships in the market are meant mainly for exploration drilling, where the limited deck load restricts activities. “But for CAN-DO, we discussed the design with the (rig) owners, operators, and oil majors to expand the drill-ship capabilities. As such CAN-DO will be a development and exploration drillship,” says Tong. “You have to be creative, innovative, and decisive in coming up with something that will fll the niche market.”
He concedes that all these designs and en-gineering have not come easy. “It has been a long and arduous journey at Keppel.” It began as a ship repair department in a Sin-gapore port in the early days. Incorporated in 1968, the then Keppel Shipyard Pte. Ltd. has grown into one of Singapore’s top con-glomerates, with global operations. Property, telecommunications, and energy services are among other businesses under parent group Keppel Corp. Within the group is Keppel Off-shore & Marine.
“Of course, we started off building rigs to others’ designs or owner specifed designs. Increasingly and eventually, with experi-ence gained, we were than able to do our own design and won the confdence of rig owners,” he says. “We have since then devel-oped many designs for both the jackups and semisubmersibles and now the drillship, CAN-DO.”
He points out the company has had good opportunities to work with international en-gineering experts since the 1970s. “This has given us the opportunities to overcome the challenges and, today, we are able to offer turnkey projects,” he stresses.
Building to others’ designs gave the com-pany the introduction to serving the offshore oil and gas sector. Keppel had the advantage of working closely with rig operators to gain the understanding of “what it takes to be a de-signer of better rigs,” he says.
Tong reveals that the company always wants to do more than build rigs designed by
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others. “It reaches a point whereby, if you just simply wait for or continue to build on others’ designs, all the improvement or the changes would continue to remain with the designers.”
But the company’s determination is to build rigs on its own designs. “We felt that a yard such as ours has the expertise to build to our own designs. This also helped keep all the improvements within our own designs. I would say we have come a long way from the late 1960s or early 1970s.”
Prospects
“Outlook for the upstream business is still relatively bright. Exploration and production spending is still on the uptrend, and our busi-ness is directly linked to all these upstream investments,” he says. Tong thinks that shale oil and gas will take a while to reach every global market. So, conventional hydrocarbon resources will remain the preferred sources
of coping with energy demands in developing countries.
He also assures that more effcient equip-ment and instruments are available for in-creasing exploitation of conventional hydro-carbon resources, though there is a concern about replacing depleting oil and gas reserves.
Tong highlights Mexico’s energy reforms and its all out efforts to increase oil and gas production. “All these augur well for the rig-building industry. More and more rigs would be required and more drillings would be done that would lead to higher rate of production,” he says.
The company has the experience of man-aging through lean periods during economic downturns. “Sometimes, the downturn is good for the whole industry as it stops a lot of speculators from going all out to do more than really necessary,” he says. “It is a kind of awakening for investors not to rush into
1403OFF_46 46 2/28/14 4:57 PM
www.offshore-mag.com • March 2014 Offshore 47
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speculative projects. Also, it would leave such investments to bona fde kind of investors/builders and leave the owners to plan for bet-ter projects.”
He recalls the lean period of the late 1980s and early 1990s. “We are basically a shipyard with a big engineering team. When there were not any rigs to build, we felt then that there was a need for some rigs that would be required. Not forgetting that there has been a big lull from 1980s to 2000s, when hardly a rig was built. We then saw the potential re-quirements of some new capacity rigs. As a
shipyard, when we don’t have enough jobs, we will have to make a decision. And our de-cision then was to really build a rig on specu-lation. It turned out to be the right decision because before we had completed the unit, we had buyers.”
Though there are many rigs being built today, the bulk of the rigs in operation will soon be more than 30 years old. Then, there should be another round of improving the rigs, in designs and capabilities, and meet-ing the need to increase effciencies in new rigs compared to the older drilling units.
“We defnitely like to see Singapore pros-per with more of these high-value (rig) prod-ucts over the next 10 years and compete in the global market,” he says.
The industry also enjoys the Singapore government’s support in terms of training, research and development, innovation, and automation. There is growing collaboration with local universities. “I think the offshore oil and gas industry of Singapore can play a much bigger role than we presently are play-ing,” says Tong. “Keppel is always proud in R&D work as the money invested is produc-ing better systems, designs, and processes. We do not shy away from using whatever modern technology to help us in reducing our man-hour costs.”
Within Singapore yards, one of the in-novative ideas is the use of a foating dock, given the limited availability of water-front sites. “Rather than just simply transporting a project from China to Singapore, for exam-ple, we decided to use the foating dock. And so far it has served us very well,” he says.
Tong also emphasizes the company’s safe-ty culture, built over the years in Singapore and now entrenched into the daily operations at its global business centers. •
Keppel Subic Shipyard added a 1,500-metric ton
(1,653-ton) gantry crane, which has the greatest
lifting capacity of all gantry cranes in Southeast
Asia.
1403OFF_47 47 2/28/14 4:57 PM
48 Offshore March 2014 • www.offshore-mag.com
6 0 Y E A R S O F O F F S H O R E
From Offshore, July 1964
Offshore milestones, 1964-1968
1964 Oil strike sparks boom off Nigeria
1965 Australia’s first offshore well finds gas
1966 Shell drills GoM well in record 500-ft water depths
1967 World’s largest platform installed in record 340-ft
depths in GoM South Pass 52
1968 Drilling in 11,753-ft water depths, research vessel
Glomar Challenger finds evidence of deepwater GoM oil
1403OFF_48 48 2/28/14 4:58 PM
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50 Offshore March 2014 • www.offshore-mag.com
G E O L O G Y & G E O P H Y S I C S
The 2014 Worldwide Seismic Vessel Survey lists 179 vessels. This is an increase if directly compared to the 2013 tally, but that is deceiving. There are two signifcant changes this year. The list-ing adds Geokinetics and its 43 transition zone/shallow water/OBC vessels for the frst time, and the two electromagnetic sur-
vey vessels of EMGS. That tally should grow over the near term as purpose-built, high-capacity vessels come out of shipyards, and more non-traditional geophysical survey vessels are counted.
The new purpose-built vessels are in response to the demand for increasingly complex seismic data acquisition techniques.
On the other side of the ledger, Reservoir Exploration Technology and its seven vessels are deleted, with the company in the hands of a Norwegian bankruptcy court. WesternGeco elected again this year not to participate in the survey, and that leaves a further 20 or so ves-sels unlisted.
New acquisition vessel design
Innovation is not limited to support vessels. WesternGeco has christened the frst of its Amazon-class seismic vessels, designed “from the bottom up” to handle modern seismic spreads.
Modern seismic streamer spreads typically extend up to 12 km (5 mi) in length and up to 1,400 m (4,600 ft) in width, requiring considerable sideways defection leading to additional drag. Effcient and safe storage and deployment of all this equipment requires large back decks with specialized designs. There have been a range of hull designs considered suitable for seismic operational needs, and these hulls have converted decks to accommodate and deploy the equipment. A feature common to all of these hull designs is that they were originally optimized for pur-poses other than seismic operations.
In November 2013, WesternGeco christened the world’s frst vessel designed from the bottom up to be a sustainable and effcient marine seismic platform. The company expects these Amazon-class vessels will support its activities for at least the next 10 years.
Maritime engineers were tasked to design a hull, propulsion system, and all the other vessel components to meet seismic data acquisition re-quirements with no compromises in HSE or operational effciency. The design process involved input from equipment users, and WesternGeco’s HSE knowledge management database was used to evaluate and miti-gate potential safety risks.
The frst Amazon-class vessel, Amazon Warrior, is at the Flensburger Shipyard in Germany and is scheduled to start operations in 2Q 2014. The second Amazon-class vessel, yet to be christened, is expected to enter service by 4Q 2014. At 126 m (413 ft) long, 28-32 m (92–105 ft) wide, they will provide large, powerful and stable platforms during in-clement weather. The knife-shaped bow reduces slamming to help main-tain streamer control and to reduce noise in the seismic data. There is capacity for more than 200 km (124 mi) of streamers and 18 streamer tow points. A “quad-deployment” design enables four steamers to be handled simultaneously. The available work space enables safe and effcient at-sea reconfguration of streamers. •
Gene KliewerTechnology Editor, Subsea & Seismic
Computer rendering of Amazon Warrior, scheduled to start operations in
2Q 2014. (Courtesy WesternGeco)
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1403OFF_50 50 2/28/14 4:59 PM
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1403OFF_51 51 2/28/14 4:59 PM
Worldwide Seismic Vessel Survey
Vessel
nam
e
Year
rig
ged
or
conv
erte
d
Tota
l le
ngth
(m
)
Tota
l be
am (
m)
Str
eam
er
conf
igur
atio
n
(# s
trea
mer
s x
#
chan
nels
) V
esse
l av
aila
bili
ty
(Yes
, N
o, o
r
Excl
usiv
e co
ntra
ct)
Pri
mar
y re
gion
Sou
rce
arra
y
conf
igur
atio
n as
ri
gged
(#
arra
ys x
ca
paci
ty i
n cu
in.
)
Max
imum
tow
able
fo
otpr
int (
# ca
bles
x
leng
th (
m)
x w
idth
(m
))
52 Offshore March 2014 • www.offshore-mag.com
BGP Marine, 5th Floor, E5C1, Finance Street, 3rd Avenue, TEDA, Tianjin, P.R. China 300457
BGP Challenger 2009 55 13.8 1 x 960, 2 x 480 Yes Worldwide 1 x 5,680, 2 x 2,840 1 x 12,000, 2 x 6,000
BGP Explorer 2010 64 16 1 x 960, 2 x 640, 3 x 480 Yes Worldwide 1 x 5,200 2 x 3,060 1 x 12,000, 2 x 8,000 3 x 6,000
BGP Pioneer 2006 83.7 19.5 6 x 640 Yes Worldwide 2 x 4,280 6 x 8,000
BGP Prospector 2011 100 24 12 x 640 Yes Worldwide 2 x 4,200 12 x 8,000
Dong Fang Kan Tan No. 1 2007 65.8 13.8 1 x 960 Yes Worldwide 1 x 5,340 1 x 12,000 (BGP Surveyor) 2 x 3,420
Dong Fang Kan Tan No. 2 2007 65.8 13.8 1,320 Ch Yes Worldwide 2 x 3,950 OBC cable (BGP Researcher)
Caspian Services Group Ltd., Office Building B, 7th Acreage, The Esplanade, Microdistrict 15, Aktau 13000, Kazakhstan
Caspian Galiya 2007 12.5 4.5 Yes Caspian OBC Cable
Coastal Bigfoot 2007 12.5 4.5 Yes Caspian OBC Cable
CGG, 27 Ave. Carnot, 91341 Massy Cedex, France
Oceanic Vega 2010 106 28 20 x 640 Yes Worldwide 2 x 5,000 20 x 8,000 x 100
Oceanic Sirius 2011 106 28 20 x 640 Yes Worldwide 2 x 5,000 20 x 8,000 x 100
Alize 1999 101 29 16 x 640 Yes Worldwide 2 x 5,000 16 x 8,000
Amadeus 1999 84 19 8 x 640 Yes Worldwide 2 x 5,000 8 x 8,000 x 100
Princess 2001 76 14 3 x 560 Yes Worldwide 2 x 5,000 3 x 6,000 x 100
Symphony 2000 121 23 12 x 640 Yes Worldwide 2 x 5,000 12 x 8,000 x 100
Venturer 2007 90 15 4 x 640 Yes Worldwide 2 x 5,000 4 x 8,000 x 100
Viking 1998 93 22 10 x 640 Yes Worldwide 2 x 5,000 14 x 8,000 x 100
Viking II 1999 93 22 8 x 640 Yes Worldwide 2 x 5,000 8 x 8,000 x 100
Viking Vanquish 2007 93 22 12 x 640 Yes Worldwide 2 x 5,000 12 x 8,000 x 100
Veritas Vantage 2002 93 22 10 x 640 Yes Worldwide 2 x 5,000 10 x 8,000 x 100
Viking Vision 2007 105 26 14 x 640 Yes Worldwide 2 x 5,000 14 x 8,000 x 100
Geowave Champion 2007 106 22 14 x 640 Yes Worldwide 2 x 5,000 14 x 8,000 x 100
Geowave Voyager 2008 93 22 10 x 640 Yes Worldwide 2 x 5,000 10 x 8,000 x 100
Oceanic Endeavour 2008 107 27 16 x 640 Yes Worldwide 2 x 5,000 16 x 8,000 x 100
Challenger 2006 90 19 12 x 640 Yes Worldwide 2 x 5,000 12 x 8,000 x 100
Oceanic Phoenix 2011 114 25 14 x 640 Yes Worldwide 2 x 5,000 14 x 8,000 x 100
Pacific Finder 2011 68 17 4 x 640 Yes Worldwide 2 x 5,000 4 x 8,000 x 100
Geo Coral 2010 108 28 16 x 640 Yes Worldwide 2 x 5,000 16 x 8,000 x 100
Geo Caspian 2010 108 28 16 x 640 Yes Worldwide 2 x 5,000 16 x 8,000 x 100
Geo Caribbean 2008 101 28 14 x 640 Yes Worldwide 2 x 5,000 14 x 8,000 x 100
Geo Celtic 2006 101 28 12 x 640 Yes Worldwide 2 x 5,000 12 x 8,000 x 100
Geo Barents 2007 77 21 8 x 640 Yes Worldwide 2 x 5,000 8 x 8,000 x 100
China Oilfield Services Ltd., No.6 Dongzhimenwai Xiaojie Beijing 100027 P.R.C
Bin Hai 511 1979 81 13.4 3 x 360 Yes China, Asia, CIS 2 x 2,490
Bin Hai 512 1979 79 13.4 4 x 360 Yes China, Asia, CIS 2 x 3,000
Bin Hai 517 1997 60 15 2 x 480 Yes China, Asia, CIS 4,075
HYSY 718 2005 78 18 6 x 480 Yes China, Asia, CIS 2 x 3100
HYSY719 2008 80 18 8 x 480 2 x 4,110
Dong Fang Ming Zhu 1994 79 16.5 4 x 480 2 x 3,185
Nan Hai 502 1980 66 11 2 x 360 Yes China, Asia, CIS 3,660
HYSY 708
HYSY 720
Dalmorneftegeophysica (DMNG), 426, Mira Ave., Yuzhno-Sakhalinsk, 693004, Russia
Akademik Fersman 2007 81.5 14.8 SEAL 1 x 960 Contact SE Asia / Worldwide 4 x 5,000 1 x 1,100
Orient Explorer 2011 81.8 14.8 4 x 1,440 Contact SE Asia / Worldwide 6 x 2,920 4 x 6,000 x 150
Zephyr-I 2007 81.8 14.8 SEAL 1 x 960 Contact SE Asia / Worldwide 4 strings 2,940 higher on request 1 x 11,100
EMGS, Stiklestadveien 1, N-7041, Trondheim, Norway
BOA Galatea 80.35 16.4
BOA Thalassa 80.35 16.4
Fairfield Industries,1111 Gillingham, Sugar Land, Texas 77478, USA
Geo Wave Commander 2014 93 16.5 Shooting Vessel Yes North Sea 5,330 dual
Fairfield New Venture 2004 76 18 Shooting Vessel Yes West Africa 5,330 dual
Fairfield Challenger 2005 67 14 Shooting Vessel Yes Mexico 5,330 dual
Fairfield Pursuit 2011 59 14 Shooting Vessel Yes GoM 5,330 dual
Carolyn Chouest 2010 73 16 Node Handling Vessel Yes GoM Node Vessel 1,500 - Nodes
Ocean Pearl 2014 106 18 Node Handling Vessel Yes North Sea Node Vessel 5,000 - Nodes
European Supporter 2014 105 22 Node Handling Vessel Yes West Africa Node Vessel 7,000 - Nodes
Fugro Brasil Serviços Submarinos e Levantamentos Ltda, Rua do Geólogo, 76 – Zona Especial de Negócios / ZEN , Rio das Ostras - RJ - Brasil - CEP.:28.890-000. www.fugro-br.com
Fugro Odyssey 2003 (rebuilt) 39.9 7.6 1x Sercel Sentinel up to 1,5Km (120 ch) Yes Brasil 4x40 sleeve gun cluster or single 210 GIGun N/A
Fugro Brasilis 2012 65.65 14 1x Sercel Sentinel up to 1,5Km (120 ch) 12-Jun Brasil 4x40 sleeve gun cluster or single 210 GIGun N/A
Fugro GeoServices Inc, 200 Dulles Drive, Lafayette, Louisiana 70506, USA. www.fugrogeoservices.com
Fugro Enterprise 2007 52 12 1 x 48, 1 x 96 Yes GoM 90-300 GI Guns
Geodetic Surveyor 1985 37 9 1 x 48, 1 x 96 Yes GoM 90-300 GI Guns
Universal Surveyor 1980 37 9 1 x 48, 1 x 96 Yes GoM 90-300 GI Guns
Fugro OSAE GmbH, Fahrenheitstrasse 7, D-28359 Bremen, Germany. www.fugro-osae.de
Fugro Gauss 1980/2007 69 13 (Mobile) Yes Atlantic (Mobile) (Mobile)
1403OFF_52 52 2/28/14 4:59 PM
Acq
uis
itio
n
capabil
ity
Acq
uis
itio
n
capabil
ity
Technical capability Onboard processing
Seismic
2D
3D
4C
/4D
Shall
ow
tr
ansi
tion z
one
Deepw
ate
r
Hig
h d
ensi
ty
Oce
an b
ott
om
ca
ble
Vari
able
depth
Nav
data
QC
data
Full
data
Fin
al
pri
mary
re
cord
ing m
edia
(t
ype o
r ca
rtri
dge #
)
Sate
llit
e t
ransm
issi
on
to s
hore
(co
mpany
use
d
and t
ransm
issi
on
speed (
baud )
)
www.offshore-mag.com • March 2014 Offshore 53
x x x x x 3592 Inmarsat VSAT
x x x x x 3592 Inmarsat C
x x x x x x x 3592 VSAT
x x x x x x x 3592 Inmarsat C,F VSAT
x x x x x
x x x x x x x x 3592 VSAT
x x x x x x x x
x x x x x x x x
x x x x x x x x x 3592 VSAT ≥ 128k
x x x x x x x x x 3592 VSAT ≥ 128k
x x x x x x x x x 3592 VSAT ≥ 128k
x x x x x x x x x 3592 VSAT ≥ 128k
x x x x x x x x x x 3592 VSAT ≥ 128k
x x x x x x x x x 3592 VSAT ≥ 128k
x x x x x x x x x x 3592 VSAT ≥ 128k
x x x x x x x x x 3592 VSAT ≥ 128k
x x x x x x x x x 3592 VSAT ≥ 128k
x x x x x x x x x 3592 VSAT ≥ 128k
x x x x x x x x x 3592 VSAT ≥ 128k
x x x x x x x x x 3592 VSAT ≥ 128k
x x x x x x x x x 3592 VSAT ≥ 128k
x x x x x x x x x 3592 VSAT ≥ 128k
x x x x x x x x x 3592 VSAT ≥ 128k
x x x x x x x x x 3592 VSAT ≥ 128k
x x x x x x x x x 3592 VSAT ≥ 128k
x x x x x x x x x x 3592 VSAT ≥ 128k
x x x x x x x x x 3592 VSAT ≥ 128k
x x x x x x x x x 3592 VSAT ≥ 128k
x x x x x x x x x 3592 VSAT ≥ 128k
x x x x x x x x x 3592 VSAT ≥ 128k
x x x x x x x x x 3592 VSAT ≥ 128k
x x >10 m x x x x x 3590 Inmarsat
x x >10 m x x x x x 3590 KU
x x >8 m x x x x 3590
x x 3590 KU
3590
x x 3590 KU
x x >10 m x x x x x 3590
x x x x x x 3590 VSAT
x x x x x x x x 3590 VSAT
x x x x x x 3590 VSAT
x x x x x x x x 3590
x x x X x x x x x 3590
x x x X x x x x x 3590
Yes No No No Yes Yes No No Yes Yes Yes Hard Drive No
Yes No No Yes Yes Yes No No Yes Yes Yes Hard Drive Yes
x x x x x x Hard Drive V-Sat
x x x x x x Hard Drive V-Sat
x x x x x x Hard Drive V-Sat
x x x x x x (Mobile) TBA
1403OFF_53 53 2/28/14 4:59 PM
54 Offshore March 2014 • www.offshore-mag.com
Worldwide Seismic Vessel Survey
Vessel
nam
e
Year
rigged o
r
conve
rted
Tota
l le
ngth
(m
)
Tota
l beam
(m
)
Str
eam
er
co
nfi
gura
tion
(# s
tream
ers
x
# c
hannels
) V
ess
el
ava
ilabil
ity
(Yes,
No,
or
Exc
lusi
ve c
ontr
act
)
Pri
mary
regio
n
Sourc
e a
rray
co
nfi
gura
tion a
s
rigged (
# a
rrays
x
capaci
ty i
n c
u i
n.)
Maxi
mum
tow
able
fo
otp
rint (#
cable
s x
length
(m
) x
wid
th (
m))
Fugro Survey Ltd., Denmore Rd, Bridge of Don, Aberdeen AB23 8JW, UK. www.fugrosurvey.co.uk
Fugro Galaxy 2011 65.2 14 1 x 144 Yes NWECS 140
Fugro Meridian 1982/1997 72.5 13.8 1 x 240 Yes NWECS 140/1,000
Geo Prospector 1970/1997 72.6 11.8 1 x 120 Yes EAME 140
Fugro Discovery 1997/2007 70 12.6 1 x 120 Yes NWECS 140
Fugro Searcher 2010 65.2 14 1 x 240 Yes NWECS 140/1,000
Fugro Survey Africa (Pty) Ltd, Unit 24 Woodbridge Business Park, 7441 Milnerton, Cape Town, South Africa. www.fugro-africa.com
Geo Endeavour 1985/1998 45.7 10 1 x 48 Yes Subsaharan Africa 1 x 90, 1 x 150
Fugro SAE, Oil Company Complex, Km 12, Ain Sukhna Rd., Katameya, Cairo, Egypt. www.fugro-egypt.net
Fugro Navigator 1988/2009 54 11 1 x 120 Mid-2013 Med 1 x 140
Fugro Survey Pte Ltd, 35 Loyang Crescent, Singapore 509012. www.fugro.sg
Fugro Equator 2012 65 14 1 x 240 41579 Far East Mini G 4 x 40 / 4 x 20
Fugro Equinox 2011 60 16 1 x 120 41365 Far East Sleeve 4 x 40 / 4 x 20
Amarco Tiger 1975 / 2008 53 11.5 1 x 120 Yes Far East Sleeve 4 x 40 / 4 x 20
Fugro Supporter 1994 / 2013 75.4 12.5 (Mobile) Yes Far East (Mobile) (Mobile)
Fugro Survey (India) Pvt. Ltd., Fugro House, D-222/30, T.T.C. Industrial Area, M.I.D.C., Nerul, Navi, Mumbai - 400 706. Maharashtra. India Tel : +91 22 27629500 Fax : +91 22 2762 9140
Flamboyan 1983 / 2010 39 9.5 As required Yes India As required
Gardline, Endeavour House, Admiralty Rd., Great Yarmouth, Norfolk NR30 3NG UK
Sea Explorer 1993/1994/2004 58.8 11 1 x 120 Yes Worldwide 2 x 160
Ocean Endeavour 2004 64.4 11.4 1 x 120 Yes Worldwide
Sea Proflier 1992 65.7 11 1 x 120 Yes Worldwide 2 x 160
Sea Surveyor 1998/1999 64.4 11.4 1 x 480 Yes Worldwide 1 x 160 up to 1,950
Sea Trident 1984/1991/2006 57.9 10.2 1 x 120 Yes Worldwide 2 x 160
Ocean Seeker 1970/2000 80.7 13 1 x 120 Yes Worldwide 1 x 160
L’Espoir 1971/1996 67.5 10.6 1 x 120 Yes Worldwide 1 x 160
Tridens 1 1984/1991 57.9 10.2 1 x 120 Yes Worldwide 1 x 160
Global Geophysical Services, 13927 S. Gessner Rd., Missouri City, TX 77489 USA
James H. Scott 2005 70 ft 22 ft Yes GoM, International 4 x 750 Source
Global Longhorn 2007 93.9 ft 26 ft Yes GoM, International Accommodation
Global Mirage 2008 65 ft 21 ft Yes India, International 2 x 750 Source
Global Vision 2007 65 ft 21 ft Yes India, International OBC Cable
Global Quest 2007 65 ft 18 ft Yes India, International OBC Cable
Lori B 2007 48 ft 20 ft Yes GoM OBC Cable
Tiny Tune 2005 38 ft 12 ft Yes USA Source
Kiwi I 2007 54 ft 16 ft Yes GoM OBC Cable
Kiwi II 2007 49 ft 13.8 ft Yes GoM OBC Cable
Kiwi III 2008 47 ft 16.4 ft Yes GoM OBC Cable
Cobourg 2008 52.5 ft 17.4 ft Yes India, International OBC Cable
Geokinetics, 1500 CityWest Blvd., Sute 800, Houston, TX 77042
GeoTiger 1 2007 19.9 6.8 Far East 2 x 850
GeoTiger 2 2010 19.9 6.8 Americas
GeoTiger 3 2010 19.9 6.8 Americas
GeoTiger 4 2010 19.9 6.8 Americas 2 x 1,200
Expedition 1997 19.9 6.6 US/Carribean 2 x 1,000
Nieuw Holland 1989 19.8 6.6 Australia Pacific
Wild Thing 2008 19.8 6.6 Australia Pacific
BLACK JACK 2006 19.8 6.6 Australia Pacific
Katmandu 2010 18.3 6.1 Australia Pacific
Bubbles 2003 17.4 5.8 EAME
C1 2001 15.8 5.3 Carribean
C2 2001 14.8 4.9 Carribean
C3 2001 14.8 4.9 Carribean
C4 2012 14.8 4.9 US/Carribean
C5 2012 14.8 4.9 US/Carribean
GeoCat 2003 12.8 4.3 EAME
Reliance 4 2008 12.5 4.2 US/Carribean
Reliance 5 2008 12.5 4.2 US/Carribean
Reliance 6 2008 12.2 4.1 US/Carribean
Reliance 7 2008 12.2 4.1 US/Carribean
TZ:3568 2001 9.8 3.3 EAME
TZ:3218 2001 9.8 3.3 EAME
TZ:3215 2001 9.8 3.3 EAME
TZ:3222 2003 9.8 3.3 EAME
TZ:3221 2003 9.8 3.3 EAME
TZ:3227 2003 9.8 3.3 EAME
TZ:3220 2006 9.8 3.3 EAME
TZ:3219 2006 9.8 3.3 EAME
TZ:3216 2006 9.8 3.3 EAME
TZ:3216 2008 9.8 3.3 Australia Pacific
TZ:3209 2008 9.8 3.3 Australia Pacific
TZ:3208 2010 9.8 3.3 Australia Pacific
1403OFF_54 54 2/28/14 4:59 PM
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Acq
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Acq
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Technical capability Onboard processing
Seismic
2D
3D
4C
/4D
Shall
ow
tr
ansi
tion z
one
Deepw
ate
r
Hig
h d
ensi
ty
Oce
an b
ott
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ca
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Vari
able
depth
Nav
data
QC
data
Full
data
Fin
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pri
mary
re
cord
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(t
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rtri
dge #
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Sate
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)
x x x x x x LT04 Marlink
x x x x x x LT04 Marlink
x x x x x x LT04 Marlink
x x x x x x LT04 Marlink
x x x x x x LT04 Marlink
x x x x x
x x x x x x x Hard Disk
X X X X X X X 3490E VSAT 256 Kbit
X X X X X X X 3490E VSAT 128 Kbit
X X X X X X X 3490E TBA
X X X X X X X (Mobile) VSAT 256 Kbit
x x x x DLT FB
x x >10m x x x x x 3490E VSAT (256)
x x
x >10m x x x x x 3490E VSAT (256)
x x >10m x x x x x 3490E VSAT (256)
x >10m x x x x x 3490E VSAT (128)
x >10m x x x x x 3490E VSAT (256)
x >10m x x x x x 3490E VSAT (128)
x >10m x x x x x 3490E Gardline 64k
x x x x x x x x
x x x x x x x x
x x x x x x x x
x x x x x x x x
x x x x x x x x
x x x x x x x x
x x x x x x x x
x x x x x x x x
x x x x x x x x
x x x x x x x x
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x x x x x x x x
x x x x x x x x
x x x x x x x x
x x x x x x x x
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x x x x x x x
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56 Offshore March 2014 • www.offshore-mag.com
Worldwide Seismic Vessel Survey
Vessel
nam
e
Year
rigged o
r
conve
rted
Tota
l le
ngth
(m
)
Tota
l beam
(m
)
Str
eam
er
co
nfi
gura
tion
(# s
tream
ers
x
# c
hannels
) V
ess
el
ava
ilabil
ity
(Yes,
No,
or
Exc
lusi
ve c
ontr
act
)
Pri
mary
regio
n
Sourc
e a
rray
co
nfi
gura
tion a
s
rigged (
# a
rrays
x
capaci
ty i
n c
u i
n.)
Maxi
mum
tow
able
fo
otp
rint (#
cable
s x
length
(m
) x
wid
th (
m))
TZ:3205 2010 9.8 3.3 Australia Pacific
TZ:3205 2010 9.8 3.3 Australia Pacific
TZ:3203 2010 9.8 3.3 Australia Pacific
TZ:3201 2010 9.8 3.3 Mexico
TZ6-2801 2010 9.8 3.3 Mexico
RIB:2401 2006 9.8 3.3 Australia Pacific
RIB:2402 2006 9.8 3.3 EAME
RIB:2403 2006 9.8 3.3 EAME
TZ9-2304 2005 7.5 2.5 EAME
TZ9-2302 2005 7.5 2.5 EAME
TZ9-2302 2005 7.3 2.4 EAME
Marine Arctic Geological Expedition (MAGE)
Geolog Dmitriy Nalivkin 1985 71.7 12.8 1 x 648 Contract Arctic, Northern seas 1 x 3,410 1 x 8,100
Professor Kurentsov 1976 68.9 12.4 1 x 648 Contract Arctic, Northern seas 1 x 8,100
NAUTIC Offshore AS, Dronningen 1, 0211 Oslo, Norway
Neptune NAIAD 2008 66.3 14.2 4 x 2,560 Yes Worldwide 2x 4,000 4 x 6,000 x 100
Offshore Seismic Surveys, OSS, 13430 NW Freeway, Suite 800, Houston TX 77040
OSS Gulf Supplier 56.4 11.6 3 x 240 Yes South America 2 x 1,500 3 x 3,000 x 200
OGS Italy, Borgo Grotta Gigante 42c, P.O. Box 2011, 34016 Trieste, Italy
OGS Explora 8 71.9 12.8 1 x 96 Worldwide inc. Antarctic 2 x 355
Orogenic GeoExpro, Loyang Crescent, Loyang Offshore Supply Base, Block 217, SOPS Ave., Box No. 5043, Singapore 508988
Genesis 1995/2006 52 11 1 x 120 TBA Asia Pacific Single GI Gun 90/150/210 N/A
PGS, Lilleakerveien 4C, N-0216 Oslo
Atlantic Explorer 1994 91.5 18 6 x 960 Yes Worldwide 2 x 4,130 3.6 sq km
Nordic Explorer 1993 81.1 16.5 1 x 804 Yes Worldwide 2 x 4,130
Pacific Explorer 1994 91.4 22 6 x 1608 Yes Worldwide 2 x 4,130 3.5 sq km
Ramform Challenger 1996 86.2 39.6 14 x 1290 Yes Worldwide 2 x 4,135 6.35 sq km
Ramform Explorer 1995 83 39.6 10 x 1128 Yes Worldwide 2 x 4,130 6.35 sq km
Ramform Valiant 1998 86.2 39.6 16 x 1296 Yes Worldwide 2 x 4,130 8.9 sq km
Ramform Vanguard 1999 86.2 39.6 16 x 1296 Yes Worldwide 2 x 4,130 8.9 sq km
Ramform Viking 1998 86.2 39.6 16 x 1296 Yes Worldwide 2 x 4,130 8.9 sq km
Ramform Sovereign 2008 102.2 40 18 x 1296 Yes Worldwide 2 x 4,130 10.9 sq km
Ramform Sterling 2009 102.2 40 18 x 648 Yes Worldwide 2 x 4,130 10.9 sq km
PGS Apollo 2010 106.8 19.2 10 x 1290 Yes Worldwide 2 x 4,135 8.1 sqkm
Sanco Spirit 2011 86 16 1 x 1608 Yes Worldwide 2 x 4,135
Ramform Titan 2013 104.2 70 20 x 1296 Yes Worldwide 2 x 4,130 12.2 sqkm
Ramform Atlas 2014 104.2 70 20 x 1296 Yes Worldwide 2 x 4,130 12.2 sqkm
Polarcus, Almas Tower, Level 32, Jumeirah Lakes Towers, P.O. Box 283373, Dubai, U.A.E.
Polarcus Nadia 2009 89 19 10 x 648 Yes Worldwide 2 x 4,240 10 x 8,100 x 100
Polarcus Naila 2010 89 19 12 x 648 Yes Worldwide 2 x 4,240 12 x 8,100 x 100
Polarcus Asima 2010 92 21 12 x 648 Yes Worldwide 2 x 4,240 12 x 8,100 x 100
Polarcus Alima 2011 92 21 12 x 648 Yes Worldwide 2 x 4,240 12 x 8,100 x 100
Polarcus Amani 2012 92 21 14 x 648 Yes Worldwide 2 x 4,240 14 x 8,100 x 100
Polarcus Adira 2012 92 21 14 x 648 Yes Worldwide 2 x 4,240 14 x 8,100 x 100
Reflect Geophysical Pte. Ltd., 8 Temasek Boulevard #17-01, Suntec Tower Three, Singapore 038988
Reflect Aries 1993/2010 70.1 18 4 x 960 Yes Worldwide 2x 3,000 4 x 5,000 x 100
Orient Explorer 1988/1995 81.8 14.8 4 x 960 Yes Worldwide 2x 3,000 4 x 6,000 x 100
Pacific Titan 1982/2010 64.5 18.5 N/A Yes Worldwide 2x 3,000 N/A
Sea Bird Exploration Nedre Vollgate 3, P.O. Box 1302, Vika 0112 Oslo, Norway
Aquila Explorer 2007 71 17.5 1 x 960 PGS Worldwide 2 x 5,000
Geo Mariner 2001/2004 38.2 12.8 2 x 320 Yes Worldwide 2 X 1,700; 3 X 1,995 2 x 3,600 x 100
Harrier Explorer 2007 81 18.3 Source PGS Worldwide
Hawk Explorer 2006 66 14.5 1 x 960 Fugro Geoteam Worldwide 1 x 4,400
Hugin Explorer 2007/2008 86 20 Yes Worldwide 2 x 4,400
Kondor Explorer (source only) 1984/1997 63.5 13.6 Source Yes Worldwide 2 X 5,260 (client selectable)
Munen Explorer 2007 60 14 1 x 960 Yes Worldwide 2 x 5,000
Northern Explorer 1987/1998/2004 76 14 1 x 960 Yes Worldwide X 5,000 Bolt
Osprey Explorer 2006 81 16 Source Yes Worldwide 2 X 5,000 (client selectable)
Sevmorneftegeofizika (SMNG), 17 Karl Marx St., 183025 Murmansk, Russia
Akademik Lazarev 1987/96 81.8 14.8 1 x 960 Yes Worldwide 4 x 4,200 1 x 12,000
Akademik Nemchinov 1988/97 84 14.8 4 x 480 Yes Worldwide 6 x 7,874 4 x 6,000 x 100
Akademik Shatskiy 1986/91 83.5 14.8 1 x 960 Yes Worldwide 6 x 6,444 2 x 6,000 x 100
Geo Arctic 1988/97 84 14.8 1 x 960 Yes Worldwide 4 x 4,820 1 x 12,000
Iskatel - 5 1989/97 49.2 18.2 1 x 480 Yes Worldwide 4 x 3,000 1 x 6,000
Professor Rjabinkin 1989/1995/2007 49.9 10.5 2 x 800 Yes Worldwide 2 x 2,280 1 x 6,000
Vyacheslav Tikhonov 2011 84.2 17 8 x 480 Yes Worldwide 6 x 4,240 6 x 8,100 x 150
Shanghai Offshore Petroleum Bureau SINOPEC, 1225 Shangcheng Rd. Pu Dong, Shanghai China
Discoverer 1980 72 16.4 2 x 480 Yes Worldwide 2 x 3,480 2 x 6,000
Discoverer 2 1993 70.1 17.98 3 x 480 Yes Worldwide 2 x 3,480 3 x 6,000
Discoverer 6 2013 100 24 12 x 640 Yes Worldwide 2 x 5,800 12 x 8,000
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x x x
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x x x
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x x x
x x x
x x x
x x x
x x x x x x 3590, 3592 Iridium Open port Skansat CT TT-3020C
x x x x x x 3590, 3592
x x x x x x x x 3590, EHD, USB VSAT
x x x x 3590 V-SAT
x x x x x x 3490E 64k
x YES YES YES 3590 VSAT
x x x x x x x x 3592 256K
x x x x x 3592 256K
x x x x x x 3592 256K
x x x x x x x x 3592 256K
x x x x x x x x 3592 256K
x x x x x x x x 3592 256K
x x x x x x x x 3592 256K
x x x x x x x x 3592 256K
x x x x x x x x 3592 256K
x x x x x x x x 3592 256K
x x x x x x x x 3592 256K
x x x x x 3592 256K
x x x x x x x x 3592 265K
x x x x x x x x 3592 265K
x x x x x x x x 3592 VSAT
x x x x x x x x 3592 VSAT
x x x x x x x x 3592 VSAT
x x x x x x x x 3592 VSAT
x x x x x x x x 3592 VSAT
x x x x x x x x 3592 VSAT
x x x x x x x x 3590, EHD, USB VSAT
x x x x x x x x 3590, EHD, USB VSAT
x x x x x x x x VSAT
x x x x Inmarsat C
x x x x x x 3590 NorSat C
x Inmarsat C
x x x x Inmarsat C
x x x x x x x Inmarsat C
x x KU Band
x x x x Inmarsat C
x x x x 3590 NorSat C
x x Inmarsat C
x x x x x x 3590 64k
x x x x x x x x 3590 64k
x x x x x x x x 3590 64k
x x x x x x 3592 64k
x x x x
x x x x x x 3490E 9.6k
x x x x x x x x 3592, USB VSAT
x x x x x x x 3592 VSAT
x x x x x x x 3592 VSAT
x x x x x x x 3592 VSAT
1403OFF_57 57 2/28/14 4:59 PM
58 Offshore March 2014 • www.offshore-mag.com
G E O L O G Y & G E O P H Y S I C S
Seismic LWD reduces time, risk
in remote ultra-deepwater well
Exploratory wells in ultra-deepwater hold great promise, but are inherently risky and expensive. Complex, uncertain geol-ogy in often-remote areas with little or no exploration history or data present a host of unknowns that push the limits of conventional technology. As activity continues to ramp up in
this new frontier, E&P companies are looking to expand the scope of existing tools and expertise to plan and develop the most diffcult wildcat wells, achieving what, until now, has been unachievable.
Ultra-deepwater wildcat wells present the greatest challenges to the oil and gas industry today, due to lack of offset well data and lim-itations of surface seismic data that compromise precise decision-making. For this high-stakes environment, operators must be able to accurately calibrate the seismic and pore pressure models used extensively in exploration drilling to evaluate multiple reservoir tar-gets, drill on budget, and drill safely.
High-tech logging-while-drilling (LWD) services have widened the operational envelope for exploratory drilling in ultra-deepwater, deliver-ing both real-time, time-depth-velocity data, and formation pressures to address the fundamental challenges of depth and pore pressure uncer-tainty. Seismic LWD measures the velocity, or speed of sound, between the sea surface and the downhole tool behind the drill bit. The ve-locity measurement, or seismic checkshot, is repeated as the well is deepened, allowing the operator to acquire velocity data as the well is being drilled and more defnitively calculate the depth of approaching formation tops. Formation pressure-while-drilling (FPWD) is able to di-rectly measure formation pressure.
The formation tops can be up-dated in the pre-drill pore pressure model used to determine the number of casing sections required, placement of casing shoes, and mud weight win-dow parameters. Incorrect estimates of FPWD can result in formation fracturing if the mud weight is too high, and well control problems if the mud weight is too low.
The Schlumberger seismicVISION seismic-while-drill-ing (SWD) service used real-time measurements to update the velocity model in a wildcat well off the coast of West Africa and enabled the well target objectives to be achieved with confdence while reducing risk and time to drill the well. In one well section with a challenging mud weight window (MWW), SWD was used alongside the Schlum-berger StethoScope FPWD service to more accurately calibrate the pre-drill pore pressure model. The acquired
formation pressures, coupled with while-drilling petrophysical data, fa-cilitated calibration of a velocity-to-pore-pressure transform and normal compaction trend lines, providing reduced uncertainty in the pore pres-sure model.
Understanding depthDevelopment of look-ahead SWD technology for drilling challeng-
ing exploratory wells and planning development wells is rooted in the need to better understand the subsurface. Traditionally, indus-try has relied on surface seismic data to assess the potential location of a reservoir by using a refection seismic image to measure refec-tions in time and estimate the velocity of the rock at different depths. However, without reliable offset well data to calibrate the formation, velocity depths are inherently uncertain.
Over the years, several “while-drilling” methods have been intro-duced to determine where the bit is on the seismic map before reach-ing the next casing point. These methods use indirect measurements and observations, and rely on multi-disciplinary petrotechnical exper-
tise for data correlation between surface seismic, basin modeling, LWD petrophysical logs, synthetic seismogram, mud logging, and biostratigraphy—the study of mi-crofossils to determine the geo-logic age of the rock.
The success of these techniques to place the bit on seismic is limited, because they depend on the accu-racy of the assumptions used, con-tinuous quality real-time logs, and/or models developed from seismic interpretation.
SWD addresses that defciency by providing a direct time-depth conversion. During the drilling process, guns are fred to measure the time for the sound to travel from the surface to the downhole tools, enabling the operator to determine well depth with more certainty relative to formation tops ahead. This more accurate depth measurement saves time, minimizes risk and enhances safety, and potentially can reduce hole size and the number of casings required.
In acquiring the time-depth data for exploration wells, the SWD technique improves effciency by us-ing an LWD tool in the bottomhole assembly (BHA), rather than conventional wireline, to run seismic tools while drilling. Whereas most wireline tools can be run in combination in the hole, seismic tools are sometimes deployed in a dedicated logging run.
Using an LWD tool involves little or no additional rig time. Seismic sensors in the LWD tools consist of geo-phones, which respond to the physical motion of the wellbore, and hydrophones, which provide a more ro-bust measurement by responding to pressure waves. Real-time seismic measurements also have been used
Martin Richards Chariot Oil & Gas
Neil KelsallSchlumberger
Seismic LWD system consists of a downhole LWD tool syn-
chronized with a surface air gun control system. Synchroni-
zation is achieved using high precision clocks with GPS time
as a reference. (Images courtesy Schlumberger)
1403OFF_58 58 2/28/14 5:00 PM
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60 Offshore March 2014 • www.offshore-mag.com
G E O L O G Y & G E O P H Y S I C S
in development wells for highly deviated well landing. A seismic refec-tor refects the sound off the top of the reservoir to build an image of the reservoir location below the tool to more accurately place the well.
Real-time SWD data is continually transmitted through the Inter-ACT global connectivity, collaboration, and information service to ensure quality control in updating predicted target depths and po-tential casing or coring points.
West Africa wildcat wellThe seismicVISION service was deployed to guide the well trajec-
tory from spud to total depth (TD) in three sections of an ultra-deep-water wildcat well for Chariot Oil & Gas off Namibia, an important ultra-deepwater frontier. The SWD service provided real-time seis-mic checkshot data for velocity model calibration during drilling, signifcantly reducing depth uncertainty and providing waveform data in real time for vertical seismic profle (VSP) look-ahead.
The service was used during the drilling operation of the Tapir South well, located in a remote region with limited exploratory activity in wa-ter depth of more than 2,100 m (6,890 ft). The nearest offset wells were more than 100 km (62 mi) to the north and south, and the onshore base and supply port was located more than 600 km (373 mi) away.
With rig spread rates exceeding $1 million per day, attention to detail was essential in every phase of the remote operation, including pre-job and logistical planning, offset evaluation, risk mitigation, and contingen-cy measures. Because offset well data were extremely limited, with no nearby wells, a key challenge was to reduce depth uncertainty in pre-drill models to make accurate drilling decisions in the 17.5-in. and 12.25-in. sections of the well. By reducing depth uncertainty, Chariot Oil & Gas was able to update the formation depths in the pore pressure model dur-ing drilling and thereby avoid drilling into potentially high-pressure areas.
The pre-job planning phase involved assessing how to effcient-ly apply the technologies, minimize risk and non-productive time (NPT), and ensure a clear process for the operation. A decision tree was used to give the rig team autonomy to make drilling optimiza-tion decisions, such as when to stop and take a pretest. Planning for the SWD involved deciding where to acquire the data and ensuring that the data would be reliably available. Plans for all three sections included memory and real-time data acquisition at connections from the mudline down to TD of the 12.25-in. section.
The exploration model began with the surface seismic data, which was analyzed and interpreted to form a complex model upon which other models could be developed to provide a framework for designing the well. The pre-drill velocity analysis derived from surface seismic data showed the frst reservoir target had depth uncertainty of +/-150 m (492 ft). The model also indicated that 133⁄8-in. casing needed to be placed just above the frst target to optimize the mud weight and limit the number of casing sections required for the remainder of the well.
S-shape trajectoryThe depth uncertainty posed an additional problem due to the
need for an S-shape trajectory. This was required to avoid a seismic anomaly, indicating a shallow drilling hazard, and to enable the well to penetrate several amplitude variations with offset (AVO) responses laterally offset on different horizons that could indicate hydrocarbons. Deviated wells pose the risk of missing the target if the anticipated tar-get depth is not correct. If the target depth is shallower than expected, the wellbore will go under the target. If depth is deeper than expected, the wellbore will go over the top. In this case, it was important that the depth of the kick-off point from vertical be as accurate as possible to maintain a smooth section and avoid side tracks.
For the 26-in. hole section, the plan was to drill without a riser and acquire data when pulling out of the hole after jetting in the 36-in. conductor and drilling to section TD. After reaching the 20-in. casing point, the operator took several days to run the blowout pre-
venter, riser, and casing. During this time, the onshore SWD team processed the high-quality seismic data in memory acquired from section TD up to 700 m (2,297 ft) above the seabed.
This produced a good-quality VSP and revealed a 4-ms time shift between the VSP and surface seismic images. Checkshot data re-vealed that the shallow velocity was slower than expected, making the expected target depths shallower. The well trajectory was re-vised accordingly and predicted depth of the frst target was continu-ally updated as subsequent sections were drilled.
While drilling the 17.5-in. and 12.25-in sections, real-time checkshot data was used to continuously calibrate the velocity model, place the bit on the seismic section, and repeatedly predict the depth of reser-voir targets ahead of the bit. The checkshot data ensured the reservoir was not accidentally penetrated, since it was shallower than the pre-drill model prediction. This enabled Chariot Oil & Gas to drill the 17.5-in. section to within 20 m (66 ft) of the frst reservoir target as planned.
The 12.25-in. section intersected several 2D targets, with seismic data acquired at each drilling connection. Because the casing shoe was placed close to the frst target formation, it allowed the MWW to be optimized. For this section the pre-drill pore pressure model exhibited four different pore pressure models, with a disparity of up to 1.8 pounds per gallon (ppg). The StethoScope formation pressure-while-drilling service was deployed to calibrate in real time the best pore pressure model for optimizing the MWW and casing placement to minimize kicks and drilling delays.
For this complex ultra-deepwater well, the use of SWD service to cali-brate a real-time velocity model enabled Chariot Oil & Gas to overcome several major challenges related to depth uncertainty. With the integrat-ed approach of using SWD and FPWD in the 12.25-in. section, the opera-tor adjusted the well path while drilling and penetrated the key targets, eliminating a 9.625-in. casing string and 8.5-in. hole section, which would otherwise have been needed as the measurements gave assurance that kick tolerance and safe overbalance were maintained at a safe level.
As operators continue to explore ultra-deepwater felds in remote regions with unknown geological hazards, tools that deliver critical model calibration information such as SWD and FPWD assist in meet-ing well objectives and are essential for achieving effciency, reducing costs and time, and mitigating risk. •
Actual measured velocity data compared to the pre-drill velocity models
revealed slower formation than expected and hence shallower targets.
1403OFF_60 60 2/28/14 5:00 PM
Deep local knowledge.Global expertise.Anywhere in the world.www.intecsea.com
This is more than a
subsea umbilical.“It’s the delivery of more than 30 years of global deepwater leadership. It represents hundreds of hours of planning, design and manufacturing oversight by experts around the world, and the opportunity to learn from them.
And it’s my contribution in delivering just one part of the solution to our customer.”
- Ron L., INTECSEA Subsea Systems Engineer, USA
1403OFF_61 61 2/28/14 5:00 PM
62 Offshore March 2014 • www.offshore-mag.com
D R I L L I N G & C O M P L E T I O N
Advances in dual gradient drilling
will facilitate deepwater development
When drilling conventionally, the column of wellbore an-nulus returns (mud and cuttings) presents a single depth versus pressure gradient. Dual gradient drilling (DGD) technology involves creating two or more depths versus pressure gradients in the returns path.
The concept itself dates to the 1960s, and during the 1990s the tech-nique gained favor as an underbalanced drilling (UBD) technique on land drilling programs. A parasite string alongside the casing enabled the injection of a gas (usually nitrogen) at some depth, creating a DG. The objective was to invite the well to fow while drilling, primarily for the purpose of increasing well productivity by avoiding damage to the porosity of the pay zone.
The technique was later introduced to offshore drilling as one of the four variations of managed pressure drilling (MPD). Unlike onshore UBD applications, the offshore application of DG is certainly not to invite the well to fow. The primary purpose is to more precisely stay within shifting, narrow and sometimes relatively unknown safe mud weight windows, and to achieve greater depths with each size casing string.
Don Hannegan, Weatherford manager, strategic technology develop-ment–MPD notes that in conventional deepwater and ultra-deepwa-ter operations, the marine riser is flled with weighted mud and cuttings that exert excessive hydrostatic pressure on the ex-posed wellbore. This severely impacts casing design and cre-ates a host of problems, not the least of which is well control. DGD is particularly suitable for addressing a number of off-shore drilling challenges because it enables a wellbore pres-sure profle to more closely match the pressures presented by nature, reducing or eliminating the impact of water depth on well design. Regarding well control, current methods of achieving dual gradient enable drilling with heavier mud weights than is possible with conventional methods. Because dual gradient is created in the annulus returns path and not within the drill string, concurrent processes such as MWD and LWD are usually not affected.
The method with the greatest number of applications to date is riserless dual gradient, also called riserless mud recovery. This method employs subsea pumps and a dedi-cated fowline for returning mud and cuttings back to the rig, as opposed to the riserless “pumping and dumping” method of establishing subsea wellheads.
There are several DGD methods suitable for deepwater rigs with conventional marine risers and subsea BOPs:
• Subsea mud-lift (pumps near the seafoor)• Controlled annular mud level (pumps shallower to
the rig)• Mud dilution (with concentric riser)
• Inert gas injection (with parasite string). Wellbore pressure management (ECD management) is simi-
lar to the constant bottomhole pressure (CBHP) variation of MPD. Depending on the method and specialized equipment, modifed kick circulation procedures may be required.
The subsea mud-lift method uses positive displacement pumps and is often referred to as “true” DGD because the sub-sea wellhead sees only seawater gradient pressure, as if the rig were on the seafoor. Depending upon water depth and capability of the subsea pumps, the method may allow drilling with a kill-weight mud, posing less risk of environmental consequences in the event of an emergency disconnect.
The controlled mud-level method is often referred to as “mid-riser DGD.” The level in the riser some distance below sea level is managed by subsea pumps mounted alongside the riser.
The mud dilution method is somewhat akin to that of using a booster pump to inject cuttings-free mud into the riser at some depth. A concentric riser enables a lighter mud from the rig to be injected between the inner and outer riser into the annulus returns. Centrifuges may be used to recondition the injectable mud.
The inert gas injection method involves injecting an inert gas, such as nitrogen, into the riser or casing at some depth. The use of a nitrogen production unit (membranes) aboard may be most practical source.
In each method, the specialized equipment required should comply with applicable industry standards. For example, the subsea mud-lift method requires a subsea rotating control device (SRD) to serve as an annulus barrier, allowing the riser above to be
Don Francis
Special Correspondent
DGD enables navigation of narrow, shifting or relatively unknown safe
mud weight windows to greater depths, simplifying well construction
toward achieving total depth objective with large enough hole for well
productivity. (Courtesy Weatherford)
SRD being shop tested in preparation
of subsea mud-lift DGD application in the
Gulf of Mexico. (Courtesy of Weatherford)
1403OFF_62 62 2/28/14 5:00 PM
RIGHTDESIGNTM
Making the RIGHTCHOICES
www.polarcus.com
At Polarcus we operate the most ���������������������������������3D seismic vessels in the industry. � ����������������������������������������������������������������environmental footprint, our vessels ����� ������������������������������� ����������������������� ����tions in the harshest of climates.
1403OFF_63 63 2/28/14 5:00 PM
64 Offshore March 2014 • www.offshore-mag.com
D R I L L I N G & C O M P L E T I O N
flled with seawater and to positively divert re-turns to the subsea pumps.
It is important to note that each method re-quires considerable preplanning, appropriate hazard identifcation, hydraulic fow model-ing, crew training, and (in most waters) pre-approval by regulatory bodies. The specialized equipment required to perform each method is still relatively new, and care should be taken to qualify each component of the DGD “kit” with shop tests or controlled feld trials to ensure that it is ft for purpose.
Dual gradient drilling challenges
According to Frederic Jacquemin, Pacifc Drilling’s dual gradient drilling program direc-tor, there are several challenges to successful DGD operations. “There is a lot of equipment involved, a lot of heavy equipment especially on the particular dual gradient drilling technology that we are deploying with Chevron,” said Jac-quemin. “Most of the equipment is right above the BOP on the seabed. The key equipment is called the MaxLift Pump. It’s about the size and the weight of the BOP and has the complexity of the BOP as well, with control systems and hydraulics, and despite all the redundancy built in the system presents some incremental over-all downtime risks.”
The MLP is the heart of the DGD system, says Jacquemin. “It’s the pump that is on the seabed and brings all the returns on a sepa-rate 6-in. line along the riser to provide the dual gradient mechanism. Therefore, we end up with heavy mud below the mudline and a very light fuid with a density equivalent to seawater inside the riser, above the pump.”
In deepwater, mud-lift pumping is the solution that provides the most beneft of dual gradient, “because we have the beneft of the full mud column all the way down to the seabed being lightened to the equivalent seawater density,” Jacquemin explained. “The full beneft of dual gradient can only be achieved with the pump right on the seabed; any other mechanism of pumping some-
where in the mud column or in a dilution-based system cannot achieve those results.”
Another challenge, he notes, is the au-tomation of the control systems for these pumps. “We’ve spent a lot of time getting our rigs ready for dual gradient drilling by automating a lot of the fuid managing sys-tem. We are talking about three different types of fuid: the heavy mud that is used to drill below the mudline, the riser fuid that is equivalent to seawater, and then we have the seawater power fuid that is powering this pump on the seabed,” Jacquemin noted. “So we are talking about three completely inde-pendent fuid systems that need to be man-aged, that need to be transferred from A to B to be manipulated on the surface without any mixing of the different fuids.”
And, it should be very clear at all times where each fuid is and how it has been transferred, Jacquemin added. “Having all those additional lines, additional valves prop-erly tagged, most of them being remotely controlled, all the virtualization tools and screens and means to operate those valves and educate all the crews and the third par-ties into the different lineups is where we spend a lot of effort, and this is where the bulk of the rig modifcations were, to re-vamp the fuid management system.”
The technologies that need development are in the valve control systems and in data transmission, Jacquemin observes. The goal is “to gain as much as we can in rig integra-tion, in having the controls of the system from the rig side and from the pump side all integrated into a comprehensive system on the rig. This will assist with training of per-sonnel, and the virtualization of different line-ups will make sure that everything is lined up properly and minimize the risk of misplaced fuid, environmental contamination, or other incidents by having the wrong lineups.”
Ultra-deepwater DGDGE Oil & Gas is one of the companies lead-
ing the way in the development of new dual gra-
dient drilling technology. Ahmet Duman, GE Oil & Gas MaxLift pump engineering manager, recently described some of his companies lat-est efforts in this arena. “Our DGD technology removes the unwanted hydraulic pressure on a formation by flling the riser with seawater-density fuid instead of mud, and using a subsea pump at the mudline to transfer mud from well-bore annulus to the rig through a separate mud return line,” explained Duman. “The hydrostat-ic head of the mud from the rig to mudline is totally eliminated from acting on the formation, replaced with the hydrostatic head of seawater-density fuid. The system can drill in tighter fracture and pore pressure gradients of heavy subsalt plays, making previously unreachable reservoirs possible to reach.”
“Our dual-gradient technology was devel-oped and tested 13 years ago in a joint indus-try project and proven in the world’s frst DGD well in 2001 in the Gulf of Mexico,” Duman continued. “After a seven-year pause, we spent more than four years designing and manu-facturing the subsea MaxLift Pump, which is the heart of the entire system. The 30-ft high pump, the size of a lower blowout preventer stack, is powered by seawater and lifts mud to the surface from the seabed foor. It is rated for 10,000 ft water depth and can pump up to 1,800 gal/min, at up to 6,600 psi.”
DGD becomes essential“Appropriate caution is advised, but it is well
worth the effort and cost because the size of the prize is great,” Hannegan observes. “We have already drilled almost all of the easy deepwater prospects with conventional sys-tems, whose hydraulic principles were devel-oped more than a century ago. Remaining prospects are likely to be considerably more challenging or even impossible to drill safely and effectively with conventional means.” As with other variations of MPD, DGD’s ability to drill the undrillable is likely to ultimately play out to be its legacy—that of increasing the world’s recoverable resources from what otherwise would have been the case. •
(Above) The heart of the dual gradient drilling system, the GE-built MaxLift
pump, was installed onboard Pacific Santa Ana in August 2013. (Courtesy
Pacific Drilling)
(Left) Pacific Santa Ana arrived in the US Gulf of Mexico in May 2012 and is
currently drilling for Chevron. (Courtesy Pacific Drilling)
1403OFF_64 64 2/28/14 5:00 PM
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THERE'S
A LOT RIDING ON THIS
DRAUGHT
PLATFORM POSITION
128,500 FT
TO SEA LEVEL
VESSEL
TO PLATFORM
CENTER
OF GRAVITY
75 N
50 N
25 N
MAST HEIGHT
125.56’
LATITUDE: 36°
14’ 55.1789”
LONGITUDE:-115°
10’ 24.2677”
545.135‘
35’ DECK
TO WATER
VESSEL HEIGHT
WIND SPEED
135 FT
647.8’
1403OFF_65 65 2/28/14 5:00 PM
66 Offshore March 2014 • www.offshore-mag.com
P R O D U C T I O N O P E R AT I O N S
Compact coiled tubing unit makes
small completion interventions feasibleCustomized service has been deployed on a number of Southeast Asia workovers
As the number of offshore installations increases globally and others mature, there is a growing industry require-ment for more cost-effective inter-vention methods. Many times, these
installations require a costly and complicated intervention to remediate the well for contin-ued optimum production. In some cases, the cost and logistics of conducting such an in-tervention with conventional methods make the endeavor technically and economically infeasible.
Dating from original developments in the early 1960s, coiled tubing (CT) has become an integral component of many well services, workover, and other intervention programs. According to estimates from the Intervention & Coiled Tubing Association (ICoTA), well servicing and workovers account for 75% of all CT applications, and the global number of CT units continues to increase. The ad-vantages associated with CT are well known, and largely center around cost and effciency benefts. A CT application can be run without a workover rig, it can rapidly trip in and out of the well, and CT operations may be per-formed without having to kill the well.
As the offshore E&P community continues to drill deeper, highly deviated and horizon-tal wells, larger and more technically com-plex completions have resulted. CT service providers have followed suit by developing larger and more robust equipment to deploy larger CT pipe sizes and support increasingly challenging wellbore interventions.
Conventional CT pipe sizes have increased dramatically in the last 50 years, from ½-in. OD to nearly 7-in. OD tubing. This has sub-sequently increased the size and weight of CT unit skids, which must be transported to location by a vessel and positioned on the deck of the platform using a crane. However, many older, marginal, or depleted felds have platforms with access, deck space, and crane limitations (often with downgraded ratings) that restrict the use of larger and heavier con-ventional CT units.
Alternative offshore deployments and con-
fgurations exist, including the deployment of temporary or self-erecting crane packages to lift the CT unit and associated equipment onto the platform, in instances where plat-form cranes are not adequate. For platforms with insuffcient deck space, the CT unit may be placed on the platform, while the pump-ing equipment remains onboard a nearby support vessel. In cases where both deck and crane limitations preclude these options, the CT unit operation may be run from a lift boat, barge, or rig.
While these alternate options may be tech-nically feasible, they may be too costly to justi-fy the expense. In some cases, wells have been abandoned before reaching their potential producing life because the economic incentive was not strong enough to compel the operator to deploy a conventional CT unit.
Think small for big gainsThese realities guided Baker Hughes in
the development of its Micro CT Coiled Tub-ing service, a more compact, lighter weight and modular system using a combination of equipment and proprietary intervention mod-eling software to circumvent the deployment challenges of larger CT equipment. The unit effectively bridges the gap between traditional capillary and CT services to allow operators to economically service wells that might other-wise have to be shut in or abandoned.
Tim RamseyGordon Mackenzie
Adrian Terry Rick StanleyBaker Hughes
Micro CT units are a more compact, lighter weight and modular system
using a combination of equipment and proprietary intervention modeling
software to circumvent the deployment challenges of larger CT equipment.
1403OFF_66 66 2/28/14 5:00 PM
www.offshore-mag.com • March 2014 Offshore 67
P R O D U C T I O N O P E R AT I O N S
An operator in the Gulf of Thailand used Baker
Hughes Micro CT system because barge-sup-
ported CT operations were not economically
feasible, and the platform did not have sufficient
deck space to rig up either a conventional CT
equipment package or a hydraulic workover unit.
The smaller CT system is primarily designed to run 5⁄8-in., ¾-in., and 1-in. work strings with a 20,000-lb pull injector capacity, but can also run larger CT, injector heads, and reels. The unit breaks down into nine main components. The modules include:
• A control cabin designed for an operator and with an additional fold-down seat for an assistant. The cabin includes integrat-ed stairways, handrails, and food lights.
• An engine module and hydraulic module power packs, designed to meet Zone II, DNV 2.7-1, and/or Class 1 Div II speci-fcations. The engine module drives the hydraulic module’s various hydraulic sys-tems through a quick connecting prop-shaft. The modules assemble in about 15 minutes with a few hoses, cables, and quick-connecting driveshaft.
• An auxiliary module provides powered hose reels for quick rig up and easy man-ual handling, along with BOP accumula-tor banks for pressure control typically associated with CT units. In situations where deck space is limited or a larger CT reel is required, the control cabin can be stacked upon the auxiliary module.
• An option for two drum sizes, capable of holding 10,000 ft (3,048 m) and 17,000 ft (5,182 m) of ¾-in. tubing (or larger tub-ing with shorter lengths).
• A pressure control/injector/gooseneck basket, which holds a 20,000-lb capacity injector head capable of running both capillary and coiled-tubing stings; a 3 1/16-in., 10,000-psi (689-bar) working pressure well control stack.
The modular nature of the system reduces the need for self-erecting cranes and support/supply vessels, as it is easier to transport and rig up compared to conventional systems. The system also minimizes logistics and onboard personnel to reduce HSE risks. To date, the customized CT service has been deployed in a number of workovers in Southeast Asia to assist in downhole scale removal, solids clean out, mill-ing, perforating, and gas-lift extension projects.
Scale removal An operator in the Gulf of Thailand was chal-
lenged with the buildup of scale deposits in a 13,200 ft (4,023 m) well that prevented access to deeper portions of the well. Multiple wireline attempts had proven unsuccessful in removing these deposits, which compelled the operator to use CT to remove the scale and improve well production. The Micro CT service was pro-posed, as barge-supported CT operations were not economically feasible, and the platform did not have suffcient deck space to rig up either a conventional CT equipment package or a hydraulic workover unit. In addition, the rig’s crane capacity had been derated, which pre-vented any heavy lifts onto the platform.
A site survey was conducted using the com-pany’s CIRCA modeling software to simulate CT operations and to provide a thorough un-derstanding of the available deck space. This information was then used to engineer a cus-tomized equipment spread that was deployed to the platform, thus eliminating the need for a support vessel.
The workover then began by running a 1-in. CT string to 13,200 ft TD, where a jetting tool affxed to the string pumped a 15% HCl inhibit-ed-acid solution treatment to dissolve the scale deposits from the tubing completion. The scale was removed in one trip, as confrmed by a sep-arate wireline run to verify the post-treatment condition of the tubing and collect additional data to improve well productivity.
The job took four days of actual operat-ing time and required no milling tools. By placing the modular system on the platform deck, the operator was able to eliminate the need for a standby support vessel. At a day rate of $30,000, avoiding a support vessel saved the operator 30% to 40% of the costs of a conventional CT operation.
Boosting production An operator of a monobore single gas well
in the Golok Barat feld offshore Malaysia was experiencing dwindling production and challenges with reaching and perforat-ing the lower completion due to a damaged permanent tubing patch straddle section at a depth of 5,269 ft (1,606 m). The patch had previously been installed to abandon an up-
per zone at 5,194 to 5,354 ft (1,583 to 1,632 m), but now had to be milled out to allow ac-cess to the lower zone and boost production.
The operator narrowed its intervention options down to the small CT system or trac-tor-deployed milling, but settled on the CT system because of its smaller footprint and lighter weight. Baker Hughes conducted coiled tubing simulations on the well, which had a corkscrew profle characterized by a tortuous well path due to high dogleg sever-ity of 5.04°/30.28 m at 2,053 ft (626 m) and a maximum hole angle of 71°.
Given these challenges, the service provid-er and operator arrived at a deployment plan that called for frst milling the ID restriction to gain access below the permanent tubing patch, followed by spotting a gel pill across the milled section to reduce potential cross fow and fnally, perforating with slickline. While the milling operation was successful using friction-reduced water at a pump rate of 0.8 to 1.0 bpm and 4,000 to 4,500 psi (276 to 310 bar), the subsequent slickline run be-came held up at 5,262 ft (1,604 m).
A secondary option of perforating the lower section with the small CT unit was then initi-ated. A total of 23 runs, including 14 perfora-tion runs, were performed with the small CT unit over 20 days, without any major issues. The production effect was instantaneous with a gas rate of 15 MMcf/d. The intervention has allowed the operator to continue producing the well and access new reserves without the expense of an extensive workover operation.
This small CT operation allowed for various downhole tools to pass through restrictions and perforate the new production interval. No NPT was recorded, and the operation was car-ried out as per the job program. Good commu-nication and teamwork between the service company and the operator were key to execut-ing the job safely and without incident.
Future applications While the Micro CT service was initially
developed for the Asia/Pacifc region its grow-ing successful track record there has garnered greater interest from offshore operators abroad. The Gulf of Mexico, for example, contains a large number of small-deck satellite platforms, many of which have been in production for de-cades and are in need of workover operations to boost production. In addition, the industry de-sire for modular and lightweight rig components with a minimal footprint has increased over the past two decades in the GoM, and service pro-viders have answered this call by designing ever smaller and more nimble rig equipment.
The Micro CT service was specially de-signed with these industry requirements in mind, and Baker Hughes continues to tailor the service for the Gulf of Mexico, West Af-rica, Middle East, and Europe. •
1403OFF_67 67 2/28/14 5:00 PM
68 Offshore March 2014 • www.offshore-mag.com
S U B S E A
This issue of Offshore contains the 2014 Worldwide Survey of Subsea Process-ing Systems, the seventh installment of this industry resource, a joint ef-fort between INTECSEA and Offshore
magazine. The primary aims of this poster are to chronicle the development and the de-velopers of these systems, and to document the continued commitment of oil companies to the application of these technologies. For online access to view and download all sev-en posters, please visit www.offshore-mag.com/maps-posters.html.
Each year’s edition of the poster refects the evolution of the technology, and is also an evolution in itself in the way the information is presented. This year, we have noted a distinct trend: subsea boosting is more a matter of course for many operators, and efforts have shifted toward effective implementation. The formation of API Committee 17X, charged with development of a Recommended Practice for Subsea Pumping within the next year, is evi-dence of the focus on effective implementation, and also marks the beginnings of standardiza-tion in the subsea processing arena. While we have worked each year to graphically illustrate the various subsea processing architectures and their respective applications, this year we have revised our approach to further capture this trend toward implementation, even while the key technologies continue to evolve.
Subsea confgurations Subsea processing confgurations, a
newly revised section this year, is in the lower right-hand quadrant of the poster. In this section, there are three graphical sys-tem confgurations, titled short, medium and long distance confguration examples. These diagrams capture the basic elements of subsea processing systems, and show how these systems evolve as requirements of the feld under development steadily ex-pand with increasing distance from the host platform or shore facility. We also note that the use of the various building blocks is not necessarily restricted to the short, medium or long distance examples in which we have portrayed them. There are exceptions to every rule, yet we believe we have captured the concepts in a way that will help our read-ers understand and apply the capabilities of the technologies.
Short distance The short distance confguration example
is in Figure 1 of the subsea processing con-fgurations section of the poster. The single element of subsea processing in this fgure is subsea boosting which, again, is becoming a matter of course for many operators. This example applies to tieback distances up to 15 km (9.3 mi). Figure 1 is accompanied by a one-line electrical diagram, Figure 2, and a process fow diagram, Figure 3, correspond-ing to the equipment layout of Figure 1.
Also included in the subsea processing con-fgurations section are eight charts entitled subsea power and processing technology at-tributes, each showing currently qualifed ca-pabilities and those being qualifed or under further development. For the short distance example, tables 4.2 and 4.3 are applicable for the electrical power system and subsea boost-ing technology, respectively.
Medium distance The medium distance confguration ex-
ample is in Figure 4 of the subsea process-ing confgurations section, and the electrical one-line diagram and process fow diagrams are shown in Figures 5 and 6, respectively. Medium distance ranges up to 60 km (37.3 mi). In this range, fow assurance challenges typically present the need for gas/liquid sepa-ration (we have also included the capability for raw seawater injection). The subsea pow-er and processing technology attributes are shown in Tables 4.4, 4.5, and 4.8 for power, two-phase separation, and raw seawater injec-tion technology, respectively; Table 4.3 still applies for subsea boosting.
Long distance The most challenging, and most interesting,
example is the long distance confguration, in Figure 7, for distances ranging up to 140 km (87 mi). At this distance, all the major elements of subsea processing might come into play: three phase separation, produced water re-injection,
and gas compression, as well as subsea boost-ing. The attributes are shown in Tables 4.1, 4.3, 4.6, and 4.7.
Power system step-out One feature from the 2013 poster retained
for this year is Table 5: power system step-out confgurations. The Type 1, 2, and 3 cat-egories in this table correspond to the Type 1, 2, and 3 electrical diagrams used in the short, medium and long distance confgura-tions. The Type 4 category shown in Table 5 was not illustrated with a subsea process-ing confguration in this year’s poster. The range for Type 4 extends up to 400 km (~250 mi), and perhaps even further. This range lies clearly in the future, beyond the projec-tions we have made to date.
Two areas to watchA number of technology advances are
identifed in the poster, each of which will be quite interesting to follow, but there are two areas worthy of special note: separator tech-nology and gas compression. Whereas the conventional vessel technology has seen suc-cess, most notably at Pazfor, concerns over cost, size and weight continue to drive inter-est in alternatives. Finally, we are confdent that the pending installations of gas compres-sors at Åsgard and Gullfaks will draw special interest, and may guide the subsea process-ing industry closer toward a complete and comprehensive subsea capability. •
Larry ForsterMac McKeeJohn AllenINTECSEA
The subsea gas compressor for Statoil’s Åsgard field, which is scheduled to start production in 1Q 2015. For more details on current subsea processing trends and technologies, see the poster included in this issue. (Image courtesy MAN Diesel & Turbo)
Subsea processing retains innovation,
moves toward standardization
1403OFF_68 68 2/28/14 5:02 PM
Refinery-wide modellingusing your own standards
REFINING
Facility models thatunderstand field plans
PRODUCTION
[email protected] www.kbcat.com blog.kbcat.com
EMEA: +44 1932 242424 ASIA: +65 6735 5488 AMER: +1 281 293 8200
KBC Advanced Technologies plc
1403OFF_69 69 2/28/14 5:02 PM
MARCH 2014
STATUS OF THE TECHNOLOGY
2014 WORLDWIDE SURVEY OF SUBSEA PROCESSING: SEPARATION, COMPRESSION,
AND PUMPING SYSTEMS
M A G A Z I N E
Offshore Magazine1455 West Loop South, Suite 400
Houston, TX 77027 USA Tel: 713-621-9720
www.offshore-mag.com
Larry Forster, Thiago Mesquita Paes, Richard Voight, Spiridon Ionescu, John Allen, RJ Baker, Rachel Townsend, Julie Burke and Mac McKee of INTECSEA,
E. Kurt Albaugh of Repsol E & P USA, and David Davis of Offshore MagazinePoster Assembled By: Chris Jones of XenonGroupDesign.com
Digital Images by: Sid Aguirre of C-Ray MediaE-Mail Comments, Corrections or Additions to: [email protected]
To Download a PDF, go to: www.offshore-mag.com/maps-posters.html or www.intecsea.com/publications/posters
INTECSEA, Inc.15600 JFK Boulevard, Ninth Floor
Houston, TX 77032 USA Tel: 281-987-0800 www.intecsea.com
ACKNOWLEDGEMENT OF THE CONTRIBUTORSINTECSEA and Offshore Magazine wish to acknowledge the following companies and individuals who continue to support our efforts
to educate and inform the oil & gas industry on the status of subsea processing technologies.Aker Solutions: Jonah Margulis and Kate Winterton; OneSubsea: Jarle Michaelsen and Jessica Clements; Flowserve: Bob Urban and Marc L. Fontaine; FMC Technologies: Janardhan Davalath, Jayne Merritt, Alan Szymanski and Citlalli Utrera; MAN Diesel & Turbo: Domingo Fernandez; Repsol E & P USA: Ron Pettus; Saipem: Claude Valenchon, Stephanie Abrand and Stephane Anres; Shell: Chris Shaw; Siemens: Ordin Husa; Schneider Electric: Kristina Hakala; Schlumberger: Grant Harris; SEABOX AS: Torbjorn Hegdal and Eirik Dirdal; SPX: Ross Dobbie; Technip: Chuck Horn, Mike Zerkus and Tim Lowry
Information Accuracy: We have attempted to use correct and current, as of press time, information for the subsea processing systems and equipment described herein. No installed,
sanctioned, or pending application was intentionally excluded. We have summarized the capability and operating experience by acting as a neutral party and integrator of information.
Information has been collected from public sources, company brochures, personal interviews, phone interviews, press releases, industry magazines, vendor-supplied information, and
web sites. No guarantee is made that information is accurate or all-inclusive. Neither INTECSEA nor Offshore Magazine guarantees or assumes any responsibility or liability for any party’s
use of the information presented. If any information is found to be incorrect, not current, or has been omitted, please send comments to [email protected].
©2
01
4 O
ffshore
POSTER
111Norwegian Sea
Tordis (Separation, Boosting, WI)
Troll C. Pilot (Separation, WI)
Tyrihans (WI)
Draugen (Boosting)
Draugen - Expansion (Boosting)
Aasgard (Compression)
Gullfaks (Compression)
DEMO 2000 (Compression)
Ormen Lange (Compression)
Troll (Compression)
Equatorial Guinea
Topacio (Boosting)
Ceiba FFD (Boosting)
Ceiba C3+C4 (Boosting)
North Sea
Columba E. (WI)
Brenda & Nicol (Boosting)
Lyell (Boosting)
Machar/ETAP (Boosting)
Highlander (Separation)
Argyll (Separation)
Mediterranean
Montanazo & Lubina (Boosting)
Prezioso (Boosting)
Angola
Pazflor (Sep., Boosting)
CLOV (Boosting)
GirRi (Girassol) (Boosting)
Congo
Azurite (Boosting)
Moho Phase 1 BIS (Boosting)
West of Shetlands
Schiehallion (Boosting)
Abu Dhabi
Zakum (Separation)
Barents Sea
Shtokman (Compression)
Snohvit (Compression)
Espirito Santo Basin
Jubarte - Phase 2 (Boosting)
Golfinho (Boosting)
Jubarte - Phase 1 (Boosting)
Jubarte EWT (Boosting)
Canapu (Separation)
Atlanta (Boosting)
Parque das Baleias (Boosting)
GOM
Perdido (Separation, Boosting)
Navajo (Boosting)
King (Boosting)
Cascade & Chinook (Boosting)
Jack and St. Malo (Boosting)
Julia (Boosting)
Stones (Boosting)
South China Sea
Lufeng (Boosting)
Campos Basin
BC-10 - Phase 1 (Separation, Boosting)
Espadarte (Field Trial) (Boosting)
Barracuda (Boosting)
Marimba (Separation, Boosting)
Marlim SSAO - Pilot (Separation)
Albacora L'Este (WI)
Marlim (Boosting)
Congro (Separation, Boosting)
Corvina (Separation, Boosting)
BC-10 - Phase 2 (Separation, Boosting)
Western Australia
Mutineer/Exeter (Boosting)
Vincent (Boosting)
Installed & Currently Operating
Installed & Not Currently Operating or In-active
Abandoned, Removed
Awarded and in Manufacturing or Delivered
Qualified/Testing
Conceptual Project
Canceled Project
WORLDWIDE LOCATIONS FOR SUBSEA PUMPING, COMPRESSION, AND SEPARATION SYSTEMS (As of Feb., 2014)
COURTESY OF
GRAPH 1 – GVF vs. DIFFERENTIAL PRESSURE - OPERATIONAL AND CONCEPTUAL CAPABILITIES
250
200
150
100
50
0 bar
3,625
3004,400
2,900
2,175
1,450
725
0 psi
SPP - Single Phase Pump (Centrifugal)
TSP - Twin Screw Pump
WGC - Wet Gas Compression
DGC - Dry Gas Compression
HSP - Hydraulic Submersible Pump
Dif
fere
nti
al P
ress
ure
GVF (%)
High BoostHelico-Axial
StandardHelico-Axial
Hybrid
HSP
SPP (Centrifugal)
TSP
WGC DGC
TSP
1000 10 20 30 40 50 60 70 80 90
0% 20% 40% 60% 80% 100% 0 100 200 300 400
GRAPH 2 – HIGH LEVEL COMPARISON OF SUBSEA BOOSTING OPTIONS
Pump Types GVF Range (Approximate) Pressure Differential (Bar)
CENTRIFUGAL
HYBRID (CENTRIFUGAL/HELICO-AXIAL)
MULTIPHASE ESP
HSP
HELICO-AXIAL
TWIN SCREW
Notes:
1. Combination of parameter values shown above is not feasible.
2. There are a number of other parameters/factors that need to be considered for any pump selection.
3. Based upon recent updates from Flowserve’s subsea boosting system test results.
4. HSP can tolerate up to 100% of gas slug.
125
175 (Note 3)
200 (Note 2)
75%
COURTESY OF COURTESY OF
TABLE 2 – PUMP TYPES & APPLICATIONSTYPE CONFIG. APPLICABILITY FOR SUBSEA BOOSTING
CENTRIFUGAL HORIZONTAL OR VERTICAL
H Highest differential pressure capability among pump types.
H Handles low Gas Volume Fraction (GVF) < 15% at suction conditions.
HYBRID (CENTRIFUGAL & HELICO-AXIAL)
VERTICALH Combination of helico-axial and centrifugal impeller stages.
H Primary application is for use downstream of separator or in low GOR applications
where GVF is consistently < 38% at suction conditions.
MUDLINE ESP HORIZONTAL OR VERTICAL
H Widely deployed technology used for boosting in wells, caissons, flowline risers, and
mudline horizontal boosting applications.
H Applicable for conditions of GVF < 50% (continuous) and for improved flow assurance.
HSP HORIZONTAL OR VERTICAL
H Compact hydraulic drive boosting pump for wells, caissons & mudline applications.
H Applicable for conditions of GVF < 75% (continuous) and for improved flow assurance.
HELICO-AXIAL VERTICALH Applicable for higher GVF boosting applications - typical range of 30-95% GVF at
suction conditions.
H Moderate particulate tolerance.
TWIN SCREW HORIZONTAL OR VERTICAL
H Good for handling high GVF - up to 98% GVF at suction conditions.
H Preferred technology for high viscosity fluids.
SUBSEA BOOSTING PUMP TYPES
Fig. 1: Vertically ConfguredCentrifugal Single Phase Pump & Motor Diagram
Fig. 3: OneSubsea’s Multiphase Hybrid SS Boosting Pump
HYBRID: OneSubsea’s hybrid pump was developed and qualifed for the Pazfor subsea separation and boosting project. It comprises a combination of lower helico-axial stages and upper centrifugal stages on the same shaft. This confguration tolerates moderate gas fraction and generates high differential head to allow a wide operating envelope.
CENTRIFUGAL PUMPS (For GVF < 15%)
HYBRID PUMPS (For GVF < 38%)
HELICO-AXIAL PUMPS (For GVF < 95%)
TWIN SCREW PUMPS (For GVF < 98%)
Courtesy of OneSubsea
Fig. 7: Deployment of a OneSubsea Helico-Axial Multiphase Pump
HELICO-AXIAL: OneSubsea’s multiphase pump stages in a vertical confguration. Recent testing and successful qualifcation work, in the HiBoost MPP Joint Industry Project, have greatly increased differential head capability (see Graph 2 for details).
HSPs can be confgured as a downhole pump with the power pressure pump residing on a platform or on the seabed. The downhole pump can also be vertically confgured in a seabed caisson for boosting and separation purposes.
Fig. 6: Vertically ConfguredHelico-Axial Pump & Motor Diagram
Courtesy of OneSubsea
Fig. 9: Vertically Confg-ured SMPC Series 4 Twin Screw Pump & Motor
Courtesy of Bornemann
Fig. 8: Twin Screw PumpCross Section Diagram
Courtesy of Leistritz
Fig 11: Vertically Confgured SMPC Series 4 Twin Screw Pump & Motor
Courtesy of Bornemann
Courtesy of Bornemann
Fig. 10: Bornemann Twin Screw Cross Section Diagram
Fig. 12: Flowserve Horizontally Confgured Twin Screw Pump & Motor Concept
Courtesy of Flowserve
Fig. 2: VerticallyConfgured Hybrid Pump& Motor Diagram
Courtesy of OneSubsea
Fig. 4: Diagram of Vertically Confgured Gas Handling ESP in a Seabed Caisson
Fig. 5: Diagram of HSP Principle of Operation
ESP PUMPS (For GVF < 50%)
HSP PUMPS(For GVF < 75%)
Courtesy of Schlumberger
Courtesy of ClydeUnion Pumps (SPX)
ESPs can be installed in a caisson to gather and boost fow from multiple wells.
POSTER COLOR CODE KEYThe poster is divided into discrete sections and each section is marked by a background color. The colors denote the type of technology presented in the sections. This color code is carried throughout the poster. Below are the intuitive color code designations for each of the six themes.
Full Wellstream Subsea Boosting
Subsea Separation
Subsea Gas Compression
Water Injection with Subsea Pumps
Power Transmission/Distribution and Controls
Miscellaneous Information/Combination of Technologies
CHART 1 – SUBSEA SUPPLIER MATRIX (As of Feb., 2014) SUBSEA PROCESSING
SUBSEAPUMPING
AKER SOLUTIONS
akersolutions.com
FMC TECHNOLOGIES (6)
fmctechnologies.com
GE
ge-energy.com
AKER SOLUTIONS
akersolutions.com
BORNEMANN (8)
bornemann.com
FLOWSERVE
flowserve.com
PUMPSYSTEM
PACKAGERS
ELECTRICMOTOR
MANUFACTURERS
ONESUBSEA
onesubsea.com
BAKER HUGHES
bakerhughes.com
ONESUBSEA
onesubsea.com
ONESUBSEA
onesubsea.com
ClydeUnion (SPX)
spx.com
SCHLUMBERGER
slb.com
LEISTRITZ
leistritzcorp.com
AKER SOLUTIONS
akersolutions.com
DIRECT DRIVE SYSTEMS (1)
fmctechnologies.com
FLOWSERVE
flowserve.com
CURTISS WRIGHT
curtisswright.com
LOHER (2)
automation.siemens.com
HAYWARD TYLER
haywardtyler.com
AKER SOLUTIONS
akersolutions.com
DUCO
technip.com
JDR
jdrcables.com
DRAKA
draka.com
OCEANEERING
oceaneering.com
NEXANS
nexans.com
PARKER
parker.com
ABB
abb.com
FURUKAWA
Furukawa.co.jp
MITSUBISHI
mitsubishielectric.com
BICC BERCA
biccberca.com
OKONITE
okonite.com
NKT
nktcables.com
SUMITOMO
sumitomo.com
BRUGG
bruggcables.com
HITACHI
hitachi.com
ALCATEL
alcatel-lucent.com
NEXANS
nexans.com
PRYSMIAN
prysmiangroup.com
ABB
abb.com
CONVERTEAM (7)
ge-energy.com
ONESUBSEA
onesubsea.com
BAKER HUGHES
bakerhughes.com
SCHNEIDER ELECTRIC
schneider-electric.com
AKER SOLUTIONS
akersolutions.com
BAKER HUGHES
bakerhughes.com
PUMPMANUFACTURERS
AKER SOLUTIONS
akersolutions.com
FMC TECHNOLOGIES
fmctechnologies.com
GE
ge-energy.com
BAKER HUGHES
bakerhughes.com
ONESUBSEA
onesubsea.com
SUBSEA RAWSEAWATER
INJECTION (3)
AKER SOLUTIONS
akersolutions.com
ASCOM
ascomseparation.com
SUBSEASEPARATION
SYSTEMS
AKER SOLUTIONS
akersolutions.com
ONESUBSEA
onesubsea.com
GE
ge-energy.com
XXXXXXXXX
XXXXXXXXX
DRESSER RAND
dresser-rand.com
GE POWER SYSTEMS
ge-energy.com
MAN Diesel & Turbo
mandieselturbo.com
ONESUBSEA
onesubsea.com
SIEMENS INDUSTRIAL
TURBO MACHINERY
turbomachinerysolutions.com
UMBILICALS
ALSTOM
alstom.com
XXXXX
BENNEX (4)
energy.siemens.com
DEUTSCH (5)
te.com
GE VetcoGray
ge-energy.com
SEACON
seaconworldwide.com
SIEMENS
energy.siemens.com
TELEDYNE ODI
odi.com
DIAMOULD
diamould.com
HVCONNECTORS
BENESTAD (9)
benestad.com
DIAMOULD
diamould.com
SIEMENS
energy.siemens.com
DEUTSCH (5)
te.com
TELEDYNE ODI
odi.com
TELEDYNE D.G.O’BRIEN
dgo.com
PENETRATORSAKER SOLUTIONS
akersolutions.com
CONVERTEAM (7)
ge-energy.com
ALPHA THAMES
alpha-thames.co.uk
SCHNEIDER ELECTRIC
schneider-electric.com
AKER SOLUTIONS
akersolutions.com
BAKER HUGHES
bakerhughes.com
VETCO GRAY SCANDINAVIA
ge-energy.com
SIEMENS
energy.siemens.com
ASDs/VSDs & X-FORMERS
POWERCABLES
HV &AC/DC POWER
CONTROLSYSTEMS
TESTINGFACILITIES
FMC TECHNOLOGIES/
SULZER (6)
fmctechnologies.com
sulzer.com
ONESUBSEA
onesubsea.com
SEABOX
sea-box.no
SAIPEM
saipem.com
NSW
nsw.com
BORNEMANN (8)
bornemann.com
FLOWSERVE
flowserve.com
FMC TECHNOLOGIES
fmctechnologies.com
ONESUBSEA
onesubsea.com
PROLAB
prolabnl.com
STATOIL: P-LAB & K-LAB
(Norway)
PETROBRAS ATALAIA LAB
(Brazil)
SHELL GASMER
(Houston, TX)
SULZER (6)
sulzer.com
LEISTRITZ
leistritzcorp.com
OTHERSUPPORTING
SYSTEMS
COMPRESSORS
FMC TECHNOLOGIES
fmctechnologies.com
COMPRESSIONSYSTEM
PACKAGERS
SUBSEACOMPRESSION
GE
ge-energy.com
ONESUBSEA
onesubsea.com
FMC Technologies
fmctechnologies.com
TWISTER BV
twisterbv.com
SAIPEM
saipem.com
SCHNEIDER ELECTRIC
schneider-electric.com
SULZER (6)
sulzer.com
COURTESY OF
NOTES: 1. Direct Drive Systems is a subsidiary of FMC Technologies. 2. Loher is a Siemens company. 3. Subsea raw seawater injection refers to only those projects utilizing a subsea pump to inject
seawater and does not include typical water injection using a pump on a topside facility. 4. Bennex is a Siemens company.
5. Deutsch is part of the TE connectivity group. 6. FMC Technologies and Sulzer have formed a joint venture.7. CONVERTEAM is a GE company. 8. Bornemann is an ITT Company.9. Benestad is a Aker Solution company
TABLE 7 – OTHER INFORMATION SOURCES Go to www.onepetro.org to order the SPE & OTC papers listed below.
SUBSEA BOOSTING PROJECTS
OTC 23178 2012 FMC Pazflor: Test/Qual. of Novel Tech.
OTC-24498 2013 PETROBRAS SS Proc. & Boost. in Brazil
OTC-24401 2013 FMC/SULZER Dev. & Qual. of a High DP SS Pump
OTC-24201 2013 PETROBRAS Mudline ESP in a Subsea Skid
OTC-24428 2013 PETROBRAS/ONESUBSEA SS High Boost MPP
OTC-24217 2013 PETROBRAS Barracuda Subsea Helico-Axial MPP
SPE-164757 2013 JOH. HEINR. BORNEMANN MP Boosting in Oil and Gas
OTC-24263 2013 ONESUBSEA Evolution of SS Boosting
SUBSEA SEPARATION
IPTC-16914 2013 KERR-MCGEE & BAKER HUGHES Downhole Oil and Water Separation
SPE-166079 2013 BP & SOUTHWEST R. INST. Evaluation of Separation in a Casing
OTC-24533 2013 PETROBRAS Comiss./Startup of SS Marlim Separ.
SPE-167334 2013 PANDIT DEENDAYAL PET. UNIV. Effective Gas-Liquid Separation
OTC-24359 2013 SAIPEM SS Gas-liq. and Water-hydro. Sep.
OTC 23223 2012 FMC/EXMOB/WOODSIDE Compact SS Sep. for Deep Water
OTC 23478 2012 ENI SS Gas/Liquid Separation
DOT-T2S1O2 2011 SAIPEM Development of the Spoolsep
SUBSEA RAW SEAWATER AND PRODUCED WATER INJECTION DEVELOPMENT
OTC-24167 2013 PETROBRAS Albacora Subsea Raw WI
OTC-24111 2013 CHEVRON WI in the Gulf of Mexico
SPE-166576 2013 SEA-BOX/AKER SUBSEA SS Water Treatment and Injection
SPE-165138 2013 TOTAL EP Produced Water Re-Injection
SPE-164372 2013 SAUDI ARAMCO Prod. Water Re-Injection Sys. Optim.
OTC-24273 2013 TOTAL/SAIMPEM/VWS WEST. Springs: Subsea WI Treatment
MULTIPHASE BOOSTING SYSTEMSPE 134341 2010 SHELL/FLOWSERVE Dev. of High Boost System
SUBSEA COMPRESSIONIPTC-17649 2013 A/S NORSKE SHELL SS Compression at Ormen Lange
IPTC-16982 2013 CURTIN U. Appl. of Downhole Gas Compressor
IPTC 14231 2011 FRAMO Advances in SS Wet Gas Comp.
OTC 21346 2011 STATOIL/ONESUBSEA Testing of SS Wet Gas Comp.
OCT 24211 2011 AKER SOLUTIONS SS Compression: A Game Changer
DOT AMST. 2010 SHELL Qualifying the Technology
POWER TRANSMISSION/DISTRIBUTIONOTC-25278 2014 INTECSEA Hybrid “Split” VFD / SSP Tieback
OTC-24129 2013 PETROBRAS SS Electrical Power Trans. and Dist.
OTC-24448 2013 INTECSEA High Voltage Power Transmission
OTC-24129 2013 PETROBRAS Devel. of a SS Elect. Power Transm.
OTC-23935 2013 DEUTSCH/SCHNEIDER Powering Subsea Processing
OTC-24147 2013 DET NORSKE VERITAS Power System for the New Era
SPE-166558 2013 SCHLUMBERGER SS Cable Applications in Offshore
IPTC-17269 2013 TOTAL EP Selection of Power from Shore
OTC-24183 2013 GE Modular Stacked DC Transmission
OTC-23960 2013 HUSKY OIL CHINA LTD. Husky Liwan Deepwater SS Control
COMPANY EXPERIENCE & APPROACH TO SUBSEA PROCESSINGOTC-24307 2013 STATOIL Steps to the Subsea Factory
OTC-24161 2013 PETROBRAS SS Proc. Systems: Future Vision
OTC-24519 2013 PETROBRAS Subsea vs Topside Processing
OTC-23970 2013 TECORP INT. Challenges World Largest Slug
Catcher
OTC-24162 2013 PETROBRAS Cascade and Chinook Subsea Dev.
COURTESY OF
2P Two Phase3P Three PhaseAC Alternate CurrentAL Artifical LiftALM Artifical Lift ManifoldASD Adjustable Speed DriveBOPD Barrels of Oil per Day BPD Barrels per Day CAPEX Capital Expenditures COSSP Configurable Subsea Separation
& PumpingCSSP Centrifugal Subsea Submersible
PumpCTCU Cable Traction Control Unit DMBS Deepwater Multiphase Boosting
SystemESP Electrical Submersible Pump FFD Full Field Development FPS Floating Production System FPSO Floating, Production, Storage,
& Offloading Vessel GLCC Gas/Liquid Centrifugal CyclonicGLR Gas Liquid RatioGVF Gas Volume Fraction
Hp HorsepowerHSP Hydraulic Submersible PumpHV High VoltageIOR Improved (Increased) Oil Recovery JB Junction Box kW Kilowatt LDDM Long Distance Delivery Management LDDS Long Distance Delivery System MPP Multiphase Pump MW Mega WattsNF Natural FlowOPEX Operational Expenditures PCDM Power and Communication
Distribution Module PCM Power Control ModulePFD Process Flow DiagramPLET Pipeline End TerminationPLIM Pipeline Inline Manifold PSIG Pipeline Simulation Interest Group/
Pounds per Square Inch (Gauge)PSUTA Pump Subsea Umbilical Termination
AssemblyROV Remote Operated Vehicle RPM Revolutions per Minute
SCM Subsea Control Module SFB Seafloor BoostingSIORS Subsea Increased Oil Recovery System SMUBS Shell Multiphase Underwater Boost
StationSPEED Subsea Power Electrical Equipment
DistributionSPP Single Phase PumpSS SubseaSSBI Subsea Separation Boosting InjectionSSP Subsea ProcessingSUBSIS Subsea Separation and Injection
System SUTA Subsea Umbilical Termination
AssemblyTUTA Topside Umbilical Termination
AssemblyVASPS Vertical Annular Separation and
Pumping System VSD Variable Speed Drive WD Water DepthWI Water InjectionWI XT Water Injection Christmas TreeXT Christmas Tree
COURTESY OF
TABLE 6 – ACRONYMS & ABBREVIATIONS
SUBSEA GAS COMPRESSION SYSTEMS & PRODUCTS BY COMPANYFig. 1: Ormen Lange Subsea Compression Pilot
Courtesy of Aker Solutions
Fig. 2: Subsea Gas Compression Station Concept
Courtesy of FMC Technologies
Fig. 4: Åsgard SS Compressor
Courtesy of MAN Diesel & Turbo
Fig. 7: Åsgard SS Compression Support Structure in Transit to Field
Courtesy of Aker Solutions
Fig. 8: Kvaerner Booster Station(KBS) for SS Gas Compression
Courtesy of GE Oil & Gas
Fig. 6: Åsgard Subsea Compression Station Template Installation
Courtesy of Aker Solutions
Fig. 5: Illustration of the OneSubsea Gullfaks Wet Gas Compression Station
Courtesy of OneSubsea
Fig. 3 : OneSubsea Counter-rotating 5MW Wet Gas Compressor built for Gullfaks Qualifcation Test
Courtesy of OneSubsea
SUBSEA POWER CONDITIONING EQUIPMENT & CONNECTORS
Note: The Siemens Subsea Power Grid is shown in Fig. 5, with the main building blocks in Figs. 6, 7 and 8.
Wet mate 36kV connectors and control system will also be part of the Siemens Subsea Power Grid.
Fig. 2: SS HV Multi Circuit Breaker 60 MVA Concept
Courtesy of Schneider Electric
Fig. 1: Ormen Lange Pilot SS Circuit Breaker
Courtesy of Aker Solutions
Fig. 5: Siemens Subsea Power Grid Concept
Courtesy of Siemens
Fig. 6: Subsea Transformer Prototype at Shallow Water Test in 2012
Courtesy of Siemens
Courtesy of Siemens
Fig. 7: Subsea Variable Speed Drive Illustration
Courtesy of Aker Solutions
Fig. 3: Ormen Lange Pilot Subsea Pump ASD
Fig. 8: SS Circuit Breaker/SS Switchgear Illustration
Figs.: 8-11 Courtesy of Siemens
Fig. 10: Tronic FoeTRONWet-Mate Connectors
Fig. 4: Tronic SpecTRON 10 Wet-Mate Connectors
Fig. 9: Tronic ElecTRON Wet-Mate Connectors
Courtesy of Siemens
Fig. 11: Tronic DigiTRONWet-Mate Connectors
SUBSEA PROCESSING CONFIGURATIONS
SUBSEA SEAWATER INJECTION AND TREATMENT
Fig. 1: Aker Solutions’ LiquidBooster™ Subsea Raw Seawater Injection System(Photo: Statoil Tyrihans Subsea Raw Seawater Injection (SRSWI) System)
Courtesy of Aker Solutions
Figs. 5 and 6: Courtesy of SEABOX AS
Fig. 3: One of four AlbacoraRaw Seawater WI Pump Systems undergoing SIT in OneSubsea Test dock in late 2009
Courtesy of OneSubseaFig. 4: Total-Saipem-VWS Westgarth Conceptual Subsea Sulphate Removal Station for Deep and Ultradeep Water Applications Fig. 5: Subsea Water Intake and Treatment (SWIT)
Unit Capable of Treating 40,000 barrels per day
Fig. 6: Integrated SS Raw Seawater Injection System Integrating SPP and Filtration
SS Water Injection Tree
(WI XT)
Single Phase Pump
for Water Injection
(SPP WI)
Raw Seawater Intake
& Filtration (SWIT Unit)
Courtesy of Saipem SA
Fig. 2: Conceptual Illustration of Installation of Tyrihans Subsea Raw Seawater Injection (SRSWI) System
SUBSEA SEPARATION SYSTEM TYPES: 1. GRAVITY SEPARATION SYSTEMS (Figs. 1–6)
HORIZONTAL SEPARATOR - This type is more effcient for oil/water separation. An example is the orange colored horizontal separator for the Tordis Project shown in Fig. 1A above.
VERTICAL SEPARATOR – This type is more effcient for gas/liquid separation. The liquid keeps a fuid blanket on the pump and reduces potential pump cavitation. An example is the Pazfor vertical separator shown in Fig. 2.
Fig. 1A: Illustration of FMC Subsea Separation System for the Tordis Project
Courtesy of FMC Technologies
Fig. 2: Illustration of FMC SS Gas/Liquid Separa-tion & Boosting System for Pazfor Project
Courtesy of FMC Technologies
Fig. 5: Aker Solutions’ DeepBooster™ with Separation System Flexsep™ Concept
Courtesy of Aker Solutions
Fig. 3: Troll C Separation System
Courtesy of GE Oil & Gas
Fig. 4: Saipem COSSP (2-Phase Gas/Liquid Separation & Boosting System Concept)
Fig. 6: Saipem SpoolSep (3-Phase Separation & Produced Water Reinjection System) Concept
Figs. 5 and 6 Courtesy of Saipem SA
Fig. 1B: Tordis Separator
TABLE 3: SURVEY OF SUBSEA ELECTRICAL POWER CONNECTOR AND PENETRATORS
STATUS MAN
UFAC
TURE
R
PART
NUM
BER
WAT
ER
DEPT
H
VOLT
AGE
CL
ASS
CURR
ENT
RATI
NG
FREQ
UENC
Y
CABL
E TE
RMIN
ATIO
NW
ET M
ATE
PENE
TRAT
OR
(m) (ft) (kV) (A) (Hz)
Currently Operating TE Connectivity Deutsch P6-MD300 400 1,312 6/10(12) 300 15-70 H
Installed on Pilot TE Connectivity Deutsch P6-SW1600 2,000 6,562 6/10(12) 1,600 200 H H
Installed on Pilot TE Connectivity Deutsch P18-SW900 2,000 6,562 18/30(36) 900 15-70 H H
Qualified TE Connectivity Deutsch P18-SD 300 3,000 9,843 18/30(36) 400 200 H H
Qualified Siemens Tronic SpecTRON 5 1,330 4,364 2.9 /5(5.8) 200 100 H H H
Qualified Siemens Tronic SpecTRON 8 3,000 9,843 5/8.7(10) 355 200 H H H
Qualified Siemens Tronic SpecTRON 10 3,000 9,843 6/10(12) 630 200 H H H
Qualified GE VetcoGray MECON DM 900 2,953 76/132(145) 600 50 H
Qualified GE VetcoGray MECON WM-I 1,500 4,921 12/20(24) 300 50 H H
Qualified GE VetcoGray MECONWM-II 1,500 4,921 18/30(36) 500 50 H H
Under Qualification GE VetcoGray MECON WM 3,048 10,000 18/30(36) 500 15-100 H H
Under Qualification TE Connectivity Deutsch P6-3W250 3,000 9,843 6/10(12) 250 15-200 H H H
Delivered Benestad AS 15k Power Penetrator 3,048 10,000 6/10(12) 450 15-200 H H H
Delivered TE Connectivity Deutsch P6-SW400 3,000 9,843 6/10(12) 400 15-100 H H H
Delivered TE Connectivity Deutsch P18-SW400 3,000 9,843 18/30(36) 400 15-200 H H H
Delivered TE Connectivity Deutsch P18-SD400 3,000 9,843 18/30(36) 400 15-200 H H
Proposed TE Connectivity Deutsch P6-SW900 3,048 10,000 6/10(12) 900 200 H H H
Proposed TE Connectivity Deutsch P18-SW900 3,048 10,000 18/30(36) 900 200 H H H
Note 1: The configurations and diagrams below are examples only and do not represent specific projects. Note 2: The configurations shown below illustrate a “building block” approach, demonstrating mudline technologies and no ESP based configurations. The “building blocks” primarily use retrievable module elements within their designs. Note 3: The distances implied in the short, medium, and long distance configurations of Figs. 1, 4, and 7 are indicative only for these examples. Actual distance limitations and system configurations for real-world fields will depend on the specific production/reservoir conditions, and on the detailed capabilities of the associated processing and power system equipment. For applications beyond 100 miles (160 Km), the system configurations are only in the conceptual stage, and are not depicted here.
HostSwitchgear
HostGeneration
ASD(Frequency Converter)
Host FloatingProduction Facilities
Subsea
Topsides
TYPE 2
Direct Step Outwith Subsea Transformer
G
~
~
TUTA
PSUTA
Transformer
JB
Purge
Safety Disconnect / Earthing Switch
(For multi-circuit umbilicals)
Static or DynamicPower Umbilical
~
M
SubseaTransformer
R
HighResistanceResistance
Booster Pump or Compressor
SS Processing Station
~
M
R
HighResistance
Water Injection Single Phase
Pump
SS WI Station
SSTransformer
Module
PSUTA
~
~
Up to ~12.5 MW, Typically 6.6kV
Up to 36 kV
Fig. 5: Type 2 Electrical Diagram (see Table 5)
~
M
~
~
~
~
~
~
PSUTA
~
M~
M
SS ASD
6.6 kV
Up to 36 kV
SS Power Skid with Switchgear
Static or Dynamic Power Umbilical
Subsea
PlatformOR
Onshore Facilities
Transformer4.16 kV - 13.8 kV (typical)
TYPE 3Subsea AC Power Distribution
w/MV or HV Power Transmission
TUTA
Host Switchgear
Wet MateConnector
(Typ.)
R
Solid or LowResistance
Earthing
Transformer
~
JB Purge
Host Switchgear
(Output voltage ~36kV or higher depending on load & distance)
(SS Transformer Optional depending on selected transmission voltage)
SPP Gas
Compr.
WI SPP
SS Processing Station (3P)
ShorelineTopsides or Land
Fig. 8: Type 3 Electrical Diagram (see Table 5)
SYMBOL KEY
Production Umbilical
Utility Umbilical
Production Flowline
Pump StationXT
XT
SS Manifold
PSUTA
SUTA
Fig 3: Short Distance Process Flow Diagram (PFD)
SS ProcessingStation (Two Phase)SS ProcessingStation (2P)
Production Umbilical
Utility Umbilical
Gas Flowline
Liquid Flowline
Multiphase Flowline
Seawater
XT
XT
SS Manifold
PSUTA
WI XT
WI Flowline
SUTA
SS WI StationSS WI Station
Fig 6: Medium Distance Process Flow Diagram (PFD)
Production Umbilical
Utility Umbilical
Gas Flowline
SS Processing Station (3P) (Three Phase + WI)
Oil Flowline Multiphase Flowline
WI Flowline
PSUTA SS Power Skid
XT
XT
WI XT
WI XT
WI XT
SS Manifold SUTA
Fig 9: Long Distance Process Flow Diagram (PFD)
Fig. 1: Short Distance Confguration Example
Subsea
Topsides
TYPE 1
Direct Step Out
G
~
~
HostSwitchgear
HostGeneration
TUTA
PSUTA
~
M
ASD(Frequency Converter)
Static or DynamicPower Umbilical
MP Boosting Pump
Up to ~3000 kW, Typically 6.6kV
Purge
Safety Disconnect / Earthing Switch
(For multi-circuit umbilicals)
JB
Electrical Flying Lead (EFL)
Pump Station
Host FloatingProduction Facilities
Fig. 2: Type 1 Electrical Diagram (see Table 5)
SUBSEA POWER SYSTEM TYPES AND CONFIGURATIONS
Fig. 1: SUBSEA POWER SYSTEM STEP-OUT CONFIGURATIONSTABLE 5: POWER SYSTEM STEP-OUT CONFIGURATIONS
CATE
GORY
VOLTAGE & POWER RATING
INDICATIVE STEP-OUT
(4)
ADJUSTABLE SPEED DRIVE
POWER TRANS-
FORMERS
NOMINAL TRANS-
MISSION FREQ.
Radius (1)
Tops
ide
Subs
ea
Tops
ide
(Ste
p Up
)
Subs
ea(S
tep
Dow
n)
50 o
r 60
Hz
AC
16.7
-25
Hz
AC
Type 1
Capacity: 1-4 MWTransmission: ~6kVDistribution: ~6kV
0-15 Km(0-9.3 Mile) H H
Type 2
Capacity: 1-4 MWTransmission: Up to 36kVDistr./Motor Input: ~6kV
0-60 Km(0-37.3 Mile) H H
(2)H
(2)H
Type 3
Capacity: Up to 70 MWTransmission: 36kV-145kVDistr. Switchgear: Up to 36kVDistr./Motor Input: ~6kV
0-160 Km(0-100 Mile) H H
(3)H
(3)H
Type 4
Capacity: Up to ~100 MWLF Transmission: Up to 145kVLF Dist. Switchgear: Up to 36kVDistr./Motor Input: ~6kV
>140-400 +Km(>87-248.5 +Mile) H H
(3)H
(3)H
Notes:1. Indicative radius subject to system power rating. See Figure 1, Step-Out Configurations.
2. Transformer location likely after ASD to meet umbilical transmission voltage.
3. Transformer location likely before ASD to meet umbilical transmission voltage.
4. Stepout is the distance from the host facility.
5. Barracuda project with a step out of 14 km (8.7 Mi) is a deployed example of Type 1 Configuration.
6. Tyrihans project with a step out of 31 km (19.3 Mi) is a deployed example of Type 2 Configuration.
7. There is no deployed example of Type 3. Type 4 is currently conceptual.
COURTESY OF
COURTESY OF
Host FloatingProductionFacility
ProductionFlowline
UtilityUmbilical
ProductionUmbilical
PSUTA
PLET
SUTA
SS Manifold
XT(TYP.)
Pump Station
Type 1
Fig. 4: Medium Distance Confguration Example
Host FloatingProductionFacility
ProductionUmbilical
UtilityUmbilical
GasFlowline
PLET
PLET
LiquidFlowline
SS ProcessingStation (2P)
PSUTA
SUTA
SS Manifold
Multiphase Line
Multiphase Line
WI Line
WI XT (TYP.)
XT(TYP.)
Type 2
MPP
(2P)
MULTIPHASE BOOSTING SYSTEM EXAMPLES (CONCEPTUAL & DELIVERED)
Fig. 6: GE Oil & Gas Boosting Station
Courtesy of VetcoGray (GE Oil & Gas)
Fig. 1: Aker Solutions MultiBooster™ System (BP King)
Courtesy of Aker Solutions
Fig. 2: FMC/Flowserve SS Multiphase Pumping System with 2 Retrievable Pump Modules
Courtesy of FMC Technologies
Fig. 3: OneSubsea - Loadout of 1 of 6, 2.3 MW HybridPumps for Pazfor Project
Courtesy of OneSubseaFig. 5: FMC TechnologiesSS Multiphase PumpingModule with Sulzer Pump
Courtesy of Sulzer
Fig. 4: 1 of 3 Jack & St Malo Pump Stations in the Factory Test Pit for System Integration Test (SIT) Immediately Prior to Filling with Water
Courtesy of Chevron and OneSubsea
MUDLINE ESP OR HSP SYSTEM EXAMPLES
Courtesy of FMC Technologies
Fig. 1: Horizontal ESP Boosting Station Fig. 2: ESP Jumper Boosting System
Courtesy of Baker Hughes
Fig. 3: Seafoor Boosting System Using ESPs in Caissons
Courtesy of Baker Hughes
Fig. 4: Seafoor Boosting Using ESP in caisson
Courtesy of Aker Solutions
Fig. 5: HSP for Mudline Boosting
Courtesy of ClydeUnion
Pump (SPX)
2. CAISSON SEPARATION SYSTEMS (Figs. 7–9) INSTALLED < 100 m INTO SEABED
Fig. 7: BCSS Seabed Equipment
Courtesy of Aker Solutions
3. COMPACT/DYNAMIC SEPARATION SYSTEMS (Figs. 10-12)
Fig. 10: OneSubsea’s Compact 2-Phase Separator & Pump Module
Fig. 11: OneSubsea’s Compact 3-Phase Separation Module Concept
Courtesy of OneSubsea
Fig. 12: FMC 3-Phase Separation System with Produced Water Re-injection Using In-Line Separation Technology for the Marlim Project
Courtesy of FMC Technologies
deeper understandingwww.genesisoilandgas.com
Don’t just scratch
the surface
More powerful pumps:
Maximize production now. Image courtesy of Sulzer Pumps
Copyright © FMC Technologies, Inc. All Rights Reserved. www.MaximizeRecovery.com
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applications applications
rly at high GVF) at high GVF)
For more information visit
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Reliable Seabed Boosting With Subsea Multiphase Pumps and Motors
Design Ratings
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Enabling Subsea Processing by Connecting Innovation with Experience siemens.com/energy/subsea
Fig. 9: FMC’s VerticalAccess Caisson with ESP Boosting (Gas/Liquid Separation & Boosting) System Diagram
Courtesy of FMC Technologies
Fig. 8: Caisson Separation/ESP Boosting System
Courtesy of Baker Hughes
Note: This table is a sampling of the current market, and is not comprehensive.
Fig. 7: Long Distance Confguration Example
Onshore FacilitySS Processing
Station (3P)
SS Power Skid
(3P)
SPP Oil
WI SPP
Type 3
ProductionUmbilical
UtilityUmbilical Gas
Flowline
PLET
PLET
OilFlowlinePSUTA
SUTA
SS Manifold
Multiphase Line
WI Line
WI XT (TYP.)
~
~
Multi Phase Mudline Boosting, Single Phase Pumping, or Water Injection Pumping
Two Phase or Three Phase Separation
Gas Compression
Seawater Filtration/Intake
SS Power System
Adjustable Speed Drive (ASD)
SS Transformer
Safety Disconnect/ Earthing Switch
Switchgear
HV Wet Mate Connector
6.6 kV Wet Mate Connector
~
~
Courtesy of OneSubsea
XT(TYP.)
Note 1: SWIT Unit provides disinfection and low Total Suspended Solids (TSS) water for either matrix or sweep fooding.
TABLE 1 – 2014 WORLDWIDE SURVEY OF SUBSEA GAS COMPRESSION, BOOSTING, WATER INJECTION, AND SEPARATION (1)(2) – As of Feb. 2014
PROC
ESSI
NG
DISC
IPLI
NE
COUN
T
FIELD OR PROJECT (Ordered by Start Date)
CURR
ENT
STAT
US
COMMENTSOWNER/
FIELD OPERATOR
REGION/ BASINS
WATER DEPTH
TIEBACK DISTANCE
SYSTEM FLOW RATE (@LINE CONDITIONS)
DIFFERENTIAL PRESSURE
UNIT
MOT
OR
POW
ER (3
)
GVF
(GAS
VOL
UME
FRAC
TION
) (5)
SYSTEM PACKAGER
NO. OF PUMPS UNITS
PUMP TYPE or
COMPR. TYPE
COMPRESSOR/PUMP MANUFACTURER
IN-SERVICE/OPERATING INFORMATION
COMPANY Meters Feet Km Miles M3/Hr. MBOPD MBWPD BAR (4) PSI
(4) MW % OF VOL. COMPANY PUMPS or
COMPR. TYPE COMPANY START (11) (Month-Year)
END or PRESENT
MTHS
SUBS
EA G
AS
COM
PRES
SION
1 DEMO 2000 Q Statoil K-Lab Test Statoil Offshore Norway 3.60 n/a OneSubsea Counter Axial OneSubsea 2001
2 Ormen Lange Gas Compression Pilot Q Testing 1 train @ Nyhamna, Norway Statoil Offshore Norway 860 2,821 0.0 0.0 25,000 3776 60.0 870 12.50 n/a Aker Solutions 1 Centrifugal GE Compr / Aker Pump 2011 1-Mar-14
3 Aasgard - Midgard & Mikkel Fields M Subsea Gas Compression Statoil Offshore Norway 300 984 40.0 25.0 40,000 6,042 60.0 870 11.50 n/a Aker Solutions 2+1 Spare +1 Centrifugal MAN / Aker pumps Q1, 2015
4 Gullfaks South Brent (28) M Subsea Wet Gas Compression Statoil Offshore Norway 135 443 15.5 9.7 9,600 1450 30.0 435 5.00 95% OneSubsea 2 + 1 Spare Counter Axial OneSubsea Q4, 2015
5 Ormen Lange Gas Compression Q Subsea Gas Compression Norske Shell Offshore Norway 860 2,821 120.0 75.0 50,000 7553 60.0 870 12.50 n/a TBA 2 Centrifugal TBA 2021
6 Troll C Subsea Gas Compression Statoil Offshore Norway 340 1,116 4.0 2.5 n/a TBA Undecided TBA 2016
7 Snohvit C Subsea Gas Compression Statoil Barents Sea 345 1,132 143.0 89.4 TBD n/a TBA Centrifugal TBA 2020
8 Shtokman C Subsea Gas Compression Gazprom Barents Sea 350 1,148 565.0 353.1 TBD n/a TBA Centrifugal TBA 2022
FULL
WEL
LSTR
EAM
SUB
SEA
BOOS
TING
(N
OTE
1. S
EABE
D &
RISE
R ON
LY, N
OTE
2. E
XCLU
DES
DOW
NHOL
E ES
Ps)
1 Prezioso (20) A MPP at Base of Platform AGIP Italy 50 164 0.0 0.0 65.0 10 40.0 580 0.15 30-90% Nuovo Pignone (8) 1 Twin-Screw GE 1994 1995
2 Draugen Field A SMUBS Project, 1 HSP A/S Norske Shell Offshore Norway 270 886 6.0 3.7 193.0 29 53.3 773 0.75 42% OneSubsea 1 + 1 Spare HSP SPX ClydeUnion Nov-95 15-Nov-96 12.2
3 Lufeng 22/1 Field (9) (19) A Tieback to FPSO Statoil South China Sea 330 1,083 1.0 0.6 675.0 102 35.0 508 0.40 3% OneSubsea / FMC Tech. 5+2 Spare Centrifugal (SPP) OneSubsea Jan-98 15-Jul-09 138.0
4 Machar Field (ETAP Project) A Hydraulic Turbine Drive BP Amoco UK North Sea 85 277 35.2 21.9 1,100.0 166 22.0 319 0.65 64% OneSubsea 2+1 Spare Helico-Axial OneSubsea
5 Topacio Field O 1 x Dual MPP System ExxonMobil Equatorial Guinea 550 1,805 8.0 5.0 940.0 142 35.0 508 0.86 75% OneSubsea 2+1 Spare Helico-Axial OneSubsea Aug-00 1-Mar-14 162.2
6 Ceiba C3 + C4 O Phase 1 SS MPP Project Hess Equatorial Guinea 750 2,461 7.0 4.3 600.0 91 45.0 653 0.85 75% OneSubsea 2+1 Spare Helico-Axial OneSubsea Oct-02 1-Mar-14 136.2
7 Jubarte EWT A Riser lift to Seillean Drillship Petrobras Espirito Santo Basin 1,400 4,593 1.4 0.9 145.0 22 140.0 2,000 0.70 22% FMC Technologies 1 ESP Schlumberger (REDA) Dec-02 1-Dec-06 47.9
8 Ceiba Field (FFD) O Full Field Development (FFD) Hess Equatorial Guinea 700 2,297 14.5 9.0 2,500.0 378 40.0 580 1.20 75% OneSubsea 6+ 2 Spare Helico-Axial OneSubsea Dec-03 1-Mar-14 122.3
9 Mutineer / Exeter O 2 x Single MPP Systems Santos NW Shelf, Australia 145 476 7.0 4.3 1,200.0 181 30.0 435 1.10 0-40% OneSubsea 7 SS ESP, 2 MPP Helico-Axial OneSubsea (16) Mar-05 1-Mar-14 107.3
10 Lyell (Original Install) A SS Tieback to Ninian South CNR UK North Sea 146 479 15.0 9.3 1,100.0 166 18.0 261 1.60 40-70% Aker Solutions 1 Twin Screw Bornemann SMPC 9 Jan-06 Dec-06 11.0
11 Navajo (17) I, N ESP in Flowline Riser Anadarko GOM 1,110 3,642 7.2 4.5 24.0 4 40.2 583 0.75 57% Baker Hughes 1 ESP Baker Hughes Feb-07 1-Aug-07 5.5
12 Jubarte Field - Phase 1 A Seabed ESP-MOBO, Uses BCSS (14) Petrobras Espirito Santo Basin 1,350 4,429 4.0 2.5 120.0 18 138.0 2,002 0.90 10-40% FMC Technologies 1 ESP Schlumberger (REDA) Mar-07 Aug-07 5.0
13 Brenda & Nicol Fields O MultiManifold with 1 MPP Premier Oil UK North Sea 145 476 8.5 5.3 800.0 121 19.0 276 1.10 75% OneSubsea 1+1 Spare Helico-Axial OneSubsea Apr-07 1-Mar-14 82.4
14 King (7) (13) A SS Tieback to Marlin TLP Freeport McMoRan GOM, MC Blocks 1,700 5,578 29.0 18.0 496.5 75 50.0 725 1.30 0-95% Aker Solutions 2+1 Spare Twin-Screw Bornemann / Loher Nov-07 15-Feb-09 15.0
15 Vincent O Dual MPP System Woodside NW Shelf, Australia 475 1,558 3.0 1.9 2,400.0 363 42.0 609 1.80 25-70% OneSubsea 2+2 Spare Helico-Axial OneSubsea Aug-10 1-Mar-13 30.9
16 Marlim A SBMS-500 SS Field Test Petrobras Campos Basin 1,900 6,234 3.1 1.9 500.0 75 60.0 870 1.20 0-100% Curtiss-Wright / Cameron 1 Twin-Screw Leistritz 0.0
17 Golfinho Field I, N Seabed ESP-MOBO, Uses BCSS (14) Petrobras Espirito Santo Basin 1,350 4,429 146.0 22 138.0 2,002 1.10 10-40% FMC Technologies 2 ESP Baker Hughes (35) Mar-07 Aug-07 5.0
18 Azurite Field A Dual MPP System Murphy Oil Congo, W. Africa 1,338 4,390 3.0 1.9 350.0 53 41.0 595 0.85 28% OneSubsea 2+1 Spare Helico-Axial OneSubsea Sep-10 1-Oct-13 36.5
19 Golfinho Field I, N MOBO BCSS (ESP) Caissons (14) Petrobras Espirito Santo Basin 1,350 4,429 146.0 22 138.0 2,002 1.10 10-40% Aker Solutions 2 ESP Baker Hughes Mar-07 Aug-07 5.0
20 Espadarte (Field Trial) O Horizontal ESP on Skid Petrobras Brazil 1,350 4,429 11.5 7.1 125.0 19 100.0 1,450 0.90 10-40% FMC Technologies 2 ESP Baker Hughes Dec-11 Mar-13 14.5
21 Parque Das Conchas (BC 10) Phase 1 (23) O Caisson / Artifical Non-Separated Shell Campos Basin 2,150 7,054 9.0 5.6 185.0 28 152 2,205 1.10 40% FMC Technologies 2 ESP Baker Hughes Jul-09 1-Mar-14 55.4
22 Parque Das Conchas (BC-10) Phase 2 (23) M 2 additional ESP Systems Shell Campos Basin 2,150 7,054 9.0 5.6 185.0 28 152 2,205 1.10 40% FMC Technologies 2 ESP Baker Hughes
23 Jubarte Field - Phase 2 (25) I, N Tieback to FPSO P-57, Uses BCSS (14) Petrobras Espirito Santo Basin 1,400 4,593 8.0 5.0 1,325.0 200 200 3,000 1.20 30-40% Aker Solutions 15 ESP Schlumberger (REDA) 6-Dec-10 1-Mar-14 38.7
24 Cascade & Chinook (6) I, N Skid BCSS - Horizontal ESP on Skid Petrobras US GOM 2,484 8,150 8.0 5.0 135.0 20 220.0 3,191 1.10 10% FMC Technologies 4+2 Spare ESP Baker Hughes Q4 2013 0.0
25 Barracuda (32) O SS MP High Boost Pump System Petrobras Campos Basin 1,040 3,412 10.5 6.5 280.0 42 70.0 1,015 1.50 35-60% OneSubsea 1 Helico-Axial OneSubsea Jul-12 1-Mar-14 7.0
26 Montanazo & Lubina I, N Single MPP System Repsol Mediterranean 740 2,428 9.0 5.6 80.0 12 65.0 943 0.23 10% OneSubsea 2 Centrifugal (SPP) OneSubsea 2014
27 Schiehallion I, N 2 x Dual MPP Systems BP UK, West of Shetland 400 1,312 4.0 2.5 2,700.0 408 26.0 377 1.80 74% GE / OneSubsea 4+0 Spare Helico-Axial OneSubsea 2014 Delayed Start Up
28 CLOV (22) M Subsea MPP System TOTAL Angola, Blk 17 1,170 3,839 11.0 6.8 660.0 100 45.0 652 2.30 50% OneSubsea 2+1 Spare Helico-Axial OneSubsea Q3 2014
29 Jack & St. Malo M Full Wellstream subsea Boosting Chevron US GOM 2,134 7,000 21.0 13.0 1,191.0 180 241.3 3,500 3.00 10% OneSubsea 3+2 Spare Centrifugal (SPP) OneSubsea Q3-2014
30 Lyell Retrofit I, N MPP Retrofit System - Tieback to Ninian CNR UK North Sea 145 476 7.0 4.3 700.0 106 21.0 305 1.00 97% OneSubsea 1 Helico-Axial OneSubsea Q3 2012
31 GirRi (Girassol) (27) M Field Expansion Project Total Angola, Blk 17 1,350 4,429 18.0 11.2 600.0 91 130.0 1,885 2.50 20-50% OneSubsea 4+2 Spare Helico-Axial OneSubsea Q1 2015
32 Draugen Field M Brownfield Dual MPP System A/S Norske Shell Offshore Norway 268 879 4.0 2.5 1,710.0 253 47.5 689 2.30 10-31% OneSubsea 2 Helico-Axial OneSubsea Q3-2014
33 Julia M SS Tieback ExxonMobil US GOM 2,287 7,500 27.2 17.0 331 50 175.0 2,550 3.00 10% OneSubsea 2 Centrifugal (SPP) TBD Mid- 2016
34 Moho Phase 1bis M Brownfield Tieback to Alima FPU Total Congo, W. Africa 650 2,133 6.7 4.0 400 60 133.5 1,935 3.50 49% OneSubsea 2 Helico-Axial OneSubsea Q4 2015
35 Atlanta Field C Caisson Application QGEP (26) Santos Basin, Blk BS-4 1,500 4,922 TBD ESP 2015
36 Stones C Single Phase HPHT Pump System Shell US GOM 2,927 9,600 5.0 3.1 TBD TBD TBD TBD TBD <10% TBD 2 +1 Spare TBD TBD 2018
37 Parque Das Baleias M Skid BCSS - Horizontal ESP on Skid (14) Petrobras Espirito Santo Basin 1,500 4,922 10.0 6.2 125.0 19 100 1,450 1.10 10-25% FMC Technologies 3+1 Spare ESP Schlumberger (REDA) Q1 2015
SUBS
EA
WAT
ER
INJE
CTIO
N 1 Troll C Pilot (15) (21) O SUBSIS (SS Sep. and WI Sys.) NorskHydro AS Offshore Norway 340 1,116 3.5 2.2 250.0 38 151.0 2,190 1.60 0% GE / OneSubsea 1+1 Spare Centrifugal (SPP) OneSubsea Aug-01 1-Mar-14 149.9
2 Columba E. I, N Dual SPP System CNR North Sea 145 476 7.0 4.3 331.0 50 305.0 4,424 2.30 0% OneSubsea 2+0 Spare Centrifugal (SPP) OneSubsea May-07 1-Oct-13 76.4
3 Tordis (WI) O (12), Separation, Boosting, WI Statoil Offshore Norway 210 689 11.0 6.8 700.0 106 77.0 1,117 2.30 0% FMC Technologies 1+1 Spare SPP&MPP OneSubsea Oct-07 1-Mar-14 76.4
4 Tyrihans O SS Raw Sea WI System Statoil Offshore Norway 270 886 31.0 19.3 583.0 88 205.0 2,973 2.70 0% FMC / Aker Solutions 2+1 Spare Centrifugal (SPP) Aker Solutions 29-Nov-13 1-Mar-14 3.0
5 Albacora L'Este Field (33) I, N Raw Water Injection to 7 Wells Petrobras Campos Basin, Brazil 400 1,312 4 to 9 2.5-6.0 1125 170 85 1,233 1.2 0% OneSubsea 3+1 Spare Centrifugal (SPP) OneSubsea Q1 2013 0.0
SUBS
EA S
EPAR
ATIO
N
1 Zakum A Shallow Water Test Separation System BP Offshore Abu Dhabi 1969 1972 36
2 Highlander Field (34) A SS Separator / Slug Catcher Texaco UK North Sea 420 128
3 Argyll A SS Sep. and Pumping Unit (SSPU) Hamilton Bros UK North Sea BOET (30) 1989
4 Marimba Field (24) I, N VASPS Field Test Petrobras Campos Basin 395 1,296 1.7 1.1 60.0 9 52.0 754 0.3 Cameron 1 ESP Schlumberger (REDA) Jul-01 1-Jul-08 83.0
5 Troll C Pilot (15) (21) O Horizontal SUBSIS (SS Sep. & WI Sys.) Hydro (Statoil) Offshore Norway 340 1,116 3.5 2.2 250.0 38 151.0 2,190 1.60 0% GE / OneSubsea 1+1 Spare n/a OneSubsea Aug-01 1-Mar-14 149.9
6 Tordis O (12), Separation, Boosting, WI Statoil Offshore Norway 210 689 11.0 6.8 1,500.0 227 27.0 392 2.30 10-68% FMC Technologies 1+1 Spare Helico-Axial OneSubsea Oct-07 1-Mar-14 76.4
7 Parque Das Conchas (BC 10) Phase 1 (23) O Separation Caisson / Artifical Lift Manifold Shell Campos Basin 2,150 7,054 25.0 15.6 185.0 28 152.0 2,205 1.10 15% FMC Technologies 4(+2 Future?) ESP Baker Hughes Centrilift Aug-09 1-Mar-14 54.4
8 Perdido O Caisson Separation and Boosting Shell GOM 2,438 7,999 0.0 0.0 132-264 20 - 40 158.8 2,303 1.20 15% FMC Technologies 5 ESP Baker Hughes Centrilift Mar-10 1-Mar-14 47.9
9 Pazflor O 3 Gas/Liquid Vertical Separation System Total Angola, Blk 17 800 2,625 4.0 2.5 1,800.0 272 105.0 1,523 2.30 <16% FMC Technologies 6+2 Spare Hybrid H-A OneSubsea Aug-11 1-Mar-14 30.0
10 Marlim SSAO - Pilot O In-Line Separation Petrobras Campos Basin 878 2,881 3.8 2.4 135.0 20 245 3,553 1.9 67% FMC Technologies 1 Centrifugal (SPP) OneSubsea Mar-13 1-Mar-14 11.0
11 Congro (29) CP VASPS with Horizontal ESP Petrobras Campos Basin 197 646 11.0 7.0 135.0 20 21 305 0.4 <10% FMC Technologies 2 ESP Baker Hughes Centrilift
12 Parque Das Conchas (BC 10) Phase 2 (23) M 2 additional ESP systems Shell Campos Basin 2,150 7,054 25.0 15.6 185.0 28 152.0 2,205 1.10 15% FMC Technologies 2 ESP Baker Hughes Centrilift
13 Canapu M In-Line Separation by Twister BV Petrobras Espirito Santo Basin 1,700 5,579
14 Corvina (29) M VASPS w/Horizontal ESP Petrobras Campos Basin 280 919 8.0 5.0 135.0 20 21 305 0.4 <10% FMC Technologies 1 ESP Baker Hughes Centrilift
CURRENT STATUS CATEGORIES
C Conceptual Project
Q Qualified/Testing
M Awarded and in Manufacturing or Delivered
O Installed & Currently Operating
I,N Installed & Not Currently Operating or In-Active
A Abandoned, Removed
CP Canceled Project
NOTES: 1. Qualification Status - See information accuracy statement below title block and note that the qualification
status categorizations shown in this table, and throughout the poster, are based on unverified claims from
equipment suppliers and field operators. These qualification status designations are not necessarily derived
using technology readiness level (TRL) assessments per API RP 17Q or DNV-RP-A203.
2. Pumping & Boosting: The terms “Pumping” and “Boosting” are used interchangeably throughout this poster
and in the industry.
3. Unit Motor Power: Is the unit motor power for either a pump or compressor motor.
4. Differential Pressure: Differential Pressure values are for individual pumps.
5. GVF = Gas Volume Fraction at inlet of pump.
6. Cascade & Chinook - Utilizes horizontal ESPs on a skid above mudline. It is an alternative ESP boosting
configuration to caisson in the seabed. This technology is designed to cover the low GVF and high DeltaP
multiphase flow. Pump cartridge successfully installed Q4 2013.
7. King Field: Power cables are incorporated within the service umbilical.
8. Nuovo Pignone is now part of GE.
9. Lufeng 22/1: Low wellhead pressure of 100 psig at seabed dictated that artificial lift was required. System
has now been decomissioned due to field abandonment.
10. VASPS - Vertical Annular Separation and Pumping System
11. START: Month & Year indicates first month and year of operation for the SS processing system.
12. Tordis Field: 1+1 Spare Multiphase Boosting Pumps, and 1+1 Spare Water Injection Pumps; Tieback to
Gullfaks C platform. Statoil hopes to increase oil recovery from 49% to 55%, an additional 36 MMBO, due to
the world's first commercial subsea separation, boosting, injection and solids disposal system.
13. King Field: Is a subsea tieback to the Marlin TLP. In 2012, BP sold the field to Plains Exploration and
Production. McMoran Freeport later purchased the field. Pumps remain shut-in due to operational issues.
The company is reportedly considering to redo the boosting system.
14. BCSS - Centrifugal Subsea Submersible Pumps. Pumps are placed in protective holes in the seabed, 200m
from producing wells. MOBO - Modulo de Bombas (Pumping Module)
15. Troll C Pilot: SUBSIS - The world's longest operating subsea separation system and first subsea water
injection pump system.
16. Mutineer/Exeter Projects: Manufacturers are: OneSubsea and Centrilift. There are 2 ESPs per well feeding
one OneSubsea MPP per asset on seafloor.
17. Navajo Field: Is a Subsea tieback to Anadarko's Nansen spar.
18. BH Centrilift = Baker Hughes Centrilift
19. LUFENG - Closed down due to field economics, after 11 years of operation.
20. PREZIOSO - World's first deployment of an electrically driven twin screw MPP operating on a live well.
Testing occurred in 1994 and 1995 for a total of 7,850 hours of operation at base of platform on seafloor.
21. Troll C Pilot - Separation began on Aug. 25, 2001. See OTC paper 20619, page 10 for further details on
operating experience. Note that injection pump data is only shown in the subsea water injection section
of the table.
22. CLOV - Total reports that the CLOV development will utilize seabed multiphase pumps to boost Cravo, Lirio,
Orquidea and Violeta Miocene from First Oil + 2 years
23. Parque Das Conchas (BC 10) Phase 1 - Composed of 3 reservoirs: Ostra, Abalone and Argonauta B-West.
Argonauta O-North to be added in Phase 2.
24. Marimba VASPS - 2000 - First installation in Marimba (JIP Petrobras / Eni-Agip/ ExxonMobil, 2001 - Startup
and Operation (July to Dec.) until ESP failure, 2002 End of JIP, By-pass production, 2003 - Workover Plan,
2004 - Workover and Re-start on May 8, 2004. From 2005 until 2008 VASPS operated ok until well failure.
25. Jubarte Field (Phase 2) - Was installed in 2011. Wells were connected to the FPSO P-57. All wells will have
gas-lift as a backup.
26. QGEP - Queiroz Galvao Exploracao e Producao
27. Girassol Field Pumping System - for the Girassol Resources Initiatives (GirRI)
28. Gullfaks South Brent - According to Statoil the SS wet gas compression will increase recovery from the
reservoir by 22 million barrels of oil equivalent.
29. Canceled Project - Petrobras has determined Congro and Corvina are not commercially feasible.
30. BOET - British Offshore Engineering Technology
31. Perdido - Cassion for separation is 350 feet long drilled into the seabed. Read OTC Paper 21716.
32. Barracuda - Ref. 2013 OTC Paper 24217 for additional information about the MPP.
33. Albacora Field - Ref. 2013 OTC Paper 24167
34. Highlander Field - SS Tieback to the Tartan Field which has a SS separator/slug catcher installed for the
tie-in to the Tartan Platform
35. Petrobras is changing ESP supplier from Baker Hughes to Schlumberger (REDA) in Q4 2014. REPRESENTATIVE SUBSEA POWER & PROCESSING TECHNOLOGY ATTRIBUTES (CURRENT AND UNDER DEVELOPMENT)
Table 4.8: Raw Seawater Injection Technology Filter, Treat, & Boost Raw Seawater Subsea for Injection
Attribute Installed or Qualified To be Qualified within 5 yrs.Water Depth 400 m (1,312 ft) 3,048 m (10,000 ft)
Shut-in Pressure Rating 5,000 psi (345 bar) 15,000 psi (1,035 bar)
System Flow Rate 88 MBOPD 150 MBOPD
Pump Differential Pressure (ea) 3,000 psi (205 bar) 4,500 psi (310 bar)
Unit Motor Power 2.5 MW 6.0 MW
Nominal Voltage 6.6 kV 6.6 kV
Water Quality 35-50 micron 5-10 micron
Key Elements in Current Development & Qualification Projects
Enhanced Inlet Water Conditioning & Treatment / Higher Current & Power Penetrator / Enhanced Motor and Pump Capabilities / Series Pumps for > Injection Pressure / Depth
Future Technology EnhancementsSalinity Reduction & Micro-Filtration (To Limit Reservoir Degradation Due to Injection) / Higher Power Rating & ∆P Capabilities / Enhanced Condition & Process Monitoring
Table 4.6: Power System Technology - Type 3 Extending Topside ASD Step Out by Increasing SS Umbilical Transmission Voltage (See Table 5 for Detail)
Attribute Installed or Qualified To be Qualified within 5 yrs.Water Depth 900 m (2.952 ft) 3,048 m (10,000 ft)
Tieback Distance 120 km (75 miles) 160 km (100 miles)
Power Rating 25 MW 70 MW
Distribution (Input) Voltage 145 kV 36 - 145 kV
Distribution Switchgear Voltage 36 kV 36 kV
Utilization (Output) Voltage 6.6 kV 6.6 kV
Key Elements in Current Development & Qualification Projects
Integration of Subsea Elements: Switchgear / ASD with Integral Transformer / Wet Mate Connectors + AC Umbilicals
Future Technology EnhancementsEnhancement for Power & Depth for HV Wet Mate Connectors / Power Distribution System Surveillance
Table 4.4: Power System Technology - Type 2 Extending Topside ASD Step Out By Increasing SS Umbilical Transmission Voltage (See Table 5 for Detail)
Attribute Installed or Qualified To be Qualified within 5 yrs.
Depth Classification Ultra Deep Water Shallow Water Ultra Deep Water
Water Depth 2,439 m (8,000 ft) 300 m / (984 ft) 3,048 m (10,000 ft)
Tieback Distance 21 km (13 miles) 43 km (29 miles) 60 km (37 miles)
Power Rating per Motor 3.0 MW 11.5 MW 12.5 MW
Primary Voltage 36 kV 36 kV 36 kV
Secondary Voltage 6.6 kV 6.6 kV 6.6 kV
Key Elements in Current Development & Qualification Projects
Transformer Marinization / High Resistance Grounding / Wet Mate Connectors for Combination of Deep Water & High Current / AC Umbilical
Future Technology EnhancementsHigher Power Rating & Robustness of Primary Side Wet Mate Connectors / Power Distribution System Surveillance
Table 4.2: Power System Technology - Type 1 Topside ASD with No Transformer to Subsea Motor (See Table 5 for Detail)
Attribute Installed or Qualified To be Qualified within 5 yrs.Water Depth 1,700 m (5,576 ft) 2,485 m (8,150 ft)
Tieback Distance 29 km (18 miles) 15 km / 9.3 miles)
Power Rating per Motor 2.3 MW 4 MW
Nominal Voltage 6.6 kV 6.6 kV
Key Elements in Current Development & Qualification Projects
Wet Mate Connectors / AC Umbilical
Future Technology Enhancements Power Distribution System Surveillance
Table 4.7: Three Phase Separation Technology Raw Wellstream, Gas or Oil Service
Attribute Installed or Qualified To be Qualified within 5 yrs.Water Depth 878 m (2,881 ft) 3,048 m (10,000 ft)
Shut-in Pressure Rating 5,000 psi (345 bar) 15,000 psi (1,035 bar)
System Capacity (Flow Rate) 20 MBOPD As Required for Duty
Target LVF in Gas at Outlet TBD < 2%
Target GVF in Oil or Water 10 - 15% < 10%
Outlet Oil in (Injection) Water TBD ppm TBD ppm
Booster Power (O/G/W) 1.9 MW As Required for Duty
Separation System Type Compact Separation - Modular
Key Elements in Current Development & Qualification Projects
Proven Separation Effectiveness of Raw Wellstream / Turn Down / Vessel Integrity / Control Logic with Pumps and / or Compressor / Real Time Process Monitoring
Future Technology EnhancementsWide Separator Operating Range and Separation Effectiveness Especially at Turn Down Rates / Enhanced Process and Booster Control Logic & Surveillance
Table 4.5: Two Phase Separation Technology Raw Wellstream, Gas / Liquid Separation With Liquid Boosting
Attribute Installed or Qualified To be Qualified within 5 yrs.Water Depth 2,439 m (7,999 ft) 3,048 m (10,000 ft)
Shut-in Pressure Rating 5,000 psi (345 bar) 15,000 psi (1,035 bar)
System Capacity (Flow Rate) 30 MBOPD As Required for Duty (See Table 4.3)
Boosting Differential Pressure 1,305 psi (90 bar) As Required for Duty (See Table 4.3)
Target GVF at Liquid Booster Inlet < 15% 10-15%
Unit Motor Power 1.1 MW As Required for Duty (See Table 4.3)
Separation System Type Compact Separation - Modular
Key Elements in Current Development & Qualification Projects
Proven Separation Effectiveness of Raw Wellstream / Turn Down / Vessel Integrity / Control Logic with Pump and / or Compressor / Robust Process Monitoring
Future Technology EnhancementsWide Separator Operating Range and Separation Effettiveness Especially at Turn Down Rates / Enhanced Process and Booster Control Logic Monitoring
Table 4.3: Subsea Boosting Technology Single Phase or Multi Phase Pump
Attribute Installed or Qualified To be Qualified within 5 yrs.
Pump Classification Single Phase Multi Phase Single Phase Multi Phase
Water Depth 2,439 m (8,000 ft) 1,350 m (4,428 ft) 3,048 m (10,000 ft) 3,048 m (10,000 ft)
Shut-in Pressure Rating 13,000 psi (897 bar) 5,000 psi (345 bar) 15,000 psi (1034 bar) 15,000 psi (1034 bar)
Pump Flow Rate (Nominal) 60,000 MBOPD 40,000 MBOPD 75,000 MBOPD 60,000 MBOPD
Differential Pressure (Nominal) 3,700 psi (225 bar) 1,885 psi (130 bar) 4,500 psi (310 bar) 2,320 psi (160 bar)
GVF Range at Inlet 10 - 15% 0 - 90% 10 - 15 % 0 - 90%
Unit Motor Power 3.0 MW 2.5 MW 5.0 - 6.0 MW 5.0 - 6.0 MW
Nominal Voltage 6.6 kV 6.6 kV 6.6 kV 6.6 kV
Key Elements in Current Development & Qualification Projects
Higher Power & Depth Rating of Penetrators & Wet Mates / 5-6 MW Motors / Permanent Magnet Motors / Alternate Barrier Fluid / 15 ksi Housings / High Rate & Head Multiphase Stages / Marinized Condition Monitoring Equipment / Higher Operating Speed
Future Technology EnhancementsHigher Power & Depth Rating of Penetrators & Wet Mates / Higher Motor Power / High Rate & Head Single Phase & Multiphase Stages / Enhanced Condition Monitoring Systems / >15 ksi System Rating
Table 4.1: Gas Compression Technology Liquid Tolerant Compression - Raw Wellstream, Wet Gas Service
Attribute Installed or Qualified To be Qualified within 5 yrs.Water Depth 914 m (3,000 ft) 1,024 m (5,000 ft)
Shut-in Pressure Rating 3,190 psi (220 bar) 7,500 psi (517 bar)
System Flow Rate 500 MMscf/d (14 Msm3/sd) 500 MMscf/d (14 Msm3/d)
Pressure Ratio 4 6
GVF at Inlet > 97 % < 95 %
Unit Motor Power 12.5 MW 12.5 MW
Nominal Voltage 6.6 kV 6.6 kV
Stage Type Liquid Tolerant Centrifugal
Key Elements in Current Development & Qualification Projects
Enhancing Liquid Tolerance & System Robustness for Raw Gas / Active Magnetic Bearing & Anti Surge Marinization / Increased Depth for Wet Mate Connectors / Pressure Ratio
Future Technology EnhancementsDepth and Power Capabilities of Power Penetrators & Wet Mates / Supporting Process System Simplification / Enhanced Condition Monitoring
COURTESY OF
COLOR CODEInstalled
Qualified
Manufactured
Proposed
1403OFFSubseaPoster_1 1 2/28/14 5:09 PM
MARCH 2014
STATUS OF THE TECHNOLOGY
2014 WORLDWIDE SURVEY OF SUBSEA PROCESSING: SEPARATION, COMPRESSION,
AND PUMPING SYSTEMS
M A G A Z I N E
Offshore Magazine1455 West Loop South, Suite 400
Houston, TX 77027 USA Tel: 713-621-9720
www.offshore-mag.com
Larry Forster, Thiago Mesquita Paes, Richard Voight, Spiridon Ionescu, John Allen, RJ Baker, Rachel Townsend, Julie Burke and Mac McKee of INTECSEA,
E. Kurt Albaugh of Repsol E & P USA, and David Davis of Offshore MagazinePoster Assembled By: Chris Jones of XenonGroupDesign.com
Digital Images by: Sid Aguirre of C-Ray MediaE-Mail Comments, Corrections or Additions to: [email protected]
To Download a PDF, go to: www.offshore-mag.com/maps-posters.html or www.intecsea.com/publications/posters
INTECSEA, Inc.15600 JFK Boulevard, Ninth Floor
Houston, TX 77032 USA Tel: 281-987-0800 www.intecsea.com
ACKNOWLEDGEMENT OF THE CONTRIBUTORSINTECSEA and Offshore Magazine wish to acknowledge the following companies and individuals who continue to support our efforts
to educate and inform the oil & gas industry on the status of subsea processing technologies.Aker Solutions: Jonah Margulis and Kate Winterton; OneSubsea: Jarle Michaelsen and Jessica Clements; Flowserve: Bob Urban and Marc L. Fontaine; FMC Technologies: Janardhan Davalath, Jayne Merritt, Alan Szymanski and Citlalli Utrera; MAN Diesel & Turbo: Domingo Fernandez; Repsol E & P USA: Ron Pettus; Saipem: Claude Valenchon, Stephanie Abrand and Stephane Anres; Shell: Chris Shaw; Siemens: Ordin Husa; Schneider Electric: Kristina Hakala; Schlumberger: Grant Harris; SEABOX AS: Torbjorn Hegdal and Eirik Dirdal; SPX: Ross Dobbie; Technip: Chuck Horn, Mike Zerkus and Tim Lowry
Information Accuracy: We have attempted to use correct and current, as of press time, information for the subsea processing systems and equipment described herein. No installed,
sanctioned, or pending application was intentionally excluded. We have summarized the capability and operating experience by acting as a neutral party and integrator of information.
Information has been collected from public sources, company brochures, personal interviews, phone interviews, press releases, industry magazines, vendor-supplied information, and
web sites. No guarantee is made that information is accurate or all-inclusive. Neither INTECSEA nor Offshore Magazine guarantees or assumes any responsibility or liability for any party’s
use of the information presented. If any information is found to be incorrect, not current, or has been omitted, please send comments to [email protected].
©2
01
4 O
ffshore
POSTER
111Norwegian Sea
Tordis (Separation, Boosting, WI)
Troll C. Pilot (Separation, WI)
Tyrihans (WI)
Draugen (Boosting)
Draugen - Expansion (Boosting)
Aasgard (Compression)
Gullfaks (Compression)
DEMO 2000 (Compression)
Ormen Lange (Compression)
Troll (Compression)
Equatorial Guinea
Topacio (Boosting)
Ceiba FFD (Boosting)
Ceiba C3+C4 (Boosting)
North Sea
Columba E. (WI)
Brenda & Nicol (Boosting)
Lyell (Boosting)
Machar/ETAP (Boosting)
Highlander (Separation)
Argyll (Separation)
Mediterranean
Montanazo & Lubina (Boosting)
Prezioso (Boosting)
Angola
Pazflor (Sep., Boosting)
CLOV (Boosting)
GirRi (Girassol) (Boosting)
Congo
Azurite (Boosting)
Moho Phase 1 BIS (Boosting)
West of Shetlands
Schiehallion (Boosting)
Abu Dhabi
Zakum (Separation)
Barents Sea
Shtokman (Compression)
Snohvit (Compression)
Espirito Santo Basin
Jubarte - Phase 2 (Boosting)
Golfinho (Boosting)
Jubarte - Phase 1 (Boosting)
Jubarte EWT (Boosting)
Canapu (Separation)
Atlanta (Boosting)
Parque das Baleias (Boosting)
GOM
Perdido (Separation, Boosting)
Navajo (Boosting)
King (Boosting)
Cascade & Chinook (Boosting)
Jack and St. Malo (Boosting)
Julia (Boosting)
Stones (Boosting)
South China Sea
Lufeng (Boosting)
Campos Basin
BC-10 - Phase 1 (Separation, Boosting)
Espadarte (Field Trial) (Boosting)
Barracuda (Boosting)
Marimba (Separation, Boosting)
Marlim SSAO - Pilot (Separation)
Albacora L'Este (WI)
Marlim (Boosting)
Congro (Separation, Boosting)
Corvina (Separation, Boosting)
BC-10 - Phase 2 (Separation, Boosting)
Western Australia
Mutineer/Exeter (Boosting)
Vincent (Boosting)
Installed & Currently Operating
Installed & Not Currently Operating or In-active
Abandoned, Removed
Awarded and in Manufacturing or Delivered
Qualified/Testing
Conceptual Project
Canceled Project
WORLDWIDE LOCATIONS FOR SUBSEA PUMPING, COMPRESSION, AND SEPARATION SYSTEMS (As of Feb., 2014)
COURTESY OF
GRAPH 1 – GVF vs. DIFFERENTIAL PRESSURE - OPERATIONAL AND CONCEPTUAL CAPABILITIES
250
200
150
100
50
0 bar
3,625
3004,400
2,900
2,175
1,450
725
0 psi
SPP - Single Phase Pump (Centrifugal)
TSP - Twin Screw Pump
WGC - Wet Gas Compression
DGC - Dry Gas Compression
HSP - Hydraulic Submersible Pump
Dif
fere
nti
al P
ress
ure
GVF (%)
High BoostHelico-Axial
StandardHelico-Axial
Hybrid
HSP
SPP (Centrifugal)
TSP
WGC DGC
TSP
1000 10 20 30 40 50 60 70 80 90
0% 20% 40% 60% 80% 100% 0 100 200 300 400
GRAPH 2 – HIGH LEVEL COMPARISON OF SUBSEA BOOSTING OPTIONS
Pump Types GVF Range (Approximate) Pressure Differential (Bar)
CENTRIFUGAL
HYBRID (CENTRIFUGAL/HELICO-AXIAL)
MULTIPHASE ESP
HSP
HELICO-AXIAL
TWIN SCREW
Notes:
1. Combination of parameter values shown above is not feasible.
2. There are a number of other parameters/factors that need to be considered for any pump selection.
3. Based upon recent updates from Flowserve’s subsea boosting system test results.
4. HSP can tolerate up to 100% of gas slug.
125
175 (Note 3)
200 (Note 2)
75%
COURTESY OF COURTESY OF
TABLE 2 – PUMP TYPES & APPLICATIONSTYPE CONFIG. APPLICABILITY FOR SUBSEA BOOSTING
CENTRIFUGAL HORIZONTAL OR VERTICAL
H Highest differential pressure capability among pump types.
H Handles low Gas Volume Fraction (GVF) < 15% at suction conditions.
HYBRID (CENTRIFUGAL & HELICO-AXIAL)
VERTICALH Combination of helico-axial and centrifugal impeller stages.
H Primary application is for use downstream of separator or in low GOR applications
where GVF is consistently < 38% at suction conditions.
MUDLINE ESP HORIZONTAL OR VERTICAL
H Widely deployed technology used for boosting in wells, caissons, flowline risers, and
mudline horizontal boosting applications.
H Applicable for conditions of GVF < 50% (continuous) and for improved flow assurance.
HSP HORIZONTAL OR VERTICAL
H Compact hydraulic drive boosting pump for wells, caissons & mudline applications.
H Applicable for conditions of GVF < 75% (continuous) and for improved flow assurance.
HELICO-AXIAL VERTICALH Applicable for higher GVF boosting applications - typical range of 30-95% GVF at
suction conditions.
H Moderate particulate tolerance.
TWIN SCREW HORIZONTAL OR VERTICAL
H Good for handling high GVF - up to 98% GVF at suction conditions.
H Preferred technology for high viscosity fluids.
SUBSEA BOOSTING PUMP TYPES
Fig. 1: Vertically ConfguredCentrifugal Single Phase Pump & Motor Diagram
Fig. 3: OneSubsea’s Multiphase Hybrid SS Boosting Pump
HYBRID: OneSubsea’s hybrid pump was developed and qualifed for the Pazfor subsea separation and boosting project. It comprises a combination of lower helico-axial stages and upper centrifugal stages on the same shaft. This confguration tolerates moderate gas fraction and generates high differential head to allow a wide operating envelope.
CENTRIFUGAL PUMPS (For GVF < 15%)
HYBRID PUMPS (For GVF < 38%)
HELICO-AXIAL PUMPS (For GVF < 95%)
TWIN SCREW PUMPS (For GVF < 98%)
Courtesy of OneSubsea
Fig. 7: Deployment of a OneSubsea Helico-Axial Multiphase Pump
HELICO-AXIAL: OneSubsea’s multiphase pump stages in a vertical confguration. Recent testing and successful qualifcation work, in the HiBoost MPP Joint Industry Project, have greatly increased differential head capability (see Graph 2 for details).
HSPs can be confgured as a downhole pump with the power pressure pump residing on a platform or on the seabed. The downhole pump can also be vertically confgured in a seabed caisson for boosting and separation purposes.
Fig. 6: Vertically ConfguredHelico-Axial Pump & Motor Diagram
Courtesy of OneSubsea
Fig. 9: Vertically Confg-ured SMPC Series 4 Twin Screw Pump & Motor
Courtesy of Bornemann
Fig. 8: Twin Screw PumpCross Section Diagram
Courtesy of Leistritz
Fig 11: Vertically Confgured SMPC Series 4 Twin Screw Pump & Motor
Courtesy of Bornemann
Courtesy of Bornemann
Fig. 10: Bornemann Twin Screw Cross Section Diagram
Fig. 12: Flowserve Horizontally Confgured Twin Screw Pump & Motor Concept
Courtesy of Flowserve
Fig. 2: VerticallyConfgured Hybrid Pump& Motor Diagram
Courtesy of OneSubsea
Fig. 4: Diagram of Vertically Confgured Gas Handling ESP in a Seabed Caisson
Fig. 5: Diagram of HSP Principle of Operation
ESP PUMPS (For GVF < 50%)
HSP PUMPS(For GVF < 75%)
Courtesy of Schlumberger
Courtesy of ClydeUnion Pumps (SPX)
ESPs can be installed in a caisson to gather and boost fow from multiple wells.
POSTER COLOR CODE KEYThe poster is divided into discrete sections and each section is marked by a background color. The colors denote the type of technology presented in the sections. This color code is carried throughout the poster. Below are the intuitive color code designations for each of the six themes.
Full Wellstream Subsea Boosting
Subsea Separation
Subsea Gas Compression
Water Injection with Subsea Pumps
Power Transmission/Distribution and Controls
Miscellaneous Information/Combination of Technologies
CHART 1 – SUBSEA SUPPLIER MATRIX (As of Feb., 2014) SUBSEA PROCESSING
SUBSEAPUMPING
AKER SOLUTIONS
akersolutions.com
FMC TECHNOLOGIES (6)
fmctechnologies.com
GE
ge-energy.com
AKER SOLUTIONS
akersolutions.com
BORNEMANN (8)
bornemann.com
FLOWSERVE
flowserve.com
PUMPSYSTEM
PACKAGERS
ELECTRICMOTOR
MANUFACTURERS
ONESUBSEA
onesubsea.com
BAKER HUGHES
bakerhughes.com
ONESUBSEA
onesubsea.com
ONESUBSEA
onesubsea.com
ClydeUnion (SPX)
spx.com
SCHLUMBERGER
slb.com
LEISTRITZ
leistritzcorp.com
AKER SOLUTIONS
akersolutions.com
DIRECT DRIVE SYSTEMS (1)
fmctechnologies.com
FLOWSERVE
flowserve.com
CURTISS WRIGHT
curtisswright.com
LOHER (2)
automation.siemens.com
HAYWARD TYLER
haywardtyler.com
AKER SOLUTIONS
akersolutions.com
DUCO
technip.com
JDR
jdrcables.com
DRAKA
draka.com
OCEANEERING
oceaneering.com
NEXANS
nexans.com
PARKER
parker.com
ABB
abb.com
FURUKAWA
Furukawa.co.jp
MITSUBISHI
mitsubishielectric.com
BICC BERCA
biccberca.com
OKONITE
okonite.com
NKT
nktcables.com
SUMITOMO
sumitomo.com
BRUGG
bruggcables.com
HITACHI
hitachi.com
ALCATEL
alcatel-lucent.com
NEXANS
nexans.com
PRYSMIAN
prysmiangroup.com
ABB
abb.com
CONVERTEAM (7)
ge-energy.com
ONESUBSEA
onesubsea.com
BAKER HUGHES
bakerhughes.com
SCHNEIDER ELECTRIC
schneider-electric.com
AKER SOLUTIONS
akersolutions.com
BAKER HUGHES
bakerhughes.com
PUMPMANUFACTURERS
AKER SOLUTIONS
akersolutions.com
FMC TECHNOLOGIES
fmctechnologies.com
GE
ge-energy.com
BAKER HUGHES
bakerhughes.com
ONESUBSEA
onesubsea.com
SUBSEA RAWSEAWATER
INJECTION (3)
AKER SOLUTIONS
akersolutions.com
ASCOM
ascomseparation.com
SUBSEASEPARATION
SYSTEMS
AKER SOLUTIONS
akersolutions.com
ONESUBSEA
onesubsea.com
GE
ge-energy.com
XXXXXXXXX
XXXXXXXXX
DRESSER RAND
dresser-rand.com
GE POWER SYSTEMS
ge-energy.com
MAN Diesel & Turbo
mandieselturbo.com
ONESUBSEA
onesubsea.com
SIEMENS INDUSTRIAL
TURBO MACHINERY
turbomachinerysolutions.com
UMBILICALS
ALSTOM
alstom.com
XXXXX
BENNEX (4)
energy.siemens.com
DEUTSCH (5)
te.com
GE VetcoGray
ge-energy.com
SEACON
seaconworldwide.com
SIEMENS
energy.siemens.com
TELEDYNE ODI
odi.com
DIAMOULD
diamould.com
HVCONNECTORS
BENESTAD (9)
benestad.com
DIAMOULD
diamould.com
SIEMENS
energy.siemens.com
DEUTSCH (5)
te.com
TELEDYNE ODI
odi.com
TELEDYNE D.G.O’BRIEN
dgo.com
PENETRATORSAKER SOLUTIONS
akersolutions.com
CONVERTEAM (7)
ge-energy.com
ALPHA THAMES
alpha-thames.co.uk
SCHNEIDER ELECTRIC
schneider-electric.com
AKER SOLUTIONS
akersolutions.com
BAKER HUGHES
bakerhughes.com
VETCO GRAY SCANDINAVIA
ge-energy.com
SIEMENS
energy.siemens.com
ASDs/VSDs & X-FORMERS
POWERCABLES
HV &AC/DC POWER
CONTROLSYSTEMS
TESTINGFACILITIES
FMC TECHNOLOGIES/
SULZER (6)
fmctechnologies.com
sulzer.com
ONESUBSEA
onesubsea.com
SEABOX
sea-box.no
SAIPEM
saipem.com
NSW
nsw.com
BORNEMANN (8)
bornemann.com
FLOWSERVE
flowserve.com
FMC TECHNOLOGIES
fmctechnologies.com
ONESUBSEA
onesubsea.com
PROLAB
prolabnl.com
STATOIL: P-LAB & K-LAB
(Norway)
PETROBRAS ATALAIA LAB
(Brazil)
SHELL GASMER
(Houston, TX)
SULZER (6)
sulzer.com
LEISTRITZ
leistritzcorp.com
OTHERSUPPORTING
SYSTEMS
COMPRESSORS
FMC TECHNOLOGIES
fmctechnologies.com
COMPRESSIONSYSTEM
PACKAGERS
SUBSEACOMPRESSION
GE
ge-energy.com
ONESUBSEA
onesubsea.com
FMC Technologies
fmctechnologies.com
TWISTER BV
twisterbv.com
SAIPEM
saipem.com
SCHNEIDER ELECTRIC
schneider-electric.com
SULZER (6)
sulzer.com
COURTESY OF
NOTES: 1. Direct Drive Systems is a subsidiary of FMC Technologies. 2. Loher is a Siemens company. 3. Subsea raw seawater injection refers to only those projects utilizing a subsea pump to inject
seawater and does not include typical water injection using a pump on a topside facility. 4. Bennex is a Siemens company.
5. Deutsch is part of the TE connectivity group. 6. FMC Technologies and Sulzer have formed a joint venture.7. CONVERTEAM is a GE company. 8. Bornemann is an ITT Company.9. Benestad is a Aker Solution company
TABLE 7 – OTHER INFORMATION SOURCES Go to www.onepetro.org to order the SPE & OTC papers listed below.
SUBSEA BOOSTING PROJECTS
OTC 23178 2012 FMC Pazflor: Test/Qual. of Novel Tech.
OTC-24498 2013 PETROBRAS SS Proc. & Boost. in Brazil
OTC-24401 2013 FMC/SULZER Dev. & Qual. of a High DP SS Pump
OTC-24201 2013 PETROBRAS Mudline ESP in a Subsea Skid
OTC-24428 2013 PETROBRAS/ONESUBSEA SS High Boost MPP
OTC-24217 2013 PETROBRAS Barracuda Subsea Helico-Axial MPP
SPE-164757 2013 JOH. HEINR. BORNEMANN MP Boosting in Oil and Gas
OTC-24263 2013 ONESUBSEA Evolution of SS Boosting
SUBSEA SEPARATION
IPTC-16914 2013 KERR-MCGEE & BAKER HUGHES Downhole Oil and Water Separation
SPE-166079 2013 BP & SOUTHWEST R. INST. Evaluation of Separation in a Casing
OTC-24533 2013 PETROBRAS Comiss./Startup of SS Marlim Separ.
SPE-167334 2013 PANDIT DEENDAYAL PET. UNIV. Effective Gas-Liquid Separation
OTC-24359 2013 SAIPEM SS Gas-liq. and Water-hydro. Sep.
OTC 23223 2012 FMC/EXMOB/WOODSIDE Compact SS Sep. for Deep Water
OTC 23478 2012 ENI SS Gas/Liquid Separation
DOT-T2S1O2 2011 SAIPEM Development of the Spoolsep
SUBSEA RAW SEAWATER AND PRODUCED WATER INJECTION DEVELOPMENT
OTC-24167 2013 PETROBRAS Albacora Subsea Raw WI
OTC-24111 2013 CHEVRON WI in the Gulf of Mexico
SPE-166576 2013 SEA-BOX/AKER SUBSEA SS Water Treatment and Injection
SPE-165138 2013 TOTAL EP Produced Water Re-Injection
SPE-164372 2013 SAUDI ARAMCO Prod. Water Re-Injection Sys. Optim.
OTC-24273 2013 TOTAL/SAIMPEM/VWS WEST. Springs: Subsea WI Treatment
MULTIPHASE BOOSTING SYSTEMSPE 134341 2010 SHELL/FLOWSERVE Dev. of High Boost System
SUBSEA COMPRESSIONIPTC-17649 2013 A/S NORSKE SHELL SS Compression at Ormen Lange
IPTC-16982 2013 CURTIN U. Appl. of Downhole Gas Compressor
IPTC 14231 2011 FRAMO Advances in SS Wet Gas Comp.
OTC 21346 2011 STATOIL/ONESUBSEA Testing of SS Wet Gas Comp.
OCT 24211 2011 AKER SOLUTIONS SS Compression: A Game Changer
DOT AMST. 2010 SHELL Qualifying the Technology
POWER TRANSMISSION/DISTRIBUTIONOTC-25278 2014 INTECSEA Hybrid “Split” VFD / SSP Tieback
OTC-24129 2013 PETROBRAS SS Electrical Power Trans. and Dist.
OTC-24448 2013 INTECSEA High Voltage Power Transmission
OTC-24129 2013 PETROBRAS Devel. of a SS Elect. Power Transm.
OTC-23935 2013 DEUTSCH/SCHNEIDER Powering Subsea Processing
OTC-24147 2013 DET NORSKE VERITAS Power System for the New Era
SPE-166558 2013 SCHLUMBERGER SS Cable Applications in Offshore
IPTC-17269 2013 TOTAL EP Selection of Power from Shore
OTC-24183 2013 GE Modular Stacked DC Transmission
OTC-23960 2013 HUSKY OIL CHINA LTD. Husky Liwan Deepwater SS Control
COMPANY EXPERIENCE & APPROACH TO SUBSEA PROCESSINGOTC-24307 2013 STATOIL Steps to the Subsea Factory
OTC-24161 2013 PETROBRAS SS Proc. Systems: Future Vision
OTC-24519 2013 PETROBRAS Subsea vs Topside Processing
OTC-23970 2013 TECORP INT. Challenges World Largest Slug
Catcher
OTC-24162 2013 PETROBRAS Cascade and Chinook Subsea Dev.
COURTESY OF
2P Two Phase3P Three PhaseAC Alternate CurrentAL Artifical LiftALM Artifical Lift ManifoldASD Adjustable Speed DriveBOPD Barrels of Oil per Day BPD Barrels per Day CAPEX Capital Expenditures COSSP Configurable Subsea Separation
& PumpingCSSP Centrifugal Subsea Submersible
PumpCTCU Cable Traction Control Unit DMBS Deepwater Multiphase Boosting
SystemESP Electrical Submersible Pump FFD Full Field Development FPS Floating Production System FPSO Floating, Production, Storage,
& Offloading Vessel GLCC Gas/Liquid Centrifugal CyclonicGLR Gas Liquid RatioGVF Gas Volume Fraction
Hp HorsepowerHSP Hydraulic Submersible PumpHV High VoltageIOR Improved (Increased) Oil Recovery JB Junction Box kW Kilowatt LDDM Long Distance Delivery Management LDDS Long Distance Delivery System MPP Multiphase Pump MW Mega WattsNF Natural FlowOPEX Operational Expenditures PCDM Power and Communication
Distribution Module PCM Power Control ModulePFD Process Flow DiagramPLET Pipeline End TerminationPLIM Pipeline Inline Manifold PSIG Pipeline Simulation Interest Group/
Pounds per Square Inch (Gauge)PSUTA Pump Subsea Umbilical Termination
AssemblyROV Remote Operated Vehicle RPM Revolutions per Minute
SCM Subsea Control Module SFB Seafloor BoostingSIORS Subsea Increased Oil Recovery System SMUBS Shell Multiphase Underwater Boost
StationSPEED Subsea Power Electrical Equipment
DistributionSPP Single Phase PumpSS SubseaSSBI Subsea Separation Boosting InjectionSSP Subsea ProcessingSUBSIS Subsea Separation and Injection
System SUTA Subsea Umbilical Termination
AssemblyTUTA Topside Umbilical Termination
AssemblyVASPS Vertical Annular Separation and
Pumping System VSD Variable Speed Drive WD Water DepthWI Water InjectionWI XT Water Injection Christmas TreeXT Christmas Tree
COURTESY OF
TABLE 6 – ACRONYMS & ABBREVIATIONS
SUBSEA GAS COMPRESSION SYSTEMS & PRODUCTS BY COMPANYFig. 1: Ormen Lange Subsea Compression Pilot
Courtesy of Aker Solutions
Fig. 2: Subsea Gas Compression Station Concept
Courtesy of FMC Technologies
Fig. 4: Åsgard SS Compressor
Courtesy of MAN Diesel & Turbo
Fig. 7: Åsgard SS Compression Support Structure in Transit to Field
Courtesy of Aker Solutions
Fig. 8: Kvaerner Booster Station(KBS) for SS Gas Compression
Courtesy of GE Oil & Gas
Fig. 6: Åsgard Subsea Compression Station Template Installation
Courtesy of Aker Solutions
Fig. 5: Illustration of the OneSubsea Gullfaks Wet Gas Compression Station
Courtesy of OneSubsea
Fig. 3 : OneSubsea Counter-rotating 5MW Wet Gas Compressor built for Gullfaks Qualifcation Test
Courtesy of OneSubsea
SUBSEA POWER CONDITIONING EQUIPMENT & CONNECTORS
Note: The Siemens Subsea Power Grid is shown in Fig. 5, with the main building blocks in Figs. 6, 7 and 8.
Wet mate 36kV connectors and control system will also be part of the Siemens Subsea Power Grid.
Fig. 2: SS HV Multi Circuit Breaker 60 MVA Concept
Courtesy of Schneider Electric
Fig. 1: Ormen Lange Pilot SS Circuit Breaker
Courtesy of Aker Solutions
Fig. 5: Siemens Subsea Power Grid Concept
Courtesy of Siemens
Fig. 6: Subsea Transformer Prototype at Shallow Water Test in 2012
Courtesy of Siemens
Courtesy of Siemens
Fig. 7: Subsea Variable Speed Drive Illustration
Courtesy of Aker Solutions
Fig. 3: Ormen Lange Pilot Subsea Pump ASD
Fig. 8: SS Circuit Breaker/SS Switchgear Illustration
Figs.: 8-11 Courtesy of Siemens
Fig. 10: Tronic FoeTRONWet-Mate Connectors
Fig. 4: Tronic SpecTRON 10 Wet-Mate Connectors
Fig. 9: Tronic ElecTRON Wet-Mate Connectors
Courtesy of Siemens
Fig. 11: Tronic DigiTRONWet-Mate Connectors
SUBSEA PROCESSING CONFIGURATIONS
SUBSEA SEAWATER INJECTION AND TREATMENT
Fig. 1: Aker Solutions’ LiquidBooster™ Subsea Raw Seawater Injection System(Photo: Statoil Tyrihans Subsea Raw Seawater Injection (SRSWI) System)
Courtesy of Aker Solutions
Figs. 5 and 6: Courtesy of SEABOX AS
Fig. 3: One of four AlbacoraRaw Seawater WI Pump Systems undergoing SIT in OneSubsea Test dock in late 2009
Courtesy of OneSubseaFig. 4: Total-Saipem-VWS Westgarth Conceptual Subsea Sulphate Removal Station for Deep and Ultradeep Water Applications Fig. 5: Subsea Water Intake and Treatment (SWIT)
Unit Capable of Treating 40,000 barrels per day
Fig. 6: Integrated SS Raw Seawater Injection System Integrating SPP and Filtration
SS Water Injection Tree
(WI XT)
Single Phase Pump
for Water Injection
(SPP WI)
Raw Seawater Intake
& Filtration (SWIT Unit)
Courtesy of Saipem SA
Fig. 2: Conceptual Illustration of Installation of Tyrihans Subsea Raw Seawater Injection (SRSWI) System
SUBSEA SEPARATION SYSTEM TYPES: 1. GRAVITY SEPARATION SYSTEMS (Figs. 1–6)
HORIZONTAL SEPARATOR - This type is more effcient for oil/water separation. An example is the orange colored horizontal separator for the Tordis Project shown in Fig. 1A above.
VERTICAL SEPARATOR – This type is more effcient for gas/liquid separation. The liquid keeps a fuid blanket on the pump and reduces potential pump cavitation. An example is the Pazfor vertical separator shown in Fig. 2.
Fig. 1A: Illustration of FMC Subsea Separation System for the Tordis Project
Courtesy of FMC Technologies
Fig. 2: Illustration of FMC SS Gas/Liquid Separa-tion & Boosting System for Pazfor Project
Courtesy of FMC Technologies
Fig. 5: Aker Solutions’ DeepBooster™ with Separation System Flexsep™ Concept
Courtesy of Aker Solutions
Fig. 3: Troll C Separation System
Courtesy of GE Oil & Gas
Fig. 4: Saipem COSSP (2-Phase Gas/Liquid Separation & Boosting System Concept)
Fig. 6: Saipem SpoolSep (3-Phase Separation & Produced Water Reinjection System) Concept
Figs. 5 and 6 Courtesy of Saipem SA
Fig. 1B: Tordis Separator
TABLE 3: SURVEY OF SUBSEA ELECTRICAL POWER CONNECTOR AND PENETRATORS
STATUS MAN
UFAC
TURE
R
PART
NUM
BER
WAT
ER
DEPT
H
VOLT
AGE
CL
ASS
CURR
ENT
RATI
NG
FREQ
UENC
Y
CABL
E TE
RMIN
ATIO
NW
ET M
ATE
PENE
TRAT
OR
(m) (ft) (kV) (A) (Hz)
Currently Operating TE Connectivity Deutsch P6-MD300 400 1,312 6/10(12) 300 15-70 H
Installed on Pilot TE Connectivity Deutsch P6-SW1600 2,000 6,562 6/10(12) 1,600 200 H H
Installed on Pilot TE Connectivity Deutsch P18-SW900 2,000 6,562 18/30(36) 900 15-70 H H
Qualified TE Connectivity Deutsch P18-SD 300 3,000 9,843 18/30(36) 400 200 H H
Qualified Siemens Tronic SpecTRON 5 1,330 4,364 2.9 /5(5.8) 200 100 H H H
Qualified Siemens Tronic SpecTRON 8 3,000 9,843 5/8.7(10) 355 200 H H H
Qualified Siemens Tronic SpecTRON 10 3,000 9,843 6/10(12) 630 200 H H H
Qualified GE VetcoGray MECON DM 900 2,953 76/132(145) 600 50 H
Qualified GE VetcoGray MECON WM-I 1,500 4,921 12/20(24) 300 50 H H
Qualified GE VetcoGray MECONWM-II 1,500 4,921 18/30(36) 500 50 H H
Under Qualification GE VetcoGray MECON WM 3,048 10,000 18/30(36) 500 15-100 H H
Under Qualification TE Connectivity Deutsch P6-3W250 3,000 9,843 6/10(12) 250 15-200 H H H
Delivered Benestad AS 15k Power Penetrator 3,048 10,000 6/10(12) 450 15-200 H H H
Delivered TE Connectivity Deutsch P6-SW400 3,000 9,843 6/10(12) 400 15-100 H H H
Delivered TE Connectivity Deutsch P18-SW400 3,000 9,843 18/30(36) 400 15-200 H H H
Delivered TE Connectivity Deutsch P18-SD400 3,000 9,843 18/30(36) 400 15-200 H H
Proposed TE Connectivity Deutsch P6-SW900 3,048 10,000 6/10(12) 900 200 H H H
Proposed TE Connectivity Deutsch P18-SW900 3,048 10,000 18/30(36) 900 200 H H H
Note 1: The configurations and diagrams below are examples only and do not represent specific projects. Note 2: The configurations shown below illustrate a “building block” approach, demonstrating mudline technologies and no ESP based configurations. The “building blocks” primarily use retrievable module elements within their designs. Note 3: The distances implied in the short, medium, and long distance configurations of Figs. 1, 4, and 7 are indicative only for these examples. Actual distance limitations and system configurations for real-world fields will depend on the specific production/reservoir conditions, and on the detailed capabilities of the associated processing and power system equipment. For applications beyond 100 miles (160 Km), the system configurations are only in the conceptual stage, and are not depicted here.
HostSwitchgear
HostGeneration
ASD(Frequency Converter)
Host FloatingProduction Facilities
Subsea
Topsides
TYPE 2
Direct Step Outwith Subsea Transformer
G
~
~
TUTA
PSUTA
Transformer
JB
Purge
Safety Disconnect / Earthing Switch
(For multi-circuit umbilicals)
Static or DynamicPower Umbilical
~
M
SubseaTransformer
R
HighResistanceResistance
Booster Pump or Compressor
SS Processing Station
~
M
R
HighResistance
Water Injection Single Phase
Pump
SS WI Station
SSTransformer
Module
PSUTA
~
~
Up to ~12.5 MW, Typically 6.6kV
Up to 36 kV
Fig. 5: Type 2 Electrical Diagram (see Table 5)
~
M
~
~
~
~
~
~
PSUTA
~
M~
M
SS ASD
6.6 kV
Up to 36 kV
SS Power Skid with Switchgear
Static or Dynamic Power Umbilical
Subsea
PlatformOR
Onshore Facilities
Transformer4.16 kV - 13.8 kV (typical)
TYPE 3Subsea AC Power Distribution
w/MV or HV Power Transmission
TUTA
Host Switchgear
Wet MateConnector
(Typ.)
R
Solid or LowResistance
Earthing
Transformer
~
JB Purge
Host Switchgear
(Output voltage ~36kV or higher depending on load & distance)
(SS Transformer Optional depending on selected transmission voltage)
SPP Gas
Compr.
WI SPP
SS Processing Station (3P)
ShorelineTopsides or Land
Fig. 8: Type 3 Electrical Diagram (see Table 5)
SYMBOL KEY
Production Umbilical
Utility Umbilical
Production Flowline
Pump StationXT
XT
SS Manifold
PSUTA
SUTA
Fig 3: Short Distance Process Flow Diagram (PFD)
SS ProcessingStation (Two Phase)SS ProcessingStation (2P)
Production Umbilical
Utility Umbilical
Gas Flowline
Liquid Flowline
Multiphase Flowline
Seawater
XT
XT
SS Manifold
PSUTA
WI XT
WI Flowline
SUTA
SS WI StationSS WI Station
Fig 6: Medium Distance Process Flow Diagram (PFD)
Production Umbilical
Utility Umbilical
Gas Flowline
SS Processing Station (3P) (Three Phase + WI)
Oil Flowline Multiphase Flowline
WI Flowline
PSUTA SS Power Skid
XT
XT
WI XT
WI XT
WI XT
SS Manifold SUTA
Fig 9: Long Distance Process Flow Diagram (PFD)
Fig. 1: Short Distance Confguration Example
Subsea
Topsides
TYPE 1
Direct Step Out
G
~
~
HostSwitchgear
HostGeneration
TUTA
PSUTA
~
M
ASD(Frequency Converter)
Static or DynamicPower Umbilical
MP Boosting Pump
Up to ~3000 kW, Typically 6.6kV
Purge
Safety Disconnect / Earthing Switch
(For multi-circuit umbilicals)
JB
Electrical Flying Lead (EFL)
Pump Station
Host FloatingProduction Facilities
Fig. 2: Type 1 Electrical Diagram (see Table 5)
SUBSEA POWER SYSTEM TYPES AND CONFIGURATIONS
Fig. 1: SUBSEA POWER SYSTEM STEP-OUT CONFIGURATIONSTABLE 5: POWER SYSTEM STEP-OUT CONFIGURATIONS
CATE
GORY
VOLTAGE & POWER RATING
INDICATIVE STEP-OUT
(4)
ADJUSTABLE SPEED DRIVE
POWER TRANS-
FORMERS
NOMINAL TRANS-
MISSION FREQ.
Radius (1)
Tops
ide
Subs
ea
Tops
ide
(Ste
p Up
)
Subs
ea(S
tep
Dow
n)
50 o
r 60
Hz
AC
16.7
-25
Hz
AC
Type 1
Capacity: 1-4 MWTransmission: ~6kVDistribution: ~6kV
0-15 Km(0-9.3 Mile) H H
Type 2
Capacity: 1-4 MWTransmission: Up to 36kVDistr./Motor Input: ~6kV
0-60 Km(0-37.3 Mile) H H
(2)H
(2)H
Type 3
Capacity: Up to 70 MWTransmission: 36kV-145kVDistr. Switchgear: Up to 36kVDistr./Motor Input: ~6kV
0-160 Km(0-100 Mile) H H
(3)H
(3)H
Type 4
Capacity: Up to ~100 MWLF Transmission: Up to 145kVLF Dist. Switchgear: Up to 36kVDistr./Motor Input: ~6kV
>140-400 +Km(>87-248.5 +Mile) H H
(3)H
(3)H
Notes:1. Indicative radius subject to system power rating. See Figure 1, Step-Out Configurations.
2. Transformer location likely after ASD to meet umbilical transmission voltage.
3. Transformer location likely before ASD to meet umbilical transmission voltage.
4. Stepout is the distance from the host facility.
5. Barracuda project with a step out of 14 km (8.7 Mi) is a deployed example of Type 1 Configuration.
6. Tyrihans project with a step out of 31 km (19.3 Mi) is a deployed example of Type 2 Configuration.
7. There is no deployed example of Type 3. Type 4 is currently conceptual.
COURTESY OF
COURTESY OF
Host FloatingProductionFacility
ProductionFlowline
UtilityUmbilical
ProductionUmbilical
PSUTA
PLET
SUTA
SS Manifold
XT(TYP.)
Pump Station
Type 1
Fig. 4: Medium Distance Confguration Example
Host FloatingProductionFacility
ProductionUmbilical
UtilityUmbilical
GasFlowline
PLET
PLET
LiquidFlowline
SS ProcessingStation (2P)
PSUTA
SUTA
SS Manifold
Multiphase Line
Multiphase Line
WI Line
WI XT (TYP.)
XT(TYP.)
Type 2
MPP
(2P)
MULTIPHASE BOOSTING SYSTEM EXAMPLES (CONCEPTUAL & DELIVERED)
Fig. 6: GE Oil & Gas Boosting Station
Courtesy of VetcoGray (GE Oil & Gas)
Fig. 1: Aker Solutions MultiBooster™ System (BP King)
Courtesy of Aker Solutions
Fig. 2: FMC/Flowserve SS Multiphase Pumping System with 2 Retrievable Pump Modules
Courtesy of FMC Technologies
Fig. 3: OneSubsea - Loadout of 1 of 6, 2.3 MW HybridPumps for Pazfor Project
Courtesy of OneSubseaFig. 5: FMC TechnologiesSS Multiphase PumpingModule with Sulzer Pump
Courtesy of Sulzer
Fig. 4: 1 of 3 Jack & St Malo Pump Stations in the Factory Test Pit for System Integration Test (SIT) Immediately Prior to Filling with Water
Courtesy of Chevron and OneSubsea
MUDLINE ESP OR HSP SYSTEM EXAMPLES
Courtesy of FMC Technologies
Fig. 1: Horizontal ESP Boosting Station Fig. 2: ESP Jumper Boosting System
Courtesy of Baker Hughes
Fig. 3: Seafoor Boosting System Using ESPs in Caissons
Courtesy of Baker Hughes
Fig. 4: Seafoor Boosting Using ESP in caisson
Courtesy of Aker Solutions
Fig. 5: HSP for Mudline Boosting
Courtesy of ClydeUnion
Pump (SPX)
2. CAISSON SEPARATION SYSTEMS (Figs. 7–9) INSTALLED < 100 m INTO SEABED
Fig. 7: BCSS Seabed Equipment
Courtesy of Aker Solutions
3. COMPACT/DYNAMIC SEPARATION SYSTEMS (Figs. 10-12)
Fig. 10: OneSubsea’s Compact 2-Phase Separator & Pump Module
Fig. 11: OneSubsea’s Compact 3-Phase Separation Module Concept
Courtesy of OneSubsea
Fig. 12: FMC 3-Phase Separation System with Produced Water Re-injection Using In-Line Separation Technology for the Marlim Project
Courtesy of FMC Technologies
deeper understandingwww.genesisoilandgas.com
Don’t just scratch
the surface
More powerful pumps:
Maximize production now. Image courtesy of Sulzer Pumps
Copyright © FMC Technologies, Inc. All Rights Reserved. www.MaximizeRecovery.com
operating hours.
And counting.
Delivering increased recovery requires a reliable subsea processing solution that is designed on the premise of the reservoir.
OneSubsea™ presents the most comprehensive suite of products providing scalable subsea processing and boosting system
solutions for all environments, including extreme conditions up to 15,000 psi and 3000 meters water depth.
With more than 30 operating systems in subsea regions from the North Sea to Australia, West Africa to Brazil, OneSubsea
has a portfolio of proven, reliable boosting and pumping systems successfully increasing production rates from 30% up to
100% for operators. Visit www.onesubsea.com/pumpingsystems
Up to 100% increased production rate from the
industryÕs only subsea multiphase boosting systems
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Taking subsea
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tances and depths.
ABB AS
Tel. +47 22 87 20 00
www.abb.com
TV
03
93
© C
op
yrig
ht
20
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AB
B.
All
rig
hts
reserv
ed
.
Contact us:[email protected]
www.clydeunion.com
Scan for more
infomation
Part of SPX’s expansive portfolio of products serving the oil & gas industry.
Learn more at www.spx.com
Maximize your uptime & flexibility; greatly lower OPEX with the SPX HSP:
Contact us:[email protected]
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� High reliability - MTTF > 11 years in subsea environment
� True multi-phase capability; Excels in gassy, heavy crude applications
� Unrivalled operating range from a single frame (particularly at high GVF)
� Minimal installation time; plug & play design
� Ideally suited to downhole lift & seabed boosting
Innovative Hydraulic Submersible Pump (HSP) Technology from SPX
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ude apude ap
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X with the SPX HSP:
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applications applications
rly at high GVF) at high GVF)
For more information visit
www.flowserve.com
Reliable Seabed Boosting With Subsea Multiphase Pumps and Motors
Design Ratings
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Enabling Subsea Processing by Connecting Innovation with Experience siemens.com/energy/subsea
Fig. 9: FMC’s VerticalAccess Caisson with ESP Boosting (Gas/Liquid Separation & Boosting) System Diagram
Courtesy of FMC Technologies
Fig. 8: Caisson Separation/ESP Boosting System
Courtesy of Baker Hughes
Note: This table is a sampling of the current market, and is not comprehensive.
Fig. 7: Long Distance Confguration Example
Onshore FacilitySS Processing
Station (3P)
SS Power Skid
(3P)
SPP Oil
WI SPP
Type 3
ProductionUmbilical
UtilityUmbilical Gas
Flowline
PLET
PLET
OilFlowlinePSUTA
SUTA
SS Manifold
Multiphase Line
WI Line
WI XT (TYP.)
~
~
Multi Phase Mudline Boosting, Single Phase Pumping, or Water Injection Pumping
Two Phase or Three Phase Separation
Gas Compression
Seawater Filtration/Intake
SS Power System
Adjustable Speed Drive (ASD)
SS Transformer
Safety Disconnect/ Earthing Switch
Switchgear
HV Wet Mate Connector
6.6 kV Wet Mate Connector
~
~
Courtesy of OneSubsea
XT(TYP.)
Note 1: SWIT Unit provides disinfection and low Total Suspended Solids (TSS) water for either matrix or sweep fooding.
TABLE 1 – 2014 WORLDWIDE SURVEY OF SUBSEA GAS COMPRESSION, BOOSTING, WATER INJECTION, AND SEPARATION (1)(2) – As of Feb. 2014
PROC
ESSI
NG
DISC
IPLI
NE
COUN
T
FIELD OR PROJECT (Ordered by Start Date)
CURR
ENT
STAT
US
COMMENTSOWNER/
FIELD OPERATOR
REGION/ BASINS
WATER DEPTH
TIEBACK DISTANCE
SYSTEM FLOW RATE (@LINE CONDITIONS)
DIFFERENTIAL PRESSURE
UNIT
MOT
OR
POW
ER (3
)
GVF
(GAS
VOL
UME
FRAC
TION
) (5)
SYSTEM PACKAGER
NO. OF PUMPS UNITS
PUMP TYPE or
COMPR. TYPE
COMPRESSOR/PUMP MANUFACTURER
IN-SERVICE/OPERATING INFORMATION
COMPANY Meters Feet Km Miles M3/Hr. MBOPD MBWPD BAR (4) PSI
(4) MW % OF VOL. COMPANY PUMPS or
COMPR. TYPE COMPANY START (11) (Month-Year)
END or PRESENT
MTHS
SUBS
EA G
AS
COM
PRES
SION
1 DEMO 2000 Q Statoil K-Lab Test Statoil Offshore Norway 3.60 n/a OneSubsea Counter Axial OneSubsea 2001
2 Ormen Lange Gas Compression Pilot Q Testing 1 train @ Nyhamna, Norway Statoil Offshore Norway 860 2,821 0.0 0.0 25,000 3776 60.0 870 12.50 n/a Aker Solutions 1 Centrifugal GE Compr / Aker Pump 2011 1-Mar-14
3 Aasgard - Midgard & Mikkel Fields M Subsea Gas Compression Statoil Offshore Norway 300 984 40.0 25.0 40,000 6,042 60.0 870 11.50 n/a Aker Solutions 2+1 Spare +1 Centrifugal MAN / Aker pumps Q1, 2015
4 Gullfaks South Brent (28) M Subsea Wet Gas Compression Statoil Offshore Norway 135 443 15.5 9.7 9,600 1450 30.0 435 5.00 95% OneSubsea 2 + 1 Spare Counter Axial OneSubsea Q4, 2015
5 Ormen Lange Gas Compression Q Subsea Gas Compression Norske Shell Offshore Norway 860 2,821 120.0 75.0 50,000 7553 60.0 870 12.50 n/a TBA 2 Centrifugal TBA 2021
6 Troll C Subsea Gas Compression Statoil Offshore Norway 340 1,116 4.0 2.5 n/a TBA Undecided TBA 2016
7 Snohvit C Subsea Gas Compression Statoil Barents Sea 345 1,132 143.0 89.4 TBD n/a TBA Centrifugal TBA 2020
8 Shtokman C Subsea Gas Compression Gazprom Barents Sea 350 1,148 565.0 353.1 TBD n/a TBA Centrifugal TBA 2022
FULL
WEL
LSTR
EAM
SUB
SEA
BOOS
TING
(N
OTE
1. S
EABE
D &
RISE
R ON
LY, N
OTE
2. E
XCLU
DES
DOW
NHOL
E ES
Ps)
1 Prezioso (20) A MPP at Base of Platform AGIP Italy 50 164 0.0 0.0 65.0 10 40.0 580 0.15 30-90% Nuovo Pignone (8) 1 Twin-Screw GE 1994 1995
2 Draugen Field A SMUBS Project, 1 HSP A/S Norske Shell Offshore Norway 270 886 6.0 3.7 193.0 29 53.3 773 0.75 42% OneSubsea 1 + 1 Spare HSP SPX ClydeUnion Nov-95 15-Nov-96 12.2
3 Lufeng 22/1 Field (9) (19) A Tieback to FPSO Statoil South China Sea 330 1,083 1.0 0.6 675.0 102 35.0 508 0.40 3% OneSubsea / FMC Tech. 5+2 Spare Centrifugal (SPP) OneSubsea Jan-98 15-Jul-09 138.0
4 Machar Field (ETAP Project) A Hydraulic Turbine Drive BP Amoco UK North Sea 85 277 35.2 21.9 1,100.0 166 22.0 319 0.65 64% OneSubsea 2+1 Spare Helico-Axial OneSubsea
5 Topacio Field O 1 x Dual MPP System ExxonMobil Equatorial Guinea 550 1,805 8.0 5.0 940.0 142 35.0 508 0.86 75% OneSubsea 2+1 Spare Helico-Axial OneSubsea Aug-00 1-Mar-14 162.2
6 Ceiba C3 + C4 O Phase 1 SS MPP Project Hess Equatorial Guinea 750 2,461 7.0 4.3 600.0 91 45.0 653 0.85 75% OneSubsea 2+1 Spare Helico-Axial OneSubsea Oct-02 1-Mar-14 136.2
7 Jubarte EWT A Riser lift to Seillean Drillship Petrobras Espirito Santo Basin 1,400 4,593 1.4 0.9 145.0 22 140.0 2,000 0.70 22% FMC Technologies 1 ESP Schlumberger (REDA) Dec-02 1-Dec-06 47.9
8 Ceiba Field (FFD) O Full Field Development (FFD) Hess Equatorial Guinea 700 2,297 14.5 9.0 2,500.0 378 40.0 580 1.20 75% OneSubsea 6+ 2 Spare Helico-Axial OneSubsea Dec-03 1-Mar-14 122.3
9 Mutineer / Exeter O 2 x Single MPP Systems Santos NW Shelf, Australia 145 476 7.0 4.3 1,200.0 181 30.0 435 1.10 0-40% OneSubsea 7 SS ESP, 2 MPP Helico-Axial OneSubsea (16) Mar-05 1-Mar-14 107.3
10 Lyell (Original Install) A SS Tieback to Ninian South CNR UK North Sea 146 479 15.0 9.3 1,100.0 166 18.0 261 1.60 40-70% Aker Solutions 1 Twin Screw Bornemann SMPC 9 Jan-06 Dec-06 11.0
11 Navajo (17) I, N ESP in Flowline Riser Anadarko GOM 1,110 3,642 7.2 4.5 24.0 4 40.2 583 0.75 57% Baker Hughes 1 ESP Baker Hughes Feb-07 1-Aug-07 5.5
12 Jubarte Field - Phase 1 A Seabed ESP-MOBO, Uses BCSS (14) Petrobras Espirito Santo Basin 1,350 4,429 4.0 2.5 120.0 18 138.0 2,002 0.90 10-40% FMC Technologies 1 ESP Schlumberger (REDA) Mar-07 Aug-07 5.0
13 Brenda & Nicol Fields O MultiManifold with 1 MPP Premier Oil UK North Sea 145 476 8.5 5.3 800.0 121 19.0 276 1.10 75% OneSubsea 1+1 Spare Helico-Axial OneSubsea Apr-07 1-Mar-14 82.4
14 King (7) (13) A SS Tieback to Marlin TLP Freeport McMoRan GOM, MC Blocks 1,700 5,578 29.0 18.0 496.5 75 50.0 725 1.30 0-95% Aker Solutions 2+1 Spare Twin-Screw Bornemann / Loher Nov-07 15-Feb-09 15.0
15 Vincent O Dual MPP System Woodside NW Shelf, Australia 475 1,558 3.0 1.9 2,400.0 363 42.0 609 1.80 25-70% OneSubsea 2+2 Spare Helico-Axial OneSubsea Aug-10 1-Mar-13 30.9
16 Marlim A SBMS-500 SS Field Test Petrobras Campos Basin 1,900 6,234 3.1 1.9 500.0 75 60.0 870 1.20 0-100% Curtiss-Wright / Cameron 1 Twin-Screw Leistritz 0.0
17 Golfinho Field I, N Seabed ESP-MOBO, Uses BCSS (14) Petrobras Espirito Santo Basin 1,350 4,429 146.0 22 138.0 2,002 1.10 10-40% FMC Technologies 2 ESP Baker Hughes (35) Mar-07 Aug-07 5.0
18 Azurite Field A Dual MPP System Murphy Oil Congo, W. Africa 1,338 4,390 3.0 1.9 350.0 53 41.0 595 0.85 28% OneSubsea 2+1 Spare Helico-Axial OneSubsea Sep-10 1-Oct-13 36.5
19 Golfinho Field I, N MOBO BCSS (ESP) Caissons (14) Petrobras Espirito Santo Basin 1,350 4,429 146.0 22 138.0 2,002 1.10 10-40% Aker Solutions 2 ESP Baker Hughes Mar-07 Aug-07 5.0
20 Espadarte (Field Trial) O Horizontal ESP on Skid Petrobras Brazil 1,350 4,429 11.5 7.1 125.0 19 100.0 1,450 0.90 10-40% FMC Technologies 2 ESP Baker Hughes Dec-11 Mar-13 14.5
21 Parque Das Conchas (BC 10) Phase 1 (23) O Caisson / Artifical Non-Separated Shell Campos Basin 2,150 7,054 9.0 5.6 185.0 28 152 2,205 1.10 40% FMC Technologies 2 ESP Baker Hughes Jul-09 1-Mar-14 55.4
22 Parque Das Conchas (BC-10) Phase 2 (23) M 2 additional ESP Systems Shell Campos Basin 2,150 7,054 9.0 5.6 185.0 28 152 2,205 1.10 40% FMC Technologies 2 ESP Baker Hughes
23 Jubarte Field - Phase 2 (25) I, N Tieback to FPSO P-57, Uses BCSS (14) Petrobras Espirito Santo Basin 1,400 4,593 8.0 5.0 1,325.0 200 200 3,000 1.20 30-40% Aker Solutions 15 ESP Schlumberger (REDA) 6-Dec-10 1-Mar-14 38.7
24 Cascade & Chinook (6) I, N Skid BCSS - Horizontal ESP on Skid Petrobras US GOM 2,484 8,150 8.0 5.0 135.0 20 220.0 3,191 1.10 10% FMC Technologies 4+2 Spare ESP Baker Hughes Q4 2013 0.0
25 Barracuda (32) O SS MP High Boost Pump System Petrobras Campos Basin 1,040 3,412 10.5 6.5 280.0 42 70.0 1,015 1.50 35-60% OneSubsea 1 Helico-Axial OneSubsea Jul-12 1-Mar-14 7.0
26 Montanazo & Lubina I, N Single MPP System Repsol Mediterranean 740 2,428 9.0 5.6 80.0 12 65.0 943 0.23 10% OneSubsea 2 Centrifugal (SPP) OneSubsea 2014
27 Schiehallion I, N 2 x Dual MPP Systems BP UK, West of Shetland 400 1,312 4.0 2.5 2,700.0 408 26.0 377 1.80 74% GE / OneSubsea 4+0 Spare Helico-Axial OneSubsea 2014 Delayed Start Up
28 CLOV (22) M Subsea MPP System TOTAL Angola, Blk 17 1,170 3,839 11.0 6.8 660.0 100 45.0 652 2.30 50% OneSubsea 2+1 Spare Helico-Axial OneSubsea Q3 2014
29 Jack & St. Malo M Full Wellstream subsea Boosting Chevron US GOM 2,134 7,000 21.0 13.0 1,191.0 180 241.3 3,500 3.00 10% OneSubsea 3+2 Spare Centrifugal (SPP) OneSubsea Q3-2014
30 Lyell Retrofit I, N MPP Retrofit System - Tieback to Ninian CNR UK North Sea 145 476 7.0 4.3 700.0 106 21.0 305 1.00 97% OneSubsea 1 Helico-Axial OneSubsea Q3 2012
31 GirRi (Girassol) (27) M Field Expansion Project Total Angola, Blk 17 1,350 4,429 18.0 11.2 600.0 91 130.0 1,885 2.50 20-50% OneSubsea 4+2 Spare Helico-Axial OneSubsea Q1 2015
32 Draugen Field M Brownfield Dual MPP System A/S Norske Shell Offshore Norway 268 879 4.0 2.5 1,710.0 253 47.5 689 2.30 10-31% OneSubsea 2 Helico-Axial OneSubsea Q3-2014
33 Julia M SS Tieback ExxonMobil US GOM 2,287 7,500 27.2 17.0 331 50 175.0 2,550 3.00 10% OneSubsea 2 Centrifugal (SPP) TBD Mid- 2016
34 Moho Phase 1bis M Brownfield Tieback to Alima FPU Total Congo, W. Africa 650 2,133 6.7 4.0 400 60 133.5 1,935 3.50 49% OneSubsea 2 Helico-Axial OneSubsea Q4 2015
35 Atlanta Field C Caisson Application QGEP (26) Santos Basin, Blk BS-4 1,500 4,922 TBD ESP 2015
36 Stones C Single Phase HPHT Pump System Shell US GOM 2,927 9,600 5.0 3.1 TBD TBD TBD TBD TBD <10% TBD 2 +1 Spare TBD TBD 2018
37 Parque Das Baleias M Skid BCSS - Horizontal ESP on Skid (14) Petrobras Espirito Santo Basin 1,500 4,922 10.0 6.2 125.0 19 100 1,450 1.10 10-25% FMC Technologies 3+1 Spare ESP Schlumberger (REDA) Q1 2015
SUBS
EA
WAT
ER
INJE
CTIO
N 1 Troll C Pilot (15) (21) O SUBSIS (SS Sep. and WI Sys.) NorskHydro AS Offshore Norway 340 1,116 3.5 2.2 250.0 38 151.0 2,190 1.60 0% GE / OneSubsea 1+1 Spare Centrifugal (SPP) OneSubsea Aug-01 1-Mar-14 149.9
2 Columba E. I, N Dual SPP System CNR North Sea 145 476 7.0 4.3 331.0 50 305.0 4,424 2.30 0% OneSubsea 2+0 Spare Centrifugal (SPP) OneSubsea May-07 1-Oct-13 76.4
3 Tordis (WI) O (12), Separation, Boosting, WI Statoil Offshore Norway 210 689 11.0 6.8 700.0 106 77.0 1,117 2.30 0% FMC Technologies 1+1 Spare SPP&MPP OneSubsea Oct-07 1-Mar-14 76.4
4 Tyrihans O SS Raw Sea WI System Statoil Offshore Norway 270 886 31.0 19.3 583.0 88 205.0 2,973 2.70 0% FMC / Aker Solutions 2+1 Spare Centrifugal (SPP) Aker Solutions 29-Nov-13 1-Mar-14 3.0
5 Albacora L'Este Field (33) I, N Raw Water Injection to 7 Wells Petrobras Campos Basin, Brazil 400 1,312 4 to 9 2.5-6.0 1125 170 85 1,233 1.2 0% OneSubsea 3+1 Spare Centrifugal (SPP) OneSubsea Q1 2013 0.0
SUBS
EA S
EPAR
ATIO
N
1 Zakum A Shallow Water Test Separation System BP Offshore Abu Dhabi 1969 1972 36
2 Highlander Field (34) A SS Separator / Slug Catcher Texaco UK North Sea 420 128
3 Argyll A SS Sep. and Pumping Unit (SSPU) Hamilton Bros UK North Sea BOET (30) 1989
4 Marimba Field (24) I, N VASPS Field Test Petrobras Campos Basin 395 1,296 1.7 1.1 60.0 9 52.0 754 0.3 Cameron 1 ESP Schlumberger (REDA) Jul-01 1-Jul-08 83.0
5 Troll C Pilot (15) (21) O Horizontal SUBSIS (SS Sep. & WI Sys.) Hydro (Statoil) Offshore Norway 340 1,116 3.5 2.2 250.0 38 151.0 2,190 1.60 0% GE / OneSubsea 1+1 Spare n/a OneSubsea Aug-01 1-Mar-14 149.9
6 Tordis O (12), Separation, Boosting, WI Statoil Offshore Norway 210 689 11.0 6.8 1,500.0 227 27.0 392 2.30 10-68% FMC Technologies 1+1 Spare Helico-Axial OneSubsea Oct-07 1-Mar-14 76.4
7 Parque Das Conchas (BC 10) Phase 1 (23) O Separation Caisson / Artifical Lift Manifold Shell Campos Basin 2,150 7,054 25.0 15.6 185.0 28 152.0 2,205 1.10 15% FMC Technologies 4(+2 Future?) ESP Baker Hughes Centrilift Aug-09 1-Mar-14 54.4
8 Perdido O Caisson Separation and Boosting Shell GOM 2,438 7,999 0.0 0.0 132-264 20 - 40 158.8 2,303 1.20 15% FMC Technologies 5 ESP Baker Hughes Centrilift Mar-10 1-Mar-14 47.9
9 Pazflor O 3 Gas/Liquid Vertical Separation System Total Angola, Blk 17 800 2,625 4.0 2.5 1,800.0 272 105.0 1,523 2.30 <16% FMC Technologies 6+2 Spare Hybrid H-A OneSubsea Aug-11 1-Mar-14 30.0
10 Marlim SSAO - Pilot O In-Line Separation Petrobras Campos Basin 878 2,881 3.8 2.4 135.0 20 245 3,553 1.9 67% FMC Technologies 1 Centrifugal (SPP) OneSubsea Mar-13 1-Mar-14 11.0
11 Congro (29) CP VASPS with Horizontal ESP Petrobras Campos Basin 197 646 11.0 7.0 135.0 20 21 305 0.4 <10% FMC Technologies 2 ESP Baker Hughes Centrilift
12 Parque Das Conchas (BC 10) Phase 2 (23) M 2 additional ESP systems Shell Campos Basin 2,150 7,054 25.0 15.6 185.0 28 152.0 2,205 1.10 15% FMC Technologies 2 ESP Baker Hughes Centrilift
13 Canapu M In-Line Separation by Twister BV Petrobras Espirito Santo Basin 1,700 5,579
14 Corvina (29) M VASPS w/Horizontal ESP Petrobras Campos Basin 280 919 8.0 5.0 135.0 20 21 305 0.4 <10% FMC Technologies 1 ESP Baker Hughes Centrilift
CURRENT STATUS CATEGORIES
C Conceptual Project
Q Qualified/Testing
M Awarded and in Manufacturing or Delivered
O Installed & Currently Operating
I,N Installed & Not Currently Operating or In-Active
A Abandoned, Removed
CP Canceled Project
NOTES: 1. Qualification Status - See information accuracy statement below title block and note that the qualification
status categorizations shown in this table, and throughout the poster, are based on unverified claims from
equipment suppliers and field operators. These qualification status designations are not necessarily derived
using technology readiness level (TRL) assessments per API RP 17Q or DNV-RP-A203.
2. Pumping & Boosting: The terms “Pumping” and “Boosting” are used interchangeably throughout this poster
and in the industry.
3. Unit Motor Power: Is the unit motor power for either a pump or compressor motor.
4. Differential Pressure: Differential Pressure values are for individual pumps.
5. GVF = Gas Volume Fraction at inlet of pump.
6. Cascade & Chinook - Utilizes horizontal ESPs on a skid above mudline. It is an alternative ESP boosting
configuration to caisson in the seabed. This technology is designed to cover the low GVF and high DeltaP
multiphase flow. Pump cartridge successfully installed Q4 2013.
7. King Field: Power cables are incorporated within the service umbilical.
8. Nuovo Pignone is now part of GE.
9. Lufeng 22/1: Low wellhead pressure of 100 psig at seabed dictated that artificial lift was required. System
has now been decomissioned due to field abandonment.
10. VASPS - Vertical Annular Separation and Pumping System
11. START: Month & Year indicates first month and year of operation for the SS processing system.
12. Tordis Field: 1+1 Spare Multiphase Boosting Pumps, and 1+1 Spare Water Injection Pumps; Tieback to
Gullfaks C platform. Statoil hopes to increase oil recovery from 49% to 55%, an additional 36 MMBO, due to
the world's first commercial subsea separation, boosting, injection and solids disposal system.
13. King Field: Is a subsea tieback to the Marlin TLP. In 2012, BP sold the field to Plains Exploration and
Production. McMoran Freeport later purchased the field. Pumps remain shut-in due to operational issues.
The company is reportedly considering to redo the boosting system.
14. BCSS - Centrifugal Subsea Submersible Pumps. Pumps are placed in protective holes in the seabed, 200m
from producing wells. MOBO - Modulo de Bombas (Pumping Module)
15. Troll C Pilot: SUBSIS - The world's longest operating subsea separation system and first subsea water
injection pump system.
16. Mutineer/Exeter Projects: Manufacturers are: OneSubsea and Centrilift. There are 2 ESPs per well feeding
one OneSubsea MPP per asset on seafloor.
17. Navajo Field: Is a Subsea tieback to Anadarko's Nansen spar.
18. BH Centrilift = Baker Hughes Centrilift
19. LUFENG - Closed down due to field economics, after 11 years of operation.
20. PREZIOSO - World's first deployment of an electrically driven twin screw MPP operating on a live well.
Testing occurred in 1994 and 1995 for a total of 7,850 hours of operation at base of platform on seafloor.
21. Troll C Pilot - Separation began on Aug. 25, 2001. See OTC paper 20619, page 10 for further details on
operating experience. Note that injection pump data is only shown in the subsea water injection section
of the table.
22. CLOV - Total reports that the CLOV development will utilize seabed multiphase pumps to boost Cravo, Lirio,
Orquidea and Violeta Miocene from First Oil + 2 years
23. Parque Das Conchas (BC 10) Phase 1 - Composed of 3 reservoirs: Ostra, Abalone and Argonauta B-West.
Argonauta O-North to be added in Phase 2.
24. Marimba VASPS - 2000 - First installation in Marimba (JIP Petrobras / Eni-Agip/ ExxonMobil, 2001 - Startup
and Operation (July to Dec.) until ESP failure, 2002 End of JIP, By-pass production, 2003 - Workover Plan,
2004 - Workover and Re-start on May 8, 2004. From 2005 until 2008 VASPS operated ok until well failure.
25. Jubarte Field (Phase 2) - Was installed in 2011. Wells were connected to the FPSO P-57. All wells will have
gas-lift as a backup.
26. QGEP - Queiroz Galvao Exploracao e Producao
27. Girassol Field Pumping System - for the Girassol Resources Initiatives (GirRI)
28. Gullfaks South Brent - According to Statoil the SS wet gas compression will increase recovery from the
reservoir by 22 million barrels of oil equivalent.
29. Canceled Project - Petrobras has determined Congro and Corvina are not commercially feasible.
30. BOET - British Offshore Engineering Technology
31. Perdido - Cassion for separation is 350 feet long drilled into the seabed. Read OTC Paper 21716.
32. Barracuda - Ref. 2013 OTC Paper 24217 for additional information about the MPP.
33. Albacora Field - Ref. 2013 OTC Paper 24167
34. Highlander Field - SS Tieback to the Tartan Field which has a SS separator/slug catcher installed for the
tie-in to the Tartan Platform
35. Petrobras is changing ESP supplier from Baker Hughes to Schlumberger (REDA) in Q4 2014. REPRESENTATIVE SUBSEA POWER & PROCESSING TECHNOLOGY ATTRIBUTES (CURRENT AND UNDER DEVELOPMENT)
Table 4.8: Raw Seawater Injection Technology Filter, Treat, & Boost Raw Seawater Subsea for Injection
Attribute Installed or Qualified To be Qualified within 5 yrs.Water Depth 400 m (1,312 ft) 3,048 m (10,000 ft)
Shut-in Pressure Rating 5,000 psi (345 bar) 15,000 psi (1,035 bar)
System Flow Rate 88 MBOPD 150 MBOPD
Pump Differential Pressure (ea) 3,000 psi (205 bar) 4,500 psi (310 bar)
Unit Motor Power 2.5 MW 6.0 MW
Nominal Voltage 6.6 kV 6.6 kV
Water Quality 35-50 micron 5-10 micron
Key Elements in Current Development & Qualification Projects
Enhanced Inlet Water Conditioning & Treatment / Higher Current & Power Penetrator / Enhanced Motor and Pump Capabilities / Series Pumps for > Injection Pressure / Depth
Future Technology EnhancementsSalinity Reduction & Micro-Filtration (To Limit Reservoir Degradation Due to Injection) / Higher Power Rating & ∆P Capabilities / Enhanced Condition & Process Monitoring
Table 4.6: Power System Technology - Type 3 Extending Topside ASD Step Out by Increasing SS Umbilical Transmission Voltage (See Table 5 for Detail)
Attribute Installed or Qualified To be Qualified within 5 yrs.Water Depth 900 m (2.952 ft) 3,048 m (10,000 ft)
Tieback Distance 120 km (75 miles) 160 km (100 miles)
Power Rating 25 MW 70 MW
Distribution (Input) Voltage 145 kV 36 - 145 kV
Distribution Switchgear Voltage 36 kV 36 kV
Utilization (Output) Voltage 6.6 kV 6.6 kV
Key Elements in Current Development & Qualification Projects
Integration of Subsea Elements: Switchgear / ASD with Integral Transformer / Wet Mate Connectors + AC Umbilicals
Future Technology EnhancementsEnhancement for Power & Depth for HV Wet Mate Connectors / Power Distribution System Surveillance
Table 4.4: Power System Technology - Type 2 Extending Topside ASD Step Out By Increasing SS Umbilical Transmission Voltage (See Table 5 for Detail)
Attribute Installed or Qualified To be Qualified within 5 yrs.
Depth Classification Ultra Deep Water Shallow Water Ultra Deep Water
Water Depth 2,439 m (8,000 ft) 300 m / (984 ft) 3,048 m (10,000 ft)
Tieback Distance 21 km (13 miles) 43 km (29 miles) 60 km (37 miles)
Power Rating per Motor 3.0 MW 11.5 MW 12.5 MW
Primary Voltage 36 kV 36 kV 36 kV
Secondary Voltage 6.6 kV 6.6 kV 6.6 kV
Key Elements in Current Development & Qualification Projects
Transformer Marinization / High Resistance Grounding / Wet Mate Connectors for Combination of Deep Water & High Current / AC Umbilical
Future Technology EnhancementsHigher Power Rating & Robustness of Primary Side Wet Mate Connectors / Power Distribution System Surveillance
Table 4.2: Power System Technology - Type 1 Topside ASD with No Transformer to Subsea Motor (See Table 5 for Detail)
Attribute Installed or Qualified To be Qualified within 5 yrs.Water Depth 1,700 m (5,576 ft) 2,485 m (8,150 ft)
Tieback Distance 29 km (18 miles) 15 km / 9.3 miles)
Power Rating per Motor 2.3 MW 4 MW
Nominal Voltage 6.6 kV 6.6 kV
Key Elements in Current Development & Qualification Projects
Wet Mate Connectors / AC Umbilical
Future Technology Enhancements Power Distribution System Surveillance
Table 4.7: Three Phase Separation Technology Raw Wellstream, Gas or Oil Service
Attribute Installed or Qualified To be Qualified within 5 yrs.Water Depth 878 m (2,881 ft) 3,048 m (10,000 ft)
Shut-in Pressure Rating 5,000 psi (345 bar) 15,000 psi (1,035 bar)
System Capacity (Flow Rate) 20 MBOPD As Required for Duty
Target LVF in Gas at Outlet TBD < 2%
Target GVF in Oil or Water 10 - 15% < 10%
Outlet Oil in (Injection) Water TBD ppm TBD ppm
Booster Power (O/G/W) 1.9 MW As Required for Duty
Separation System Type Compact Separation - Modular
Key Elements in Current Development & Qualification Projects
Proven Separation Effectiveness of Raw Wellstream / Turn Down / Vessel Integrity / Control Logic with Pumps and / or Compressor / Real Time Process Monitoring
Future Technology EnhancementsWide Separator Operating Range and Separation Effectiveness Especially at Turn Down Rates / Enhanced Process and Booster Control Logic & Surveillance
Table 4.5: Two Phase Separation Technology Raw Wellstream, Gas / Liquid Separation With Liquid Boosting
Attribute Installed or Qualified To be Qualified within 5 yrs.Water Depth 2,439 m (7,999 ft) 3,048 m (10,000 ft)
Shut-in Pressure Rating 5,000 psi (345 bar) 15,000 psi (1,035 bar)
System Capacity (Flow Rate) 30 MBOPD As Required for Duty (See Table 4.3)
Boosting Differential Pressure 1,305 psi (90 bar) As Required for Duty (See Table 4.3)
Target GVF at Liquid Booster Inlet < 15% 10-15%
Unit Motor Power 1.1 MW As Required for Duty (See Table 4.3)
Separation System Type Compact Separation - Modular
Key Elements in Current Development & Qualification Projects
Proven Separation Effectiveness of Raw Wellstream / Turn Down / Vessel Integrity / Control Logic with Pump and / or Compressor / Robust Process Monitoring
Future Technology EnhancementsWide Separator Operating Range and Separation Effettiveness Especially at Turn Down Rates / Enhanced Process and Booster Control Logic Monitoring
Table 4.3: Subsea Boosting Technology Single Phase or Multi Phase Pump
Attribute Installed or Qualified To be Qualified within 5 yrs.
Pump Classification Single Phase Multi Phase Single Phase Multi Phase
Water Depth 2,439 m (8,000 ft) 1,350 m (4,428 ft) 3,048 m (10,000 ft) 3,048 m (10,000 ft)
Shut-in Pressure Rating 13,000 psi (897 bar) 5,000 psi (345 bar) 15,000 psi (1034 bar) 15,000 psi (1034 bar)
Pump Flow Rate (Nominal) 60,000 MBOPD 40,000 MBOPD 75,000 MBOPD 60,000 MBOPD
Differential Pressure (Nominal) 3,700 psi (225 bar) 1,885 psi (130 bar) 4,500 psi (310 bar) 2,320 psi (160 bar)
GVF Range at Inlet 10 - 15% 0 - 90% 10 - 15 % 0 - 90%
Unit Motor Power 3.0 MW 2.5 MW 5.0 - 6.0 MW 5.0 - 6.0 MW
Nominal Voltage 6.6 kV 6.6 kV 6.6 kV 6.6 kV
Key Elements in Current Development & Qualification Projects
Higher Power & Depth Rating of Penetrators & Wet Mates / 5-6 MW Motors / Permanent Magnet Motors / Alternate Barrier Fluid / 15 ksi Housings / High Rate & Head Multiphase Stages / Marinized Condition Monitoring Equipment / Higher Operating Speed
Future Technology EnhancementsHigher Power & Depth Rating of Penetrators & Wet Mates / Higher Motor Power / High Rate & Head Single Phase & Multiphase Stages / Enhanced Condition Monitoring Systems / >15 ksi System Rating
Table 4.1: Gas Compression Technology Liquid Tolerant Compression - Raw Wellstream, Wet Gas Service
Attribute Installed or Qualified To be Qualified within 5 yrs.Water Depth 914 m (3,000 ft) 1,024 m (5,000 ft)
Shut-in Pressure Rating 3,190 psi (220 bar) 7,500 psi (517 bar)
System Flow Rate 500 MMscf/d (14 Msm3/sd) 500 MMscf/d (14 Msm3/d)
Pressure Ratio 4 6
GVF at Inlet > 97 % < 95 %
Unit Motor Power 12.5 MW 12.5 MW
Nominal Voltage 6.6 kV 6.6 kV
Stage Type Liquid Tolerant Centrifugal
Key Elements in Current Development & Qualification Projects
Enhancing Liquid Tolerance & System Robustness for Raw Gas / Active Magnetic Bearing & Anti Surge Marinization / Increased Depth for Wet Mate Connectors / Pressure Ratio
Future Technology EnhancementsDepth and Power Capabilities of Power Penetrators & Wet Mates / Supporting Process System Simplification / Enhanced Condition Monitoring
COURTESY OF
COLOR CODEInstalled
Qualified
Manufactured
Proposed
1403OFFSubseaPoster_1 1 2/28/14 5:09 PM
B U S I N E S S B R I E F S
70 Offshore March 2014 • www.offshore-mag.com
PeopleElisse B. Walter, former chairman of the
US Securities and Exchange Commission, has been elected to Occidental Petroleum Corp.’s board of directors.
Nautronix has appointed Donald Thomson as vice president sales, commercial acoustics, and Bob Barrett as global sales manager – NASNet.
Glacier Energy Services has appointed Mike Straughen as a non-executive director.
EnQuest has appointed Neil McCulloch as president, North Sea.
Somesh Singh has joined Paradigm as chief product offcer.
ONGC has appointed Tapas Kumar Sen-
gupta as director (offshore).Ashtead Technology has
appointed Wendy Lee as regional general manager in Singapore and Paul Mor-
rison as key account manager in Aberdeen, UK.
Seatronics has promoted Phil Middleton to deputy managing director based in the Aberdeen offce.
STATS Group has promoted Dave Vernon to director of isolation services and promoted Dale Millward to director of emergency pipe-line repair systems and subsea services.
HB Rentals has named Kristian Magar as director of health, safety, and environ-ment.
LDD has appointed James
McGovan as vice president sales and marketing.
dGB Earth Sciences has appointed Arnaud
Huck as chief geoscientist and Nanne Hems-
tra as executive vice president for Brazil.Sparrows has appointed Stewart Mitchell
as CEO.iSURVEY Offshore Ltd. has appointed
Andrew McMurtrie as managing director.Aker Arctic Technology Inc. has elected
Ole Johansson as chairman of the board of directors and Juha Marjosola as vice-chair-man of the board. The company has appointed
Reko-Antti Suojanen as managing director.Bowtech Products Ltd. has appointed Colin
Main as sales manager - sub-sea connections.
Andrew Bridges has joined Enteq Upstream as head of engineering.
Aquatic Asia Pacifc Pte. Ltd. has appointed Nicholas
Dale as regional manager, Asia/Pacifc.
Kenneth A. Pontarelli and Peter R.
Coneway have resigned from Cobalt Interna-tional Energy’s board of directors.
WEG has appointed Andrew Glover as European and Middle East low voltage motors product manager.
Quickfange UK general manager Pamela Ogilvie has been elected to the board of directors of Decom North Sea. She is the frst female to be elected to the board.
Robert Conners has joined Prysmian Group as head of the subsea umbilicals, risers, and fowlines business unit.
Total has appointed Maarten Scholten as senior vice president, general coun-sel.
PMI Industries has promoted Jay Marino to laboratory manager.
Det norske oljeselskap has appointed Gro
G. Haatvedt as senior vice president explora-tion.
Tendeka has promoted An-
nabel Green to vice president of strategy and marketing.
Marathon Oil Corp. has elected Deanna L. Jones as vice president of human resources and administrative services.
Pulse Structural Monitoring has appointed Mike Campbell as operations director. Based in the UK, he will lead the pro-duction, project management, and offshore departments.
Markel International has promoted Li Shengnan to head the offshore energy team in Singapore, and has appointed Kelvin Lee as as-sistant manager, fnance and operations.
Andy Brown has taken medical leave. Maarten Wetselaar will serve as acting upstream international director, in addition to carrying out his regular duties as executive vice president integrated gas.
Company NewsGE Oil & Gas has agreed to acquire Cam-
eron’s Reciprocating Compression division for $550 million.
Aker Solutions has completed the sale of its mooring and loading systems business to Cargotec for an enterprise value of NOK 1.4 billion ($231 million).
Specialist recruitment agency for the oil and gas industry, Oil Consultants Ltd., has opened an offce in Dubai.
Artifcial Lift Co. has moved its headquar-ters from Great Yarmouth, UK, to Houston. Situated in the Westchase District near the
Energy Corridor, the company’s offces and warehouse total 28,000 sq ft (2,600 sq m) with 40 employees based at the location. The head-quarters consist of engineering, manufactur-ing, operations, and general support services.
SpeedCast has opened new facilities in Perth, Australia.
dGB Earth Sciences has opened an offce in Rio de Janeiro.
Newpark Resources Inc. has agreed to sell its Environmental Services business to ECOSERV, part of Lariat Partners, for $100 million.
Suretank has entered into a formal agree-ment with long-term Dutch partner Stain-
less Equipment Works to launch Suretank
Netherlands. The new partnership will act as an agent for Suretank providing engineer-ing and sales support to strengthen Sure-tank’s market position in the Dutch offshore industry.
Jacobs Engineering Group Inc. has acquired Eagleton Engineering.
Offshore marine and engineering consul-tancy Aqualis Offshore has opened an offce in Bahrain.
Great Yarmouth, UK-based Sonar Equip-
ment Services has changed its name to Subsea Technology & Rentals.
Fendercare Marine Middle East has opened new premises in Sharjah, UAE. The new base will provide products including fendering, buoyancy, mooring, quayside and deck equipment, and a new range of lifting and testing services, diving and ROV, single-point mooring maintenance, and hose testing.
The University of Texas at Austin De-
partment of Petroleum and Geosystems
Engineering has opened three new state-of-the-art laboratories that will advance energy research and transform how students learn about drilling for oil and gas. The three labs include the Real-time Operations Center, the Drilling Automation Lab, and the Zonal Isola-tion Lab. Baker Hughes donated $1.7 million to the university.
2H Offshore has opened a newly refur-bished 16,547-sq ft (1,537-sq m) offce in Woking, Surrey.
Atlas Copco Air & Gas Purifcation has inaugurated its new production facility in Oosterhout, the Netherlands. The facility will provide custom engineered solutions for air and gas purifcation systems and biogas upgrading.
MicroSeismic has purchased the US assets of Reservoir Imaging Inc. The acquisition includes geospace equipment, wireline units, and equipment for downhole microseismic data acquisition services.
Prysmian Group has established a new headquarters in Houston for its subsea umbili-cals, risers, and fowlines business.
EV has opened an offce in Perth, Australia.
Lee
Glover
Ogilvie
Green
Shengnan
Magar
Bridges
1403OFF_70 70 2/28/14 5:02 PM
PENNWELL PETROLEUM GROUP1455 West Loop South, Suite 400, Houston, TX 77027
PHONE +1 713 621 9720 • FAX +1 713 963 6228David Davis (Worldwide Sales Manager)
[email protected] Cohen (Regional Sales Manager)
[email protected] Jordan (Classified Sales) [email protected]
GREATER HOUSTON AREA, TXDavid Davis [email protected]
USA • CANADA
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Viale Monza, 24 - 20127 Milano, ItalyPHONE +39 (02) 28 46716 • FAX +39 (02) 28 93849
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Smartpublishing Ltd/ OGJLA Pennwell BrazilHEADQUARTERS: Rua Raimundo Chaves 2182, L5
Natal RN 59064-390, BRAZILRIO OFFICE: Ave. Erasmo Braga 227, 11th foor
Rio de Janeiro RJ 20024-900, BRAZILPHONE +55 (21) 2533 5703 or +55 (21) 3084 5384
FAX +55 (21) 2533 4593Jean-Paul Prates [email protected]
JAPANICS Convention Design, Inc.
6F Chiyoda Bldg., 1-5-18 Sarugakucho Chiyoda-Ku, Tokyo 101-8449, Japan
PHONE +81 3 3219 3641 • FAX +81 3 3219 3628Manami Konishi [email protected]
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Interads Ltd., A-113, Shivalik, New Delhi 110 017 PHONE +91 11 628 3018 • FAX +91 11 622 8928
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Flat 8, 3rd foor (Oluwatobi House) 71 Allen Ave, Ikeja, Lagos, Nigeria
PHONE +234 805 687 2630 or +234 802 223 2864 Dele Olaoye [email protected]
SALES OFFICESA
Aker Solutions ...................................... 11www.akersolutions.com
ASME / UH Crawfish Boil .....................46
B
Baker Hughes ...................................... C2www.bakerhughes.com
Bentley Systems ...................................65www.bentley.com
Bluebeam Software, Inc. ........................7www.bluebeam.com
Bredero Shaw ..........................................9brederoshaw.com
Brunswick Commercial &Government Products ..........................44
brunswickcgp.com
C
Cameron ................................................ 13www.c-a-m.com
CGG Services US, Inc. .........................31www.cgg.com
CUDD Energy Services .................. 10, 23www.cudd.com
D
Deep Down, Inc. ......................................6www.deepdowninc.com
Dräeger ..................................................59www.draeger.com
Dril-Quip ..................................................1www.dril-quip.com
E
Elettrotek Kabel S.p.A. .........................47www.elettrotekkabel.com
F
FMC Technologies ............................... C4www.fmctechnologies.com
I
INTECSEA .............................................61www.intecsea.com
IPLOCA ..................................................34www.iploca.com
J
JD Neuhaus Group ...............................29www.jdngroup.com
K
Karmsund Maritime Offshore Supply ....................................................16
www.kamos.no
KBC Advanced Technologies ..............69www.kbcat.com
Kobelco / Kobe Steel, Ltd. ....................43www.kobelcocompressors.com
L
Lincoln Electric .....................................35www.lincolnelectric.com
M
M-I SWACO ..............................................3www.miswaco.com
Magnetrol ..............................................49www.magnetrol.com
N
National Oilwell Varco. ..........................27www.nov.com
Nylacast. ................................................ 18www.nylacast.com
O
Oceanic Marine Contractors ................ 15www.oceanicmc.com
OneSubsea ............................................25www.onesubsea.com
P
PennWell
Deep Offshore Technology Conference & Exhibition .................33
www.deepoffshoretechnology.com
Offshore Group .......................... 36-37www.offshore-mag.com
PNEC Conferences ..........................17www.pnecconferences.com
PH Industrie-Hydraulik Gmbh & Co. KG..................................... 19
www.ph-hydraulik.dePolarcus .................................................63
www.polarcus.com
S
S. Himmelstein and Company .............41www.himmelstein.com
SERCEL .................................................51www.sercel.com
Spectrum GEO, Inc. ..............................39www.spectrumasa.com
Supreme Services ................................40www.supremeservices.com
T
T.D. Williamson, Inc. ............................. C3www.tdwilliamson.com
TOTAL SA ..............................................21www.total.com
V
Van Oord Offshore B.V. ........................45www.vanoord.com
W
W&O Supply ..........................................41wosupply.com
Weatherford .............................................5weatherford.com
The index of page numbers is provided as a service. The publisher does not assume any liability for error or omission.
ADVERTISERS INDEX
1403OFF_rev_71 71 3/5/14 9:09 AM
This page refects 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].
72 Offshore March 2014 • www.offshore-mag.com
B E Y O N D T H E H O R I Z O N
Who are the natural owners of maturing offshore assets in the UK North Sea? It has become an increasingly pertinent question, and one that is central to helping to create a sustainable, long-term future for the province.
One of the characteristics of a maturing basin is that the chal-lenges get bigger while the prizes become smaller. The last barrel of oil is the hardest to produce. It therefore takes a huge amount of focus, energy, commitment, vision, and technical expertise to suc-cessfully manage maturing assets.
The largest operators certainly possess those qualities but it can be diffcult for late-life assets to compete for these companies’ re-sources with many other opportunities elsewhere on the agenda. A vicious circle can develop as neglect of the facilities increasingly diminishes prospects of attracting the fresh investment that they need.
When considering “natural” ownership, materiality is the key. If an asset is material to the owner it will receive maximum attention, creating a virtuous circle of investment and prolonged production life.
Thistle, northeast of the Shetland Islands, is a textbook case of the virtuous circle in action. The feld was frst developed in the 1970s, but by 2009 was struggling to produce 2,000 b/d. The turnaround program that followed under new ownership paid huge dividends. By last summer, it was recording the highest production levels since the 1990s.
If EnQuest had done nothing with Thistle after acquiring it in 2010 -- when the infrastructure was aging to the point where produc-tion may have stopped -- it would potentially have been abandoned by now. It is a similar story for some of the company’s other assets in the region such as Heather and the Dons felds.
Reinstating the platform rig allowed EnQuest to drill the feld’s frst new wells in 20 years. Furthermore, a series of modifcations and upgrades as part of the company’s Late Life Extension project will secure the future of the Thistle platform to 2025 and beyond.
The UK government’s brownfeld tax allowance, one of a series of new measures designed to stimulate North Sea investment, has helped the company to execute this program, in the process real-izing reserves of 35 MMboe. The goals include simplifying and
streamlining the Thistle process to create a safe and reliable pro-duction environment. The project calls for a major power upgrade featuring the installation of a 30-MW power generation turbine, a new process control safety system, and topsides integrity work to ensure the platform’s long-term future.
There are tremendous opportunities in the North Sea but the as-sets must be in the hands of the right companies with the capability and the determination to invest time, effort, and money to make the most of these prospects.
As Sir Ian Wood, who recently led a major independent review of the UK North Sea oil and gas industry, pointed out, UK production could increase substantially over the coming years if major changes are made to how the oil and gas sector operates. If these changes are not made, he warned, Britain could fail to recover even a fraction of the remaining oil and miss out on a £200-billion ($333-billion) injec-tion to the economy.
EnQuest’s approach to maximizing oil recovery from mature as-sets was underpinned by a recent report by Oil & Gas UK’s produc-tion effciency taskforce. The report showed that during 2010-2012, the company’s operations exceeded the taskforce’s ambitious target of 80% production effciency and that last year, it had moved into the top quartile of production effciency performance of all companies on the UK continental shelf.
The North Sea will continue to witness a strategic trend of matur-ing assets moving from the global major operators to independents. This process is also evident in more mature provinces such as on-shore US, where more and more assets are in the hands of smaller companies.
This shift is a natural progression - to use a wildlife analogy, a lion may make the kill and eat its fll, but there is still a viable meal there for others. It is essential, however, that current owners do not run maturing assets into the ground before moving them on. The in-dustry has to have a regulatory framework that protects assets and helps them move into the hands of companies that are committed to investing in maximizing recovery.
John Cowie
Area Manager-Northern North SeaEnQuest
New life for North Sea fields under new management
1403OFF_72 72 2/28/14 5:02 PM
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1403OFF_C4 4 2/28/14 5:03 PM
Energy AbundanceSecuring Australia’s
petroleum resources
SUPPLEMENT TO
®
140303OGJBHP_C1 1 2/14/14 3:12 PM
Contents
2 Home Team Advantage
4 Macedon
8 Good Neighbors
13 The North West Cape
17 Minerva
18 Other Joint Ventures
20 Just Ahead
22 Company Profiles
Energy Abundance
Securing Australia’s
petroleum resources
140303OGJBHP_C2 2 2/14/14 3:12 PM
“ Australia has the enviable position of being self-suffcient in natural gas as well as being a signifcant oil producer, and BHP Billiton has played a major part in making it so. Our goal now is to wisely steward Australia’s rich petroleum reserves, to develop the country’s energy potential well into the future.”
TIM CUTT
PRESIDENT, PETROLEUM AND POTASH
BHP BILLITON
140303OGJBHP_1 1 2/14/14 3:12 PM
BHP Billiton | Energy Abundance2
Home Team AdvantageBHP Billiton is Australia’s largest producer of oil, and the nation’s main provider of natural gas for domestic use.
BHP Billiton owns or operates major oil and gas projects on fve
continents. Within the company—long known for its strength in the
minerals mining sector—Petroleum now delivers about one third of
BHP Billiton’s annual income. Australia accounted for 60 percent of
the company’s total oil and gas production in 2013. That same year,
the Energy Intelligence Group ranked BHP Billiton among the world’s
largest private-sector petroleum companies.
At home, BHP Billiton is Australia’s largest producer of oil, and
the nation’s main provider of natural gas for domestic use.
Through projects such as the US$1.5 billion Macedon domestic gas
development, facility expansions in Bass Strait and the North West
Shelf, and exploration offshore Western Australia, the company will
continue to deliver reliable, affordable and sustainable energy for
decades to come.
Aussie Oil
Oil was produced for the frst time in Australia in 1869, but for the
next 96 years, no one found enough of it to develop a signifcant
petroleum industry. As the global reliance on oil continued to rise
in the frst half of the 20th century, Australia’s economy suffered
for the lack of it. In the early days, most of the country’s refned
products came from the United States, but when the Suez Canal
crisis erupted in 1956 and dragged into 1957, refned products
became even harder to get.
Although BHP had a sprinkling of oil and gas wells in Australia,
the portfolio was not a signifcant part of the mining company’s
business. The Petroleum side of BHP Billiton was founded in 1961
as BHP Petroleum. Its urgent mission was to explore for and develop
domestic petroleum.
The Petroleum side of BHP Billiton was founded in 1961 as BHP Petroleum. Its urgent mission was to explore for and develop domestic petroleum.
RIGHT: Todd Lee, general manager of the Australia Production
Unit for BHP Billiton Petroleum.
140303OGJBHP_2 2 2/14/14 3:12 PM
BHP Billiton | Energy Abundance 3
BHP’s petroleum business took off in 1965 with the frst oil discovery
drilled in Bass Strait. It was a career milestone for the American
geologist Lewis Weeks and the famboyant Australian geology
professor Samuel Carey, who collaborated with Weeks on the fnd.
Far beyond that, fnding oil and gas in Bass Strait was a turning
point for Australia’s economy.
“That 1965 discovery off the Gippsland coast created a critical
mass for Australia’s oil industry,” says Todd Lee, general manager,
Australia, for BHP Billiton Petroleum.
By 1967, a quick succession of discoveries by BHP and its venture
partner, Esso Australia, had identifed enough crude in Bass Strait
to make the country 70 percent self-suffcient in oil. Recovering
it pushed the limits of existing offshore technology, yet drilling
continued. The pace of innovation increased dramatically, laying the
foundation for Australia’s modern petroleum industry.
“BHP Petroleum was the frst to deploy a foating production,
storage and offoading vessel (FPSO) in Australia,” Lee says.
“We introduced FPSO technology in the Timor Sea, and that
experience shows. Today, many operators use them, and
BHP Billiton’s record run-times for its FPSOs leads the industry.”
The second big boost to Australia’s energy future was a series of
offshore discoveries in what became known as the North West Shelf
(NWS), Australia’s largest oil and gas development. BHP Petroleum’s
involvement in the NWS began in 1976. Since NWS exploration
began, the venture partners have spent more than US$27 billion on
offshore platforms, subsea wells, pipelines and onshore processing
facilities. Exploration and development continues to extend the lives
of the felds.
With Room to Grow
The Brookfeld Place offce building in Perth is the headquarters for
BHP Billiton Petroleum in Australia, and the global headquarters for
BHP Billiton’s Iron Ore business. It houses almost 3,500 employees.
The billion-dollar multiplex, completed in 2012, earned Green Star’s
rare 6-star rating for energy effciency and sustainable design.
Green Star is a voluntary rating system to evaluate the design and
construction of new buildings. The Perth offce is the nerve center
for the company’s Macedon, Pyrenees, Stybarrow, Minerva, NWS
and Bass Strait projects featured in the following pages.
ABOVE: BHP Billiton Petroleum operates or is a partner in all of Australia’s major oil and gas regions.
1 Macedon (71.43%) A domestic gas development with a stand-alone gas plant. First production achieved in August 2013.
2 Pyrenees Venture (40–71.4%) An FPSO facility producing oil from the Crosby, Stickle and Ravenworth felds.
3 Stybarrow Venture (50%) An FPSO facility producing oil from the
Stybarrow and Eskdale felds.
4 Minerva (90%) An offshore gas feld and onshore plant producing gas and condensate.
5 North West Shelf (8.3–16.7%) Supplies oil and gas to Australian and international markets.
6 Bass Strait (50%) 20 producing oil and gas felds with 21 offshore structures.
3
2 1
4
5
6
140303OGJBHP_3 3 2/14/14 3:12 PM
BHP Billiton | Energy Abundance4
Macedon“…the economics of the project were tight. We knew that if we didn’t develop it then, we might not do it at all.”
At the beginning of 2008, Macedon was still working its way up
BHP Billiton’s queue of potential developments, but it was not yet
the highest priority. Gas from the Macedon feld was of slightly
lower heating value than was approved for sale on the open market.
Upgrading the gas, while technically possible, would have cost more
than the gas was worth. Instead, Macedon’s production could simply
be added to the higher quality gas already in the pipeline, so that
the blended mix would still meet specifcations. One delay was the
legal limit on the amount of broad specifcation gas that could be
put into the state’s main pipeline system. Lawmakers feared that an
inadvertent slug of lower quality gas could cause older appliances
such as home water heaters and stoves to malfunction.
Things changed suddenly in 2008 when a serious industrial accident
and subsequent emergency legislation pushed the Macedon project
to the head of the line. In early June of that year, an aging methane
pipeline ruptured on Varanus Island. No one was injured, but
the resulting explosion and fre knocked out nearly 35 percent of
Western Australia’s supply of natural gas. Within days, businesses
were curtailing operations or closing altogether. Ministers pleaded
with citizens to voluntarily conserve power to avoid mandatory cuts.
They did, but for a time the Perth skyline went dark.
“The incident highlighted the need for a more secure supply of
domestic natural gas,” said Garry Walker, Macedon project director,
who led the Macedon development project through the summer of
2013. “We were already working with regulators to convince them
to blend the broad specifcation gas, because upgrading it frst
would be too expensive. They quickly passed new laws to allow it,
and that meant we could proceed. It was a key piece of legislation.
“We made a 130 million-dollar commitment prior to sanctioning,”
Walker explained. “That was quite unusual, but we had to move
quickly. We had a rig available from the Pyrenees project, so
we extended the contract and moved that rig into the Macedon
feld, which saved a lot of time and money in the long run. That
was important because the economics of the project were tight.
We knew that if we didn’t develop it then, we might not do it at all.”
The Appliance Replacement Program
The legislative green light to sell gas from the Macedon feld was
welcome, but it was not the only hurdle. There was still the question
of what to do about older home appliances that might not be
able to handle it. The most direct solution—approved by Western
ABOVE: Garry Walker, Macedon project director.
140303OGJBHP_4 4 2/14/14 3:13 PM
BHP Billiton | Energy Abundance 5
Australia’s Offce of Energy Safety—was to test and certify or
replace all home gas appliances made before 1980.
“We spent more than US$22 million in about 18 months,” said
Catherine Leong, who led the Gas Appliance Rectifcation Program
for BHP Billiton. “There was a massive advertising campaign to
reach anyone with older appliances. By January 1, 2012, we had
tested more than 24,000 water heaters, stoves and home heaters
to make sure they could operate safely using gas with the revised
specifcation. Any appliance that did not meet those requirements
was replaced at our expense. One of the oldest was a water heater
made in 1937.”
As a bonus, the inspection process revealed many leaks and other
safety hazards that homeowners might might not have otherwise
been aware of. Ken Bowron, director of Energy Safety for Western ABOVE: Catherine Leong led the Gas Appliance Rectifcation
Program for the Macedon project.
ABOVE: The Macedon plant provides about 20 percent of Western Australia’s domestic gas.
140303OGJBHP_5 5 2/14/14 3:13 PM
BHP Billiton | Energy Abundance6
Australia, commented on that in the Department of Commerce
Energy Bulletin in July, 2013.
“A major success of the program has been an increase in the safety
of the older gas installations and the replacement of a number
of domestic gas appliances that were converted from town gas
to natural gas in the early 1970s,” Bowron said. “The safety
inspections undertaken as part of the program found a number of
old unvented gas water heaters installed in bathrooms, despite them
being banned in the early 1990s.”
Moving on
The Macedon feld development includes four subsea wells
connected to the onshore gas treatment plant by a 90-kilometer
(65-mile) 20-inch wet gas pipeline.
Chemical and electrical umbilical lines are used to control and
monitor the subsea wells. BHP Billiton, with 71.48 percent of
the project, is the operator. Apache Corporation is the joint-
venture partner.
The Macedon gas plant is located at Ashburton North, about
17 kilometers (10.5 miles) southwest of Onslow. At the Macedon
gas plant, which can handle up to 200 million scf per day, the small
quantity of liquids are removed and the gas is compressed. The dry
gas is exported from Macedon through a 67-kilometer (42-mile)
20-inch pipeline that ties into the Dampier to Bunbury trunk line,
which supplies most of Western Australia’s natural gas.
Both offshore drilling and onshore construction began in 2010.
Over the next two years, the project employed more than
600 workers—about 10 percent of them from the indigenous
community—and pumped more than $865 million into the economy
of Western Australia.
The State’s Strategic Plan
The Macedon domestic gas plant is the frst in what the government
of Western Australia has designated as the Ashburton North Strategic
Industrial Area (ANSIA). The long-term goal is to attract heavy
industries to build there, and to provide the land and infrastructure
to support them.
ABOVE: Steve Pastor (left), BHP Billiton Petroleum asset president for the conventional business and Colin Barnett, premier of Western
Australia, at the offcial opening of the Macedon plant in September 2013.
140303OGJBHP_6 6 2/14/14 3:13 PM
BHP Billiton | Energy Abundance 7
The initial state plan, approved in 2011, includes two main access
and utility corridors to facilitate construction of new plants and
access to the planned port. After Macedon, Chevron became the
second tenant of the ANSIA when it began building its Wheatstone
LNG plant, which is scheduled for startup in 2016.
“The frst year’s activity was very much about building
infrastructure,” says Steve Jeffcote, Health, Safety and
Environmental supervisor for the Macedon project. “Onslow is a
town of about 600 people and the area is remote, so there was
very little to support industrial development.”
Not Without Challenges
The land set aside for the industrial zone is fat and near the ocean,
so anyone building in the area must plan for potential storm surges
from the sea, and the area’s sudden, torrential rains.
“We did the overall food modeling and looked at what we’d need
as a minimum elevation,” says Dene Kuenen, Macedon project
supervisor. “Then we decided that as an extra margin of safety,
we would build the plant and construction camp 7.5 meters (25 feet)
above the mean sea level.”
Crews began moving dirt, building roads and laying out the
construction camp in 2011. One of the frst tasks was to drill a water
well, but even that was not routine. Much of the effort was ensuring
that the well was safe.
“The old Tubridgi gas feld is nearby,” Jeffcote explains. “Since we
were drilling deeper than normal to reach water, we knew there was
a chance that the water might contain traces of natural gas. To be
absolutely safe, we took the precaution of using a blowout preventer
on the water bore, and that was an extraordinary measure.”
The frst of nearly 40 equipment modules built in Thailand began
arriving at the port in Dampier in 2012. From there, the modules
were trucked the fnal 300 kilometers (186 miles) to the Macedon
plant. The main limitations were the overall weight the bridges could
handle safely, and the height of power lines across the roads.
Eventually, the onshore workforce building the plant grew to a
peak of more than 600. By the time Macedon went on stream in
September, 2013, crews had logged more than 5.8 million man-
hours. The US$1.5 billion project was delivered on time, on budget,
and with just one lost-time injury. That was enough to win the
2013 Western Australia Gas Industry Development Award for
contributions to the domestic natural gas industry.
“It is a steady, secure supply of gas,” Walker adds. “The Macedon
project will continue to make a signifcant contribution to the
security of the state’s domestic gas supply through at least 2033.”
The Macedon project will continue to make a signifcant contribution to the security of the state’s domestic gas supply through at least 2033. ABOVE: Dene Kuenen, engineering delivery supervisor.
140303OGJBHP_7 7 2/14/14 3:13 PM
BHP Billiton | Energy Abundance8
Good Neighbors“ The benefts will last well beyond
the length of our project.”
Long before the heavy equipment arrived to clear land for the
pipeline and the Macedon plant, Angelo Mustica, senior commercial
advisor, began working with local residents to let them know what
was planned and what to expect.
Preserving Heritage Sites
Several Aboriginal groups live in the Pilbara region, but by law the
Thalanyji people have the strongest ancestral ties to land around
Onslow. Those who were most familiar with the heritage were hired
to assist as project monitors.
“Our initial meeting with Thalanyji representatives about Macedon
was in June, 2008,” Mustica recalls, “but we already had a long
relationship with them because of our earlier involvement with
the Griffn feld and Tubridgi gas plant. Shortly after, we made a
presentation to a larger group, including four of the elders.”
Much of the discussions were about long-term opportunities
for Thalanyji youth and projects to preserve the group’s
cultural heritage.
“We settled on a number of projects that we would sponsor under the
native title agreement,” Mustica says. “We also established a business
incubation fund that will be available for the next 20 years.”
Some of the earliest involvement was a Thalanyji joint-venture with
an established catering frm to provide services to Macedon and
other industrial sites planned for the area. “It was a win-win for all
parties,” Mustica says. “The benefts will last well beyond the length
of our project.”
Another initiative is the company’s continuing support of the
David Wirrpanda Foundation. “David was a popular footballer
here in Western Australia,” says Bindi Gove, Government and
External Affairs manager for Australia. “His foundation has a
strong reputation for encouraging indigenous kids to continue their
education. The foundation’s work begins with the primary schools,
providing incentives for students to learn and for their parents to
participate in the process.”
BHP Billiton is helping the larger community as well, including
plans to build a new basketball facility in town. The company
already sponsors regular youth basketball tournaments that bring in
hundreds of players and fans.
“We’re committed to our relationship with the community,” Gove
says. “We’ve been here in Onslow for quite a while, and we’ll be
here for at least another 20 years. It is essential for our operations
that we are accepted in town, and we want the community to be on
board with everything we do.
“The company has treated Onslow like it has all communities,”
Gove adds. “Whether we’re building in Onslow, or building in
a highly urbanized and environmentally sensitive area like Port ABOVE: Angelo Mustica, senior commercial advisor.
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BHP Billiton | Energy Abundance 9
Campbell, Victoria, BHP Billiton recognizes the intrinsic value of the
land and takes the same care with it as the people who live there.”
BHP Billiton has been part of the Onslow community for
over 20 years. Since 2007, the company has invested more
than AUD$5.5 million in the township to improve the lives of
Onslow’s citizens.
“The way we do things in Onslow is a function of how this company
operates elsewhere in the world,” says Michiel Van Akkooi, senior
manager, International Government and External Affairs.
“BHP Billiton’s way of working with its neighbors is quite different
from many other companies.”
Honoring their ancestors
In 2007, BHP Billiton was the frst company to
launch the Reconciliation Action Plan, which seeks
to strengthen relationships with Australia’s various
Aboriginal groups. The goal is to provide work and
business opportunities for local indigenous people,
while respecting their rich cultural heritage.
For the Macedon project, Thalanyji monitors worked
with project planners to identify numerous cultural
heritage sites. Especially sensitive areas were avoided
altogether. Awareness training—also conducted with
the help of Thalanyji monitors—acquainted every
BHP Billiton employee and contractor who was working
on the project with the local cultural history.
ABOVE: Claire Hall with one of many local children who take
part in the community events she organizes.
We’re committed to our relationship with the community. We’ve been here in Onslow for quite a while, and we’ll be here for at least another 20 years.
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BHP Billiton | Energy Abundance10
Turtle Monitoring
Most visitors to Onslow never see a live cowrie, but the marine
turtles that lay their eggs at Urala Beach are hard to miss. These
dinosaur descendants are the size of a dinner table, and they weigh
more than 300 pounds. The tracks they leave in the sand make it
look like a tractor has just gone by.
Sea turtles mate offshore, and up to seven times a season, females
cross the beach to lay their eggs and bury them in the sand. When
the eggs hatch seven weeks later, hundreds of palm-sized baby
turtles dig their way out and scramble to the sea.
The female turtles lay clutches of more than 100 eggs, but many are
found and eaten by predators before they hatch. Hatchlings lucky
enough to survive beyond birth may be gobbled by other predators
waiting for them offshore. That, plus a loss of natural habitat,
are the reasons sea turtle populations are declining worldwide.
It’s also why the life cycle of the turtles affected the timing of the
Macedon plant.
“The turtle season runs from the frst of November through the end
of April,” says HSE supervisor Steve Jeffcote. “That coincided with
the time we were preparing to bring our pipeline ashore.”
In this case, the shore crossing meant that a trench had to be dug
for the pipeline, and the beach restored to its natural state once the
line was in place.
“We decided on a shore crossing point that was likely to have the
fewest number of turtles trying to lay their eggs,” Jeffcote says.
“We knew there would be fewer turtles because there were much
better nesting sites up and down the beach.”
But, as Jeffcote explained, few is not the same as none.
“We established a 200-meter protected area on either side of the
pipeline trench. During the breeding season, we monitored the
area 24 hours a day and clearly marked any new nests. Not a single
turtle egg was lost due to our activities, and now, when you visit the
place where our pipeline crosses the shore, you wouldn’t even know
we were there.”
Even the Macedon plant’s fare system was designed with the turtles
in mind. Instead of a fame at the top of a tall tower, Macedon’s
ground-level fare cannot be seen from the beach.
Cowrie Care
The name “cowrie” applies to a wide range
of egg-shaped sea snails with exceptionally
beautiful shells. For at least 3,000 years—
probably much longer— cowrie shells have
been used as currency, employed as tools,
prized as decoration, worn as jewelry—and
fought over in games of chance. They just feel
good in your hand. Some cowries are quite rare,
and it turns out that one such species lived
right in the underwater path of the proposed
Macedon pipeline.
“There are a series of low, pristine islands
between the beach and our subsea wells,” says
HSE supervisor Steve Jeffcote, “They’re home
to a variety of animals we knew about, but
not this rare snail. The state had just approved
the environmental plan for the offshore
portion of our pipeline when we learned
about the cowries. Shifting gears at that point
required several kilometers more pipe and an
extra six months, but we applied for a new
permit and routed our line well away from
the cowrie beds.”
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BHP Billiton | Energy Abundance 11
ABOVE: Hidden beneath the sands of Western Australia beaches are the nests of marine turtles, each holding clutches of up to 120 eggs.
RIGHT: During construction of the Macedon pipeline, senior
environmental specialist Andrew McTaggart and his team
monitored turtle nesting sites along the beach to make sure that
none of them were disturbed.
Of the seven species of marine turtles in the world, six can be found off the coast of Australia. Each year, hundreds of them—mostly greens and leatherbacks—lay their eggs on Urala beach, not far from the Macedon plant.
140303OGJBHP_11 11 2/14/14 3:13 PM
The FPSO Pyrenees Venture can
process up to 100,000 barrels of
liquids per day, with an onboard
storage capacity of around
900,000 barrels.
140303OGJBHP_12 12 2/14/14 3:13 PM
If oil and gas development in Western Australia were a baseball game, the Pyrenees and Stybarrow felds have been home runs.
As their reservoirs mature, the twin offshore
developments continue to be star players.
Now, exploration and planned drilling campaigns
in both felds could extend their careers for at least
another decade.
The North West Cape
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BHP Billiton | Energy Abundance14
Pyrenees
The Pyrenees feld is located in water depths as much as 820
meters (2,690 feet) deep off the North West Cape of Australia,
some 25 kilometers (15 miles) from Exmouth. It is a US$1.7 billion
joint venture between the operator, BHP Billiton (71.43 percent),
and Apache Energy (28.57 percent). Discovered in 2003, the
project began production ahead of schedule in 2010. In its frst
year, Pyrenees delivered the energy equivalent of more than 30
million barrels of oil. The production system is a foating production,
storage, and offoading vessel, (FPSO), called the Pyrenees Venture.
“Soon after Pyrenees came on line, it was making more than 100,000
barrels of oil per day,” says feld manager Mark Thomson. “That’s one
tanker cargo every six days.”
The initial development plan included 13 horizontal oil wells
producing from the Crosby, Stickle and Ravensworth reservoirs.
A planned expansion of Pyrenees includes six new wells that should
be completed by early 2014. Production from the three reservoirs
could extend the life of the feld beyond 2035.
“ In the near term, drilling at Pyrenees and Stybarrow will make up for the natural decline in production from existing wells,” says feld manager Mark Thomson.
ABOVE: Operations supervisor Spencer Black (left), production operation technician Dwight McMasters (center) and maintenance
supervisor Kevin Scarterfeld (right) discuss operations in the Stybarrow FPSO’s Central Control Room.
ABOVE: Mark Thomson, feld manager.
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BHP Billiton | Energy Abundance 15
Stybarrow
Discovered in 2003, the Stybarrow development is a 50/50 joint
venture between the operator, BHP Billiton, and Woodside Energy.
The oil and gas feld is located some 65 kilometers (40 miles)
northwest of Exmouth in about 825 meters (2,707 feet) of water.
It is one of Australia’s deepest offshore felds.
Stybarrow’s 10 subsea well completions include six producing wells,
three water injectors and one gas injector. The $760 million project,
also includes the Stybarrow Venture FPSO, which can process up to
80,000 barrels of oil per day and 45 million scf of gas. The vessel
itself can store 900,000 barrels of oil.
Reliable Performance
Both the Pyrenees and Stybarrow developments are known for their
industry-leading run-times—the number of days each year that the
facilities are producing oil, rather than shut down for repairs.
“In 2012, Pyrenees had by far the best up-time in the region,”
Thomson says, “and Stybarrow was not far behind. If you take out
the eight or nine days we lost due to cyclones, our facilities were
operating about 97 percent of the time.”
Thomson credits at least part of good operational performance to
the skill of BHP Billiton engineers.
“In December 2012, a routine underwater inspection of the
Pyrenees Venture found hairline cracks in the outer shell of the double
hull.” he says. “The initial response from the maritime authorities
was that we had to take the vessel straight to dry dock to get it fxed.
That would have caused long delays and lost production. As there was
no environmental risk, our engineers designed braces that could be
welded on to secure the hull and give us more time.”
Production continued for the next six months aboard the FPSO
while divers worked on the hull. When the FPSO left for dry dock in
October, 2013, it was a scheduled event, rather than a hasty retreat.
There was a clear engineering plan for making the repairs quickly
and a budget in place to cover them. The extra ten months that the
Pyrenees Venture remained in the feld allowed marketers to reallocate
shipments of crude oil to customers, and to minimize the overall loss
of revenue. Thomson estimates that the additional time the FPSO
stayed on site amounted to at least a million barrels of production.
“Pyrenees and Stybarrow have each produced more than
50 million barrels of oil,” Thomson adds. “In terms of proftability,
reliability and cash fow, oil and gas developments don’t get much
better than this.” ABOVE: Pyrenees and Stybarrow have the best up-time
operating records of any FPSOs in the region.
140303OGJBHP_15 15 2/14/14 3:13 PM
BHP Billiton | Energy Abundance16
Wave-cut limestone towers known
as the Twelve Apostles mark the
southern boundary of the Port Campbell
National Park.
Photo ©iStock.com
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BHP Billiton | Energy Abundance 17
MinervaOut of sight in one of Australia’s most popular tourist spots
The most noteworthy thing about the Minerva gas development
is what you don’t see. When onshore work began in 2003, the
planners were especially careful to ensure this was the case. The
area is one of Victoria’s premier tourist attractions, and their goal
was to keep it that way.
Minerva’s two wells, for example, are subsea completions in 60
meters (200 feet) of water, about 11 kilometers (seven miles) south-
southwest of the township of Port Campbell in Western Victoria.
The production pipeline comes ashore under the beach at Two Mile
Bay. From there, the buried line brings the wet gas another 4.5
kilometers (2.8 miles) inland, where it is processed at the Minerva
gas plant. Most of the plant’s equipment is painted green, with
shrubs and trees planted around the site to hide it from view.
The Minerva development is a joint venture between BHP Billiton
(90 percent) and Santos (10 percent). It is the second of two gas
plants that BHP Billiton operates in Australia. Minerva can produce
up to 150 terajoules of natural gas and 600 barrels of condensate
per day for customers in South Australia and Victoria.
“One hallmark of Minerva was the lengthy approval process to build
it,” says Ian Sinclair, feld manager for onshore gas processing. “A
national park runs along the beach and extends at least a kilometer
inland in most places.”
Tiny fairy penguins stroll the beach, while giant limestone stacks—
some the height of 12-story buildings—enhance the view from
the Great Ocean Road. Just outside the park boundaries, pristine
homesteads support families, crops and livestock. The area has
a rich Aboriginal heritage as well. All of that remained largely
undisturbed as the plant and pipeline were being built.
“The environmental approvals were very stringent in terms of noise,
emissions and runoff from the site,” Sinclair explains. “There were
restrictions on when we could run vehicles in and out of the plant.
We were not allowed to operate trucks on the weekends or public
holidays, and when we were on the road, there were designated
routes. The facility itself is very low profle, and our ground level
fare is completely enclosed. We reuse most of our water to irrigate
the trees on our site, and we even supply some of our extra water to
a farmer nearby.”
Although Minerva is relatively small, it has contributed a dependable
supply of natural gas to the region for more than a decade. It will
continue to do so for several more years, allowing time for other
development projects to take its place.
ABOVE: Little penguins—also known as Fairy penguins and Little
Blues—thrive along Australia’s southern beaches and bays.
Ph
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140303OGJBHP_17 17 2/14/14 3:13 PM
BHP Billiton | Energy Abundance18
Other Joint VenturesIntroducing the rest of the team
Besides the felds and facilities that BHP Billiton operates in
Australia, the company has an interest in several major
developments that are operated by one of the other joint venture
partners.
The projects vary in size and the nature of their production.
While those on the North West Shelf tend to produce more natural
gas, activity off the North West Cape tends to yield more oil.
Developments in the Bass Strait produce a mix of oil, natural gas
and condensates.
The North West Shelf
More than 40 percent of Australia’s oil and gas comes from two
major areas of what geologists call the North West Shelf. Since
1984, the North West Shelf has been producing natural gas from the
North Rankin A, Goodwin A and Angel platforms. Collectively, they
have the capacity to produce from 600 million to 2,300 million cubic
feet of gas per day. The gas is transported by pipeline to an onshore
plant at Withnell Bay in Western Australia.
The world-class Karratha gas
plant is the North West Shelf
Venture’s largest onshore asset.
140303OGJBHP_18 18 2/14/14 3:13 PM
BHP Billiton | Energy Abundance 19
The venture’s oil comes from the Wanaea, Cossack, Lambert and
Hermes felds. The oil is retrieved through the Okha FPSO, which has
a capacity of 60,000 barrels per day.
North West Shelf is operated by Woodside Petroleum, which owns
16.67 to 33.34 percent of the asset. Woodside’s joint venture
partners include BHP Billiton, Chevron, BP, and Japan Australia, each
with about 16.67 percent.
The venture’s largest land-based asset is the world-class Karratha
Gas Plant, which includes fve LNG processing trains and two
domestic gas trains. The 200-hectare (495-acre) facility can produce
more than 16 million metric tons of LNG per year. Each day it
delivers some 12,000 metric tons of natural gas to the domestic
market, and 130,000 barrels of condensate.
Bass Strait – Turrum, Tuna and Kipper
The Bass Strait oil and gas felds in southern Australia’s Gippsland
Basin is a 50/50 joint venture between BHP Billiton and the venture
operator, Esso Australia. Developed in the 1960s, Bass Strait is
capable of producing the energy equivalent of 200,000 barrels
of oil per day from its 20 producing felds. Of these, 17 produce
oil and the rest produce natural gas. Since 1969, Bass Strait has
delivered more than four billion barrels of oil and seven trillion
cubic feet of gas.
The feld’s infrastructure includes 14 steel jacket platforms, three
subsea developments, two steel gravity-based towers and two
concrete gravity-based platforms. About 600 kilometers (373
miles) of pipeline connect the Bass Strait to Longford and the Long
Island fractionation plant and crude oil tank farm. The plant serves
Melbourne and other cities in Victoria. In addition, crude oil can
be transported by sea tankers or pipeline from Long Island Point to
refneries in Altona and Geelong.
“The Bass Strait has been producing for more than four decades,”
says Rob Jellis, joint interest general manager for BHP Billiton in
Australia through 2013. “The producing sands are tilted in a number
of felds. The reservoirs have high permeability and strong water
drives. In many ways, they are ideal.”
The Kipper Tuna Turrum (KTT) project—the last major discovery in
the Bass Strait—began an expansion program in 2008. The newest
structure is the Marlin B platform, which is linked by a walkway
to Marlin A. The US$1.4 billion facility, completed in late 2013,
could boost the feld’s daily production by 11,000 barrels of oil and
200 million cubic feet of gas. New wells from Marlin B will access
the Turrum reserves.
To handle the additional gas, the Longford Gas Conditioning Plant,
about 19 kilometers (12 miles) south of the town of Sale, is being
expanded to serve customers throughout East Australia. When the
US$1 billion facility is operational in 2016, it will deliver 1.6 trillion
cubic feet of gas to the domestic market, helping to replace the
declining production from existing felds. The state-of-the-art facility
also will reduce the carbon dioxide content of the treated gas to less
than 3 percent.
Work on the Kipper, Tuna and Turrum project, including the
Longford expansion, is the largest domestic oil and gas development
in eastern Australia. So far it has created some 1,300 construction
and installation jobs. When the expansion is complete in 2016,
Longford will be able to supply enough clean-burning energy to
power a city of a million people for 35 years.
ABOVE: The North Rankin B platform, attached by bridges to
North Rankin A, is the newest structure in the North West Shelf.
140303OGJBHP_19 19 2/14/14 3:13 PM
BHP Billiton | Energy Abundance20
Just AheadStrong growth in Western Australia
While even the most fast-track projects take years to come on
stream, recent movement on three fronts could go a long way
toward securing Australia’s energy future.
Tallaganda
BHP Billiton’s largest fnd in 2012 tapped the Tallaganda formation
of the Carnarvon Basin. The discovery well, completed late in the
year, is in an area between the Macedon feld and BHP Billiton’s
50-50 joint venture known as Scarborough. Although pre-drilling
estimates suggest a substantial amount of gas, the well data is still
being evaluated.
Scarborough
One of the most interesting new projects is the proposed 50-50
joint venture between BHP Billiton and ExxonMobil to develop the
Scarborough natural gas feld off Western Australia. ExxonMobil
affliate Esso Australia would operate the feld, which is located
about 220 kilometers (137 miles) northwest of Exmouth in 900
meters (2,950 feet) of water. Scarborough is one of the most remote
of the Carnarvon Basin gas resources.
One concept being considered is a Floating LNG (FLNG) vessel, an
innovative way to recover natural gas from remote areas. Instead
of bringing the gas to shore by pipeline, it is processed in the
feld, converted to LNG and offoaded onto LNG tankers at regular
intervals. The technology has the potential to recover so-called
“stranded” offshore gas that would otherwise not be produced.
The challenge in this project—estimated at more than
US$10 billion—is not the LNG technology itself, but rather the
diffculty of making LNG trains compact enough to ft on a ship.
With a length of 495 meters (1,624 feet) and a width of 75 meters
(246 feet), a Scarborough FLNG would become the largest ocean
vessel of any kind ever built. An alternative concept is to bring
Scarborough gas to shore via pipeline and to tie into existing
onshore facilities and infrastructure.
If the project moves ahead, the Scarborough gas would come from
as many as 12 new wells. The front-end engineering and design
work could begin soon, leading to a fnal investment decision.
Regardless of the development plan, Scarborough is likely to become
a major part of the country’s energy mix.
ABOVE: The petroleum industry as a whole has committed
an estimated US$120 billion to develop Australia’s oil and gas
resources over the next few years, and much of that activity will
be off the coast of Western Australia.
140303OGJBHP_20 20 2/14/14 3:13 PM
BHP Billiton | Energy Abundance 21
Seismic surveys like this one
will lead explorers to Western
Australia’s next big felds.
140303OGJBHP_21 21 2/14/14 3:13 PM
22 Axens
23 Baker Hughes
24 Bureau Veritas Australia PTY Ltd
25 Wood Group Kenny
26 Oceaneering International, Inc
28 OneSubsea
29 Streicher Australia PTY Ltd
30 Schlumberger
32 Technip Oceania Pty Ltd
AXENS
COMPANY PROFILE
Axens’ Mercury Removal Products Selected for MacedonAxens is an international provider of advanced technologies, catalysts, adsorbents and services, with a global reputation for basic engineering design excellence. The main scope of Axens’ business is focused on the conversion of oil, coal, natural gas and biomass to clean fuels as well as the production and purifcation of major petrochemical intermediates.
Axens was the pioneer of mercury (Hg) removal technology in the 1970s as a direct result of the frst mercury corrosion related industrial incident at Skikda in Algeria. Axens technology consists of an active phase impregnated on devoted and optimised alumina carriers (AxTrap™ 200 Series). The trapping mechanism implies a chemical reaction between the mercury and the sulphur of the active phase to form cinnabar (HgS) which is a non-hazardous and very stable form.
Thanks to an intensive R&D, licensing activities and technical services, Axens has
an extensive mercury removal portfolio and provides a global offer including a wide range of services.
BHP Billiton operates the Macedon gas feld located in Western Australia. The Macedon plant consists of four offshore production wells and an onshore gas treatment plant (Onslow).
The natural gas is routed to the onshore plant via a subsea pipeline, where the gas is processed prior to being sent to Bunbury Natural Gas Pipeline. The natural gas contains 2 µg/Sm3 (microgram of Hg per standard cubic meter) of mercury and the outlet concentration needs to be lowered to 10 ng/Sm3 (nanogram of Hg per standard cubic meter). Axens received an award for the design of a 5-year lifetime mercury removal unit. The mercury removal unit is placed in water saturated gas upstream of the dehydration unit. This unit treats 200 MMSCFD and consists of two vessels in parallel loaded with Axens’ product.
Axens89, bd Franklin Roosevelt – BP 50802
92508 Rueil-Malmaison – Francewww.axens.net
Axens mercury removal technology
Hg°
Poroussupport
Active phase
Mercury
Cinnabar HgS
Company Profles VP, PennWell Custom Publishing
Managing Editor and
Principal Writer
Richard [email protected]
Art Director
Meg Fuschetti
Production Manager
Shirley Gamboa
PennWell Petroleum Group
1455 West Loop South, Suite 400Houston, TX 77027 U.S.A.713.621.9720fax: 713.963.6285
PennWell Corporate
Headquarters
1421 S. Sheridan Rd., Tulsa, OK 74112P.C. Lauinger, 1900–1988
Chairman
Frank T. Lauinger
President/CEO
Robert F. Biolchini
140303OGJBHP_22 22 2/14/14 3:13 PM
COMPANY PROFILE
BAKER HUGHES
BHP Billiton | Energy Abundance 23
Innovative Wellbore Cleanup Solution Enables Casing Repair, Assures ProductionBaker Hughes has served BHP Billiton’s Australian operations since 2001, providing a wide range of technologies from drill bits to openhole completions and wellbore cleanup services for the Pyrenees, Upper Pyrenees, Stybarrow, Scarborough and Griffn projects.
A recent example of an innovative Baker Hughes technology solution delivered to BHP Billiton was the engineered application of wellbore cleanup technology to enable the repair of a damaged well and assure its future production.
The ChallengeIn 2013, BHP Billiton conducted a three-well drilling campaign in the Moondyne Field on Australia’s Northwest Shelf. On one well, drilled as an oil producer, BHP Billiton installed the sand screens, then during a test of the reservoir isolation valve (RIV) at the top of the lower completion, a leak was identifed in the 10¾ × 95⁄8-in casing crossover approximately 100 m below the mud line. To remediate the casing leak, BHP Billiton decided to install an internal casing patch.
Installing the casing patch required use of an aluminum internal shoe. However, after setting the patch and engaging the seals, BHP Billiton would have to drill out the shoe, which would create debris that, if left in the well, could prevent the RIV from re-opening, creating a high risk of losing the well.
The Baker Hughes SolutionBHP Billiton contacted Baker Hughes to help protect the lower completion from the debris and guard it from pressure cycles that would occur during the patch and casing tests. BH engineers worked along with BHP Billiton engineers to design a solution that included a GT™ retrievable bridge plug and a modular vectored annular cleaning system, modular VACS™ tool.
The Model GT retrievable bridge plug is designed to provide a pressure barrier to temporarily shut in offshore template wells. In this application, the plug would provide a barrier to hold proppant sand and cement and to prevent debris from falling onto the RIV.
The modular VACS system captures debris left at the bottom of the well after drilling
or other well operations. As fuid fows through the tool’s jet nozzles, the VACS jet engine design produces increased suction pressure at the base of the tool, pulling in debris or junk from the well into the tool basket. The system’s modular design makes it safe and easy to operate, and also reduces nonproductive time (NPT) by eliminating the need to handle debris at the rig site.
Well Repair and Cleanup OperationThe frst step of the casing patch operation was to set the GT bridge plug at a depth of 509m MDRT and to place 500 kg of frac sand proppant above the plug. An 80 m cement plug was then spotted above the proppant to enable milling of large debris. The aluminum shoe was then milled out and debris settled on top of the cement plug. This debris was then milled up as 40 m of the cement plug was drilled out.
The modular VACS assembly was then run in hole, comprised of one VACS debris module and fnger catchers installed inside a shoe to capture large and small debris. A second drill out run was then made to remove the remaining cement and enable access to the proppant above the GT bridge plug. A second VACS system was run with two
modules, recovering approximately 50% of the frac sand.
Prior to the operational program being complete a Rig De-man was required due to a cyclone in the area. After the weather delay, the VACS system was run for a third time and retrieved the remaining sand. In case any debris remained in the well, a debris-tolerant, short-catch LT-CT tool was used to retrieve the GT plug. This run went smoothly and the operator successfully installed the upper completion to prepare the well for production.
Baker Hughes2929 Allen Parkway; Houston, Texas 77019
Phone: +1 713-439-8600Fax: +1 713-439-8699www.bakerhughes.com
Christine Mathers713.438.8738
140303OGJBHP_23 23 2/14/14 3:13 PM
COMPANY PROFILE
BUREAU VERITAS
BHP Billiton | Energy Abundance24
Validation Services for BHP Billiton’s
Macedon Onshore Gas Plant
Design to Operations — Verifcation,
Inspection, Certifcation, Validation
Established in 1828, Bureau Veritas is a global leader in Testing, Inspection and Certifcation (TIC), delivering high quality services to help clients meet the growing challenges of quality, safety, environmental protection and social responsibility. We are recognized and accredited by major national and international organizations. Bureau Veritas has 59,000 employees worldwide, 1,330 offces and laboratories in 140 countries, 400,000 clients, 8 global businesses with leadership positions and 900 accreditations and delegations
As a trusted partner, Bureau Veritas offers innovative solutions that go beyond simple compliance with regulations and standards. Bureau Veritas helps operators understand and control risk, improve performance and promote sustainable development. Whether you are operating in the upstream, midstream, or downstream segment of the oil and gas industry, environmental, safety and reliability issues are business critical. Bureau Veritas has solutions to help meet those challenges.
At Bureau Veritas, we use our own methods, verifcation tools and laboratories to help operators to meet internal, regulatory and governmental requirements. Our scope of services encompasses Asset Integrity Management, Training and Consulting in oil and gas and LNG markets.
From conception through design of your new facilities (CAPEX) to maintenance and operation (OPEX), Bureau Veritas operates worldwide to support deepwater, offshore and onshore projects.
In April, 2012, Bureau Veritas Australia Pty Ltd was contracted by BHP Billition to provide Third Party Validation Services for the Macedon onshore gas plant in accordance with Division 7 Regulation 41.0 of the Western Australia Petroleum Pipeline (Management of Safety of Pipeline Operation) Regulations 2010 and the Department of Mines and Petroleum (DMP) accepted Scope of Validation. Our services included 3 key activities:
1. IRC (Independent Review Certifcate)
This service involves the review of documents with safety critical elements. Safety critical elements include the structure, containment systems, shutdown systems, power systems, pressure systems and drainage systems. To further protect people and equipment we also review communication, escape, rescue, detection (gas, smoke, fre) and active fre protection systems. We ensure the facilities have the proper safety and protection systems defned.
The IRC also confrmed the Macedon onshore gas plant used the Safety Case description, appropriate design codes and standards, and is designed to incorporate measures that protect the health and safety of people at the facility.
2. Overall Site Surveillance for Construction Verifcation (Fabricators sites)
The Macedon Onshore Gas Plant had components manufactured at Technip and
other vendors at locations worldwide. These components were then installed at the BHP Billiton site. QA/QC activities were carried out on all safety critical equipment as per the Overall Site Surveillance for Construction Verifcation Plan.
Bureau Veritas made both inspections of, and surveillance visits to, these locations. Inspections verifed that the components were manufactured in accordance with
Inspection at Construction site
Inspection at Fabrication site
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WOOD GROUP KENNY
COMPANY PROFILE
BHP Billiton | Energy Abundance 25
Plant - Concept Design
the specifed Codes and Standards and that facility construction addressed all the interfaces between vendor packages.
While not an integral part of the scope of design validation, surveillance visits were made to ensure that design requirements were incorporated during the process of construction. These visits included a review of Manufacturers Data Reports (MDR) of the vendor supplied packages and components at the manufacturing facilities. Both inspections
and surveillance visits were performed by designated and suitably qualifed inspectors.
3. Overall Site Surveillance for Construction Verifcation (Macedon Site)
The Construction Verifcation process is aligned with the project completion and handover process. The Interim Construction Validation certifes the onshore gas plant is ready for the commencement of commissioning, Ready For Gas In (RFGI).The interim validation scope for the site construction completion was executed via routine in-process surveillance visits, and via unrestricted gas plant site access provided by BHP Billiton. The key documents reviewed during these visits included:
•Mechanical Completion Certifcates and associated Inspection Test Records (ITRs)
•Functional test ITRs
•Pre-commissioning Test Procedures
•System Completion certifcates
•Project Completion System
•System complete punch-list items
The Final Construction Validation certifed the OGP was complete, ready for hand over to operations and is prepared to deliver natural gas and other hydrocarbon products to market.
Bureau Veritas Australia Pty Ltd26 Colin Street. WA 6005Tel: +61 - 8 - 9481 0100
http://www.bureauveritas.com.au/
www.woodgroupkenny.com
WGK Integrates Global TeamsOffshore projects require engineering and project personnel to be located across global locations. Wood Group Kenny (WGK) provided integrated dual project locations to support the BHP Billiton Macedon project.
The Houston team provided early Front-End Engineering Design (FEED), risk management assessments and detail design. The Perth team provided additional detail design, support for pre-commissioning, installation, start-up, and ongoing asset integrity management.
Design PhaseFEED services for the Macedon project included engineering and project management for fexible fow lines, an in-line SLED (ILS), subsea manifold, and an export wet gas pipeline. The subsea equipment and four production wells are operated 100 km from the offshore wells at the Macedon onshore gas plant (OGP) .
WGK conducted a thorough fow assurance analysis to optimize the performance of the Macedon production system. The teams also analyzed offshore wet gas pipelines at start-up phase and onshore sales gas pipelines.
WGK’s Houston and Perth teams successfully transitioned from design to operations with BHP Billiton’s operators.
Execute and Operations PhaseThe Perth team applied risk management standards in the following studies and analyses•Corrosion modelling/management
•Material and coating selection
•Cathodic protection design
•Erosion pipeline assessments
•Sand management
•Inspection
•Maintenance, monitoring, and repair
•Onshore sales gas pipeline modeling
BHP Billiton and WGK recognised the importance of corrosion risks associated with multiple wells, manifold, pipelines, and a 100 km offshore site. Environmental safety drove a thorough simulation of many production scenarios using WGK custom modelling software. WGK evaluated the dynamic liquid and vapour phase effects in more than 50,000 individual corrosion simulations.
Our integrity management team used its Nexus Integrity Centre (NEXUS IC) to implement an industry risk-based inspection (RBI) programme for the OGP. This programme provides the lowest lifecycle operations cost and ensures system integrity and safety. Risk assessment workshops determined potential failure points, resulting in plant inspection plans and repair work scopes.
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COMPANY PROFILE
OCEANEERING
BHP Billiton | Energy Abundance26
Distance, Remoteness, and ‘Creature Features’ Test Oceaneering Design Teams
Every umbilical project involves specifc challenges
and requires creative, customized solutions.
But the Macedon gas development off Western
Australia was in a class of its own.
Early in the Macedon design phase, once BHP Billiton opted to develop the feld as a subsea tieback to shore, the company faced a crucial choice: to control the project from a local buoy near the offshore well site, or to connect Macedon’s subsea wells to controls systems onshore with an extended reach umbilical. Both options had their challenges, says BHP Billiton senior manager
Garry Walker, who was Macedon project director at the time. But “based on the environmental and safety risks associated with having surface facilities out on the ocean in a cyclone-impacted area,” he says, “we decided to go with the extended reach umbilical – 66 km single length of umbilical, tied into a 13-km near-shore umbilical.”
To build and install this critical lifeline to shore, the company turned to Oceaneering International, which has more than 35 years of experience manufacturing highly engineered, technologically complex umbilicals and related hardware. Along with in-house engineering and project management teams, the company’s Oceaneering Umbilical Systems (OUS) division manufactures umbilicals at strategically placed sites in Panama City, Florida; Niteroi, Brazil; and Rosyth, Scotland.
Down Under demandsWhile every job requires specifc, customized solutions, the Australia project presented challenges of both scale and technology, explains Oceaneering Umbilical Systems technical sales manager Alun Rees.
“The challenge really was, it was a subsea-to-shore tieback that would run 70 km from the beach to the subsea well site,” he says. “In the end, we supplied 15 steel tube and electric power/fber optic umbilicals – about 120 km altogether – and 17 major hardware pieces. It was a huge project, probably the largest one OUS had ever done.”
To deliver it successfully, Oceaneering would rely on its integrated supply chain for sourcing – a global network that, in this case, included sourcing from the United States, Colombia, Norway, Czech Republic and the United Kingdom.
One particularly challenging aspect of the job was the need to extend the umbilicals
Telescopic cutaway of the main
subsea-to-shore Macedon umbilical that
runs from the subsea well site to shore.
Installation vessel carousel loaded with Macedon umbilical and hardware before lay operations.
20” Subsea Pig Launch System with intelligent
pig capability. Shown on test and shipping stand,
the system can load and independently and
sequentially launch up to four pigs in succession.
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BHP Billiton | Energy Abundance 27
more than 15 km inland to the onshore processing plant. “On the shore side, in a very remote part of Western Australia, they had to go inland with an umbilical,” Rees says. “That was unusual for us. We build umbilicals for subsea. But we had to bring it ashore, trench it along the beach, get through some sand dunes, through some wetlands, under a river, more wetlands, and fnally the plant.”
This being Western Australia, there were “some fora and fauna issues to get through,” he notes. For the onshore portion, the umbilical electric power cables had to be coated in nylon to protect against electrical cable-eating termites; offshore, the tubes passed through a lengthy stretch prone to Teredo worms, or shipworms, that burrow into ship hulls, and are also fond of electrical cables. To discourage them, the shallow water and subsea power cables include a layer of copper tape.
Linking upTo connect the shallow water and subsea sections of the main umbilical, Oceaneering developed a connector that could be retrieved from the seafoor, used to connect both sections, and then re-deployed to the seabed. Another connection had to be made in the main onshore section, where the umbilical was split into two separate cables to meet installation weight limitations. The onshore umbilicals had to be divided into multiple sections no heavier than 50 tonnes, including the installation reels and pieces of hardware. “The challenge was, if you’ve got
all these short lengths, how are you going to join them together in the outback with no infrastructure?” Rees says.
Oceaneering Subsea Products’ engineering team, including VP of business development Michael Cunningham, came up with custom-built connection systems for the umbilicals that allowed them to be assembled onsite, both onshore and offshore. “Having to make the thing up offshore was a pretty signifcant challenge,” Cunningham says. Oceaneering had performed a similar operation offshore in the Gulf of Mexico. “But that was a thermoplastic hose-style umbilical, so torsion in the umbilical was quite easy to deal with, relative to the steel tube one. That’s where the idea for an inline joint installation tool came into play, so we could actually manipulate the ends of the umbilical to align the two halves of the splice to be able to mate them.”
Low-loss fber was included to keep the umbilicals’ circumference, and overall weight, within bounds. “Normally, they would have used electric cables for communications, but it’s too far – the cables would be too big,” Rees says. “So they communicate from shore to the well site digitally, through an optic cable. Then, when they get to the well site, they convert to analog and distribute communications via electrical cables.”
Precision piggingDuring the Macedon planning process, BHP Billiton asked Oceaneering to come up with a design for a subsea pig launcher. “They wanted the unit to be able to do
commissioning work on the pipeline at the completion of installation, and then to do operational pigging, including intelligent pigging operations,” says Cunningham. “They asked us to come up with a design that they felt was the least risky for a single fowline system.”
Oceaneering had done similar work on other projects, albeit on a smaller scale. “Even though it was ROV operable, the complexity was signifcantly greater than what we had done in the past for commissioning systems,” he continues. BHP Billiton “wanted different types of pigs to be deliverable through the system, and to the best of my knowledge, this may be the frst one that can deliver an intelligent pig from the subsea location, certainly the frst we’d ever done.”
During pigging operations, the pig launcher attaches to the subsea manifold via an Oceaneering Grayloc clamp-style connector. “It is not a self-contained system in that it has to have intervention from the surface, both from an ROV to operate the barriers between pigs, and also to deliver the kicker fuid required for initial motivation,” Cunningham says. “The design was customized very specifcally for this location.”
The oil and gas industry has long sought a pig launching system for single-fow projects such as Macedon, he adds. “But it’s got signifcant challenges. If you’re going to bet the farm – basically, bet the wells – on a single pipeline system, then you better be pretty darn comfortable that you can get a pig from the well location back to the beach without getting stuck somewhere.”
Overall, Rees says, Macedon was “one of the most challenging” umbilical jobs that Oceaneering has ever taken on. “Usually, we’re faced with depth and weight,” he explains. “Here, it was not the depth but the length, horizontally, and the environmental challenges. And then these odd creature features. It was very interesting. And it worked well – the relationship has always been good with BHP.”
Oceaneering International, Inc.11911 FM 529, Houston, Texas 77041 U.S.A.
www.oceaneering.com
Onshore installation of Macedon umbilical using an inline joint installation tool to facilitate
the alignment and engagement process.
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COMPANY PROFILE
ONESUBSEA
BHP Billiton | Energy Abundance28
One Comprehensive Resource for Integrated Subsea Solutions.
Macedon World Class Subsea Solution
OneSubsea production system solution
OneSubsea™ is a unique company, launched in mid-2013 by two subsea leaders, Cameron and Schlumberger. OneSubsea delivers integrated solutions, products, systems and services for the subsea oil and gas market. The company offers a step change in reservoir recovery for the subsea oil and gas industry through integration and optimization of the entire production system over the life of the feld. OneSubsea combines Cameron’s fow control expertise, process technologies, and world-class manufacturing and aftermarket capabilities with Schlumberger’s petrotechnical leadership, reservoir and production technology and R&D capabilities.
For the BHP Billiton Macedon feld development, OneSubsea delivered:
•A subsea production system producing directly to and controlled from the onshore facility, nearly 100 kilometers away
•The production system, including wellhead systems, trees and fowbases and diverless fowline connection equipment
•Valves for the subsea manifold valve assemblies; valves for the onshore gas plant were provided by Cameron
•The subsea fber-optic controls system
As with many large, complex projects, OneSubsea engaged its global resources for increased capability. OneSubsea provided support to BHP Billiton and its project team from manufacturing and design facilities in Houston, USA; Johor, Malaysia; Leeds, England; Celle, Germany; and Perth, Australia.
Production System and ValvesOneSubsea provided the production wellheads, fowbases, trees, chokes and CVC™ diverless fowline connection systems. The wellhead systems were based on a feld-proven STM-15™ metal-to-metal sealing system and were equipped to accommodate the OneSubsea drill-through SpoolTree™ and completion system. This unique design helps reduce rig time. The subsea trees included
fully clad annulus fowpath, including valve and fowloop, which allowed for gas lift injection and erosion protection.
OneSubsea also provided valves for the subsea manifold, while Cameron provided the valves for the Macedon onshore gas plant. This included more than 2800 valves of all sizes and working pressures, as well as gate, ball and check valves. Materials and equipment were designed to industry standards and specifc Australian requirements.
Control SystemOne of the key aspects of this project was the control system for the subsea trees, manifold and subsea distribution systems. OneSubsea has feld-proven, reliable, advanced and modular control systems, based on fexible state-of-the-art power and communication systems, providing best-in-class, customer-specifc solutions. For the BHP Billiton Macedon development, the OneSubsea Broadband Communication System was utilized. Subsequently, OneSubsea supervised the installation activities and performed the commissioning. The broadband communication system is an open communication network based on the use of fber optics to control all valves and chokes, and provides communication for all instrumentation/sensors.
The OneSubsea pre-engineered design allows for remote monitoring, additional surveillance and data access. All data and signals from the subsea drill centers are carried via the subsea fber-optic lines, a much faster system than a traditional copper-based production controls communications system.
The umbilical connects the onshore gas plant and the subsea wells carrying hydraulic and electrical power and communication. The fber-optic communication lines carry instructions and data to and from the subsea equipment and operators in the control room. With the control room located at the onshore
gas plant nearly 100 km from the well locations, this is one of the longest offset control systems worldwide. The Macedon project has helped prove the reliability of these systems, pioneering development of projects with less offshore infrastructure.
The system is equipped with unique, multiple channel, back-up redundancy, eliminating the need for additional back-up copper communications lines; this reduces
the overall main umbilical cost. Furthermore, the system is designed
to handle additional wells depending on the operator’s full feld development plans.
Importantly, the OneSubsea broadband communication system is designed to communicate with the onshore gas plant emergency shut-down (ESD) system to protect people and the subsea and onshore equipment. Other safety measures of the system include an escalating warning process when certain parameters reach critical values, and interlocks, which prevent operators from performing unsafe actions. Safety is a top priority at OneSubsea, and was a critical aspect of this control system design.
OneSubseawww.onesubsea.com
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COMPANY PROFILE
STREICHER AUSTRALIA PTY LTD.
BHP Billiton | Energy Abundance 29
STREICHER Australia Pty Ltd
STREICHER Australia
is the Australian branch
of STREICHER Group
based in Germany.
Established in 1909 STREICHER Group operates in four business sectors:
•Pipeline and Plants
– Pipeline Construction
– Microtunneling
– Horizontal Directional Drilling
– Special Crossings
– Pipeline Operation and Maintenance
– Hydrotesting
– Condition Monitoring
•Mechanical Engineering
– Drilling Technology
– Process Engineering
– Amusement Rides
•Civil and Structural Engineering
– Road and Civil Engineering
– Bridge Construction
– Landfll Construction
– Industrial Construction
– Public Private Partnership
•Raw and Construction Material
– Asphalt Mixing Plant
– Quarries and Gravel Mills
– Sand and Gravel extraction
– Construction Material Acceptance
STREICHER Australia is based in Queensland and can undertake projects in the Asia Pacifc Region drawing on the STREICHER Group support and cooperation to provide the full services that the group offers.
BHP Billiton was attracted to the capability of STREICHER subsidiary, DrillTec, and invited DrillTec to tender on the BHP Billiton gas project.
DrillTec realized the opportunity to showcase STREICHER Group capability in Australia and tendered for the complete installation package for the wet and sales gas pipelines on the Macedon project, bringing together the three subsidiaries of the STREICHER Group to deliver one project.
STREICHER with its Joint Venture partner, Clough Seam Gas, constructed:
•82 km of DN 500 gas pipeline (heavy and light wall)
•Two shore crossings using horizontal directional drilling
•Two river crossings of the Ashburton River
•A number of road crossings; some roads were required to remain operational
•Installation of 16 km shoreline of electrical umbilical pipeline
•Installation of 16 km shoreline of hydraulic umbilical pipeline
•All hydrotesting, drying and pigging of the line
safety was an absolute priority, with a team of safety professionals providing support along the whole length of the pipeline.
The environmental and heritage requirements presented some unique challenges, such as a round-the-clock turtle monitoring campaign during the shore crossing operation, the twice daily fauna inspection of
the open trench that was done on foot, and the identifcation, fencing and monitoring of heritage areas.
STREICHER Australia PTY Ltd.First Floor (RHS)
225 Brisbane TerraceGoodna QLD 4300
AustraliaPhone: +61(0)7 3436 0700
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COMPANY PROFILE
SCHLUMBERGER
BHP Billiton | Energy Abundance30
Collaboration Lands Complex Wells
Schlumberger and BHP Billiton work closely
to sharpen the view in complex reservoirs
For BHP Billiton, successfully delivering wells to target depth in their offshore felds often means navigating through a geologically complex patchwork of overlapping and dipping channel sands and unconformable top and subseismic faulting. To deliver these wells to target, on time and within budget, BHP Billiton called on Schlumberger for assistance.
Schlumberger has a well-established work history in Australia, which includes several successful technology deployments with BHP Billiton over the past fve years. Schlumberger approaches each of BHP Billiton’s drilling projects as a partnership, with an ultimate goal of helping the operator overcome its technical challenges and meet its drilling and well placement objectives.
Working Together to Reduce Well TortuositySuch a technology partnership was critical to BHP Billiton’s goal of drilling and completing a well within the oil-bearing Lower Barrow Group sandstones within the Pyrenees development. The well was to be positioned within 3 m total vertical depth (TVD) of the reservoir top to maximize intersection with the reservoir, which was made more complicated by the reservoir’s internal stratigraphic layering and unconformable top.
A multidisciplinary team of Schlumberger personnel collaborated with BHP Billiton’s subsurface team to develop a geosteering solution for wells in this challenging geological environment. After
reviewing all relevant reservoir properties and drilling and completion parameters, the team decided to deploy the Schlumberger PeriScope HD* multilayer bed boundary detection service, which incorporates several formation evaluation measurements, including real-time directional resistivity and azimuthal gamma ray, to yield a multi-layer
detection capability and optimally place the well with respect to the overburden.
Schlumberger provided a bottomhole assemble (BHA) with the new PeriScope HD service to minimize potential standoff with respect to the unconformable overlying shale. The tool identifed multiple resistivity layers and delivered information about the reservoir internal geometry.
Schlumberger’s well placement engineers worked hand-in-hand with BHP Billiton to successfully drill and place the well. The PeriScope HD service’s unique depth of investigation, coupled with the multilayer
detection capability, provided an increased understanding of the complex reservoir geometry, in addition to continuously detecting the upper boundary of the reservoir while simultaneously identifying internal layering and several dipping progrades.
The well was drilled with an average of 3 m TVD below the top of the unconformable reservoir and achieved a 100 percent net-to-gross ratio to remain within the sweet spot. This confrmed to BHP Billiton that the multilayer bed boundary detection service would provide the level of performance and well placement assurance that is needed. BHP Billiton plans to use PeriScope HD service in additional horizontal wells within the feld.
A Sharper Focus on Formation FluidsBHP Billiton has advanced its real-time reservoir knowledge with the use of the FLAIR* fuid logging and analysis in real-time service delivered by engineers at Geoservices, a Schlumberger company. This premium gas service provides near real-time PVT-equivalent analysis at
*Mark of Schlumberger
The PeriScope HD service accurately detects multiple formation layers, orientation of approaching beds and fuid boundary positions to enable advanced well placement.
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BHP Billiton | Energy Abundance 31
the well site, by extracting hydrocarbons directly from the drilling mud at surface and conducting a unique quantitative analysis of lighter organics (C1 through C5), as well as a qualitative analysis of C6 through C8 components and light aromatics.
The FLAIR technology provides accurate analysis from deepwater wells, cold mud returns and complex modern drilling fuids, while circulating. Rather than send a fuid sample to a lab and wait weeks or months for results, the customer gets this information for each drilled section in quasi-real time. This speeds up drilling decision making for subsequent sections, and gives greater assurance that the well is on track to hit its intended target.
BHP Billiton used FLAIR in three wells in 2013. The frst well, the Homevale-1, was a vertical exploration well drilled at a water depth of 1,283 m offshore Western Australia. The service clearly identifed the presence of hydrocarbons, despite a very low gas concentration in the analyzed range. By heating the cold mud to 90 °C, the service identifed hydrocarbons down to a minimum of 5 ppm in the C3+ range, and highlighted a clear compositional trend from light to heavier fuids in the lower part of the logged section.
The second and third wells were a primary well and a sidetrack in the Stybarrow feld, offshore Western Australia. The data collected and the interpretation provided by the service indicated the presence of hydrocarbons in the main target. However, the sidetrack well showed low concentrations, and with a different signature than the PVT sample from an offset well where FLAIR was not run. Further comparison between the primary and sidetrack wells indicated a lighter fuid composition (only traces of C3 and no C3+ fraction) in the sidetrack. This suggested that the formation penetrated by the sidetrack was water bearing. The decrease of gas signal and the shift towards lighter components in a continuous hydrocarbon column was interpreted as an indication of the presence of water. This is because the high solubility of the C1 (Methane) in water pushes the C1/Cn ratios towards lighter values, and this is clearly identifed by the FLAIR technology in nearly real-time.
In each of these applications, BHP Billiton was able to integrate the FLAIR interpretation with other formation data collected by logging-while-drilling and on wireline to provide a deeper understanding of the fuid distribution in the felds.
Collaborations ContinueSchlumberger is committed to further collaboration with BHP Billiton to solve challenging well problems. The two companies recently collaborated to use the XL-Rock* large-volume rotary sidewall coring service, which closes the gap between core plugs from continuous conventional core and wireline-conveyed rotary sidewall cores.
The service retrieves up to ffty 1.5-in-OD by 2.5-in-long sidewall core samples in a single descent. These large-volume core samples, which are 300% larger by volume than MSCT core plugs, deliver a rock volume equivalent to conventional core plugs, matching the industry’s standard sample size for routine (RCAL) and most special core analyses (SCAL) measurements.
BHP Billiton is using the XL-Rock service to run additional analyses on the rock. Not only will the operator be able to routinely test for petrology, biostratigraphy, geochemistry, chemostratigraphy, but the larger core size allows for more specialized analyses. And because this new service takes rotary cores rather than percussion cores, there is a lower risk of rock fabric damage, which is an important beneft in the analysis of porosity, permeability, petrology and the study of individual sand grains in a reservoir rock.
While the XL-Rock coring service is not a direct replacement for conventional cores in every application, the larger diameter core plugs provided by the new tool offer an effcient, lower cost alternative to recovering the volume of rock required for post well studies. The successful recovery rate of the XL-Rock service already observed in BHP Billiton wells has given the operator confdence that its rock analysis requirements can be met.
Large-volume XL-Rock sidewall cores recover a suffcient volume of rock to extract three triaxial minicores for full analysis of completion quality, which previously required samples taken from conventional core. (Image courtesy of Schlumberger)
Schlumberger Australia Pty Ltd.256 St Georges Terrace, Level 5
Perth, WA 6000www.slb.com
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COMPANY PROFILE
TECHNIP
BHP Billiton | Energy Abundance32
Integrated Team Delivers World Class Macedon Gas Plant
In a remote part of Western Australia, Technip relies on its local
experience and global capabilities to complete Macedon facility
BHP Billiton has successfully started production from the Macedon gas feld, delivering 20% of Western Australia’s domestic gas supply via the Dampier to Bunbury Natural Gas Pipeline (DBNGP). Technip is proud to have delivered the onshore portion of this important project as the lead EPCM (Engineering Procurement Construction Management) contractor, later transitioning to an integrated team with BHP Billiton.
The scope of work for the Macedon onshore gas plant project was to design and build a gas dehydration and compression facility capable of producing 200 million
standard cubic feet per day of dry gas, along with associated support facilities. The scope included the following key components:
•Construction of a 13km-long plant access road within a nominated 150m-wide easement
•Establishment of a 380-person construction village
• Establishment of ground water supply for the construction camp, and reverse osmosis treatment to provide potable water to the construction village
•Installation of a 15km wet gas pipeline and umbilical from the shore crossing to the plant site, including horizontal directional drilling under sand dunes
•Construction of a gas treatment and compression plant and associated infrastructure
•Installation of condensate storage and truck off-loading facilities to export produced condensate
•Installation of a 67km sales gas pipeline to the DBNGP, including metering station
The Macedon onshore plant was delivered in July, 2013 and commenced the export of sales gas in August, 2013. Execution of the Macedon project required a combination of global capabilities and local knowledge
and experience. Globally, Technip is a world leader in project management, engineering and construction for the energy industry. Technip’s Onshore segment provides the full range of onshore facilities for oil and gas, petrochemicals and other energy industries.
Technip’s local knowledge from in-house engineering disciplines within Australia, combined with access to the Group’s proprietary and third-party technologies, enables project support for a wide range of services. These include concept studies through to design, construction, commissioning and start-up.
Umbilical installation
Sales gas compressor
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BHP Billiton | Energy Abundance 3C3
In Australia and New Zealand, Technip has been involved in the delivery of three recent onshore gas plant projects; Macedon, Woodside Otway Gas Plant and Origin Kupe Gas Plant.
The Macedon Onshore Gas Plant Project team was based in Technip’s Perth offce with design support from the Kuala Lumpur operating centre. Technip’s local workforce includes 600 personnel in Perth, Brisbane and New Plymouth (New Zealand) of which 90% are Australian citizens or permanent residents of Australia.
Successful execution was supported by a suitably timed transition into an integrated team, which led to signifcant cost savings and enhanced effectiveness and productivity by streamlining decision making processes. Having both management teams embrace the importance of the new organizational concept was paramount to the successful integration. The mutual respect between Technip and BHP Billiton fostered a healthy
working relationship and a culture of success that lasted for the duration of the Macedon project.
Technip’s extensive experience with modularised design and construction was drawn on to optimise and monitor the fabrication of modules. This approach allowed for fabrication in a controlled workshop environment in South East Asia while site preparation work was being completed.
Technip’s Group HSE Program, Pulse, was implemented on Macedon to support BHP Billiton’s vision of Zero Harm to its people, the environment and the communities in which it operates.
In order to protect the local environment, Technip consistently assessed the risks and potential impacts before commencing any work. The company had the full support of BHP Billiton, which has similarly aligned values. With local experts supporting the
project team, the Macedon project was able to successfully conserve the unique and diverse range of fora and fauna in the area. For example, the project implemented a turtle management plan that restricted disruptive lighting and included a turtle spotting program on the beach.
One of the major challenges faced by the project team was the location of the gas plant — Ashburton North is located in a remote part of Western Australia. Before construction began, there were no established roads, water supply, power supply or accommodation at the project site. As noted in BHP Billiton’s Petroleum Annual Review 2013, everything from roads to the
construction camp had to be built, including water and sewage systems. The completely self-contained site was also built to withstand a category 5 cyclone.
It was in this harsh and remote location, and in a challenging economic climate, that the integrated project team came together to deliver a world-class facility on time and on budget.
Technip Oceania Pty Ltd Perth, AUSTRALIALevel 1, 1100 Hay StreetWest Perth, WA 6005
Phone: +61 (0)8 9463 2500Fax: +61 (0)8 9463 2501
Email: [email protected] vessels
The project featured a detailed Turtle Management Plan
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BHP Billiton Petroleum
1360 Post Oak Boulevard
Houston, Texas 77056
(713) 961-8500
140303OGJBHP_C4 4 2/14/14 3:13 PM