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September 2013
Houston London Paris Stavanger Aberdeen Singapore Moscow Baku Perth Rio de Janeiro Lagos Luanda
World Trends and Technology for Offshore Oil and Gas Operations
For continuous news & analysiswww.offshore-mag.com
INSID
E:
Drillin
g fuid
s
direct
ory
Shell Brasil interview
South China Sea analysis
Extended reach drilling
Enhanced oil recovery
Australia update
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International EditionVolume 73, Number 9
September 2013
C O N T E N T S
Offshore (ISSN 0030-0608) is published 12 times a year, monthly by PennWell, 1421 S. Sheridan Road, Tulsa, OK 74112. Periodicals class postage paid at Tulsa, OK, and additional offices. Copyright 2013 by PennWell. (Registered in U.S. Patent Trademark Office.) All rights reserved. Permission, however, is granted for libraries and others registered with the Copyright Clearance Center, Inc. (CCC), 222 Rosewood Drive, Danvers, MA 01923, Phone (508) 750-8400, Fax (508) 750-4744 to photocopy articles for a base fee of $1 per copy of the article plus 35¢ per page. Payment should be sent directly to the CCC. Requests for bulk orders should be addressed to the Editor. Subscription prices: US $101.00 per year, Canada/Mexico $ 132.00 per year, All other countries $167.00 per year (Airmail delivery: $234.00). Worldwide digital subscriptions: $101 per year. Single copy sales: US $10.00 per issue, Canada/Mexico $12.00 per issue, All other coun-tries $14.00 per issue (Airmail delivery: $22.00. Single copy digital sales: $8 worldwide. Return Undeliverable Canadian Addresses to: P.O. Box 122, Niagara Falls, ON L2E 6S4. Back issues are available upon request. POSTMASTER send form 3579 to Offshore, P.O. Box 3200, Northbrook, IL 60065-3200. To receive this magazine in digital format, go to www.omeda.com/os.
Celebrating Over 50 Years of Trends, Tools, and Technology
AUSTRALIA
Alternative approach required to contain costs of remote Australian offshore gas felds ............ 30The author describes how results from recent
development studies illustrate demonstrable
relationships between functional design
choices and facilities total installed cost. Chal-
lenging these choices through the application
of front-end loading techniques allows the
necessary balancing of competing develop-
ment drivers to achieve an economically viable
development.
Australia LNG projects advance despite escalating costs ...... 36A public row has erupted Down Under be-
tween local elected offcials, most prominently
WA Premier Colin Barnett, and proponents
of foating liquefed natural gas technology
as a development solution for the west’s
vast offshore gas resources. The backdrop:
skyrocketing labor and construction costs, and
potential competition from North America and
East Africa, that could derail several planned
LNG developments that included new onshore
liquefaction plants, along with the jobs and
local investment they would bring.
MIDDLE EAST
Offshore Middle East E&P activity remains robust ............... 38 The Middle East continues to be one of
the world’s most active offshore regions as
operators, developers, and state oil companies
continue to advance plans for new and existing
exploration and production projects.
BRAZIL
Shell leverages experience, technology development for future offshore Brazil .................... 41Offshore met with Kent Stingl, Shell’s vice
president of deepwater production and devel-
opment, to learn more about the pioneering
techniques being employed to maximize the
productivity of the company’s operations in
Brazil.
ASIA/PACIFIC
South China Sea offers opportunities, challenges ................... 44Offshore E&P activity in the South China
Sea is growing, driven by the potential of its
deepwater reserves and rising Asian energy
demand. But the South China Sea also poses
development challenges, most notably in the
form of boundary disputes among China,
Vietnam, and the Philippines.
GEOLOGY & GEOPHYSICS
3D broadband is the wave of the future ........................................ 52Marine seismic data is undergoing a broad-
band revolution, extending the recorded scale
with both lower and higher frequencies. By
separating upgoing and downgoing wavefelds
the ghost can be eliminated, or it can be used.
3D seismic data will play a greater role in
reservoir characterization.
DRILLING & COMPLETION
Majors continue to push boundaries of extended-reach drilling .................. 56Two papers this year at the SPE/IADC confer-
ence in Amsterdam highlighted the latest
initiatives in extended-reach drilling offshore.
Both outlined the challenges in drilling wells
from shore to access outlying reservoirs of
nearshore felds.
Environmental Drilling and Completion Fluids Directory ............... 58The 2013 Environmental Drilling and Comple-
tion Fluids Directory provides a comprehen-
sive listing of industry fuid manufacturers and
their individual products.
ENGINEERING,
CONSTRUCTION,
& INSTALLATION
Deepwater work in Gulf of Mexico spurs strong platform supply vessel market ..................................... 76Over the past year, the platform supply vessel
(PSV) market in the US Gulf of Mexico has
experienced great times. Vessel owners see
utilization remain high for PSVs of all sizes and
day rates in the US Gulf are trending upward,
even as the supply of PSVs grows due to new
deliveries or vessels returning from other
markets.
PRODUCTION OPERATIONS
Prototype AUV advances deepwater inspection capabilities ....................... 80A research project directed by Lockheed
Martin has developed and is testing an autono-
mous underwater vehicle capable of sophisti-
cated equipment inspection and monitoring in
deepwater. The research project, with funding
from the Department of Energy’s National En-
ergy Technology Laboratory, recently tested
the AUV on structures in the Gulf of Mexico,
and the results are presented.
36
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4 Offshore September 2013 • www.offshore-mag.com
International EditionVolume 73, Number 9
September 2013
D E P A R T M E N T S
PRODUCTION OPERATIONS
Detailed imaging and careful measurement boost feld recovery rates .................. 84Recently, time-lapse techniques have enabled reservoir managers to deduce how hydrocarbons
move through the reservoir. 4D seismic imaging has seen success, particularly where gas is
involved. Cross-well tomography has enabled inter-well resistivity imaging with enough preci-
sion to allow the siting of infll wells or steering of side tracks to improve sweep effciency. The
biggest disadvantage to time-lapse techniques is that they are reactive processes; achieving
maximum reservoir productivity requires predictive processes.
Metering can extend production on aging platforms ............................................... 88As evolving technologies enable North Sea platforms to produce beyond their original design
life, many operational factors come into play. Issues that directly impact productivity and down-
time are a high priority. Among these, metering systems should be regarded as critical. They
determine the quantity and quality of oil and gas recovered, and their control systems effectively
form the “cash register” of the whole production process.
SUBSEA
Drilling riser studies focus on unknowns of loading and frontier operations ......... 92Drilling in harsh environments imposes strains on risers, conductors, and wellheads. Stress
levels can be predicted, but results do not always match the reality of prolonged exposure to
buffeting waves and surging currents. This is a major concern in frontier deepwater regions
with little prior drilling history, and also for operations pushing the boundaries of jackup drilling
in established hostile plays.
COVER: COVER: Spiraling develop-ment costs and an increasingly com-petitive LNG market have complicated Australia’s ambitious plans to become the world’s leading LNG exporter by the end of this decade. In April, Woodside Petroleum scuttled a $45-billion plan for the Browse LNG development project, which originally included an onshore processing facility, and is now consider-ing a less expensive FLNG solution. But four major offshore projects are well un-der way, including Shell’s Prelude, which is on track to become the frst foating LNG development. Pictured is the Noble Clyde Boudreaux semisubmersible, which Shell and partners have con-tracted to conduct Prelude’s seven-well development drilling campaign. (Photo courtesy Noble Corp.)
Online .................................................... 6
Comment ............................................... 8
Data ..................................................... 10
Global E&P .......................................... 12
Offshore Europe .................................. 16
Gulf of Mexico ..................................... 18
Subsea Systems ................................. 20
Vessels, Rigs, & Surface Systems ...... 22
Drilling & Production .......................... 24
Geosciences ........................................ 26
Offshore Automation Solutions .......... 28
Business Briefs ................................... 96
Advertisers’ Index ............................... 99
Beyond the Horizon .......................... 100
CUSTOM
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Formation Evaluation | Well Construction | Completions | Production© 2013 Weatherford. All rights reserved.
Every company is different, every project unique. At Weatherford, we believe
in getting every job right, listening to your concerns, and working with you
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6 Offshore September 2013 • 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, e-books • Map Atlas E-book• North Sea Offshore Oil and Gas Map• 2013 Worldwide Survey of Floating Production,
Storage and Offoading Units• 2013 Environmental Drilling and Completions Fluids Directory• 2013 Subsea Processing Video E-book
Download: http://www.offshore-mag.com/maps-posters.html
New webcast➤ All-Electric HIPPS:
Advancing the Art of Subsea ProductionOperators of subsea production equipment can realize operational effcien-
cies and cost savings by introducing a subsea autonomous all-electric High In-tegrity Pressure Protection System (HIPPS), to allow a lower design pressure than the shut-in wellhead pressure.
Speakers from Total E&P Research and Technology USA and Granherne, a KBR company, will discuss safety integrity levels for an all-electric subsea HIPPS, probability of loss of containment in a HIPPS utilizing system with mul-tiple wells, and gaps to be addressed to bring all-electric HIPPS technology to the same technology readiness level as conventional electro-hydraulic HIPPS.http://www.offshore-mag.com/webcasts/offshore/2013/08/all-electric-
hipps.html
New Videos➤ Shell Olympus
The hull for Shell’s Olympus TLP, centerpiece of the Mars B development in the Gulf of Mexico, was built by Samsung Heavy Industries in South Korea and arrived in Ingleside, Texas, in January 2013. The topsides for the Olympus TLP were installed at the Kiewit Offshore Services yard in Ingleside. The TLP departed Ingleside for the Mars feld in July.
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COMMENT David Paganie • Houston
Minimizing megaproject delaysRising costs are challenging the economic feasibility of megaprojects, forcing opera-
tors to be more selective in taking fnal investment decisions (FID). Recently, two major developments in the US Gulf of Mexico and one in the Barents Sea were delayed for various fnancial reasons. The Malaysia National Oil Co. is hinting that it could defer some major projects due to increasing costs and softening oil prices. Meanwhile, the most dramatic example of the implications of infating project costs is in Australia. About $150 billion in resource projects have been deferred, revised, or canceled during the past six months, according to a recent study commissioned by the Business Council of Australia (BCA). This includes the Browse LNG and Sunrise LNG projects. In April, Woodside Petroleum shelved plans for the $45-billion Browse LNG development, say-ing the development concept did not meet the company’s commercial requirements for a positive fnal investment decision. Following further evaluation, the company said it will recommend FLNG as the optimum concept for development of the three Browse gas felds offshore Northwest Australia. It would use Shell’s FLNG technology, which is to be deployed on the Prelude feld. Shell may not have taken FID for the marginal gas development without the emergence of FLNG technology.
The BCA study, Securing Investment in Australia’s Future: Report of the Project Costs Task Force, was launched late last year to further investigate the fndings of the 2012 BCA commissioned report, Pipeline or Pipe Dream? Securing Australia’s Investment Future. The 2012 report compared the costs of resource projects in Australia to the US Gulf Coast. Its fndings were a 40% cost premium for resource projects overall, and a 200% cost in-crease for offshore oil and gas developments on the back of laybarge and drill rig costs. The study also noted that megaprojects worldwide are found to have a 60% failure rate in terms of cost or time overruns. This year’s follow-up report confrmed that project costs in Australia indeed are higher than in other developed countries. It found a number of key drivers for the high costs, including: problems with planning, design, scheduling, and procurement – partially caused by overly optimistic project scheduling, scarcity of suitably qualifed and experienced project managers and engineers and other key oc-cupations, which at times led to inadequate project execution.
The study identifed four key areas for reform to reduce Australian costs. These in-clude improving access to a skilled workforce; improving government approvals pro-cesses; a workplace relations environment that is focused on productivity; and alleviat-ing impacts of remoteness.
Concept selectionCorrect framing in the feasibility and selection phases of a project can achieve lower
costs outcomes while minimizing engineering recycle, explains Martin Stewart, Gran-herne. Stewart, in a special report for Offshore, describes how results from recent devel-opment studies illustrate demonstrable relationships between functional design choices and facilities total installed cost (TIC). To illustrate this point, he compares the develop-ment of a feld in Northwest Australia to a fctional equivalent in the Gulf of Mexico. Stewart’s full analysis begins on page 30.
Megaprojects have a low success rate. Rising project costs and a projected fattening oil price environment are further stretching the economics of megaprojects offshore. But, as noted earlier, proper evaluation early in the project design phase could minimize delays. “The most important single predictor of project success for any upstream project is the asset front-end loading index,” said Ed Merrow, founder and CEO of Independent Project Analysis, Inc. (Offshore, 2003). The index is a weighted numerical combination of the status of deliverables that defne the reservoir, the facilities, and the wells construc-tion program for an upstream development. He added, “Despite another 20 years of ex-perience with large projects, you can’t help but conclude that we have seen no material progress in the control of very large developments.” That was ten years ago.
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© 2
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Bake
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Leaders think the unthinkable.
Like a completion system with disintegrating frac balls made from nanostructured
material that is lighter than aluminum and stronger than some steels.
Or that the earth revolves around the sun.
Learn more at www.bakerhughes.com/thepayzoneleader
Advancing Reservoir Performance
Leaders discoverwhile others hesitate.
Nicolaus Copernicus
1309off_9 9 9/4/13 4:30 PM
Worldwide offshore rig count & utilization rate
August 2011 – July 2013
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
%
Aug 11
Nov
11
Feb 12
May
12
Aug 12
Nov
12
Feb 13
May
13
Contracted fleet utilization Total fleet Contracted Working
Sourc
e: IH
S
Australia capex (%) by operator 2008-2017
100
90
80
70
60
50
40
30
20
10
0
Others
Shell
Inpex
Eni
BHP Billiton
Chevron
Hess
Apache
Woodside
ExxonMobil
ConocoPhillips
2008
Source: Infield Systems
2009 2010 2011 2012 2013 2014 2015 2016 2017
US
$m
(%
)
Worldwide day rates
Year/Month Minimum Average Maximum
Drillship
2012 Aug $50,000 $443,746 $671,000
2012 Sept $50,000 $430,905 $671,000
2012 Oct $50,000 $430,519 $678,000
2012 Nov $50,000 $430,840 $678,000
2012 Dec $50,000 $442,299 $678,000
2013 Jan $50,000 $435,786 $678,000
2013 Feb $50,000 $450,447 $678,000
2013 Mar $50,000 $446,251 $678,000
2013 Apr $50,000 $454,074 $678,000
2013 May $50,000 $459,019 $678,000
2013 June $50,000 $462,267 $678,000
2013 July $180,000 $464,274 $678,000
Jackup
2012 Aug $40,000 $111,493 $368,000
2012 Sept $40,000 $111,880 $368,000
2012 Oct $30,000 $112,325 $368,000
2012 Nov $30,000 $114,722 $368,000
2012 Dec $30,000 $115,487 $368,000
2013 Jan $30,000 $118,382 $368,000
2013 Feb $30,000 $119,389 $368,000
2013 Mar $30,000 $120,342 $368,000
2013 Apr $30,000 $119,437 $368,000
2013 May $30,000 $121,942 $368,000
2013 June $30,000 $122,382 $368,000
2013 July $30,000 $123,091 $368,000
Semi
2012 Aug $69,825 $361,113 $675,000
2012 Sept $130,000 $358,349 $675,000
2012 Oct $130,000 $358,465 $648,000
2012 Nov $130,000 $363,491 $648,000
2012 Dec $130,000 $364,739 $648,000
2013 Jan $145,000 $363,945 $648,000
2013 Feb $145,000 $361,919 $648,000
2013 Mar $145,000 $363,459 $648,000
2013 Apr $145,000 $372,922 $648,000
2013 May $145,000 $380,598 $648,000
2013 June $145,000 $380,103 $648,000
2013 July $145,000 $382,671 $648,000
Source: Rigzone.com
G L O B A L D ATA
10 Offshore September 2013 • www.offshore-mag.com
Australia is expected to be one of the fastest growing regions of offshore development going forward, with large-scale projects being planned by the likes of Wood-side, ConocoPhillips, and Chevron. Woodside is expected to hold a 30% share of offshore capex, with the giant Calliance development expected to dominate the opera-tor’s investment over the period. Calliance is expected to be the most capital intensive field development offshore Australia during the timeframe, with Inpex’s Ichthys expected to take second place in terms of capex demand. Chevron is expected to be the third highest investor offshore Australia during the period with the operator continuing to direct significant capex toward the Greater Gorgon area. Wheatstone is anticipated to be the most capital intensive field development for Chevron during the next five years. ConocoPhillips is also expected to direct substantial expenditure toward developments offshore Australia, with the Poseidon/Kronos project anticipated to demand significant pipeline expenditure.
With many Australian developments characterized by their remote distance from shore, it is not surprising that the pipeline market sector is expected to form the largest percentage share of spend during the 2013-2017 period, accounting for 47% of the country’s total offshore capex. Infield Systems expects the single most capital intensive pipeline development to be the possible Woodside installation of the Calliance/Torosa to the Withnell Bay line. It is currently expected to be completed before the end of 2017. The platform market is also expected to require a significant proportion of Australian offshore capex during the period. The single most capital intensive installation is expected to be ExxonMobil’s Scarborough FLNG FPSO, while substantial investment is also anticipated for the Ichthys FPS and the GdF Suez Petrel/Tern FLNG FPSO. Altogether, Infield Systems expects 27 floating platform developments to require investment during the timeframe.
– Catarina Podevyn, Analyst, Infield Systems Ltd.
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G L O B A L E & P Jeremy Beckman • London
12 Offshore September 2013 • www.offshore-mag.com
Platform substructures under transport from Astrakhan to the V.
Filanovsky field. (Photo courtesy Lukoil)
Europe leads new pipeline investmentsGlobal investment in offshore pipelines will grow by nearly 60%
during 2013-17, according to a report by Infeld. Europe will account for the largest share of capex (25%) for two main reasons. First is the growth in long-distance trunklines taking gas from Russia and the Caspian Sea, crossing Eastern Europe in the case of South Stream and Shah Deniz II, and the North Sea, assuming expansion of the Nord Stream system. The other factor will be increased develop-ment of remote felds in the UK and Norway with long-distance con-nections to offshore infrastructure.
Asia is also set for strong growth, mainly from shallow-water pipelines offshore Indonesia, Malaysia, and Thailand, but also from subsea infrastructure associated with deepwater foating platforms.
North AmericaSuncor Energy was due to take the Terra Nova feld FPSO off
station this month from its location offshore Newfoundland and Labrador. The planned maintenance program will be extended to 11 weeks after an underwater inspection revealed that one of the ves-sel’s mooring chains had broken. The component will be repaired and maintenance completed on the remaining eight chains.
•••
Bahamas Petroleum has secured three-year extensions for each of its fve licenses offshore the Bahamas. The company is in talks with potential farm-in partners to co-fund drilling of a mandatory ex-ploration well by 2015. Drilling could start on the southern licenses during the second half of 2014.
South AmericaTullow Oil has agreed to two license deals with Japan’s Inpex. One
gives Tullow a 30% interest in block 31 offshore Suriname, where Inpex subsidiary Teikoku Oil is currently the sole licensee. Offshore Uru-guay, Tullow has agreed to transfer 30% of its equity in Area 15 in the Pelotas basin to Inpex, subject to approval from Uruguayan regulator Ancap. Here Tullow is preparing to evaluate newly acquired 3D seis-mic, over acreage in 2,000 to 3,000-m (6,561 to 9,842-ft) water depths.
•••
Shell and partners Petrobras and ONGC have committed to two new deepwater projects offshore Brazil. One involves a redevelop-ment of the Bijupirá/Salema felds, with four new wells expected to lift production to 35,000 boe/d during 2014. The other calls for installation of subsea infrastructure to tieback the Massa and Ar-gonauta O-South felds to the FPSO serving the Parque das Con-chas (BC-10) development. The current tie-in of Argonauta O-North should be completed later this year, adding 35,000 boe/d at peak.
•••
Petrobras has completed drilling and formation tests of its fourth exploration well on block BM-S-11 in the Iará area of the presalt San-tos basin. Results confrmed good-quality, 28° API oil with strong po-rosity/permeability characteristics in the Carbonate reservoirs. The location is 6 km (3.7 mi) west of the discovery well in 2,197 m (7,208 ft) of water, and 226 km (140 mi) off the coast of Rio de Janeiro.
BP has farmed into fve Petrobras-operated exploration blocks in the Poliguar basin, 40-110 km (25-68 mi) from the coast of Rio Grande do Norte and Ceará states. Water depths range from 50-2,100 m (164-6,890 ft).
West AfricaConocoPhillips will farm in to three contiguous blocks offshore
Senegal. The Rufsque, Sangomar, and Sangomar Deep concessions hold potential resources of over 1.5 Bbbl. Operator Cairn Energy has secured the semisub Cajun Express to drill two exploration wells in 2014. If the program brings a commercial discovery, ConocoPhil-lips could operate the subsequent development.
•••
AGR will provide well management services for Svenska Petro-leum’s exploration drilling campaign on blocks 2 and 5A offshore Guinea Bissau, due to start late this year.
•••
Tullow Oil has contracted MODEC to supply and operate an FPSO for the deepwater Tweneboa/Enyenra/Ntomme (TEN) project, the second in the Deepwater Tano license offshore Ghana. The VLCC Centennial J will be converted for the role, handling 80,000 b/d of oil and 170 MMcf/d of gas with 1.7 MMbbl of fuids storage capacity. SOFEC will design the associated mooring system. The TEN felds are in average water depths of 1,500 m (4,921 ft). MODEC also sup-plied the FPSO Kwame Nkrumah serving the Jubilee development.
•••
Noble Energy has started production of gas/condensate from the Alen feld in blocks 0 and 1 offshore Equatorial Guinea. Production is sent to the Aseng feld FPSO for storage. The project was com-pleted at a cost of just under $1.37 billion.
•••
Eni has discovered a potential oil and gas giant in shallow water in the Marine XII block offshore Congo. The Nene Marine 1 and 2 wells were drilled close together in around 24 m (79 ft) of water, en-countering wet gas and light oil in the presaline Lower Cretaceous clastic sequence. Eni estimates in-place resources at around 600 MMbbl and 700 bcf, with exploration upside.
•••
State oil company PetroSa is teaming with Sasol to explore an off-shore block in South Africa’s Orange basin, their frst cooperation in 10 years. Block 3A/4A on the country’s western margin is little ex-plored, but is on trend to the Ibhubesi gas feld to the north. Water depths range from 100-500 m (328-1,640 ft).
Caspian SeaA transport and installation barge has towed platform substruc-
tures from Astrakhan in southern Russia to Lukoil’s Vladimir Filanovsky feld in the northern Caspian Sea. The LQP-1 and RB substructures, supporting the living quarters and riser block plat-forms, will be fxed to the seafoor via driven piles. Next to be in-stalled are the substructures for the central processing platform, fol-lowed next year by the four platform topsides and their connecting bridges, all built by yards in Astrakhan.
1309off_12 12 9/4/13 4:30 PM
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Location of the Winchester gas discovery
in the Carnarvon basin. (Image courtesy Santos)
Mediterranean Sea
Greece’s government has awarded a con-sortium led by Hellenic Petroleum an explo-ration block offshore western Greece. The Patraikos concession covers 1,892 sq km (730 sq mi) in the Gulf of Patra, in water depths of 100-300 m (328-984 ft). According to Irish part-ner Petroceltic, the site has oil prospectivity in Jurassic, Cretcaeous, and Eocene formations. Initial work will include geological studies and 2D and 3D data acquisition.
Australasia
Oil Search has proven gas in the Hagana prospect offshore Papua New Guinea. The well hit the target in the deeper Pliocene objec-tive, confrming a new turbidite sand play with gas charge and retention at this stratigraphic level. Hagan is 225 km (140 mi) west of Port Moresby in 105 m (344 ft) of water. The fnd is a short distance northeast of Oil Search’s recent Flinders gas discovery, the frst well drilled in the Gulf of Papua in over a decade, the company claimed. The rig was next due to drill the Kidukidu prospect in license PPL 385, 40 km (25 mi) southwest of Hagana.
•••
Santos achieved its fourth consecutive gas discovery off Western Australia with the Win-
chester-1 well in the Carnarvon basin. Wire-line logs and pressure testing confrmed 40 m (131 ft) of net pay in the Jurassic Angel
and Triassic Mungaroo formations. The loca-tion is the WA-323-P permit, 135 km (84 mi) northwest of Dampier and in 75 m (246 ft) of water. The earlier fnds were Crown, Bassett West, and Bianchi.
Middle East
Qatar Petroleum and Occidental Petroleum have sanctioned Phase 5 development of the Idd El Shargi North Dome (ISND) feld off-shore Qatar. Their aim is to sustain production at around 100,000 b/d of oil for the next six years. Phase 5 will involve implementing or improving water-food schemes in all ISND’s producing reservoirs; drilling over 200 new production, water injection, and water source wells; and installing associated minimum facil-ities platforms, wellhead jackets, and fuid-pro-cessing equipment. Additionally, pilot studies will start for produced water reinjection and EOR. Costs could exceed $3 billion.
•••
The Iranian Research Institute of Petro-leum Industry (RIPI) and Kish Oil aim to develop the Tousan oil feld, southwest of Qeshm Island in the Persian Gulf, originally discovered by Petrobras. Reserves are es-timated at 400 MMbbl with around 25% re-coverable. Four wells will be drilled from a new offshore platform, with frst-phase pro-duction of 7-10,000 b/d heading through a 30-km (18.6-mi) pipeline to an onshore treat-ment plant.
East Africa
BG has discovered gas in the Mkizi struc-ture in Tanzania’s deepwater block 1. The drillship Deepsea Metro made the fnd in
1309off_14 14 9/4/13 4:30 PM
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1,301 m (4,268 ft) of water, between the ear-lier Jodari and Mzia discoveries, encounter-ing gas in a Tertiary stacked channel com-plex. There could be 600 bcf recoverable, according to partner Ophir Energy.
To the south, Statoil’s frst operated well offshore Mozambique also found gas in the Cachalote structure in Area 2, but not in large volumes, according to partner Tullow. The productive section was an upper Cretaceous deepwater channel system on the outboard fank of the Ibo High. The drillship Discoverer
Americas has since spudded the Buzio-1 well in the eastern part of the license.
India
Reliance Industries is considering sharing its east coast oil and gas-related infrastruc-ture with ONGC. Under a memorandum of understanding, both companies have agreed to perform a joint study which will investi-gate commercial terms. ONGC believes the arrangement could speed up development of its deepwater felds adjacent to those op-erated by Reliance offshore eastern India.
Southeast Asia
Salamander Energy has discovered oil in the Surin prospect in the Gulf of Thailand, 25 km (15.5 mi) from the offshore Bualang com-plex. The well was drilled in the G4.50 block in the central part of the western sub-basin, en-countering oil in Miocene fuvial sandstones.
•••
CNOOC has notched two shallow-water Bohai Bay oil discoveries offshore China. Bozhong B-4, drilled on the west slope of the Bozhong Sag, encountered oil pay zones with a total thickness of 50 m (164 ft) and fowed 660 b/d during testing. Kenli 10-4-1, drilled on the south slope of the Laizhou Bay Sag, intersected 45 m (147 ft) of oil pay and tested 2,800 b/d.
In the South China Sea, the 30,000-metric ton (33,069-ton) jacket has been installed for CNOOC’s Liwan gas feld central platform. All nine development wells have been completed and will be connected to deepwater production facilities. Pipelay is also nearing completion.
In the same sector, the company has signed production-sharing contracts with BP and Shell. BP’s covers deepwater block 54/11 in the Pearl River Mouth basin in the east of the sea, where water depths range from 370-2,300 m (1,214-7,546 ft). Shell’s PSC is for block 35/10 in the Yinggehai basin, in 80-110 m (262-361 ft) of water. During the exploration period, Shell will acquire 3D seismic and possibly drill wells, covering all associated expenditure.
•••
Japan’s frst-ever exploration well off its northwest coast was a dry hole. Japan Drilling performed drilling, on behalf of the JX Hold-ings joint venture, 30 km (18.6 mi) southwest of Sado Island in 110 m (361 ft) of water. •
1309off_15 15 9/4/13 4:30 PM
O F F S H O R E E U R O P E Jeremy Beckman • London
16 Offshore September 2013 • www.offshore-mag.com
Pieter Schelte penciled in for Brent topsidesAllseas has secured a frst contract for its giant single-lift de-
commissioning vessel Pieter Schelte, currently under construction by DSME in South Korea. Shell has booked the vessel to remove, transport and load to shore the topsides of three of the Brent feld platforms in the UK northern North Sea.
Timing is uncertain as Shell still has to submit an environmental impact assessment for the program, but the Brent Delta topsides will be the frst to be removed, probably in 2015-16. The remainder of the work will be spread over the following eight years, depending on cessation of production of the various platforms. Operations at Delta ceased in December 2011, and Shell presently expects Alpha and Bravo to follow in late 2014, followed by Charlie in late 2015. Allseas also has an option for the fourth platform topsides removal, whichever sequence Shell decides on.
Aside from the steel-jacketed Alpha, all the other three installa-tions are concrete gravity-based structures. Topsides weights range from 16,000-30,000 metric tons. All are well within the range of the 382-m (1,253-ft) long, 124-m (407-ft) wide Pieter Schelte, which will provide lift capacity of 48,000 metric tons for topsides and 25,000 metric tons for jackets.
Delta is in the middle of an “engineering down” campaign to make it clean of hydrocarbons. According to analysts BritBoss, drilling con-tractor Archer is plugging and abandoning Delta’s 40 wells, a program Shell hopes will be completed this year. The company also looks to recover a sediment sample from one of the platform’s storage cells. Analysis of the sediment composition will help it determine whether the sediments should be left in place offshore for safety reasons.
Britannia to host Alder Chevron has fnally committed to developing Alder, a high-
pressure/high-temperature gas/condensate feld in the UK central North Sea discovered in 1975 in 492 ft (150 m) of water. Texaco ap-praised the structure with various wells in the late 1980s and early 1990s, but technology solutions to handle the feld’s characteristics – wellhead shut-in pressure of 9,440 psi (651 bar) and reservoir tem-perature of 152°C (305.6°F) – have only become available in recent years. At one point Chevron considered a Sevan cylindrical FPSO, but the company and partner ConocoPhillips opted instead for a subsea tieback to the Britannia bridge-linked platform, which they jointly operate. GDF Suez is the other partner in Alder.
Atkins and Amec respectively performed front-end engineering de-sign for the subsea facilities and topsides modifcations. Alder will be developed via two wells, with the Cameron/Schlumberger joint ven-ture OneSubsea manufacturing the HP/HT vertical subsea monobore trees and wellheads at its facility in Leeds, northern England. These will connect to a manifold incorporating a subsea high integrity pres-sure protection system, with production tied back to Britannia via a
28-km (17.4-mi), 16-in. pipe-in-pipe system. Technip will design and install both, along with a 28-km (17-mi) hybrid umbilical, with group subsidiaries in the UK manufacturing the hardware. Aker Solutions in Aberdeen will supply the subsea control system.
One main reason the project is going ahead, as Chevron acknowl-edged, is the UK government’s recently introduced tax concessions for challenging HP/HT felds. Further relief measures also persuad-ed the company to go forward with the Rosebank project west of Shetland, which will be the UK’s deepest offshore development to date in 3,600 ft (1,100 m) of water.
In block 23/22b, south of Britannia/Alder, ConocoPhillips has prov-en a new gas accumulation in the Lacewing structure. The well encoun-tered a gas column of over 100 ft (30.5 m). Studies are under way to determine whether the fnd is commercial, said partner Premier Oil.
ExxonMobil terminates frontier Ireland wellExxonMobil has pulled the plug on Ireland’s frst deepwater well
on the Dunquin North prospect in the southern Porcupine basin. The location is 170 km (105 mi) from the southwest coast in around 1,700-m (5,577-ft) water depths. Drilling started in late April on the structure on the northern fank of a 700-sq km (270-sq mi) intra-basinal ridge system. Operations were terminated in mid-July after drilling through 800 ft (244 m) of porous carbonate reservoir.
Initial analysis suggested the reservoir was water-bearing, al-though partner Providence Resources put a positive spin on the result, suggesting that oil shows in sidewall cores and elevated gas levels pointed to oil which may subsequently have leaked. Pre-drill studies had indicated that the basin might be gas prone. The Dun-quin South structure might be a better bet because of its thicker seal, the company said.
Among other recent frontier wells on the Atlantic Margin, DONG Energy has discovered gas in the Cragganmore prospect in block 208/17, west of Shetland, although its other well, in the Glenrothes structure in block 208/11, was dry. The drillship West Navigator drilled both. In the Norwegian sector of the Barents Sea, Total’s 7225/3-2 appraisal well on the Norvarg feld confrmed a gas discovery there, but perhaps in smaller volumes than anticipated. The semisub Leiv Eiriksson performed two production tests in the upper and lower parts of the Triassic Kobbe formation of Norvarg’s eastern segment. Re-sults indicated that the structure is extensive, but reservoir quality is variable.
Wintershall takes over at BrageWintershall has completed an asset swap with Statoil that in-
creases its production offshore Norway to almost 40,000 boe/d. The transaction includes stakes ranging from 15%-32.7% in the producing Gjoa, Vega and Brage felds, and in Brage’s case, Wintershall’s frst operatorship of a large production platform in the Norwegian sector.
In exchange, Statoil took Wintershall’s 15% interest in the Lundin-operated Edvard Grieg development in the Utsira High region of the North Sea and fnancial compensation of $1.35 billion. This could rise by a further $100 million, contingent on future development work on Vega.
Another foreign operator, Canada’s Talisman Energy, has decided to withdraw from E&P offshore Norway and has started a sales pro-cess for its various assets. These include the operated Varg feld in the North Sea; production from the Veslefrikk and Gyda felds; and op-eratorship of the Yme feld, where the newbuild mobile offshore pro-duction unit (MOPU) has to be decommissioned and scrapped after defects came to light during the protracted commissioning campaign offshore. Contractor SBM Offshore has agreed to pay $470 million to cover termination of existing agreements, arbitration procedures, and decommissioning. The MOPU is due to be transferred onto a barge no later than 2016, with SBM transporting it to a yard for scrapping. •
Artist’s impression of the Pieter Schelte. (Image courtesy Allseas).
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1309off_17 17 9/4/13 4:30 PM
G U L F O F M E X I C O Bruce Beaubouef • Houston
18 Offshore September 2013 • www.offshore-mag.com
Safety incidents on the rise, new regulations to come
A handful of safety incidents dominated the news about Gulf of Mexico operations in July, including two well control events, one of which included a fre on a jackup rig. And in mid-Au-gust, Black Elk Energy reported the fndings of a third-party investigator that examined the causes of an explosion and fre last November on its oil production platform. These incidents stand as a reminder to the complexities and potential dangers of offshore operations.
On July 9, the US Coast Guard and the Bu-reau of Environmental Enforcement (BSEE) responded to a report from Energy Resourc-es Technology (ERT) about a loss of well control at Ship Shoal block 225 Platform B. The report, from the facility 74 mi (119 km) southwest of Port Fourchon, Louisiana, said all personnel were safely evacuated.
Work on a temporary plug at well B2 had been ongoing when the event was noticed. Two other wells on the platform were also subsequently shut-in. BSEE and Coast Guard responders performing overfights reported that natural gas was fowing from the well, and that there was a rainbow sheen.
By mid-July, ERT said that it had stopped the gas leak. The company continues to monitor the well. The well was contained by pumping drilling fuids into it, as approved by the BSEE.
ERT has submitted further plans and pro-cedures for BSEE approval regarding a per-manent seal of the well.
Perhaps most notable was the fre that occurred on the Hercules 265 jackup drilling rig in South Timbalier block 220. On July 24, the BSEE confrmed that a fre had oc-curred on the rig, and that gas had ignited the previous night when no one was aboard.
The 250-ft mat-supported cantilevered rig caught fre after it experienced a loss of con-trol of Well A-3 at approximately 8:45 a.m. on July 23. The rig, which was operating for Wal-ter Oil & Gas Corp., was performing comple-tion work on a side track well to prepare it for production. The operator reported the safe evacuation of 44 personnel, with no injuries.
The BSEE and US Coast Guard estab-lished a command center for response to the well control event. Following an overfight, the BSEE reported that there was a cloud of natural gas above the rig, and that a light sheen on the water was “quickly dissipating.”
A frefghting vessel was deployed to the location with both water and foam frefghting abilities, and Hercules Offshore hired Wild Well Control to halt the gas leak. In addition, the Rowan EXL-3 jackup drilling rig was deployed to the site to perform plugging operations.
BSEE approved Walter Oil & Gas’ permit to drill a relief well designed to target the original problem borehole. Once it reaches that well, the relief well will be used to pump drilling mud, followed by cement to secure the well.
On July 25, the BSEE reported that the gas fow at the Hercules 265 had been stopped. Ac-cording to the agency, the well had bridged over, with only residual gas left burning. Hercules Offshore said the rig remained standing, but the derrick package appeared to have been damaged. Further details are pending a return to the rig and platform.
Meanwhile, on Aug. 21, Black Elk Energy reported the fndings of a third-party investi-gator that examined the causes of an explo-sion and fre last November on its oil produc-tion platform in West Delta block 32, 17 mi (27 km) southeast of Grand Isle, Louisiana.
The report, written by ABSG Consulting after an eight-month investigation, concluded that the explosion and fre occurred after con-tractors failed to follow standard safety prac-tices. ABSG found that while production was shut in, workers welded on piping that was connected to a tank containing crude oil and fammable oil vapors, without following Black Elk Energy’s safety practices. ABSG was re-tained by Black Elk to investigate the Nov. 16, 2012, incident that resulted in the deaths of three workers and injuries to others.
According to Black Elk, the ABSG report found that:
• On the day of the incident, workers were welding a fange on open piping leading to an oil tank that contained fammable vapors. The piping leading to the tank had not been isolated and made safe for welding activities as required by Black Elk Energy safe work practices.
• Flammable vapors in the piping ignited and within seconds reached the frst oil tank and then two connected tanks.
Black Elk Energy contracted with Grand Isle Shipyard to perform the construction work. According to Black Elk, although Grand Isle committed in its contract not to use subcontrac-tors on Black Elk projects, all of the workers performing the welding involved in the incident were employed by DNR Offshore and Crewing Services, a subcontractor of Grand Isle. ABSG determined that use of the DNR Offshore sub-contractor without notifying Black Elk Energy was one of several causes of the incident.
ABSG also alleged that Grand Isle and DNR Offshore employees failed to adequate-ly follow safe work practices for performing welding and failed to stop work when unsafe conditions existed.
In conducting its investigation, ABSG reviewed thousands of pages of documents and records; collected and preserved physi-cal evidence from the platform; performed fre and explosion modeling of the incident; and used industry-accepted causal analyses to determine the causes of the incident.
Coincidentally also on Aug. 21, the BSEE released for comment a proposed rule of best practices, plus updated regulations on off-shore production safety systems and equip-ment. The proposed 149-page rule will revise 30 CFR 250 subpart H, Oil and Gas Produc-tion Safety Systems.
BSEE says the proposed rule ensures that the regulations governing the use and main-tenance of equipment in subpart H are keep-ing pace with industry’s advancements, and that they address these newer and emerging safety technologies.
The comment period is open through Oct. 21, 2013, and also invites public submissions. Comments can be submitted either online, by mail, or delivered to BSEE. •
The 250-ft (76-m) mat-supported cantilevered Hercules 265 jackup drilling rig caught fire after expe-
riencing a loss of control of Well A-3 in South Timbalier block 220 on July 23, 2013. (Photo courtesy
US Coast Guard)
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1309off_19 19 9/4/13 4:30 PM
S U B S E A S Y S T E M S Gene Kliewer • Houston
20 Offshore September 2013 • www.offshore-mag.com
MWCC establishes GoM base at KiewitThe Marine Well Containment Co. has selected Kiewit Offshore
Services in Ingleside, Texas, to serve as the shore-based location for modular capture vessels for deepwater well control emergencies. This is the second Gulf of Mexico shore base for MWCC.
MWCC’s modular capture vessels are integral to its expanded containment system designed to cap and fow a well in in water depths up to 10,000 ft (3,048 m) with 100,000 b/d of liquid.
AGR Seabed, Marin form allianceAGR Seabed Intervention and Marin have formed an alliance to
combine specialist knowledge and technical experience in route preparation, water clay-cutting, excavation, and recovery.
Unique Hydra delivers its largest-ever air dive system order
Unique Hydra has delivered its largest single order for an air dive system to Subtech Offshore Services. The order included six com-plete SL3.1 air diving controls and chamber systems as well as the relevant SL 3.6 machinery packages.
Not only does the equipment meet the current requirements of IMCA and OGP, but also fulflls the newly proposed IMCA D023 requirements and other FMEA system needs, according to Unique Hydra.
OneSubsea closes formation of joint venture
Cameron and Schlumberger have received all the required regu-latory approvals and have closed the transaction forming the One-Subsea joint venture.
Cameron will have 60% of the venture with Schlumberger holding the remaining 40%. The JV is designed to provide subsea solutions by drawing on Cameron’s history with subsea equipment design and manufacture in combination with Schlumberger’s strengths in reser-voir, well completions, subsea processing, and platform integration.
OneSubsea already has contracted Nexans to design, manufacture, and supply an integrated power umbilical and associated termination hardware for ExxonMobil’s Julia deepwater development in the GoM.
The project includes a 23-km (14.3-mi) long umbilical combining power cables and umbilicals in a single cross-section to be installed in more than 2,000 m (6,560 ft) of water to tieback Julia’s subsea systems to a semisubmersible production unit. Start-up is scheduled for 2016.
Aker Solutions gets agreement for HeidrunAker Solutions has won a frame agreement from Statoil to supply,
refurbish, and store compensation equipment used to stabilize and control the production risers on the Heidrun platform in the North Sea.
The contract includes delivery of new equipment as well as mainte-nance and storage of existing materials. Aker will provide new tapered stress joints and a complete tension system for the Heidrun TLP. Fur-thermore, it includes refurbishment and preservation of stress joints, tensioning cylinders, tensioner frames, and associated components.
The work will be carried out by Aker Solutions’ drilling technologies in Horten, Norway, and the storage will be in Kristiansund.
ROV simulator goes to MoscowMarine Simulation has delivered a ROVsim² O&G training simu-
lator to Educational Systems and Technologies On the River and the Sea Ltd., also known as STORM, in Moscow.
STORM offers IMCA Class A pilot technician grades I and II, and is the frst of its type in Russia. ROVsim² O&G is designed to repli-cate operations of observation and work class systems. It allows for adjustment of the ROV’s physics and dynamics, changes in the video overlay, casualty simulation, and changing of environments. •
Diving advancesCSA Ocean Sciences has deployed its Advanced Diver
Navigation System (above) that includes Shark Navigator, a
self-contained, portable, diver-operated mapping system with
high accuracy positioning. The system makes diver naviga-
tion independent of topside sensors or support vessels, says
CSA. The diver can plot predetermined survey lines, seabed
features, pipeline routes, or any other points of interest. The
system works while also collecting photographs or video.
A Doppler navigation system automatically notes the posi-
tion data in the event the GPS position sensor does not work
because of water depth or wave action.
Unique Systems has delivered the upgraded DNV classed,
1,000-ft saturation diving system HOSS 1 (below) to Ranger
Offshore. The system, with its deck decompression cham-
ber shown here, was increased from a six-man capacity to a
12-man capacity. Unique built the original six-man system for
Ranger in 2010. The system is portable and can be deployed
by either Ranger vessels or a customer’s vessel. The decom-
pression chamber has diving bell access via a hatch at the top
of the transfer lock plus twin mounted manway hatches for ac-
cess to the deck decompression chamber and the hyperbaric
rescue chamber.
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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
22 Offshore September 2013 • www.offshore-mag.com
HESG green lights Q7000Helix Energy Solutions Group is proceed-
ing with the construction of the well interven-tion vessel Q7000. The semisubmersible will be similar to the Q5000, now under construc-tion at Sembcorp Marine’s Jurong Shipyard and scheduled for delivery in 2015. Terrence Jamerson, HESG’s director of fnance and investor relations, said the Q7000 will have a slightly smaller footprint and was designed for use in the North Sea. In April, HESG an-nounced that the Q5000 will enter service in the US Gulf of Mexico under a fve-year con-tract with BP. The contract is for a minimum of 270 days each year and has options for two one-year extensions.
Technip and DOF awarded PLSV contracts
A joint venture of Technip and DOF will supply four new pipelay support vessels to Petrobras for fexible pipe installation offshore Brazil. The JV was awarded a total of eight con-tracts covering the design and construction of the four pipelay support vessels (PLSVs), which will be carried out by Vard Holdings Ltd. at yards in Brazil and Europe. Delivery of the PLSVs is scheduled for 2016-2017. Technip will earn about $1.8 billion in the deal, while DOF said its share would be about $1.7 billion.
Keppel FELS supplies Mexican market
Keppel Offshore & Marine subsidiary Kep-pel FELS has received two orders worth $206 million each from Mexico’s Grupo R and Uru-guay-based Parden Holding for two newbuild jackups. The KFELS B Class rigs are designed to operate in water depths up to 400 ft (122 m) and to drill to depths of 30,000 ft (9,144 m). Both units are scheduled for delivery in 4Q 2015 and will be deployed offshore Mexico. Keppel FELS has a total of nine jackups under construction for the Mexican market. In Au-gust, the company delivered La Santa Maria, a KFELS B Class rig, to private Mexican frm CP LATINA, which has a second unit sched-uled for delivery in 4Q 2013.
Seadrill feet to swell in 2015-2016
Seadrill has entered into contracts for four newbuild ultra-deepwater drillships to be deliv-ered in the second half of 2015 at a cost of about $600 million each. Two of the drillships will be built at Daewoo Shipbuilding & Marine Engi-neering, and two will be delivered from Sam-sung Heavy Industries, both in Korea. The drill-ships will have a hook load capability of 1,250 tons and a water depth capacity of up to 12,000 ft (3,658 m). Two of the vessels have options to include equipment for 20,000-psi BOP systems.
Seadrill also signed a contract with Dalian Shipbuilding Industry Offshore for the con-
struction of two newbuild high-specifcation jackups. The two new units are scheduled for delivery in 2Q and 3Q 2016 at a cost of $230 million each. Both will be based on the F&G JU2000E design, with capacity to drill up to 30,000 ft (9,144 m) in water depths up to 400 ft (122 m).
Tullow taps Modec for TEN FPSO
Tullow Oil and its partners in the TEN de-velopment offshore Ghana have selected Mo-dec to provide the project’s FPSO, a conver-sion of the crude oil tanker VLCC Centennial
J, scheduled for delivery in 2016. The FPSO will draw production from the Tweneboa, Enyenra, and Ntomme felds in the Deepwa-ter Tano area offshore Ghana, where water depths average 1,500 m (4,921 ft). The FPSO will be capable of handling expected plateau production of 80,000 b/d of oil, 170 MMcf/d (4.8 MMcm/d) of gas, and will have storage for 1.7 MMbbl of total fuids.
EMAS AMC lines up Etame expansion work
EMAS AMC’s newbuild Lewek Constella-
tion and the Lewek Express have been hired
by Houston’s VAALCO Energy for construc-tion work at the Etami Marin feld expan-sion offshore Gabon. Work scope includes the engineering, procurement, installation, and construction of rigid pipelines along with the transportation and installation of fexible pipelines and two fxed production platforms. The contract is worth about $120 million; offshore operations will begin early next year.
IHC Merwede reels in pipelay vessel orders
IHC Merwede has secured orders worth more than $1.3 billion for the design, engi-neering, and construction of six pipelay ves-sels. Three of the vessels, along with a pipe-laying simulator, will go to Seabras Sapura, the partnership between SapuraKencana and Seadrill. The other three vessel orders are from Subsea 7, which is set to take delivery of the Seven Waves pipelay vessel in the frst half of 2014. Like that vessel, the new ships will be 146 m (479 ft) long and capable of install-ing fexible fowlines and umbilicals in water depths up to 3,000 m (9,843 ft). All six vessels will be built in the Netherlands with deliver-ies spread throughout 2015 and 2016. •
Allseas’ Pieter Schelte, shown under construction at Daewoo Shipbuilding & Marine Engineering in Korea, will launch its career under contract to Shell U.K. The single-lift installation and pipelay vessel will assist in the decommissioning of the North Sea Brent field with the removal and load-in to shore of the topsides on three Brent platforms with an option to do the same with the fourth platform. The contract includes the removal of Brent Alpha’s steel jacket. The Brent field, which started pro-duction in 1975, is northeast of Lerwick, Scotland, in 140-m (460-ft) water depths. The Bravo, Charlie, and Delta platforms are gravity-based concrete structures; topside weights on the four platforms range from 16,000 to 30,000 metric tons. Removals will start with Brent Delta in 2015-2016; the entire job is expected to take about eight years. (Photo courtesy Allseas)
1309off_22 22 9/4/13 4:30 PM
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D R I L L I N G & P R O D U C T I O N Dick Ghiselin • Houston
24 Offshore September 2013 • www.offshore-mag.com
Study suggests sea change in facilities services
A recent benchmarking study of 15 rel-evant companies indicates that times may be changing for those requiring or provid-ing construction, maintenance, and upgrad-ing services for offshore facilities. Whereas Gulf of Mexico operators typically engage a number of companies to provide individual services on their platforms or foating pro-duction facilities, overseas operators often have a preference for single source suppliers.
An unbroken chainAt the heart of the overseas operators’ deci-
sions to limit participants that provide opera-tions, maintenance, and asset integrity manage-ment support of production facilities is a trend toward maintaining a “chain of accountability” among related projects. One executive of a ma-jor international oil company remarked, “We used to follow a policy of choosing the best of a wide variety of service providers. This resulted in large numbers of companies who provided specialty services. When everything went well, we felt we were getting maximum value for our money. However, if anything went wrong, the fnger-pointing began, and we were unable to determine accountability for the problem or its solution.”
The executive went on to explain that choosing a single source provider to cover related services established a clear chain of accountability for quality, logistics, safety, and effciency that represented real value, often-times exceeding the collective value provided by numbers of individual providers.
In the Gulf of Mexico, post-Macondo, the study revealed an emerging interest in single source suppliers to provide operations and main-tenance or asset integrity services for production facilities. In fact, large, integrated service provid-ers have begun to advertise “solutions” instead of “products.” They recognize that busy opera-tors want complete solutions to challenging is-sues, not a bunch of “widgets” that may or may not be easy to integrate into a solution.
Outsource or insourceRobert Peebler, former CEO of ION, has
always maintained, “Companies should focus on their core competencies and outsource everything else.” Good advice. But discipline must be observed so the outsourcing does not create an unmanageable tangle of well-meaning, disjointed suppliers. In some off-shore areas, operators outsource all of their operations and maintenance activities to tech-nical services contractors under single con-tracts covering everything from the wellhead to the fare tip. This can make good business sense for many reasons. In some cases, build-ing cumbersome infrastructure to look after production facilities can cause issues when
regional down cycles occur.A few North Sea companies focus on the
issues faced by operators there with the idea of expanding their offerings to life-of-the-asset services. Even though there are myriad tasks associated with initial hook-up and commissioning, or fnal decommission-ing and abandonment, they believe they can provide highly competent, safe crews to per-form all of these tasks under a single banner. The idea of accepting responsibility for the whole job elevates the value they offer be-cause they must excel at each phase of the operation. Because one bad apple spoils the basket, integrators know they must perform well on all tasks because they will be held accountable for all of them.
One global provider of life-of-asset services is Stork Technical Services. Martha Sandia, vice president North America and Caribbean for Stork, said, “In the Gulf of Mexico most opera-tors want to procure individual service contracts, but a few believe there is a greater risk reduction and cost savings in integrated operations and maintenance. Contracts covering inspection and testing, fabric maintenance, rigging and lifting, asset maintenance, and specialist access solu-tions in rope access and confned space entry and rescue are increasing in popularity.”
According to the benchmark study, Sandia’s comments are echoed by oilfeld services pro-viders who already integrate drilling and com-pletion services. They have found that perfor-mance is viewed as more important than price. Interestingly, the key performance indicators of oilfeld and technical services contractors are quite similar: safety, reliability, and availability of an experienced and skilled workforce.
Some common services associated with con-struction, maintenance, and upgrade projects may seem fundamental and within the capabili-ties of existing in-house feld crews. However, there is more than meets the eye to such ac-tivities as non-destructive testing, fabric main-tenance, and bolt torqueing and tensioning. Crews that do not perform these activities rou-tinely do not develop the skills and coordination to do them safely and effciently. Other services
requiring highly-skilled, experienced workers include hot bolt clamping and rope access.
What is left in-house? Operators participating in the study gen-
erally named project planning, management, and oversight of operations as necessary skills to keep in-house. While they agree that it may be desirable to outsource the work it-self, the operators retain the responsibility to plan and oversee maintenance and asset integrity programs. The in-house team often sets the scope, objectives, and standards of performance that apply to the work and then oversee the contractor carrying it out.
For several years, Norwegian operators have gone to great lengths to limit personnel-on-board (POB). They recognized the obvious fact that if a worker is not on the rig or platform there is no risk that worker will suffer an accident or injury. The practice of awarding numerous contracts to specialty contractors, some believe, goes coun-ter to improving safety. If each contractor sends workers and supervisors offshore, then POB numbers soar, not to mention the number of round trips by helicopters and boats to transport them to and from the facility. With integrated op-erations, supervisory personnel, and transport expenses are minimized. Effciency benefts be-cause one company can focus on the overall ob-jective while keeping track of progress on each subset of tasks, separating task groups logically so workfows are conducted smoothly and eff-ciently. And if unforeseen incidents occur, there is no one else to point the fnger at.
A look aheadThe independent Gulf Coast operations and
maintenance study revealed that demand for outsourcing these services will increase in the future. There is little doubt that the develop-ment of deep- and ultra-deepwater assets will require the coordinated skills of all parties involved. A way to minimize safety and opera-tional risk is to consolidate activities to make them less cumbersome to manage, contract, and supply. The chain of accountability is one that cannot tolerate any weak links. •
Experienced offshore specialists practice safety in all phases of their operations, from wearing of
personal protective equipment to rope work. By always setting a safe example, their actions influ-
ence other workers. (Photo courtesy of Stork Technologies)
1309off_24 24 9/4/13 4:30 PM
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1309off_25 25 9/4/13 4:30 PM
G E O S C I E N C E S Gene Kliewer • Houston
26 Offshore September 2013 • www.offshore-mag.com
Atlas Copco goes to Mitcham for seismic use compressors
Atlas Copco Rental has purchased Mitcham Industries’ feet of marine air compressors to be used for rental in seismic applications.
Atlas Copco Rental is also investing in the seismic market through the manufacturing, at Atlas Copco Hurricane, of two new com-pressors: the SBM7, a marine cold seawater-cooled compressor, and the air-cooled SB7.
ION, Polarcus enter survey agreement
In a concurrent move, ION has joined Po-larcus with a three-year agreement to jointly develop, execute, and market 3D multi-cli-ent projects worldwide.
Polarcus brings expertise in the 3D multi-client space to ION’s GeoVentures group’s expertise in geologically driven, basin-scale 2D multi-client surveys.
The collaboration will use ION’s BasinSPAN data library of over 450,000 km to identify new project opportunities worldwide. Further, the combination of Polarcus’ RIGHTBAND acqui-sition proposition and ION’s WiBand data pro-cessing technology will beneft from Polarcus’ feet of 3D seismic vessels.
GX Technology center targets Asia/Pacifc
ION Geophysical has scheduled the open-ing of a GX Technology seismic data pro-cessing center in Perth, Australia, to serve operators in Australia and throughout the Asia/Pacifc region. The new center is to of-fer a full range of seismic imaging services and technologies, including depth imaging and ION’s patent-pending WiBand broad-band processing technology.
Economic growth in Asia/Pacifc drives the need for dependable energy in the re-gion, prompting industry experts to predict an estimated 20% year-over-year growth in E&P capex in 2013, says ION. In 2012 alone, there were 13 offshore discoveries in the area.
Chris Usher, executive VP and COO of ION’s GeoScience division, said: “With the opening of this new center, our 13th around the world, we continue to expand our foot-print into global E&P hotspots. The Australian northwest shelf is in transition from an explo-ration to development phase. Production from these felds will continue for decades, and the challenge will be to monitor and manage feld development for optimum recovery. We found
that our customers operating there have been underserved in terms of high-end, quality seis-mic imaging, and we are pleased to open this center with material backlog.”
Kelly Beauglehole, the center’s managing director, adds, “We have seen a tremendous demand in the region for advanced imaging services, including prestack depth imaging, and high-quality seismic data, including our recently acquired 11,500 km 2D survey of Australia’s northwest shelf, known as Wes-traliaSPAN.”
ExploHUB installs HIIP software
Earthworks Reservoir has agreed with the University of Aberdeen’s ExploHUB training center to provide its prospect evaluation HIIP software. ExploHUB plans to use HIIP in its training course for the prospect evaluation module due to begin this month.
ExploHUB director Stuart Archer said, “Ex-ploHUB is delighted to have forged this partner-ship with Earthworks Reservoir. It provides our trainees with access to leading edge software and technology that will assist with the teach-ing of volumetric assessment in our exploration workfows.” •
SAIC will use MakaiLay Seismic and MakaiPlan Pro Seismic programs to simulate and control
ocean-bottom cable installations and retrievals. Makai Ocean Engineering says MakaiLay
Seismic will help accurately install and retrieve seismic arrays. MakaiLay Seismic builds on the
MakaiLay engine, but adds tools specifically for the seismic industry to accurately install and
retrieve ocean bottom cables (OBC) with many in-line sensors, or node arrays in mid- and deep-
water. MakaiLay Seismic is flexible enough to run on laptops and assimilate information from
SAIC’s collection of cable installation equipment, including Acoustic Doppler Current Profiler
(ADCP) and transponders attached to the cable, and then output vessel navigation and cable
payout instructions for the operators. SAIC submarine cable projects will now use the latest
versions of two different Makai cable software products. MakaiPlan Pro Seismic is a simulation
tool to plan installation and retrieval of OBCs in mid- and deepwater. It enables 3D, dynamic
simulations of the cable installation and retrieval, and can simulate an entire cable lay to test
the feasibility of survey plans. The simulations can be used to test the feasibility of the planned
lays, make equipment selection, train cable engineers, pre-lay and post-lay analysis, and create
a ship plan for installation.
Petroleum Geo-Services (PGS) and TGS are
back offshore East Canada for the third year
to complete acquisition of a 2D multi-client
survey offshore Newfoundland using the
GeoStreamer acquisition technology. The
program this year aims to acquire additional
data over approximately 16,000 line km
(9,942 mi) of the Northeast Newfoundland
Slope. Statoil’s Mizzen discovery (200 MMbbl
recoverable) and a recent discovery of light,
high-quality oil in the Flemish Pass basin at
Harpoon strengthens potential north of the
Jeanne d’Arc basin. Final processed data
from the 2013 acquisition will be available
during the spring of 2014. This will result in a
total of approximately 46,000 line km (28,583
mi) of 2D data acquired and processed in
Newfoundland and Labrador through the
cooperation agreement.
1309off_26 26 9/4/13 4:30 PM
1800 m/s 2800 m/s
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1309off_27 27 9/4/13 4:30 PM
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
28 Offshore September 2013 • www.offshore-mag.com
Tim SheaARC Advisory Group
Accurately measuring multi-phase fow is challenging under any circumstances, but particularly so in today’s increasingly de-manding offshore operating environments.
While not all industry participants are con-vinced that today’s multi-phase/multi-com-ponent fow metering solutions represent a practical or cost-effective solution due to mea-surement uncertainty, initial cost, and other concerns, the technology has clearly been gaining traction since its introduction in the early 1990s. This is due both to technical ma-turity and efforts by independent third par-ties to validate accuracy. Energy companies such as Statoil, PDVSA, BP, and Petrobras are deploying multi-phase fow meters (MP-FMs) on a broad scale to enable continuous measurement of the individual components in co-mingled oil, gas, and water streams.
ARC is investigating both the technical and market issues surrounding this still-emerging technology. Most MPFM solu-tions today employ multiple sensor technol-ogies to provide true physical multi-phase fow measurements, with the most popular combination being differential pressure across venturi and gamma ray attenuation. Typical applications for multi-phase fow meters include well testing, production monitoring, production optimization, fow assurance, production allocation, and fscal metering/custody transfer.
MPFMs are complex systems that are of-ten employed with other instruments such as water cut meters, and pressure and tem-perature transmitters. Some suppliers incor-porate IR absorbance, while others rely on microwave technology for wet gas and water cut metering. While experts mostly agree that MPFM solutions may never reach the accuracy provided by a full separator, but suppliers continue to strive for that objec-tive.
Accurately measuring the multiple compo-nents (typically oil, water, dry gas, and con-densate) in multi-phase fow applications is far more complex than traditional single-phase fow measurement. Since the real opportunity for MPFM solutions lies in convincing users to either replace or complement full separators, MPFM suppliers should focus development and marketing efforts on targeting applica-tions in which MPFMs clearly provide a more attractive option. Opportunities to replace and/or complement separators include:
• Offshore platforms with limited space (assuming the well is productive enough to justify the investment)
• Applications in which heavy oil is pro-
duced• Formations in which the steam-assisted
gravity drainage (SAGD) process is em-ployed in heavy oil and/or oil sand res-ervoirs
• Platforms operating in mature felds in which the well profles change con-stantly and traditional monthly well test-ing is insuffcient
• Fine-tuning artifcial lift solutions such as electrical submersible pumps (ESPs)
• Subsea projects in which the deployment of separators is not feasible and/or MPFM is used as a complementary solution to provide more timely well testing, monitor-ing, and/or fow assurance/allocation
• Any project in which the MPFM will pro-vide suffcient ROI via more real-time information to help enhance recovery or improve production.
When considering MPFMs for a particu-lar application, operators should:
1. Investigate the expected fow regimes from the wells to be measured and deter-mine the production envelope
2. Identify MPFMs with a corresponding measuring envelope
3. Select an MPFM capable of continuous-ly measuring the applicable components and volumes with appropriate (ideally, indepen-dently validated) accuracy/measurement uncertainty for the application
4. Ensure the availability of appropriate onsite resources to allow regular calibra-tion/adjustment and verifcation
On a dollar basis, subsea applications com-pose the largest segment within the overall MPFM market. This is due in part to the more expensive price tag of subsea MPFM solutions, which can range as high as $1 mil-lion or more, but more typically fall between $500,000 and $750,000. In many cases, an MPFM is the only viable solution to make a subsea production project work, since the depths, pressures, and logistics make deploy-ing three-phase separators infeasible.
However, as with most technologies, initial purchase cost is just one component to con-sider. With MPFMs, operating experience suggests that overall lifetime costs can be considerably less than alternate approaches in a variety of applications, due to reduced in-stallation, operating, and maintenance costs.
ARC has found that the greatest inhibitor to more rapid adoption of MPFM solutions is the plethora of different reservoirs and formations, and the variations of types of gas and oil compositions these contain. In most cases, the testing of an MPFM is validated for a specifc reservoir or shale formation and its specifc parameters; the performance of that MPFM may not be validated for another res-
ervoir or formation, which could possess dif-ferent gas and oil compositions, and require deployment of a different pipe diameter or different materials to handle variations, such as a greater presence of corrosives.
Organizations such as the Research Part-nership to Secure Energy for America (RP-SEA), NEL, and DNV KEMA can serve as valued partners for MPFM suppliers and end users alike. Earlier this year, DNV KEMA an-nounced the opening of the organization’s new multi-phase fow lab in Groningen, the Neth-erlands, to enable equipment manufacturers and oil and gas companies to test, validate, and calibrate multi-phase technologies (including both multi-phase separators and fow meters) to ensure the quality of the measurements. The new test lab is designed to recreate the kind of conditions that this equipment faces in the feld, including a full range of multi-phase fuid compositions at realistic temperatures, pressures, and fow rates. Another objective is to accelerate industry efforts to develop stan-dards for equipment and testing protocols, which will be critical for increasing acceptance of the technology.
Research indicates that owner/operators are implementing MPFM solutions for fow al-location – and, in some cases, for fscal meter-ing – in a growing number of subsea projects. As an MPFM product manager at a major oil-feld services company recently commented to ARC, “As long as two parties contractually agree to accept a certain level of uncertainty, then it works. In some cases, there is really no other alternative to make the project work effectively, so it’s either a case of using an MPFM, or no project at all.”
As the technology improves, and new in-dustry standards are developed for MPFM equipment and testing protocols, ARC ex-pects that the adoption rates of MPFM solu-tions will accelerate.
Only a handful of suppliers currently of-fer multi-phase fow meters. But this could change in the future. Based on the current maturity of the technology, the successful feld experience of operating companies in selected applications, the availability of inde-pendent test labs to calibrate products and confrm accuracy, and – in some cases – the sheer lack of alternate approaches, ARC recommends that owner/operators keep an open mind about MPFM solutions. They should ask suppliers to provide contact in-formation for reference clients, and do their own evaluation, on a small scale, of the busi-ness and operational benefts prior to wide-spread deployment.
While not perfect, it appears that MPFM technology can often provide a viable – and in some applications the only – solution. •
Multi-phase fow metering gains acceptance in upstream applications
1309off_28 28 9/4/13 4:30 PM
1309off_29 29 9/4/13 4:30 PM
Quality
Shorterexecutionschedule
Lowercapex
30 Offshore September 2013 • www.offshore-mag.com
A U S T R A L I A
Alternative approach required to contain costs
of remote Australian offshore gas fields
Historically, gas feld developments offshore north-west Australia (NWA) have been founded on large accumulations, in shallow water, with relatively short distances to shore. Sustained production was possible as a result of large, highly pro-
ductive reservoirs.In the search for new gas reserves, ex-
ploration and production companies are ac-quiring signifcant acreages in increasingly remote, deepwater offshore northwest Aus-tralia. Recent discoveries tend to be smaller accumulations, some with signifcant fault-ing and most with varied reservoir compositions, pressures, and temperatures. The regional challenge posed is to achieve cost-ef-fective developments in these marginal environments.
Results from recent development studies illustrate demonstrable relationships between functional design choices and facilities total installed cost (TIC). Challenging these choices through the applica-tion of front-end loading techniques allows the necessary balancing of competing development drivers to achieve an economically viable development.
Offshore oil and gas developments in NWA incur a much higher development cost than in other major oil and gas hubs, such as the North Sea and the US Gulf of Mexico (GoM).
A recent study by the Business Council of Australia compared the costs of resource projects in Australia to the US Gulf Coast. It found a 40% cost premium for resource projects overall, and a 200% increase for offshore oil and gas developments on the back of lay barge and drilling rig costs. Research by Deutsche Bank (2011) found that the current proposed and sanctioned Australian LNG projects are far more expen-sive than recent projects worldwide. Current projects are estimated to cost $2.7 billion per MMtpa compared to $1.7 billion per MMtpa for existing projects (North West Shelf Venture and Darwin LNG) and $1.2 billion per MMtpa for recently commissioned projects globally.
For NWA projects sanctioned to date, the quality and accessibility of gas felds have allowed proftable development despite the cost pressures. The major gas producing felds in the region have large, centralized reserves capable of high productivity wells, and are found in shallow water on the continental shelf or in deeper water in reasonable proximity to shore.
Early project development typically follows this sequence:1. Gather and process feld data2. Defne development rules 3. Brainstorm development concepts4. Conduct preliminary engineering defnition5. Develop cost, schedule estimates, and economic outputs.
Balancing competing driversIn recent years, operators have begun to develop more challeng-
ing, marginal gas felds farther from shore, in deeper water, with distributed reserves requiring a higher number of wells. For many
projects, the application of “typical” engineering methods has resulted in development concepts too expensive to proceed, requiring substantial engineering recycle and cost challenge phases to render the concepts economically viable.
In every development there is a limited pool of available resources – time, money, people, equipment, customers
– and constraints in one or more of these areas always apply. Thus, project developers normally seek a balance
among the three areas of cost, schedule, and quality. Quality in this sense includes increased op-
erability, safety in design, availability, re-duced maintenance downtime, incremen-tal capacity, and provision for expansion.
This trade-off most often focuses on the issues with the most impact on economics (other than reserves and product price),
generally development project capex and schedule. Capex/opex eco-nomic trade-offs usually favor reduced capex, as this has higher net present cost. Schedule defnes the start of project revenue, impacting NPV and IRR.
A project management triangle representing quality, capex, and schedule is a fgurative reminder that there is always a trade-off among the three. Moving toward one goal involves moving away from at least one of the other goals.
Engineers are typically responsible for ensuring that their concepts are technically robust and can stand up to challenge. The business unit, through the project manager, is concerned with creating a vi-able business solution, and focuses on cost and schedule. When the project reaches Stage 5 for a marginal development, cost is typically too high, sending the project into recycle at one of the earlier stages.
When internal recycle and utilization of local engineering resources do not deliver an economic outcome, parallels are often identifed be-tween felds being considered for development in NWA and many de-velopments in the GoM, a region which has had success in developing small and varied accumulations at suffciently low capital cost. By study-ing a number of recent deepwater gas developments, an understand-ing develops of the cost differences between developments in the two regions. Correct framing in the feasibility and select phases of a project can achieve lower cost outcomes while minimizing engineering recycle.
MethodologyA case study was initiated comparing development of a feld in
NWA (Case A) to a fctional equivalent in the GoM (Case B). The two developments were identical in terms of:
• Reservoir size, depth, and characteristics• Gas and condensate production rates• Formation water production rates• Distance from shore• Water depth• All wells were subsea, with tiebacks to an infeld foating facility.Drilling and completioncosts were excluded as these were essen-
tially non-differentiating within the study framework.Cost differentials between cases A and B were divided into two
main categories: Regional and Design Choice. Regional differences are a function of the geographical location
Martin StewartGranherne
Competing drivers
as illustrated in a
simple triangle diagram.
1309off_30 30 9/4/13 4:31 PM
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Case B
100 100
25
59
Case A
Design choice200
180
160
140
120
100
80
60
40
20
0
NWA regional
GoM standard
32 Offshore September 2013 • www.offshore-mag.com
A U S T R A L I A
of the feld. Any project has limited capacity to infuence these vari-ables. Key regional differences include: geotechnical and metocean conditions; regulatory framework, applicable statutory codes and standards; and transport, freight, and installation vessel costs.
Design Choice covers every element that is not region-specifc, in-cluding: topsides design philosophy; equipment sparing; material selec-tion; subsea architecture; fow assurance strategy; contracting strategy; installation methods; and materials and equipment procurement costs.
Material and equipment procurement costs are considered a de-sign choice; transport and import tax aside, they are largely driven by the commercial arrangements, tendering processes, and techni-cal specifcations used.
With the cost differentials identifed, further examination into each was conducted to understand the reason behind the difference and to identify the conditions under which the GoM approach and cost might be applicable in NWA.
Results
The comparison determined an 85% capex increase from Case B to Case A, indicating strongly that most of the cost difference be-tween the regions is not driven by geographic necessity. However, an equivalent design choice may have a different technical and com-mercial impact in NWA compared to the GoM, thus the lower capex option is not necessarily the preferred choice for a development.
Regional differences explained a 25% cost increase from Case B to Case A, split into three categories: metocean infuence; transport; and installation cost, vessel mobilization, and day rates.
Metocean infuence accounted for less than 10% of the regional dif-ference. Transport costs were slightly lower for Case A due to proxim-ity to fabrication yards in Asia. The impact of regional location on in-stallation costs was, however, overwhelming, accounting for more than 90% of the regional impact. With a limited number of vessels available for deepwater pipelay and subsea installation, the cost of mobilizing and using these vessels is disproportionately high, even with transition time to and from NWA factored in. Moreover, day rates in some instances are several times those in the GoM for the same or equivalent vessels.
Australian maritime requirements and signifcantly higher crew costs account for part of the differential. However, high rates for installation vessels in NWA are primarily commercially driven rather than cost driven. In order to minimize installation costs the commer-cial strategy should be examined early in the project life, consider-ing opportunities such as:
• Sharing major installation vessels with another project in the region
• Conditioning design to increase the number of suitable vessels• Negotiating early with vessel owners to select a suitable time
window that ties in well with their other commitments.Design choice accounted for 75% of the cost increase from Case B
to Case A. The context for design decisions is different between the two regions due to several key reasons:
Criticality of supply. Gas felds in the GoM are numerous and feed into a reticulated domestic gas network. An interruption in supply from one feld is easily accommodated by other felds. An outage will result in deferred revenue, but minimal contractual or reputation impact.
Conversely, the distance of the NWA felds from their end users means that all but the smallest gas felds feed in to LNG production, with any given feld typically providing a large proportion of supply to an LNG plant. An offshore outage could easily result in an onshore shutdown. LNG end-users demand a very reliable supply, and failure to meet a cargo can have substantial contractual penalties and reputation impact. Demurrage of waiting tankers may also add signifcant cost.
Supply chain. The supply chain for equipment, skilled vendor per-sonnel and installation vessels is substantially stronger in the GoM, resulting in much shorter times for major repairs on a platform or subsea system and corresponding greater reliability required for the same availability for the equivalent design in NWA.
Regulatory environment. GoM operators follow Code of Federal Reg-ulations (CFR) and API recommended practices. Many operators will surpass these minimum requirements with their own company codes and standards. As well as meeting prescriptive guidelines, Australian companies operate under a safety case regime, with quantitative lim-its, qualitative goal setting, and requirements for continuous improve-ment. This type of regime places an onus on the operator to drive “as low as reasonably practicable” (ALARP) outcomes within the tolera-ble risk range, resulting in a greater drive to achieve inherent, built-in safety. The GoM tends to rely more heavily on operating procedures and mitigation to manage risk within tolerable limits.
The impact on cost of the different regulatory environment is diffcult to assess, as it is embedded into other design decisions. Company codes and standards also vary substantially within each region. Regulation-based cost drivers primarily manifest themselves in hull design, subsea and topsides equipment procurement costs, and topsides segregation for safety.
It is important to note that, in the post-Macondo era, the regula-tory environment in the Gulf of Mexico has changed substantially, although the increased regulatory progress has not yet adopted a Safety Case regime. The analysis in this paper does not account for any changes resulting from that incident.
Outcomes
Design choice differences accounted for a 59% cost increase from Case B to Case A, broken down as follows:
SURF design (16.7%). Subsea, umbilical, riser, and fowline (SURF) design (including export system) proved the greatest difference in design approach between Case A and Case B. The GoM design has a substantially lower capex due to less expensive materials selection and simpler, less versatile subsea architecture.
The materials selection was driven by the level of conservatism in temperatures required to initiate unacceptable corrosion levels for a given composition. Case A adopted the more robust choice of corrosion resistant alloys (CRA), whereas Case B judged that car-bon steel with a reasonable corrosion allowance and use of chemical inhibition was suffcient to maintain integrity throughout the design life. The cost impact of CRAs is profound, both in procurement and in signifcantly extending pipelay duration.
Process design (15.0%). Different approaches in topsides process
Regional and design choice impacts on project capex.
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A U S T R A L I A
design were a substantial driver of cost. The difference is largely due to the level of con-servatism in design and willingness to impact operability and take on risk in order to keep costs low. The key reasons that the Case B process design is cheaper and lighter are:
• Lower calculated MEG requirement for hydrate inhibition in the fowlines due to lower uncertainty margins
• Reduced sparing of key equipment, no-tably gas compressors with no sparing in Case B, which uses a larger number of small, easier to repair or replace com-pressors
• Lack of dedicated surge vessels, relying on minimal surge volume allowance in inlet separators
• Pressure rating of inlet system: Case A uses early feld-life pressure to reduce compression energy requirements, whereas Case B rates piping and vessels for late feld-life pressures, relying on compressors running near full capacity from start-up. Case B requires reducing pressure at the topsides to prevent over-pressure in early- to mid-feld life.
Commercial assumptions (13.3%). Com-mercial assumptions, in this context, are the rates and norms used to derive the estimated cost of materials and equipment across the development. Due to the relatively high level cost-estimating in the development planning and concept select phases, it is not feasible to quantify the drivers behind these differences.
It is apparent, however, that the engineering estimates for both cases were derived as fairly similar percentages of procurement costs, and that item-specifc equipment costs tended to be higher for broadly equivalent items in Case A than Case B, understood to be caused by increased levels of technical specifcation for custom design, increased vendor quality assur-ance document obligations, and increased cli-ent involvement during tendering, design, and fabrication.
Topsides weight estimation (6.3%). Top-sides weight estimates for each case were factored from equipment weights using his-torically derived regional benchmarks. For a given equipment list, the NWA weight esti-mate was higher, due to factors that include:
• Lower platform density. Typical overall deck area to equipment footprint revealed ratios of roughly 5:1 in NWA versus 3:1 in the GoM. The difference in footprint is also seen in the weight-to-area ratios, with GoM norms of 1.5 metric tons/sq m much higher than a typical 1.0 metric tons/sq m in NWA. The increased deck area results in more piping, cabling, and structural steel.
• Installation constraints. Topsides instal-lation in the GoM is normally conduct-ed by quayside or offshore heavy-lift
Application of lessons learned from the comparison should result in a more balanced marginal
field development solution.
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ENGINEERED FOR
EXTREMES
INTEV
I
A U S T R A L I A
cranes/vessels with a current maximum capacity of about 10,000 metric tons, thus driving topsides weight to stay with-in that limit. Heavy lift at that capacity does not exist in NWA, and foatover in-stallation is the norm for large platforms, with a limit of more than 20,000 metric tons (installed) and more than 30,000 metric tons (planned). The absence of a hard limit reduces incentive to minimize weight growth through design.
• Higher design pressures. NWA design pressure at inlet tends to be higher to better use early feld-life pressures, and gas is compressed to a higher pressure for export due to longer distances to end destination. The higher pressures drive up piping and vessel weights.
Hull and mooring design (2.9%). Having ac-counted for different metocean conditions, a signifcant difference in hull and mooring design results from the storm design crite-ria. Case A designed for survival at 10,000-year storm condition, whereas Case B de-signed for 1,000-year storm condition.
Weight impact on hull design (2.5%). The higher topsides weight of Case A resulted in an associated increase of the hull design steel requirements.
Accommodation (2.3%). The difference in accommodation weight and cost was rough-ly equally split between the higher estimat-ed number of people on board in Case A, and differences in scope of building content, building standards, and interior fnishes.
Observations
The results of this analytical work show that demonstrable relationships can be developed between individual design choices and feld facilities TIC. The cumulative effect of many design choices creates signifcant differences in overall estimated TIC. The major beneft of identifying these differences is to highlight the importance of the relationship between various technical and commercial development requirements and TIC. Understanding these relationships assists the feld developer in mak-ing the appropriate choices.
Specifc learnings that should be consid-ered during feasibility and concept stages for marginal deepwater developments are found-ed on a principle of “justify in” rather than “jus-tify out” and include:
• Minimize deviation from vendor stan-dard equipment
• Trade sparing of large and expensive equipment for capacity-based multiple smaller units to achieve design capacity
• Assign inlet system design pressure to lowest piping class above end of plateau rate inlet pressure
• Avoid adopting multiple layers of margins (e.g. for estimating MEG requirements)
• Adopt minimal functionality of subsea architecture only
• Critically assess any requirement to de-viate from carbon steel for subsea hard-ware, fowlines, and risers.
Arrangements that reduce the cost of in-stallation vessels should be considered early as these may impact project schedule.
Application of these learnings should result in a development solution that sits somewhere between the two bookended ap-
proaches. Design choices suitable for the Gulf of Mexico are unlikely to suit off north-west Australia; however, some modifcations in scope and quality will need to be made for projects to become economically viable. •
References
Business Council of Australia. (2012). Pipeline or Pipe Dream? Securing Australia’s Investment Future.
Deutsche Bank. (2011). Austraia Energy Sector: The Australian LNG Handbook.
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36 Offshore September 2013 • www.offshore-mag.com
A U S T R A L I A
A public row has erupted Down Under between local elected offcials, most prominently WA Premier Colin Bar-nett, and proponents of foating lique-fed natural gas (FLNG) technology
as a development solution for the west’s vast offshore gas resources. The backdrop: skyrocketing labor and construction costs, coupled with new competition with likely fu-ture LNG exports from North America and East Africa that could derail several planned LNG developments, along with the new on-shore liquefaction plants and the jobs they would bring.
While LNG demand, particularly in Asia, is expected to remain strong over the next decade, increased capacity could make it tougher for operators to land the long-term supply contracts needed to fnance large-scale LNG projects, particularly greenfeld develop-ments like those offshore Western Australia. According to a recent report from Ernst & Young, high LNG development costs “will re-quire ironclad long-term off-take agreements. But more recently, the market is witnessing the inherent confict of increasingly more ex-pensive projects trying to sell to increasingly more price sensitive buyers…As substantial volumes of lower-cost LNG move into Asian markets, projects at the high end of the supply curve – namely, many of the Australian proj-ects – will become increasingly vulnerable.”
In April, Australia’s Woodside Petroleum shelved plans for the $45-billion Browse LNG development, which included a three-train processing facility at James Price Point. Say-ing the development concept “did not meet the company’s commercial requirements for a positive fnal investment decision,” Woodside promised to explore other options, including FLNG. Some analysts had speculated that the fnal cost for the James Price Point op-tion could be double the original estimate. “Browse is a world-class resource and it will be developed,” CEO and Managing Director Peter Coleman said at a conference in Mel-bourne last month. “But only at the right time, in the right way, to ensure maximum return to our shareholders.”
Barnett was “bitterly disappointed” by the decision. “I recognize Woodside has a re-sponsibility to its shareholders, however my obligation is to the people of Western Austra-lia, and this decision does not beneft them.” The Premier raised doubts about the safety of
FLNG and the thousands of construction jobs that would have followed the James Price Point development.
Despite the engineering and technologi-cal challenges, FLNG projects could be con-siderably less expensive than shore-based hub developments, chiefy because much of the equipment can be fabricated in Asian shipyards. In March, ExxonMobil submitted documents to Australian authorities seeking environmental approval for an FLNG devel-opment at the Scarborough feld, which the company operates in a 50-50 partnership with BHP Billiton. Plans include a 495-m (1,624-ft) long by 75-m (246-ft) wide foating production facility. A fnal investment deci-sion is expected in 2014 or 2015, with frst production possible about 15 years later.
Work under wayThe Scarborough facility will be slightly
larger than the massive substructure for Shell’s Prelude, now under construction at Samsung Heavy Industries in Geoje, South Korea. Prelude is on track to become the world’s frst FLNG development, and the big-gest offshore foating facility, when it goes into production around 2017. The foater will have an annual production capacity of 5.3 MM metric tons of liquids, 3.6 MM metric tons of LNG, 1.3 MM metric tons of conden-sate, and 0.4 MM metric tons of LPG.
Construction has begun in Darwin on the Prelude onshore supply base, Shell said. Work continues in Dubai on the 93-m (305-ft) high turret mooring system by SBM Off-shore. The system will be shipped to Geoje in fve pieces. More than 1,600 “blocks” – the large steel structures that will form the hull – have been built so far. Shell will use the Noble
Clyde Boudreaux semisubmersible to conduct the Prelude drilling program, which calls for seven development wells.
Three other greenfeld projects offshore Western Australia currently under develop-ment – Inpex Corp.’s Ichthys, and Chevron’s Gorgon and Wheatstone developments – will include onshore LNG processing.
With a steel-cutting for the FPSO hull at the Daewoo Shipbuilding & Marine Engineering yard, in June, all of Ichthys’ major offshore
elements are under construction. The vessel will be used for condensate dewatering, stabi-lization, storage, and export. In January, con-struction began on the development’s central processing facility, also at SHI’s Geoje yard. Inpex claims that the platform, at 150 m by 110 m (492 ft by 361 ft) will be the world’s largest semisubmersible.
Also in January, work began in Singapore on the SBM Offshore-supplied turret for the FPSO. Ichthys will export gas to a process-ing facility near Darwin via an 883-km (549-mi) subsea pipeline. Inpex plans to ship the frst LNG cargo by the end of 2016.
Work continues on the offshore and on-shore facilities for Gorgon, which will include a three-train, 15.6-MMtpa LNG facility on Barrow Island. Twenty-four caissons have been placed for the 1.3-mi (2.1-km) LNG jetty. Farther offshore, subsea umbilicals have been installed connecting Barrow Island and subsea equipment at the Gorgon and Jansz-lo gas felds. In August, Allseas’ Solitaire pipelay vessel was installing the 34-in. production pipeline to the Jansz-lo feld.
Last year, the projected cost of Gorgon rose by about $9 billion to $52 billion. Chev-ron plans to ship its frst cargo in 1Q 2015.
The Wheatstone onshore facilities at Ash-burton North near Onslow will include two LNG trains with a combined capacity of 8.9 MM tpa, with the possibility of expansion to 25 MM tpa. First LNG is expected in 2016. Four-ffths of initial production will come from the Chevron-operated Wheatstone and Iago felds; the re-maining 20% will be gathered from the Julimar and Brunello felds, which are being developed by Apache Corp. and KUFPEC. A processing platform installed in 73-m (240-ft) water depths will connect to the shore via a 225-km (140-mi) trunkline measuring 44 in. in diameter. •
Russell McCulleySenior Technical Editor
In May, workers at the Samsung Heavy Indus-
tries shipyard in Geoje, South Korea, laid the
keel for Shell’s Prelude floating LNG project.
When complete, the 600,000-metric ton facility
will be moored in 250-m (820-ft) water depths in
Australia’s Browse basin. With first production
expected around 2017, Prelude is on target to be
the world’s first FLNG development.
Australia LNG projects advance
despite escalating costs
1309off_36 36 9/4/13 4:31 PM
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38 Offshore September 2013 • www.offshore-mag.com
M I D D L E E A S T
Offshore Middle East
E&P activity remains robust Developers look to expand presence offshore Israel
The Middle East continues to be one of the world’s most ac-tive offshore regions as operators, developers, and state oil companies continue to advance plans for new and existing exploration and production projects.
New drilling campaigns are taking place offshore Saudi Arabia; feld development is occurring off Iran; and enhanced re-covery efforts are being implemented off the coast of Qatar, all in an effort to meet regional and international oil and gas demands.
Meanwhile, offshore Israel is shaping up to be one of the hottest development areas in the region, as it continues to attract invest-ment from operators and E&P frms. The following is a brief over-view of activity across the Middle East.
Offshore Israel, Noble Energy says the Tamar production com-plex became fully operational during 2Q 2013, with uptime reliabil-ity of more than 99%. Israel’s gross gas production averaged 676 MMcf/d (19 MMcm/d), with Tamar contributing 636 MMcf/d (18 MMcm/d), with a single-day production high of 784 MMcf/d (22 MMcm/d) during the period. There are plans to expand the Ash-dod onshore reception terminal, which handles Israeli gas produced offshore.
Noble estimates resources at this year’s offshore Karish discov-ery in the 1.6-2 tcf (45-57 bcm) range. Total gross mean resources in the Levant basin now stand at around 38 tcf (1.1 tcm).
The Tamar feld development is probably the most well-known project offshore Israel, but there are others. Recently, partners in the Gabriella license offshore Israel agreed to resolve their disputes over their respective funding obligations. The disputes caused drill-ing of a frst exploratory well to be suspended earlier this year.
Under the settlement and release agreement, Adira Energy, Modi’in Energy, and Brownstone Energy will waive and release each other from any claims and demands they have with respect to the license. Additionally, they will fund their proportionate share of costs in connection with the attempted drilling of the frst well.
The agreement also gives the partners rights to participate in any farm-out of their interests in the concession realized by the other members, for a period of one year. Adira also agrees to relinquish its 15% buy back option and management fee, and reduce its overriding royalty interest to 2.625%.
Adira has applied to Israel’s Ministry of Energy and Water for an extension of the date for execution of the drilling contract to Feb. 28, 2014, and for the spud of the frst well to Dec. 31, 2014.
As for the offshore Yitzhak license, the company is seeking exten-sion to Sept. 30, 2014, to sign a drilling contract and to June 30, 2015, to spud of the frst well.
Elsewhere offshore Israel, Modi’in Energy has revised its re-source report for the Yam Hadera license. Following re-interpreta-
tion of seismic data, consultants Netherland, Sewell & Associates claim that Yam Hadera could hold up to 208 MMbbl of recoverable oil and 3.4 tcf (96 bcm) of natural gas, with a geologic probability of success of 17%-29% for different horizons. The location is 30 km (18.6 mi) from the coast, between Hadera and Haifa and northwest of Adira Energy’s Gabriella and Yitzhak licenses. Adira has an op-tion to take a 15% interest in the concession.
The growing opportunities offshore Israel have individual frms looking to expand their presence there either by acquiring more acreage, or investing in companies already operating in the area. An example of the latter could be seen in July, when Pelagic Invest-ments (PI) announced that it agreed to acquire shares in offshore Israel exploration specialist Adira Energy. PI is an investment group managed by Prentis B. Tomlinson, who also owns Cayman Islands-based Pelagic Exploration, which holds interests in various licenses offshore Israel. Tomlinson said of Adira: “The development of the company’s interests in the Gabriella and Yitzhak licenses provide a unique opportunity to access a material stake in large contingent and prospective resources in highly fractured Middle Jurassic car-bonates on these Syrian Arc structures.”
Developers are also making plans to commence new drilling cam-paigns in the region. Asia Offshore Drilling reports that it has taken delivery of its third newbuild jackup drilling rig from Keppel FELS in Singapore, and is now mobilizing the AOD III offshore Saudi Ara-bia, to start a three-year contract with Saudi Aramco. Seadrill is man-
Bruce Beaubouef
Managing Editor
The Tamar production complex, located in Israel’s exclusive economic
zone in 5,600 ft (1,700 m) of water, became fully operational during
2Q 2013 after four years of development work. (Photo courtesy Noble
Energy)
1309off_38 38 9/4/13 4:31 PM
1309off_39 39 9/4/13 4:31 PM
WWW.DAMEN.COM | [email protected] | +31 183 63 99 11
THE DAMEN PSV 3300NEW DESIGN, RECENTLY DELIVERED, ALREADY AT WORK
40 Offshore September 2013 • www.offshore-mag.com
M I D D L E E A S T
aging the operations of this rig, as well as the previously delivered AOD I and AOD II, which also are working for Aramco.
Field development is proceeding in several areas, with activities heating up offshore Iran in particular. Kish Oil Co. and the Iranian Research Institute of Petroleum Industry (RIPI) were expected to fnalize a development plan in August for the offshore Tousan oil feld.
According to Mahmoud Zirakchianzadeh, managing director of Iranian Offshore Oil Co. (IOOC), the plan is to deliver production of 7-10,000 b/d of oil under a frst-phase development, eventually build-ing to 25,000 b/d. There will be four wells, one offshore platform, and a 30-km (18.6-mi) pipeline transporting production for treat-ment onshore. Sazeh Co. is responsible for facilities design.
Zirakchianzadeh, speaking to news service Shana, added that the buyback contract for the feld will be implemented within 36 months.
Tousan, discovered by Petrobras, is southwest of Qeshm Island in the Persian Gulf, and extends to Iran’s maritime border with the United Arab Emirates. It holds reserves of around 400 MMbbl, with 25% considered recoverable.
IOOC plans to develop the Qeshm region into an oil and gas hub by building infrastructure to support development of the offshore Hengam, Tousan, Northwest Tousan, Taftan, Hormozha, Gorzin, Salkh, Dostko, and Forouz A and B felds.
Offshore Qatar, operators are working to increase and optimize production from older felds. Recently, Occidental Petroleum of Qa-tar and Qatar Petroleum agreed on the Phase 5 feld development plan for the Idd El Shargi North Dome feld (ISND) offshore Qatar.
The two parties have collaborated on the feld since signing a de-
velopment and production-sharing agreement with Qatar’s govern-ment in mid-1994. Their goal is to sustain oil production levels at around 100,000 b/d over the next six years.
ISND’s Phase 5 program includes implementing or improving water-fooding practice in all the feld’s oil-producing reservoirs.
The partners plan to drill more than 200 new production, water injection and water source wells, and to support these wells by in-stalling associated facilities, including minimum facilities platforms, wellhead jackets, fuid processing equipment, and pipeline debottle-necking and water source projects.
In addition, they will implement pilot studies to support produced water re-injection and enhanced oil recovery projects. Total costs could exceed $3 billion.
Under separate contractual arrangements, Oxy Qatar also oper-ates the Idd El Shargi South Dome and Al Rayyan felds in offshore block 12, in partnership with Dolphin Energy.
While development and production activities are ongoing, service providers are making efforts to ensure the region’s existing off-shore facilities maintain their integrity and remain ft-for-purpose. In July, Zamil Mermaid Offshore Services contracted three Saab Sea-eye Panther XT Plus ROVs for a seven-year inspection and repair contract for Saudi Aramco.
According to Neil Howie, Zamil Mermaid’s operations manager, the Panther XT offers a small footprint and an ability to work easily in the 2-knot shallow water currents prevalent offshore Saudi Ara-bia. Additionally, this range is said to handle 90% of tasks normally conducted by a hydraulic work-class ROV. The three ROVs will per-form light construction, inspection, and surveying. •
1309off_40 40 9/4/13 4:31 PM
www.offshore-mag.com • September 2013 Offshore 41
B R A Z I L
Shell leverages experience, technology
development for future offshore Brazil
With the mature Parque das Con-chas and Bijupira/Salema projects entering new phases of produc-tion, their operation continues to provide valuable regional lessons
and innovations for Shell’s future in Brazil, as the government plans for the frst release of the huge Libra feld’s presalt exploration blocks in October.
The long-planned ramp-up at Shell’s two main offshore operations in Brazil sees the Parque das Conchas, also known as BC-10, and Bijupira/Salema projects both heading into second-phase production, with a third phase at BC-10 planned for 2014. The BC-10 project, in partnership with Petrobras and In-dia’s ONGC, is the frst full-feld development to be based on subsea oil and gas separation and pumping. It will also be the site of the frst full life-of-feld 4D seismic monitoring system in Brazil – and the deepest installation of its kind in the world – following a multi-mil-lion-dollar contract with OYO Geospace (now Geospace Technologies) last year. Offshore met with Kent Stingl, the company’s vice president of deepwater production and devel-opment, to learn more about the pioneering techniques being employed to maximize the productivity of Shell’s operations in Brazil.
Offshore: Parque das Conchas and Bijupi-ra/Salema are both mature assets, but how have they followed the planned course up to now?
Stingl: When we frst discovered BC-10 back in 2000, we saw a clear path forward for a two-phase development of the proj-ect. We decided that the Ostra and Argonauta felds would form Phase 1, since combined they could pro-duce close to 100,000 barrels a day. Given the inherent steep decline curve, this made the most sense. Rather than have all the felds come online at the same time and start to produce 250,000 barrels a day, then see it drop sharply down to 50,000, we installed the ... Espirito Santo FPSO and opted for a phased de-velopment. We had a peak of 93,000 boe/d back in early 2010, and that is now in decline, and Phase 2 will come in to produce a peak of around 28,000 boe/d.
The FPSO Fluminense is 10 years old and has produced 100 MMbbl of oil from Bijupira/Salema. We’re now producing around 20,000 boe/d and have just funded the redevelopment well, plus we have a rig that is going to drill four more wells there and boost production up to around 35,000 boe/d.
This third phase, however, was not some-thing we envisaged in the original plans for Parque das Conchas. It was a case of making the best of what we already have, and forms a nice synergy with Phase 2, which will be on-line towards the end of this year. Our brand new, state-of-the-art dual derrick Noble Bully II drillship is fresh out of Singapore, and as soon as it is fnished drilling the Phase 2 wells, it will be deployed for Phase 3.
Offshore: So there is a combination of for-ward planning and having the fexibility to be able to maximize your resources when opportunities arise?
Stingl: Phase 2 production was planned for the end of 2013, but we had a rig in the area, so we thought we would look elsewhere for opportunities within our block, and in 2010 made a further discovery.
This will be our fastest development from discovery to oil (forecast for 2016), and so we named the feld Massa, after the Formula One driver (Felipe Massa). It will have a sub-sea tieback to the Argonauta B-West feld, so it was a natural step and not so techni-cally challenging, allowing it to mature very quickly.
FPSOs are usually brought in as a tem-porary facility to last fve, six, or seven years. But we had Espirito Santo designed to last for 25-plus years, because we knew that, even though there would be a steep de-cline, production life remains very long. That hub design means that you have additional capacity built in, and can explore fresh opportu-nities to fll it.
The timing, then, is such that as Phase 2 starts to decline, Phase 3 comes in to fll a lot of that capacity, so it’s a nice way to maximize the use of the vessel and have a very continuous operation. The timing is perfect to maintain a consistency across the planning of resources.
Doug GrayContributing Editor
The Espirito Santo FPSO entered service at
Shell’s Parque das Conchas development, also
known as BC-10, in 2009, and reached a peak
production of 93,000 boe/d early the following
year. Second and third development phases
are in the works, and a tieback to the newly
discovered Massa field is scheduled for 2016.
(All images courtesy Shell)
Subsea field illustration of the Parque das Conchas (BC-10) development.
1309off_41 41 9/4/13 4:31 PM
B R A Z I L
Offshore: What have been the specifc challenges of the production at BC-10?
Stingl: BC-10 is a weak aquifer/depletion drive, so we had to arti-fcially boost the pressure to improve recovery effciency. What we came up with, along with FMC Technologies, was a system of sub-mersible pumps on the seafoor that give an extra 2,000-psi boost, and which is, in fact, what makes the whole operation economically viable.
To avoid problems from burn-out and corrosion, which can re-quire rig interventions costing $50 million on top of lost produc-tion, we developed MOBOs, or modules of boosting, where several pumps are clustered together to allow for some redundancy. The system has worked fawlessly since we installed it.
Offshore: How do you see the industry right now in Brazil, given the lack of new block leases for the fve years up until 2013?
Stingl: Without the lease, for fve years nobody has had access to these Libra hydrocarbons, but fortunately we had other oppor-tunities to develop in the meantime, which has really helped us and given us time to learn how to operate effciently in Brazil.
Offshore: Will Brazil have the resources to cope with the huge ex-pansion of the industry over the coming decade?
Stingl: Offshore, we use 90% local content. But Brazil has the larg-est new discoveries in the world, and Petrobras is the largest deep-water operator, so they have so much work that the industry cannot train them quickly enough. We really have to be innovative on how we stretch people and train them and get them the skills that they need to mature more quickly.
Wood Mackenzie have been estimating those requirements, and are predicting a need for 10-15 FPSOs for the Libra area alone, and produc-tion rates could be1 MMb/d across hundreds of wells. When you think about them costing $100 million each, and that’s just Libra, and Petrobras already has other developments on production now and expanding, its astounding the growth that’s required for all these developments.
Brazil has a very mature industry today. They’ll always be be-hind, but that’s good in a way because there’ll always be a demand for talent, and it brings steady growth, which is essential. This is a good, steady development program, and these are high-quality oil reserves, so there’s a consistency that helps. •
Shell contracted OYO Geospace, now Geospace Technologies, to provide
full life-of-field 4D seismic monitoring at BC-10, the first such installation in
Brazil, and at 1,700 m (5,577 ft), the world’s deepest to date.
1309off_42 42 9/4/13 4:31 PM
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44 Offshore September 2013 • www.offshore-mag.com
A S I A / PA C I F I C
South China Sea offers
opportunities, challengesBoundary disputes create uncertainty
Offshore E&P activity in the South Chi-na Sea is growing, driven by the poten-tial of its deepwater reserves and the rising Asian energy demand. But the South China Sea also poses develop-
ment challenges, most notably in the form of boundary disputes among China, Vietnam, and the Philippines.
Asian economic growth is driving demand for increased oil and gas production in the South China Sea. The US Energy Information Administration (EIA) predicts local demand for liquid fuels to grow 2.6% annually and that local demand for gas will grow 3.9% annually over the next decade. China, in particular, aims to signifcantly increase its consumption of natural gas by 2020 and the South China Sea, with its potential for new gas discoveries, is a focus area.
Most offshore oil and gas development in the South China Sea is close to shore, but Chi-na has progressively moved into deeper waters, notably in the Pearl River Mouth basin. The po-tential for further development of the region’s deepwater reserves, however, is heightened by the aforementioned border disputes.
The main areas under contention are the Spratley Islands (with a total land area of less than 3 sq mi/7.8 sq km) and other small is-land groups including the Paracel Islands, Pratas Island, and Scarborough Reef. China bases its claim to the islands on historical expeditions and an offcial map with a nine-dashed line published in 1947. Vietnam also claims the Spratly and Paracel islands, and in 1956 the Philippines claimed Scarborough Reef and part of the Spratly Islands.
Current productionMost offshore developments are within the
respective country’s exclusive economic zone. CNOOC is the most active of China’s na-
tional oil companies in the South China Sea and is working with Husky on the Liwan gas feld that has an estimated 4-6 tcf in proved and probable reserves.
As local felds such as Duri and Minas decline, Indonesia’s PT Pertamina is hoping to boost production with new acquisitions in the South China Sea. These include Natu-na’s D-Alpha block and blocks in Vietnam’s
Nam Con Son basin. The Palawan basin is a major source of do-
mestic gas for the Philippines. The Malam-paya platform there is operated by Shell in a joint venture with Chevron and the Philip-pine National Oil Co.
Thailand’s largest oil feld is Chevron’s Benjamas feld in the north Pattani basin. Also in the basin is the country’s largest gas production at Bongkot with BG Group.
PetroVietnam has partnered with a num-ber of foreign companies to develop offshore felds. Chevron currently operates major con-tracts in the Cuu Long and Phu Khanh ba-sins. Other big investors include, Eni, Cono-coPhillips, and French independent Perenco.
Singapore aims to become involved in the South China Sea and has acquired exploration rights to blocks in the Gulf of Thailand, the Pearl River Mouth basin, and offshore Indonesia.
Brunei’s largest oil and gas feld is Cham-pion, and the Southwest Ampa feld accounts for most of the country’s gas production.
China’s energy needsCurrently, 15% of China’s oil and gas
comes from offshore. However, the country is adamant about the South China Sea, says Paul Aston partner at Holman Fenwick Wil-lan Singapore, because its onshore reserves are starting to dwindle. A third of its current reserves are offshore and of these, 33% are in the South China Sea, most in deepwater.
Aston recently returned to Singapore af-ter four years in Shanghai. He says China’s dependence on foreign oil rose to 56.3% last year, and its dependence on natural gas im-ports rose to 21.5%. China will continue to be a major importer, with or without the South China Sea, says Aston. By 2030, its demand for liquid fuels will grow by 70%, and it is ex-pected to be importing 75% of this.
“China is not just interested in the South China Sea. It wants to be a major player off-shore,” says Aston. “It is now competing with the likes of Keppel, Jurong, and Daewoo to be a major builder of rigs, not just for Chinese
Wendy LaursenContributing Editor
South China Sea oil and natural gas, proved and probable reserves, MMboe (Source: US EIA).
1309off_44 44 9/4/13 4:32 PM
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46 Offshore September 2013 • www.offshore-mag.com
A S I A / PA C I F I C
companies but all companies. There are people who say there are qual-ity problems but 20 years ago people said the Koreans couldn’t build LNG vessels, now they build 85% of them. China is building jackups. They are building heavy-lift vessels, pipelaying vessels, and they are building dive support vessels – everything they need to operate as an EPC contractor in competition with companies like McDermott, Sa-puraClough, and Technip.”
China does not yet have the same level of deepwater expertise as some Western oil majors, says Gabe Collins of US analysis initiative China Signpost. He expects China to bring in overseas partners to develop the deepwater assets of the region, and oil majors with big interests in China are unlikely to partner with other countries like Vietnam to develop contentious felds if it means souring relations with China. However, he says, working in confict zones is the nature of the oil and gas industry. “Think of a place like Iraq,” he says. “Or think of a place like Nigeria, or South Sudan. Companies will go into very hostile environments if they think the molecules are there.”
Reserve estimates
The EIA estimate for the area stretching from Singapore and the Strait of Malacca to the Strait of Taiwan is approximately 11 Bbbl of oil and 190 tcf of gas in proved and probable reserves. Most conven-tional hydrocarbons reside in undisputed territory.
However, EIA admits that it is diffcult to make an accurate es-timate because of under-exploration and the territorial disputes. The contested Spratley Islands have virtually no proved or probable oil reserves and industry sources suggest less than 100 bcf of gas. However, a US Geological Survey (USGS) 2010 analysis resulted in an estimate of 0.8 to 5.4 Bbbl of oil and between 7.6 and 55.1 tcf of gas in undiscovered resources.
The contested Paracel Islands do not have signifcant discovered conventional oil and gas felds, and geological evidence suggests the area does not have signifcant potential. However, the area may con-tain signifcant natural gas hydrate resources.
Børre Gunnerud, partner at Wikborg, Rein & Co., says that, as with the reserve estimates further north in the South China Sea, the estimate of 10 tcf of gas in the 27,000-sq km (10,425-sq mi) disputed area between Thailand and Cambodia should be treated with cau-tion. Gunnerud advised the Cambodian National Petroleum Author-ity (CNPA) for several years on the overlapping claim area in the Gulf of Thailand.
“There is very little data,” she says. “The numbers are very sketchy.” The geology is also very fragmented and recovery success may
be as low as 10%.The USGS notes the complexity of the tectonic history of South-
east Asia. This history has included rifting and attenuation of con-tinental crust, opening and closing of ocean basins, development of regional fault systems, and local uplifts. The petroleum systems are mainly Cenozoic basins and the gas is focused into younger, post-rift elastic and carbonate reservoirs.
EIA predicts gas reserves will be more viable than oil in the South China Sea. However, producers would have to construct subsea pipe-lines in areas with submarine valleys and strong currents in deepwa-ter, says EIA. The region is also prone to typhoons, precluding cheap-er rigid drilling and production platforms. Tension leg tethering of production installations and managed pressure drilling to operate in high-pressure deepwater environments may be a way forward.
Energy consultancy Wood Mackenzie estimates only 2.5 Bboe for the South China Sea, and in November 2012, CNOOC estimated 125 Bbbl of oil and 500 tcf of gas in undiscovered resources.
EIA points to the sensitivity of the area for global trade. Approxi-mately 14 MMb/d of crude oil pass through the South China Sea and Gulf of Thailand, almost a third of global oil movement, accord-ing to data from Lloyd’s List Intelligence and GTIS Global Trade Atlas. Around 6 tcf of LNG, over half the global LNG trade, passed through the South China Sea in 2011, according to data from PFC Energy and Cedigaz.
Business as usual
Despite the tensions and uncertainty, there are huge areas of rapid project development in the South China Sea, says Nick Haslam, man-aging director of London Offshore Consultants’ Singapore offce.
“There are also smaller pockets of inactivity – for example, the Gulf of Thailand where little is going on at present, but overwhelmingly the region is a hive of project activity. All told, upstream projects in the South China Sea region can be valued in excess of $26 billion.”
The Malay Peninsula, East Malaysia, Vietnam, and Indonesia probably constitute the areas of highest project concentration. It is diffcult to ascertain reserves in the region but it is reasonable to assume they are abundant, says Haslam. The number of projects active and upcoming in areas such as East Malaysia, the Malay Pen-insula, and offshore Vietnam are evidence of this.
“Brunei is a territory to watch closely,” says Haslam. “Historically, Shell has held an effective monopoly on Bruneian oilfelds. But things are defnitely changing. The country seems keen to engage other en-ergy majors. We have been engaged by Total, for example, to provide warranty services for a development to the northwest of Brunei.”
CNOOC expects 10 new offshore oil and gas felds to come on-stream this year, among which the Liwan 3-1 gas feld will become the frst big deepwater gas feld offshore China. First gas at Liwan is ex-pected late 2013 or early 2014. Liwan has an estimated 4-6 tcf in proved and probable reserves. The Liwan project is in block 29/26,300 km (186 mi) southeast of Hong Kong in the South China Sea, and spans 979,773 acres (3,965 sq km). Husky Energy operates the development
The nine-dash line is the demarcation line used by China for its claim to
territories and waters in the South China Sea. (Source: IISS)
1309off_46 46 9/4/13 4:33 PM
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South China Sea estimated proved and probable reserves
Crude oil and liquids Natural gas Country reserves (Bbbl) reserves (tcf)
Brunei 1.5 15
China 1.3 15
Indonesia 0.3 55
Malaysia 5.0 80
Philippines 0.2 4
Thailand - 1
Vietnam 3.0 20
Note: Reserve totals do not include Gulf of Thailand
or onshore reserves. Reserve estimates are based on
field ownership.
Source: US EIA South China Sea report February 2013
48 Offshore September 2013 • www.offshore-mag.com
A S I A / PA C I F I C
and holds a 49% interest; CNOOC holds the remaining 51%. CNOOC maintains a stake of at least 51% in any offshore development in China.
Additionally, CNOOC will drill around 140 exploration wells, acquire approximately 15,400 km (9,571 mi) of 2D and 24,800 sq km (9,575 sq mi) of 3D seismic data, and will continue to expand deepwater exploration activities. This will involve an investment of over $20 billion. In June 2012, CNOOC offered nine oil and gas blocks to foreign bidders in part of the South China Sea overlapping Vietnam’s 200-mile exclusive economic zone in the Jiannan and Wan’an basins. According to EIA, no foreign companies have publically made a bid.
Chevron acquired new acreage in the South China Sea in 2012 through the acquisition of shallow water blocks 15/10 and 15/28 in a production-sharing agreement with CNOOC. The company also has an interest in deepwa-ter block 42/05, which covers an exploratory area of approximately 1.3 million acres (5,216 sq km), not in contested waters.
Eni has been present in China since 1980 and has 10 licenses there. The company signed a production-sharing contract with CNOOC in 2012 for the exploration of block 30/27 situated approximately 400 km (248 mi) off the coast of Hong Kong. The block covers an area of around 5,130 sq km (1,981 sq mi) in one of the most promising parts of the Chinese offshore sector.
A changing environment“We are always assessing new opportuni-
ties in the region,” says Ron Morris, ROC Oil’s president in China. “In some cases the boundary disputes have had some impact on pursuing and securing new opportuni-ties, but ROC has a rolling 20-year plan so we continually review all blocks. China is an ever-changing environment. Every year is different, every month if not every day.”
ROC is a 19.6% interest holder in the Beibu Gulf Project that achieved frst pro-duction in March. The project partnership also includes Horizon Oil, 26.95%; CNOOC, 51.0%; and Oil Australia (Majuko Corp), 2.45%. The frst phase of the project sees oil production from the Weizhou 6-12 North and 12-8 West felds in block 22/12, about
60 km (37 mi) from the southern coast of China, adjacent and connected to CNOOC’s W12-1 feld complex. The project involves the construction of a jointly owned, purpose-built processing platform and two produc-tion platforms in 30 m (98 ft) of water and their total integration with existing CNOOC infrastructure.
World’s undiscovered natural gas resources, 2012
World’s undiscovered oil resources, 2012
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* Does not include Gulf of Thailand, Indonesia's Java, Borneo and Sumatra basins, or Sulu Sea.
Source: U.S. Energy Information Administration, USGS World Estimate of Undiscovered
Resources 2012, USGS Assessment of Undiscovered Resources of Southeast Asia 2010
Note: Undiscovered resources are mean undiscovered technically recoverable resources.
* Does not include Gulf of Thailand, Indonesia's Java, Borneo and Sumatra basins, or Sulu Sea.
Source: U.S. Energy Information Administration, USGS World Estimate of Undiscovered
Resources 2012, USGS Assessment of Undiscovered Resources of Southeast Asia 2010
1309off_48 48 9/4/13 4:33 PM
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Along with the production commence-ment news came confrmation that the results of the three exploration/appraisal wells drilled on the WZ6-12 North and South structures during 2012 have led to an increase in certainty of the reserves in some of the reservoirs, as well as additions from the discovery of new pools in WZ6-12N and the Sliver prospect. The result is a 25% overall increase in proved and probable re-serves. Upon completion, a total of 10 wells drilled from the WZ6-12 platform will be connected to the production system, com-pared with fve in the original development plan. Production will progressively ramp up through the year as development wells are completed and brought online. Ultimately, the new processing platform will also enable CNOOC to bring other marginal felds in the area online.
For Morris, the project has been a suc-cess on several levels. Firstly, there were the technical challenges. The geological charac-teristics of both felds and the properties of the crudes are quite different and diffcult. Additionally, W12-8W had to be accessed by drilling horizontally above a layer of water and below a gas cap.
It would have been uneconomic under con-ventional thinking, says Morris. The project
The Beibu Gulf Project involved the construction of a jointly-owned, purpose-built processing plat-
form (PUQB). The new processing platform will enable CNOOC to bring online other marginal fields
they have in the area. (Courtesy ROC Oil)
1309off_50 50 9/4/13 4:33 PM
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was, therefore, a landmark in that all parties had to cooperate to minimize project costs and to share the existing infrastructure.
“Together with CNOOC, we had to put a common hat on and ask how the project would be developed if we were one com-pany,” says Morris. “With different manage-ment philosophies, it took some time.”
It was a way of cooperating not seen in China before, says Morris, and it enabled capital and operational costs to be reduced by half.
For example, synergies were achieved by allowing produced water to be injected into CNOOC’s existing water disposal wells.
Typically, joint ventures in China have been on a stand-alone basis, with an indepen-dent entity producing alone and exporting through its own export system. Therefore, the standard contract had to be rewritten for this project so that CNOOC was appropriate-ly compensated for its existing assets, and the operational synergies were realigned to the satisfaction of all partners.
Several traditional barriers were elimi-nated so that win-win outcomes could be achieved.
The oil spills at the ConocoPhillips’ Peng-lai 19-3 oil facility in Bohai Bay, northern China, caused a signifcant delay while all parties re-evaluated risks.
“It had an impact on everyone,” says Mor-ris.
His company, ROC, experienced several months of delays during project signoff as a result of the spill.
“I believe we are yet to see the full impact of that. China is defnitely changing the way they are looking at accountability of busi-nesses and putting in new regulations to make sure that the proper controls are in place,” says Morris.
China is an important market for ROC, and Morris is positive about the ground work done to date with CNOOC. While he believes the possibility of big oil discover-ies in shallow water offshore China are less likely, a medium-sized specialist player like ROC thrives on the opportunity to extract value from mature or diffcult to develop felds. The company promotes this proven capability as a valued service not only for na-tional oil companies in China, but through-out Southeast Asia.
New challengesThere will be technical challenges ahead
for the industry, says Ernst Meyer, DNV’s regional manager for Southeast Asia and the Pacifc. Gas is becoming a bigger focus than oil and with it new competencies will need to be developed. Many recent fnds, for ex-ample, have been characterised by sour gas or high CO2 levels. The move toward deeper
waters will also bring technical challenges, but perhaps more importantly, new safety challenges.
“The regulatory regime in the area is not very well developed,” says Meyer. “It works well if things are easy and simple, but I think it will be a major challenge to maintain accept-able safety levels without really independent regulators in the South China Sea. In some countries the national oil companies are act-ing as regulators whilst having an interest in
the resources and their development.”Still, Meyer believes the region is attrac-
tive to oil companies, particularly when com-pared to regions such as the Arctic, where project costs are expected to be high.
“If you can get access to good projects and good development sharing agreements in Southern Asia, and if you can solve all the political and technical issues, I would say it is a much more proftable area to be in at the moment,” he says. •
1309off_51 51 9/4/13 4:33 PM
52 Offshore September 2013 • www.offshore-mag.com
G E O L O G Y & G E O P H Y S I C S
3D broadband is the wave of the future
Greater reservoir characterization role one advantage
Geoscience continues to strive for bet-ter and more accurate images of the Earth. The goal is unchanged – drill fewer wells and fnd more oil and gas. While 3D seismic is key, the science
must be robust and reliable. Marine seismic data is undergoing a broadband revolution, extending the recorded scale with both lower and higher frequencies. By separating upgo-ing and downgoing wavefelds the ghost can be eliminated, or it can be used. 3D seismic data will play a greater role in reservoir char-acterization.
Deghosting or wavefeld separation for a dual-sensor streamer is based on frst princi-ple science without restricting assumptions. The result is seismic data with a broader bandwidth both at the high end and the low end of the frequency spectrum.
The technology is more operationally eff-cient, provides better seismic imaging, and of-fers advantages in reservoir characterization. Reservoir delineation and geobody detection are improved thanks to an increased signal-to-noise ratio and broader bandwidth. The extended bandwidth, especially at the low fre-quency side of the spectrum, represents a key improvement in the lithology-fuid prediction and reservoir property estimation. The need for a priori assumptions is reduced by relying more on the data, which should notably im-prove the number of successful wells.
The ghost in marine seismic recording is the result of an almost perfect refection of the acoustic wavefeld from the sea sur-face. Up-going waves refect as down-going waves with a reversed polarity, and interfere
Eivid FromyrPetroleum Geo-Services
Illustration of complementary
pressure and motion sensors.
The input to wavefield separation: Hydrophone (left), velocity sensor (middle), and the resulting
up-going wavefield (right).
A 2D example from Brazil, a comparison between a conventional acquisition with a 9-m (30-ft) streamer depth and a dual sensor at 25 m (82 ft). The
source is the same, 4,130 cu in. towed at 9 m. Note the improved penetration and improved deeper image for the dual sensor. The Campos basin, Brazil,
image to the left is a time migrated conventional line towed at 9 m. The image to the right is a dual sensor line towed at 25 m. The source is identical.
1309off_52 52 9/4/13 4:33 PM
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constructively for certain frequencies and destructively for other fre-quencies. This phenomenon can occur both on the source side and on the receiver side. The affected frequencies depend solely on source and receiver depths. Conventional marine seismic acquisition, there-fore, involves a trade-off between the various frequency ranges. To record high frequencies, sources and receivers need a shallow tow, which strongly attenuates low frequencies. Conversely, a deep tow favors low frequencies at the expense of high frequencies.
The conceptA useful concept in discussing broadband systems is the principle
of complementarity. Such an acquisition system has two or more com-ponents that complement each other when looked at in combination either in the time or frequency domain. A receiver system with both a pressure sensor and a velocity sensor represents such a complemen-tary system. There are different time domain ghost functions between the two measurements, and this gives completely complementary am-plitude spectra. The pressure sensor spectrum peaks align with the notches in the spectrum of the velocity sensor and vice versa. Adding the ghost functions together gives a completely fat spectrum, which leaves a single spike in the time domain – the ideal system response.
The simplicity of the complementary receiver system offers sev-eral advantages. Only the depths of the receivers need to be known to perform the wavefeld separation, allowing this process to be per-formed on board. Up and downgoing wavefelds can be delivered straight from the vessel during the acquisition phase to speed deliv-ery of processed products.
The data quality uplift resulting from wavefeld separation, and hence removal of the receiver ghost, has far reaching consequenc-es. The receivers can be towed deeper. It is no longer restricted by the notches in the recorded spectrum which move into the central seismic band for deeper tows. The operational advantage is diffcult to overestimate. Effciency gains of 10-20% are recorded frequently, especially in harsh weather with a limited season. GeoStreamer has introduced a new acquisition paradigm. It has been demonstrated, for example, that it is possible to have year-round operations in places like the North Sea. Short arctic seasons can be flled effciently and work programs and commitments completed in one season.
Broader bandwidth, better dataThe upgoing wave being free of the receiver ghost, no longer has a
bandwidth limited by the hydrophone notch frequencies. In fact, the bandwidth is limited only by the source ghost. When towed deeper, it has a richer content of low frequencies to improve penetration. The recording environment is also quieter, as the sensors are not subject to swell noise. Thus, the low frequencies doubly beneft from increased signal amplitude and decreased noise level.
The second dual sensor example is a 3D dataset from the North Sea. Prospects and felds that vary greatly in age and depth of burial were im-aged with a superior data quality at all levels. Targets in this case study vary from very shallow Neogene channel systems through producing Paleocene sands to the Jurassic level, with the main focus on the Tertiary section.
Because of the improvement in signal to noise, better velocities can be picked. Both components of the separated wavefeld can be used in a more accurate implementation of multiple attenuation processes like SRME (surface-related multiples elimination). The dual-sensor benefts penetrate the entire processing sequence from shot to im-age. Most exciting perhaps is the possibility of using both compo-nents of the wavefeld in novel imaging schemes.
The fact that the wavefeld can be separated makes it possible to cal-culate the equivalent of a pressure recording at an arbitrary reference depth. This yields a byproduct that is fully backward compatible with conventional data in 4D applications. The broadband data is a product in its own right but also represents a new enhanced baseline going forward.
1309off_54 54 9/4/13 4:33 PM
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G E O L O G Y & G E O P H Y S I C S
Reservoir characterizationReservoir characterization and estimation
of elastic properties greatly beneft from improved bandwidth. Extending the low fre-quencies by more than an octave stabilizes processes like inversion. Elastic properties can be estimated without well information and extended away from well control points with greater accuracy and confdence than can be achieved by conventional data. These aspects can be further understood through the effect and improvement of the seismic wavelet. The reduction of side lobes or tun-ing effects due to the presence of frequen-cies down toward 2 Hz makes AVO (ampli-tude versus offset) and related inversions more reliable and accurate.
Estimated absolute elastic properties, based on prestack inversion, have been com-pared to the well information over a particular line indicate a good match. More importantly, the scattering of points from the inversion re-sults follows the elastic behavior predicted from well information, which is not the case with the conventional seismic dataset.
As case studies have demonstrated, the broader bandwidth, especially at the low frequency side, represents a key element in improving the seismic reservoir property estimation. This is particularly the case in the lithology-fuid prediction. The need for a priori knowledge based on well information is considerably reduced. The inversion and litho-fuid prediction using broadband data depend less on sparse well data. Therefore, accuracy of prediction of reservoir proper-ties away from the wells will improve. The process becomes less model driven and in-stead more data driven.
SWIM (Separated Wavefeld IMaging)
Traditionally, multiples are removed from seismic data using processes like SRME. Since dual sensor recording enables sepa-ration of the wavefeld into an upgoing and downgoing component, there is, effectively, a secondary source at every receiver point. Therefore, multiples may be used in imag-ing by employing downgoing wavefeld. This will have far reaching consequences for im-age quality, and also opens a new chapter in terms of how geoscientists look at illumina-tion of the Earth. It could alter the thinking about acquisition as well. Both coverage and aperture could be redefned. The combina-tion of GeoStreamer wavefeld separation and new imaging condition used in depth migra-tion is producing promising results.
SourceRemoval of the source ghost has the po-
tential to take data quality to yet another level in terms of bandwidth. GeoSource is a
time and space distributed source based on conventional tuned subarrays. The source ghost can be removed due to the vertical separation of the subsources. Simultaneous fring ensures there is no loss in fold and a randomization scheme enables the separa-tion of the subsource signals. Typical tow-ing depth varies between 5 to 15 m (16 to 49 ft). The principle of complementarity is once again applied such that the subsources match each other in the frequency domain
similar to dual sensors on the receiver side. Again, this is an acquisition-based approach without restricting assumptions and thus preserves amplitude integrity all the way from feld data. •
AcknowledgmentThe author wishes to thank Lundin Malaysia BV and
PETRONAS Carigali Sdn. Bhd. for permission to
publish the Tenggol Arch data.
1309off_55 55 9/4/13 4:33 PM
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D R I L L I N G & C O M P L E T I O N
Majors continue to push boundaries
of extended-reach drilling
Two papers presented this year at the SPE/IADC conference in Amsterdam highlighted the latest initiatives in extended-reach drilling (ERD) offshore. Both outlined the challenges in drilling wells from shore to access outlying reservoirs of nearshore felds.
One paper, by authors from ExxonMobil and Exxon Neftegas, examined the new design that led to a new world record measured depth for an ERD well of 12,376 m (40,604 ft) on the Chayvo feld off-shore eastern Russia, including a reach of 11,371 m (37,306 ft). This is the latest in a series of ERD wells drilled into the Sakhalin-1 off-shore felds, using the land rig Yastreb. The other paper presented fndings from a new project based on the Reelwell Drilling Method, which targets much longer ERD wells sections.
Well-path issues The frst extended reach wells on Chayvo were drilled in 2003
from a near-coast location on Sakhalin Island. In 2011, the Yastreb returned to the Chayvo onshore well site for a new campaign.
Z-44 was the frst well to target Chayvo’s Zone 16 reservoir. Exx-onMobil planned a total of four oil producers from the existing on-shore wellpad, taking a horizontal path through the western fank
before crossing the axis of the anticline to penetrate the eastern fank. One gas injector would be placed horizontally in the gas cap. Distance to the targets was at the edge of the ERD envelope in terms of measured depth and horizontal reach, with some of the wells’ open-hole completion lengths exceeding 3,000 m (9,842 ft).
Other challenges were oil column thickness, thought to be around 20 m (65.6 ft), and the uncertainty range for the vertical position of the oil/water and gas/oil contacts of 4-5 m (13-16.4 ft). Simulation studies suggested the best recovery option would come through placement of horizontal oil producers at mid-oil column vertically,
Jeremy BeckmanEditor, Europe
Source: Reelwell
1309off_56 56 9/4/13 4:33 PM
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with small tolerance for deviation due to the risk of early gas or water breakthrough.
The campaign team opted for downhole formation pressure-while-drilling tools to minimize vertical position uncertainty, and upgraded Yastreb with equipment that in-cluded new 57⁄8-in. drillpipe with a higher torque connection capable of 71,500 ft-lb (9,885 kg/m), and two more shakers. In this case the intention was to eliminate sol-ids control as a limiter for the 17½-in. hole, speeding up drilling of that section by 20%.
Drilling of Z-44 started early in 2012 and was completed late last year. According to the au-thors, all objectives for Z-44 were accomplished, including the planned formation pressure tech-nique for wellbore positioning, with the pilot 8½-in. hole establishing both the fuid contacts and the oil column thickness. The production hole was successfully placed at mid-oil column. The only signifcant non-productive event dur-ing the entire drilling operation was a stuck pipe in the pilot hole, necessitating a whipstock side track at 8,607 m (28,328 ft) – ExxonMobil’s deepest to date, and possibly the deepest ever attempted by the industry.
Taking ERD a step furtherIn 2011, Reelwell started “ERD beyond
20 km,” a joint industry project supported by Petrobras, RWE Dea, Shell, Total, and the Research Council of Norway. The aim is to verify the extreme ERD capability of the Reelwell Drilling Method (RDM), which has been under development since 1994.
RDM has the potential to extend the en-velope for ERD because it allows fotation of the drillstring, reducing torque and drag to a minimum, and eliminates the dynamic equiv-alent circulating density (ECD) gradient as the ECD is screened from the formation. A piston-type arrangement at the drillstring provides optional hydraulic weight on bit.
The study involves an application for an offshore feld in an environmentally sensi-tive area, which may require development from an onshore site. This would call for ERD wells with a record-breaking horizontal displacement of more than 13 km (8 mi) and around 2.4 km (7,874 ft) TVD. The offshore target has various salt domes with an over-lying chalk formation, and the planned well has a target MD of almost 16 km (52,500 ft).
For the proposed well, the top section is a conventional design with a 20-in. casing set to 1,000 m (3,281 ft) depth. However, because of excessive torque and drag RDM must be used for the 13½-in. section to 14,000 m (45,931 ft) in “Heavy Over Light” (HOL) mode – this is a feature unique to RDM and denotes a situation where the annular fuid is of higher density than the active fuid in-side the drillstring. The same applies to the 9½-in. section to 15,800 m (51,837 ft).
Simulation results suggest the proposed well could be feasibly drilled using RDM to around 16,000 m (52,493 ft) MD; 2,400 m (7,874 ft) TVD with torque values of less than 30 kNm (22,127 lb-ft) and drag values of less than 50 tons. Use of a dual aluminum drillstring in combination with the HOL technique is the main enabler. Drillstring buckling, torque and drag are markedly low-er, and casing/liner installations are feasible using conventional fotation techniques. •
References
2013 SPE/IADC Drilling Conference, Amsterdam. “Case history of a challenging thin oil column extended
reach drilling (ERD) development at Sakhalin.” Authors: Vishwas Gupta, Shea Sanford, Exxon-Mobil Development Co.; Randall Mathis, Erin DiPippo, Exxon Neftegas; Michael Egan, consultant to ExxonNeftegas.
“Extended reach drilling – new solution with a unique potential.” Auhtors: O. Vestavik, Reelwell; M.Egorenkov, Merlin ERD; B. Schmalhorst, RWE Dea; J.Falcao, Petrobras.
1309off_57 57 9/4/13 4:33 PM
58 Offshore September 2013 • www.offshore-mag.com
Akzo Nobel Functional Chemicals BVLispinweg 66075 CE HerkenboschThe Netherlands+31 475 539292
American Gilsonite Co.29950 South Bonanza HighwayBonanza, Utah 84008(435) 789-1921
Aqua-Clear Inc.608 Virginia Street, EastCharleston, West Virginia 25301(304) 343-4792
AqualonOil and Gas Technologies1313 North Market StreetWilmington, Delaware 19894-0001(800) 345 0447
Archer Daniels Midland4666 Faries ParkwayDecatur, Illinois 62526(800) [email protected]
ASAP Fluids Pvt. Ltd.203-204, Kailash Commercial Complex,L B S Marg, Vikhroli West,Mumbai [email protected]
Baker Hughes Drilling Fluids2001 Rankin RoadHouston, Texas 77073(713) [email protected]
Baroid Fluid Services3000 North Sam Houston ParkwayHouston, Texas 77032(281) [email protected]
BASF 3120 Hayes Road, Suite 200, Houston, Texas 77082(832) [email protected]
Boysenblue/Celtec International Inc.P.O. Box 53648Lafayette, Louisiana 70505(337) [email protected]
Cabot Specialty FluidsCabot HouseHareness CircleAltens Industrial EstateAberdeen AB12 3LYScotland(44) 1224 897 [email protected]
Cesco Chemical100 Cesco LaneLafayette, Louisiana 70506(337) [email protected]
Chemstar Products Co.3915 Hiawatha AvenueMinneapolis, Minnesota 55406-3203(612) 722-0079
Chemtotal Pty Ltd.Deepak [email protected]
Croda Inc.300A Columbus CircleEdison, New Jersey 08837(732) 417-0800
Deep South Chemical Inc.229 Millstone RdBroussard, Louisiana 70518 (337) [email protected]
Drilling Specialties Co./ Chevron Phillips LPP.O. Box 4910The Woodlands, Texas 77387-4910(832) [email protected]
Drillsafe Janel Int.Polanska 3543-450 Ustron/Poland(48) 33 854 [email protected]
Elkem AS, MaterialsP.O. Box 8126 VaagsbygdN-4675 Kristiansand, Norway [email protected]
Emery Oleochemicals GmbHHenkelstrasse 67 40589 Duesseldorf, Germany(49) 211 5611 [email protected]
Grain Processing Corp.1600 Oregon StreetMuscatine, Iowa 52761(866) [email protected]
Gumpro Drilling Fluids Pvt Ltd.LBS Marg, Vikhroli West Mumbai 400 083, [email protected]
Impact Fluid Solutions 2800 Post Oak Blvd. Suite 2000Houston, Texas 77056(713) [email protected]
Kelco Oil Field Group10920 W. Sam Houston Pkwy. N., Ste. 800Houston, Texas 77064 (713) 895-7575
KEMTRON Technologies Inc.10050 Cash Road Stafford, Texas 77477(281) 261-5778 [email protected]
Lamberti SPAVia Marsala 38 – Torre D21013 Gallarate (VA)Italy(39) [email protected]
Lamberti USA Inc.P.O. Box 1000US 59 @ County Road 212Hungerford, Texas 77448(281) [email protected]
Liquid Casing Inc.P.O. Box 56324Houston, Texas 77256-6324(713) 785-0594
M&D Industries of Louisiana Inc.P.O. Box 82007Lafayette, Louisiana 70598-2007(337) [email protected]
Mayco Wellchem Inc. 1525 North Post Oak RoadHouston, Texas 77055(713) 688-2602
Messina Inc. 8131 LBJ Freeway, Suite 180Dallas, Texas 75251 (214) 887-9600 [email protected]
M-I SWACO5950 North Course DriveHouston, Texas 77072(713) [email protected]
Montello Inc.6106 East 32nd Place, Suite 100Tulsa, Oklahoma 74135-5495(800) [email protected]
Newpark Drilling Fluids16340 Park Ten Place, Suite 150Houston, Texas [email protected]
National Oilwell Varco4310 N. Sam Houston Pkwy E.Houston, Texas 77032(713) [email protected]
Oleon N.V.Industriezone Ter StratenVaartstraat 1302520 OelegemBelgium(32) 3 [email protected]
PQ Corp.P.O. Box 840Valley Forge, Pennsylvania 19482(610) 651-4200
Prime Eco Group Inc.2933 Hwy 60 SouthWharton, Texas 77488(979) [email protected]
PT Indobent Wijaya MineralDesa PunungPacitan, Propinsi Jawa Timur, Indonesia62 81 330886381
Q’Max Solutions Inc. 1700, 407 – 2nd Street SW Calgary, Alberta(403) [email protected]
Quaron N.V.Industrieweg 271521NE WormerveerThe Netherlands(31) 75 [email protected]
Setac5905 Johnston Street, Suite ELafayette, Louisiana 70503-5466(337) [email protected]
Special Products & Mfg. Inc.2625 Discovery BlvdRockwall, Texas 75032(972) 771-8851
Strata Control Services Inc.1811 West Mill StreetCrowley, Louisiana 70527-0272(337) [email protected]
Sun Drilling Products Corp.503 Main StreetBelle Chasse, Louisiana 70037(504) [email protected]
TBC-Brinadd4800 San FelipeHouston, Texas 77056(713) [email protected]
Tetra Technologies Inc.24955 I-45 NorthThe Woodlands, Texas 77380(281) [email protected]
Turbo-Chem International Inc.P.O. Box 60383Lafayette, Louisiana 70596(337) [email protected]
Venture ChemicalsP.O. Box 53631Lafayette, Louisiana 70505(337) 232-1977
Weatherford International Ltd.2000 St. James PlaceHouston, Texas 77056(713) 836-4000
ENVIRONMENTAL DRILLING & COMPLETION FLUIDS COMPANY LISTING
The 2013 Environmental Drilling and Completions Fluids Directory is a listing of industry fluid manufacturers and their in-dividual products. The directory is differentiated into 19 sections based on type of fluid. Fifty participating companies and dis-tributors are listed in the directory. Each listing includes new and updated products provided by each company with a description
of the product and its general characteristics. With regulations and guidelines for the North Sea operational sectors requiring substances/preparations used and discharged offshore that are considered to pose little or no risk (PLONOR) to the environment listing and Harmonized Offshore Chemical Notification Format (HOCNF) rating, this information is listed in the directory.
Environmental Drilling & Completion Fluids Directory
The accompanying survey is modified to accommodate for space. For complete listings, visit the online survey at www.offshore-mag.com/surveys.html
1309off_58 58 9/4/13 4:33 PM
1309off_59 59 9/4/13 4:33 PM
Description
Productname D
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Description
Productname D
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B A C T E R I A C I D E S
ASAP FLUIDS For complete listings, visit the online survey at www.offshore-mag.com.
BAKER HUGHES DRILLING FLUIDS
MAGNACIDE 575 Bacteriacide for well treatments • • • • 0.01-0.1% Gold Y Y
MIL-BIO Glutaraldehyde bactericide • • • • 0.1-.03% Y
MIL-BIO NS Broad spectrum biocide for North Sea • • • • 0.1-.03% Y
X-CIDE SERIES Biocide series • • • • varies
BAROID FLUID SERVICES
ALDACIDE-G Biocide-Glutaraldehyde solution • • • • 0.2-0.5 Y Y
STARCIDE Microbiocide solution • • • • 0.3-0.5 Y
STARCIDE-P Microbiocide • • • • 0.05-0.25 Y
BASF, CHEMTOTAL, DEEP SOUTH CHEMICAL, DRILLSAFE JANEL, GUMPRO, KEMTRON TECHNOLOGIES,LAMBERTI SPA, MAYCO WELLCHEM, MESSINAFor complete listings, visit the online survey at www.offshore-mag.com. M-I SWACO
M-I CIDE Non-U.S. Biocide • • • • 1.0-3.0 N N
SAFE-CIDE Non-U.S. Biocide • • • • 0.1-0.5 Y N
NOV FLUIDCONTROL
MYACIDE 25GA Bacteriacide • • • • 0.05 Y
XCIDE 207 Granular microbiocide • • • • 0.0175 Y
Q’MAX, QUARON N.V., SPECIAL PRODUCTS For complete listings, visit the online survey at www.offshore-mag.com.
TETRA TECHNOLOGIES, INC.
BIOCIDE Antimicrobial • •
WEATHERFORD INTERNATIONAL LTD.
BIOCLEAR 1000 DBPNA - fast acting, general purpose • • • • • • 0.01
C O M P L E T I O N F L U I D S , C L E A R F L U I D S , B R I N E S
AQUALON
AQUAFLO LV High viscosity Standard Polyanionic cellulose • • • • 0.25-2 Y Y
AQUAFLO HV Low viscosity Standard Polyanionic cellulose • • • • 0.25-2 Y Y
AQUAPAC LIQUID Environmental friendly anhydrous • • • • 0.5-4 D Y Y AquaPAC suspension
AQUAPAC LV Low viscosity Premium Polyanionic cellulose • • • • 0.25-2 Y Y
AQUAPAC REGULAR High viscosity Premium Polyanionic cellulose • • • • 0.25-2 Y Y
AQUAPAC ULV Ultra Low viscosity Premium Polyanionic cellulose • • • • 0.25-2 Y Y
ECODURA PLONOR rated aqueous HEC suspensions • • • • 1-10 Y Y
NATROSOL 210 HHX Ultra High viscosity and Fast hydrating HEC • • • • 0.5-2.5 Y Y
NATROSOL 250 HHR-P Ultra High viscosity HEC • • • • 0.5-2.5 Y Y
NATROSOL HI-VIS Ultra High viscosity HEC • • • • 0.5-2.5 Y Y
NATROSOL LIQUID Environmental friendly anhydrous HEC suspension • • • • 1-5 D Y Y
ARCHER DANIELS MIDLAND, ASAP FLUIDSFor complete listings, visit the online survey at www.offshore-mag.com.
BAKER HUGHES DRILLING FLUIDS
AMMONIUM CHLORIDE NH4Cl - ammonium chloride • • 8.4-9.5 lb/gal E Y
HYCAL I Calcium chloride solution to 11.6 ppg • E Y
HYCAL II Calcium chloride/ calcium • E Y bromide sol. to 15.1 ppg
HYCAL II SB Calcium bromide solution to 14.2 ppg • E Y
HYCAL III Calcium chloride/calcium bromide/ • B zinc-bromide solution to 19.2 ppg (Zn)
HYCAL III SB Calcium bromide/zinc bromide • B solution to 19.2 ppg (Zn)
NOCAL I Sodium chloride solution to 10.0 ppg • E Y
NOCAL II Sodium chloride/bromide sol. to 12.8 ppg • E Y
NOCAL II SB Sodium bromide solution to 12.8 ppg • E Y
NOCAL K Potassium chloride solution to 9.7 ppg • E Y
POTASSIUM FORMATE Potassium formate brines to 13.1 ppg • E Y
SODIUM FORMATE Sodium formate brines to 11.0 ppg • E Y
ULTRA SS DKD inhibit salt agglomeration in saturated fluid • • • • 5% with 110 and 220ppb excess salt
BAROID FLUID SERVICES
BARABRINE DEFOAM Brine defoamer • • • 0.05 -0.25 Y
BARABRINE SI Scale inhibitor for clear brines • • • • 0.025-0.05
BARABUF pH Buffer • • • • 0.1-2.0 Y Y Y
BARACOR 100 Film-forming brine corrosion inhibitor • • • • 1% Y Y
BARACOR 450 HT corr. inhibitor for >2% zinc brines • • 0.2-0.4% Y Y
BARACOR 700E Corrosion inhibitor for monovalent brines • • • • 0.5-2.0 Y Y
BARAKLEAN Degreaser and oil mud remover As needed Y
BARAKLEAN DUAL Wellbore cleaner for displacement Y
BARAKLEAN FL Wellbore cleaner for displacement 5% in H20 Y
BARAKLEAN FL PLUS Wellbore cleaner for displacement 5% in H20 Y
BARAKLEAN NS PLUS Wellbore cleaner for displacement 5% in H20 Y
BARAKLEAN GOLD Wellbore cleaner for displacement 5% in H20 Y
BARAPLUG Sized sodium chloride • • • 10-200 Y Y Y 20, 50, 6/300
BARARESIN Sized oil soluble bridging particles • • 5.0-20.0
BARARESIN-VIS Oil mud viscosifier • • 3.0-20.0 Y
BARASCRUB Terpene derived well cleaner • • • • • As needed Y
BARASORB Oil-adsorbant for brine reclamation As needed Y
BARAVIS HEC for brine viscosification • • • • 1-3 Y Y Y
BARAZAN Xanthan gum • • • • 0.1-2.0 Y Y Y
BARAZAN D Dispersion enhanced xanthan gum • • • • 0.1-2.0 Y Y Y
BARAZAN D PLUS Dispersion enhanced xanthan • • • • 0.1-2.0 Y Y Y
BARAZAN L Xanthan gum in liquid dispersion form • • • • 0.5-4.0 Y Y
BROMI-VIS HEC--liquid form for brine viscosification • • 5.0-20.0 Y
FLO-CLEAN MD Flocculant for calcium brines 1-3 vol%
FLO-CLEAN Z Flocculant for zinc brines 1-3 vol%
NO BLOK C Emulsion preventor for non-zinc brines 0.1-1 vol% Y
NO BLOK Z Emulsion preventor for zinc brines 0.1-1 vol%
OXYGON Oxygen scavenger 0.1-0.2 Y Y
BASF, BOYSENBLUE/CELTEC INTERNATIONAL For complete listings, visit the online survey at www.offshore-mag.com.
CABOT SPECIALTY FLUIDS
CESIUM ACETATE Density to 2.3 sg (19.2 ppg) • •
CESIUM FORMATE Density to 2.3 sg (19.2 ppg) • • E N
CESIUM FORMATE/ Density to 2.42 sg (20.18 ppg) • • ACETATE BLEND
MIXED FORMATES Densities from 1.0 sg to 2.3 sg • E Y
POTASSIUM FORMATE Density to 1.57 sg (13 ppg) • E Y N
SODIUM FORMATE Density to 1.3 sg (10.8 ppg) • E Y Y
CHEMSTAR, DEEP SOUTH CHEMICAL, DRILLING SPECIALTIES CO., EMERY, GUMPRO, IMPACT FLUID SOLUTIONS, KELCO OIL FIELD GROUP, KEMTRON TECHNOLOGIES, LAMBERTI SPA, LAMBERTI USA, LIQUID CASING, MESSINAFor complete listings, visit the online survey at www.offshore-mag.com.
M-I SWACO
BREAKDOWN Chelant-based clean-up system System
BREAKDOWN 7 Neutral to slightly basic chelant clean-up system System
BREAKDOWN HD High density chelant based clean-up system System
BREAKFREE Enzyme-based clean-up system System
CONQOR 101 Water-dispersible amine for packers • • 3-4 N N
CONQOR 202B Film-forming amine for drillstring application • • • • 5-15 gal slugs N N
CONQOR 303A Brine soluble filming amine • 1-4 N Y Y
CONQOR 404 Organic inhibitor for all WBM • • • • 0.2-0.5 Y N
DEEPCLEAN Solvent/surfactant wash chemical O/SBM • • 5-20% Y Y Y
DEEPCLEAN NS Solvent/surfactant wash chemical O/SBM • • 5-20% Y Y
D-SOLVER Chelant • • • To 75vol%
D-SOLVER D Dry Chelant • • • 10-25%wt Y
D-SOLVER HD High density Chelant • • • • 10-40vol% Y
D-SOLVER 7 Neutral to slightly basic chelant • • • To 80vol%
D-SOLVER PLUS Chelant/acid blend • • • • To 85vol%
D-STROYER Internal oxidizer breaker product • • 0.5-2.0
D-STRUCTOR Organic acid precursor used in FAZ-AWAY or FAZE-OUT • • >30vol% breaker systems to remove FAZEPRO filter cake
DOWFROST MI Insulating packer fluid for deepwater • • As needed
DUO-VIS Shear thinning viscosifier • • • • 1-4 Y Y
DUO-VIS L Liquid Shear thinning viscosifier • • • • 1-5 Y Y
FILTER FLOC Flocculant • • 0.01-2% N N
FLO-VIS PLUS Shear thinning viscosifier • • • • 1-3 Y Y
FLO-VIS L Liquid Shear thinning viscosifier • • • • .5-1.5 Y Y
ISOTHERM Oil-base insulating packer fluids • • Y
OS-1L Sulfite-based oxygen scavenger • • • • 0.1-0.5 Y Y
SAFE-BREAK 611 Non-emulsifier • 0.1-2% N N
SAFE-BREAK CBF Emulsion preventer for brine • 0.1-1.0% N N
SAFE-BREAK S Polymer breaker • • 0.002-0.01 N N
SAFE-BREAK ZINC Emulsion preventer for zinc bromide brine • 0.1-1.0% N N
SAFE-COR Amine-based corrosion inhibitor • 0.5-1% Y N
SAFE-COR C Modified corrosion inhibitor, amine-base for casing • 2.0 N N
SAFE-COR EN Modified amine based corrosion inhibitor • 0.3 - 0.5%
SAFE-COR HT Inorganic thiocyanate-base corrosion • • 0.00036 N N inhibitor for high-temperature use
SAFE-COR Z PLUS Amine-base corrosion inhibitor • 0.5-1 N N
SAFE-DFOAM Blended alcohol defoaming agent • • • 0.08-0.16 N N
SAFE-FLOC II Flocculant • • • 0.01-2% N N
SAFE-LINK Cross link polymer LCM non zinc • System N N
SAFE-LINK 110 Cross link polymer LCM non zinc • 32 pails/10 bbl N N
SAFE-LINK 140 Cross link polymer LCM zinc • 32 pails/10 bbl N N
SAFE-LINK 150 Cross link polymer LCM • 32 pails/10 bbl
SAFE-LUBE Water-soluble brine lubricant • 0.6vol% N N
SAFE-LUBE CW Water-soluble brine lubricant for cold weather • 0.6vol%
SAFE-SCAV CA Organic oxygen scavenger for Ca-based brines • 0.15 N N
SAFE-SCAV HS Organic H2S scavenger • 0.1 N N
SAFE-SCAV HSW Organic H2S scavenger containing methanol • 0.1 N N for cold regions
SAFE-SCAV NA Liquid bisulfate-base oxygen scavenger • 0.1 N N for Na and K brines
SAFE-SCAVITE II Calcium scale preventer • 0.15-3 N N
SAFE-SOLV E Displacement solvent • Up to 100%
SAFE SOLV OM Solvent/surfactant wash chemical O/SBM • • 3-10% N N
SAFE-SURF E Nonionic wellbore cleaning agent for OBM • • • • • 2-15%
SAFE-SURF EH Wellbore cleaning compound • • • • • 5-20vol%
SAFE-SURF NS Wash chemical for well displacement • • 5-20vol%
SAFE-SURF O Blend of surfactants, solvents and water • 3-20% N N wetting agents, for well displacement
SAFE-SURF O II Concentrated surfactant for wellbore clean-up • • 2-20% N N
SAFE-SURF W Displacement wash chemical for WBM • • • • 1-10% N N
SAFE-SURF WE Non-ionic surfactant blend • • 2-10%
SAFE-SURF WN Displacement wash chemical for WBM • • • • 1-10%
SAFE-SURF Y Displacement wash chemical for O/SBM • • 6-12% Y
SAFE-T-PICKLE Pipe dope pickel solvent • • • • • • 1 N N
SAFE-VIS Viscosifier for brine • 0.5-4 Y N
SAFE-VIS E Liquid viscosifier for brines • 5-10 Y N
SAFE-VIS HDE Liquid viscosifier for high-density brines • 14-29 N N
SAFE-VIS LE Liquid viscosifier for brines • 0.6-1.2 gpb N N
SAFE-VIS OGS Specially formulated liquid HEC • 0.6-1.2 gpb
SAFETHERM Insulating packer fluid for deepwater • • As needed
SEAL-N-PEAL Inside packer fluid loss control • • • • FLC Pill
SI-1000 Blended scale inhibitor • • • • 0.05 N N Y
SV-120 Hydrogen sulfide scavenger for cold climates • 1-5 N N
WELLZYME A Enzyme breaker w/ biocide for WB RDFs • • • • 2-5 vol% N N
WELLZYME III Enzyme breaker w/ biocide for RDFs • • • • 1-5 vol% N N
MONTELLO For complete listings, visit the online survey at www.offshore-mag.com.
NOV FLUIDCONTROL
AMBASOL Barium sulfate dissolver • • 25-50%
Magnesium Oxide Ph stabilizer 0.2
PRO-CHECK Corrosion inhibitor filming amine • • 30 gal/100 bbl
PRO-CHECK HT Corrosion inhibitor HT/heavy brine • • 55 gal/400
TRU-FLUSH Well wash • • 55 gal/100 bbl
AMONIUM CHLORIDE Salt • • As needed
PRO-CHECK O2 Oxygen scavenger • •
AMSCALE Corrosion inhibitor • • 10%
60 Offshore September 2013 • www.offshore-mag.com
1309off_60 60 9/4/13 4:33 PM
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1309off_61 61 9/4/13 4:33 PM
Description
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62 Offshore September 2013 • www.offshore-mag.com
NOV FIBER Fluid loss • • 1/10
EGMB Displacement chemical (solvent) •
AMVIS HTE Displacement chemical (viscosifier) •
AMZINC VIS I Liquid viscosifier • 3%
AMZINC VIS II Liquid viscosifier • 3%
AMZINC VIS III Liquid viscosifier • 3%
BREAKER I HEC breaker 0.25-2
BREAKER II HEC breaker
CALCIUM BROMIDE Salt • • As needed
CALCIUM CHLORIDE Salt • • As needed
CLEAN DRILL C Drill-in fluid - calcium carbonate system
CLEAN DRILL HD Drill-in fluid (high density brines) - calcium carbonate system
ENZYME I HEC breaker 20 oz/20 bbl
FIBER-VIS Viscosifier extender • • 0.5/10
HEC-SAV Thermal stabilizer • • 0.5-1%
MAGMA FIBER Lost circulation material • • 5-25
MYACIDE 25GA Bacteriacide • • 5 gal/100 bbl
NOV CARB C Calcium carbonate • • As needed
NOV CARB F Calcium carbonate • • As needed
NOV CARB M Calcium carbonate • • As needed
FOAM-OUT Defoamer • • 0.25/100 bbl
HEC-VIS L Viscosifier liquid • • 0.25-4
NOV XAN D Viscosifier dry powder • • 0.25-4
NOV XAN TD Viscosifier • • 0.25-2
NOV XAN T Viscosifier • • 0.25-2
PERM-CON Brine surfactant
PHDOWN pH stabilizer depressor • • 1/10
PHUP pH stabilizer • • 1/10
POTASSIUM CHLORIDE Salt • • As needed
SCALEHIB Scale inhibitor • • 2.50%
SD-300 Nonionic surfactant • • 5%
SODIUM BROMIDE Salt • • As needed
SODIUM CHLORIDE Salt • • As needed
OLEON N.V., PRIME ECO GROUP INC., Q’MAX, QUARON N.V., SPECIAL PRODUCTS, SUN DRILLINGPRODUCTS, TBC-BRINADD For complete listings, visit the online survey at www.offshore-mag.com.
TETRA TECHNOLOGIES, INC.
ACETIC ACID Mild organic acid • •
BUFF-10 Controlled sloubility MgO - buffer pH • •
BUFF-6 Organic carboxylic acid - to buffer pH to moderate acid • •
CALCIUM BROMIDE Calcium bromide • • 11.7-15.1
CALCIUM CHLORIDE Calcium chloride • • 8.6-11.6
CAUSTIC SODA Base • •
CITIC ACID Complex organic acid • •
HCOOK Potassium formate, 97% • •
HCOONA Sodium formate, 97% • •
HYDROCHLORIC ACID Strong mineral acid • •
KCl Potassium chloride, 99% • •
LIME Base • •
MAGNESIUM OXIDE Base • •
NACL Drillers’ salt • •
NACL Sodium chloride evaporated salt • •
NH4CL Ammonium chloride, 99% • •
POTASSIUM FORMATE Potassium formate • • 8.4-13.1
POTASSIUM Base • • HYDROXIDE
SODA ASH High purity anhydrous sodium carbonate • •
SODIUM BROMIDE Sodium bromide • • 10-12.7
SODIUM FORMATE Sodium formate • • 8.4-11
ZNBR2/CABR2 19.2 Zinc bromide and calcium bromide solutions • • 14.5-19.2 SOLUTIONS
ZNBR2/CABR2 20.5 Zinc bromide and calcium bromide solutions • • 14.5-20.5 SOLUTIONS
TURBO-CHEM INTERNATIONAL For complete listings, visit the online survey at www.offshore-mag.com.
WEATHERFORD INTERNATIONAL LTD.
ALPHA 6177 Primary well dispersing fluid, low tox.. •
CLEAR FORM K Potassium formate completion and drilling fluid base • • • • N
C O R R O S I O N I N H I B I T O R S
ASAP FLUIDS For complete listings, visit the online survey at www.offshore-mag.com.
BAKER HUGHES DRILLING FLUIDS
BRINE-PAC 250 Corrosion inhibitor for solids-free fluids • • 5-10gal/100
BRINE-PAC XTS Corrosion Inhibitor for solids-free fluids • • 12 gal/100 bbl
LATIHIB Carbon dioxide scavenger • • • 1.5-4 ppb
MIL-GARD Corrosion Inhibitor • • • • • 1-3 ppb
MIL-GARD FE H2S extractor • • • • • • 5.5 gal/100 Y
MIL-GARD L Zinc chelated sulfide scavenger • • • • • • 5.5 gal/100
MIL-GARD XPR Hydrogen sulphide scavenger for NS use • • • • • • Varies Gold
NOXYCOR Corrosion inhibitor for water based and • • • • Varies air/mist/foam drilling applications
NOXYGEN L Liquid oxygen scavenger • • • • 75-125 ppm
NOXYGEN NA Liq. oxygen scavenger - sodium bisulfite • • • • 250 ppm Y Y
NOXYGEN XT Organic oxygen scavenger • • As needed
OHR AC Acid corrosion control for the MICROWASH System 0.75-1%
OHR ACE Acid corrosion control for MICRO-WASH - enviro. safe 0.5-1% Y
BAROID FLUID SERVICES
BARABRINE SI Scale inhibitor for clear brines • • .025-.05
BARACOR 95 Corrosion inhibitor and CO2 remover • • • • 0.25-2.0 Y Y
BARACOR 100 Film-forming corrosion inhibitor • • 0.01 Y Y
BARACOR 450 HT corr. inhibitor for >2% zinc brines • • 0.2-0.4% Y Y
BARACOR 700 Corrosion inhibitor for monovalent brines • • 0.5-1.5 Y
BARACOR 700E Corrosion inhibitor for monovalent brines • • 0.5-2.0 Y Y
BARAFILM Filming amine • • 1:6 W/O Y
BARASCAV-D Powdered oxygen scavenger • • • • 0.1-0.5 Y Y Y
BARASCAV-L Liquid oxygen scavenger • • • • 0.1-0.5 Y Y Y
NO-SULF Zinc compound for sulfide scavenging • • • • • • 1.0-4.0 Y
OXYGON Oxygen scavenger • • 0.1 Y
SOURSCAV Hydrogen sulfide scavenger • • • • 1-4 Y
BASF, CRODA, DRILLSAFE JANEL, GUMPRO, LAMBERTI SPA, LAMBERTI USA, MAYCO WELLCHEM, MESSINA For complete listings, visit the online survey at www.offshore-mag.com.
M-I SWACO
CONQOR 101 Water-dispersible amine for packers • • 3-4 N N
CONQOR 202B Film-forming amine for drill string application • • • • 5-15 gal slugs N N
CONQOR 303A Brine-soluble filming amine • 1-4 Y N Y
CONQOR 404 Organic inhibitor for all WBM • • • • 0.2-0.5 Y N
SULFATREAT DFS H2S scavenger • • • • • • 20.0
OS-1L Sulfite-base oxygen scavenger • • • • 0.1-0.5 Y Y
RE-PLEX Anionic scavenger for DRILPLEX system • 0.25-0.5
SAFE-COR Amine-base corrosion inhibitor • 0.5-1.0% Y N
SAFE-COR C Modified corrosion inhibitor, amine-base for casing • 0.25-0.5% N N
SAFE-COR EN Amine-base corrosion inhibitor • 0.05-1.0% N N
SAFE-COR HT Inorganic thiocyanate-base corrosion • • 0.00036 N N inhibitor for high-temperature use
SAFE-COR Z PLUS Amine-base corrosion inhibitor • 0.5-1 N N
SAFE-SCAV CA Organic oxygen scavenger for Ca-base brines • 0.15 N N
SAFE-SCAV HS Organic H2S scavenger • 0.1 N N
SAFE-SCAV HSW Organic H2S scavenger w/ methanol • 0.1 N N
SAFE-SCAV NA Liquid bisulfate-base oxygen scavenger • 0.1 N N for Na and K brines
SAFE-SCAVITE Calcium scale inhibitor • 0.15-3 N N
SAFE-SCAVITE II Calcium scale preventer • 0.15-3 N N
SI-1000 Blended scale inhibitor • • • • 0.05 N N Y
SV-120 Cold climate H2S scavenger • 1-5 N N
NEWPARK DRILLING FLUIDS
NEWARMOR Film-forming amine • • • • 5-15 gal/100bbl
NOV FLUIDCONTROL
PRO-CHECK Filming amine • • • • 30/100 Y
PRO-CHECK HT Inorganic liquid stable @ 450¡ • • • • 55/100 Y
PRO-CHECK O2 Oxygen scavenger +B566 • • • • 0.02 Y
PRIME ECO GROUP INC., Q’MAX, SPECIAL PRODUCTS, TBC-BRINADDFor complete listings, visit the online survey at www.offshore-mag.com.
TETRA TECHNOLOGIES, INC.
BIOCIDE Antimicrobial • •
CORSAF SF Corrosion inhibitor • •
OXBAN Oxygen scavenger • •
OXBAN HB Oxygen scavenger for mid to heavy fluids • •
PAYZONE SI-139 Phosphonate scale inhibitor • •
TETRA H2S SCAVENGER H2S Scavenger • • • • 0.1-8
TETRAHIB Multicomponent inorganic film former • •
TETRAHIB PLUS Inorganic • •
WEATHERFORD INTERNATIONAL LTD.
ALPHA 1064 High solids tolerant oxygen scavenger • 0.01-0.05
ALPHA 1214 Corrosion inhibitor for brines • • 0.01-0.05
ALPHA 2068 High temperature corrosion inhibitor • • 0.25-2
ALPHA 2275 Oxygen corrosion inhibitor low tox.. • • • 0.02-0.05
ALPHA 2296 Oxygen corrosion inhibitor low tox.. • • • 0.02-0.05
ALPHA 2867 High solids scale inhibitor • 25-1000 ppm
ALPHA 3069 Packer fluid inhibitor • • 0.25-2
ALPHA 3337 Drill pipe batch corrosion inhibitor •
ALPHA 3412 Down hole or drill pipe corrosion inhibitor •
ALPHA 3444 Down hole or drill pipe corrosion inhibitor •
ALPHA 6415 Drill pipe corrosion inhibitor • 0.01-0.05
SULFACLEAR 8199 H2S scavenger • 0.5-1.5
SULFACLEAR 8411C H2S scavenger • 0.01-1.5
SULFACLEAR 8649 H2S scavenger • 0.01-1.5
D E F O A M E R S
ARCHER DANIELS MIDLAND, ASAP FLUIDSFor complete listings, visit the online survey at www.offshore-mag.com.
BAKER HUGHES DRILLING FLUIDS
DEFOAMER Defoaming agent for completion fluids • • As needed
LD-8 Non-hydrocarbon-based defoamer • • • • As needed Y for water-based fluids
LD-8e North Sea compliant defoamer for water-based fluids • • • • As needed Y
LD-9 Defoamer for both fresh & saltwater drilling fluids • • • • As needed
LD-10 Silicone based defoamer for fresh • • • • As needed & saltwater drilling fluids
LD-S Silicone based defoamer for fresh & saltwater drilling fluids
W.O. DEFOAM Alcohol-based compound for defoaming • • • • 0.1 gal/bbl Y water-based fluids
BAROID FLUID SERVICES
BARA-DEFOAM 1 Alcohol and fatty acid blend • • • 0.05-0.2 Y
BARA-DEFOAM HP Polypropylene glycol • • • 0.05-0.3 Y
BARA-DEFOAM W300 Alcohol and fatty acid blend • • • 0.05-0.2 Y
BARABRINE DEFOAM Non-ionic surfactant blend for brines • • 0.05-0.2 Y
FOAM ZAPPER Blend of renewable resource products • • • 0.05-0.2 Y
BASF, BOYSENBLUE/CELTEC INTERNATIONAL, CRODA, DRILLING SPECIALTIES CO., DRILLSAFE JANEL, GUMPRO, KEMTRON TECHNOLOGIES, LAMBERTI SPA, LAMBERTI USA, MAYCO WELLCHEM, MESSINAFor complete listings, visit the online survey at www.offshore-mag.com.
M-I SWACO
DEFOAM-A Alcohol-base defoamer • • • • 0.1-0.5 N N
DEFOAM-X Liquid low toxicity defoamer • • • • 0.1-0.5 Y N N
DEFOAM NA All-purpose defoamer • • • •
DI-ANTIFOAM Antifoaming agent for the DIPRO system • 0.3 gal/bbl
NULLFOAM Defoamer • 0.3 gal/bbl
SAFE-DFOAM Blended alcohol defoaming agent • • • 0.08-0.16 N N
NEWPARK DRILLING FLUIDS
NOFOAM A Alcohol-based • • • • • • Y
NOFOAM X Multifuntional • • • • Y
1309off_62 62 9/4/13 4:33 PM
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www.offshore-mag.com • September 2013 Offshore 63
NOV FLUIDCONTROL
ALUMINUM STEARATE Surface acting agent • • • • 0.05 Y
FOAM-OUT Water base mud defoamer • • • • 0.25 Y
Q’MAX, SETAC, SPECIAL PRODUCTS For complete listings, visit the online survey at www.offshore-mag.com.
STRATA CONTROL SERVICES, INC.
FOAM-BLAST Concentrated liquid defoamer • • • • 0.1-2 Y
SUN DRILLING PRODUCTS, TBC-BRINADDFor complete listings, visit the online survey at www.offshore-mag.com.
TETRA TECHNOLOGIES, INC.
DEFOAM HB Defoamer • •
TURBO-CHEM INTERNATIONAL For complete listings, visit the online survey at www.offshore-mag.com.
WEATHERFORD INTERNATIONAL LTD.
ALPHA 2325 BADF Organic defoamer • 25-500 ppm
D E N S I T Y / V I S C O S I F I E R S
NEWPARK DRILLING FLUIDS
CYBERVIS DW Polymeric rheological modifyier • • 0.25-2.5 Y
CYBERVIS RM Polymeric rheological modifyier • • <4 Y
EVOMOD HPHT synthetic low-end rheology mod. • • • 0.1-2 Y
EVOVIS HPHT polymeric rheology modifier • • 0.25-6 Y
GAGEVIS MMO • • • 0.8-1.2 Y
NDFT 255 biopolymer liquid • • • 0.1-2 Y
NEWBAR 4.2 SG barite • • • • • • Y
NEWGEL Montmorillonite • • • • 5-30 Y
NEWGEL NT Untreated montmorillonite • • • • 5-30 Y
NEWWATE 4.1 SG barite • • • • • • Y
NEWZAN D Biopolymer • • • • 0.2-2 Y
OPTIVIS RM Polymeric rheological modifyier • <4
D R I L L - I N F L U I D
AQUALON
AQUAFLO LV High viscosity Standard Polyanionic cellulose • • • • 0.25-2 Y Y
AQUAFLO HV Low viscosity Standard Polyanionic cellulose • • • • 0.25-2 Y Y
AQUAPAC LIQUID Environmental friendly anhydrous AquaPAC suspension • • • • 0.50-4 D Y Y
AQUAPAC LV Low viscosity Premium Polyanionic cellulose • • • • 0.25-2 Y Y
AQUAPAC REGULAR High viscosity Premium Polyanionic cellulose • • • • 0.25-2 Y Y
AQUAPAC ULV Ultra Low viscosity Premium Polyanionic cellulose • • • • 0.25-2 Y Y
ECODURA PLONOR rated aqueous HEC suspensions • • • • 1-10 Y Y
NATROSOL 180 GR Low viscosity Hydroxyethyl cellulose • • • • 0.25-2 Y Y
NATROSOL 210 HHX Ultra High viscosity and Fast hydrating HEC • • • • 0.5-2.5 Y Y
NATROSOL 250 EXR Low viscosity Hydroxyethyl cellulose • • • • 0.25-2 Y Y
NATROSOL 250 GXR Low viscosity Hydroxyethyl cellulose • • • • 0.25-2 Y Y
NATROSOL 250 HHR-P Ultra High viscosity HEC • • • • 0.5-2.5 Y Y
NATROSOL 250 LR Ultra low viscosity Hydroxyethyl cellulose • • • • Y Y
NATROSOL LIQUID Environmental friendly anhydrous HEC suspension • • • • 1-5 D Y Y
NATROSOL HI-VIS Ultra High viscosity HEC • • • • 0.5-2.5 Y Y
ARCHER DANIELS MIDLAND, ASAP FLUIDS For complete listings, visit the online survey at www.offshore-mag.com.
BAKER HUGHES DRILLING FLUIDS
GeoPACK Oil based gravel pack carrier system •
MICRO-CURE E2 Cased hole remediation Y
MICRO-WASH Open hole remediation
MPA-50 Micro-prime activator, 50% varies
MPA-100 Micro-prime activator, 100% varies
MUDZYME S Enzymes to degrade starch in filter cakes 0.4 gal/bbl
MUDZYME X Enzymes to degrade xanthan gum in filter cakes 2 gal/bbl
OMNI-FLOW DIF Invert Emulsion Reservoir Drill-in fluid
PERFFLOW LD Low density drill-In fluid • •
PERFFLOW CM Drill-in fluid - customized bridging
PERFFLOW DIF Drill-in fluid Y Y
PLUG-LIFT Multi-stage composite frac plug drill-out system • •
PRIME 100 Wellbore OBM displacement additive Y
PRIME 770 Wellbore OBM displacement additive Y
BAROID FLUID SERVICES
ALDACIDE-G Glutaraldehyde solution • • • • 0.2-0.5 Y Y
BARABLOK Powdered gilsonite, wallcake enhancer • • • • • • 5.0-35.0 Y Y Y
BARABLOK 400 Hi-temp powdered gilsonite • • • • • • 5.0-35.0 Y
BARABUF pH buffer • • • • 0.1-2.0 Y Y Y
BARACARB 5,25,50, Sized acid-soluble marble • • • • • • 5.0-60.0 Y Y Y 150,400,600,1200
BARACARB DF 5, 25, Sized acid-soluble marble • • • • • • 5.0-60.0 Y Y Y 50, 150, 600
BARACTIVE Polar activator for all-oil systems • • 4.0-7.0 Y Y Y
BARA-DEFOAM HP Polypropylene glycol • • • 0.05-0.3 Y
BARADRIL-N DRIL-N system, water based • • System Y
BARAPLUG 20, 50, 6/300 Sized salt • • 10-200 Y Y Y
BRINEDRIL-N DRIL-N system, brine based • • System
COREDRIL-N DRIL-N system, 100% oil/synthetic • • System
DRIL-N STIM RDF containing additive to improve reservoir producibility • •
DURATONE HT Oil mud filtration control additive • • 2.0-20.0 Y
DURATONE E Oil mud filtration control additive • • 2.0-20.0 Y Y
EZ-CORE Fatty acid passive emulsifier for all-oil • • 1.0-4.0 Y
MAXDRIL-N DRIL-N system, mixed metal silicate • System
N-DRIL HT PLUS Modified starch • • • • 2.0-6.0 Y Y Y
N-PLEX Activator for N-SQUEEZE • • • • • • 4 Y
N-SEAL Inorganic LCM • • • • • • 5.0-30.0 Y
N-SQUEEZE Lost circulation material • • • • • • 8.0-40.0 Y Y Y
N-VIS Biopolymer • • • • 0.5-2.0 Y
N-VIS HI Mixed metal silicates • 1 Y
N-VIS L Liquid xanthan dispersion • • • • 0.25-3.0 Y
N-VIS O Organophilic clay viscosifier • • 1.0-6.0
N-VIS P PLUS Biopolymer/modified starch • • • • 2.0-8.0 Y Y
QUICKDRIL-N DRIL-N system, modified polymer with LSRV • • System
SHEARDRIL-N DRIL-N system, clay-free with modified polymers • • System
SOLUDRIL-N DRIL-N system, polymer/sized salt • System
BASF For complete listings, visit the online survey at www.offshore-mag.com.
CABOT SPECIALTY FLUIDS
CESIUM ACETATE Density to 2.3 sg (19.2 ppg) • •
CESIUM FORMATE Density to 2.3 sg (19.2 ppg) • • E N
CESIUM FORMATE/ Density to 2.42 sg (20.18 ppg) • • ACETATE BLEND
MIXED FORMATES Densities from 1.0 sg to 2.3 sg • E Y
POTASSIUM FORMATE Density to 1.57 sg (13.0 ppg) • E Y N
SODIUM FORMATE Density to 1.3 sg (10.8 ppg) • E Y Y
CHEMSTAR, DRILLING SPECIALTIES CO., EMERY, GUMPRO, IMPACT FLUID SOLUTIONS, KELCO OIL FIELD GROUP, LAMBERTI SPA, LIQUID CASING, MAYCO WELLCHEM, MESSINA For complete listings, visit the online survey at www.offshore-mag.com.
M-I SWACO
BREAKDOWN Chelant-based clean-up system System
BREAKDOWN 7 Neutral to slightly basic chelant clean-up system System
BREAKDOWN HD High density chelant based clean-up system System
BREAKFREE Enzyme-based clean-up system System
D-SOLVER Chelant • • • To 75 vol%
D-SOLVER 7 Neutral to slightly basic chelant • • • To 80vol%
D-SOLVER D Dry Chelant • 10-25%wt Y
D-SOLVER HD High density Chelant • • • 20-35% Y
D-SOLVER PLUS Chelant/acid blend • • • To 85 vol%
D-SPERSE Surfactant for BREAKFREE and BREAKDOWN systems • • 0.25-1 vol%
D-STROYER Internal oxidizer breaker product • • 0.5-2.0
DI-ANTIFOAM Antifoaming agent for the DIPRO system • 0.03 gal/bbl
DI-BALANCE Viscosifier for the DIPRO system • 0.25-2
DI-BOOST Secondary viscosifier for the DIPRO system • .03-.06 gal/bbl
DI-INHIB Shale inhibitor for the DIPRO system • 3% by vol
DI-LOK Rheo-Mod for DI-PRO LD system •
DI-PLEX Low-end rheology maintainer for DIPRO LD systems •
DIPRO High-density, low-solids, divalent brine RDF system • System
DIPRO LD Low-density, DIPRO system • System
DI-TROL Filtration control agent for the DIPRO system • 8.0
DRILPLEX Diverse Mixed Metal Oxide system • • System
DRILPLEX MMO viscosifier • • 1-3 Y
DUAL-FLO FCA for the FLOPRO NT system • • • 4-6 N N Y
DUAL-FLO HT FCA for high-temperature applications • • • 2-7
DUO-TEC Xanthan gum, dispersible, non-clarified • • • • 0.25-2 Y N
DUO-TEC NS Xanthan gum, dispersible, clarified • • • • 0.25-2 Y N Y
DUO-VIS Xanthan gum, dispersible, non-clarified • • • • 0.25-2 Y N Y
DUO-VIS L Liquified xanthan gum, non-clarified • • • • 0.25-0.5 y N
DUO-VIS NS Xanthan gum, non-dispersible, non-clarified • • • • 0.25-2 Y N Y for use in the North Sea
DUO-VIS PLUS Xanthan gum, dispersible, non-clarified • • • • 0.25-2 Y N Y
DUO-VIS PLUS NS Xanthan gum, non-dispersible, non-clarified • • • • 0.25-2 Y N Y for use in the North Sea
FAZE-AWAY Invert-emulsion breaker system for FAZEPRO system • • System Y
FAZEBREAK Delayed clean-up system for FAZEPRO system System
FAZE-OUT Delayed breaker system for FAZEPRO system • System Y
FAZE-MUL Emulsifier for FAZEPRO System • • 8-12 N N
FAZE-MUL CW Emulsifier for FAZEPRO System in cold weather • • 8-12
FAZEPRO Reversible invert emulsion fluid system • • System
FAZE-WET Wetting agent for FAZEPRO System • • 2-4 N N
FAZE-WET CW Wetting agent for FAZEPRO System in cold weather • • 2-4
FLO-PLEX Fluid loss additive for DRILPLEX System • • 2-6 Y N Y
FLOPRO NT Minimal solids, non-damaging WB RDF system • • System
FLOPRO SF Solids-free non-damaging WB RDF system • • System
FLO-THRU Minimal solids, non-damaging WB RDF system • • System Y
FLO-THRU SF Solids-free non-damaging WB RDF system • • System Y
FLO-TROL Modified starch derivative • • • • 2-4 Y Y Y
FLO-VIS L Non-dispersible, clarified Xanthan gum • .25-.5 gal/bbl
FLO-VIS NT Non-dispersible, non-clarified Xanthan gum • • • .25-1.5
FLO-VIS PLUS Premium clarified Xanthan for FLOPRO NT systems • • • • 0.5-2.5 N N
FLO-WATE Sized salt weighting agent for FLOPRO system • 40-60 N N
K-52 Non-chloride potassium supplement • • • • 1-5 N N Y for FLOPRO NT systems
KLA-CURE Hydration suppressant for FLOPRO NT systems • • • 4-8 N Y Y
KLA-CURE II Hydration suppressant with detergent • • • 4-8 N N
KLA-GARD Shale inhibitor and hydration suppressant • • • 4-8 N Y Y for FLOPRO NT systems
KLA-GARD B Salt-free KLA-GARD • • • 4-8 N N Y
KLA-STOP Liquid polyamine shale inhibitor • • • 1-4 vol%
LUBE-167 Low-toxicity lubricant for FLOPRO NT system • • • • 4-16 N Y Y
LUBE-776 Lubricant for LSND muds • 1-3 vol%
LUBE 945 WBM lubricant • • • • 1-3 vol%
LUBE XLS Extreme pressure lubricant • • • • 1-6 Y
NOVAPRO Synthetic olefin-base RDF system • System
OPTITRAK 600 MDT tracer • • • • 1000 mg/l filtrate PARAPRO Paraffin-base RDF system • System
POWERVIS Biopolymer viscosifier • • 0.875-1.25 Y
SAFE-BREAK S Polymer breaker • • 0.002-0.01 N N
SAFE-BREAK MP Internal breaker used in polymer-base fluids • • • 0.5-4.0 Y
SAFE-CARB Ground marble weighting/bridging agent • • • • • • 10-50 Y N
SAFE-CIDE Biocide • • • • 0.1-0.5 Y N
SAFE-LUBE Water-soluble brine lubricant • 0.6vol% N N
SAFE-LUBE CW Water-soluble brine lubricant for cold weather • 0.6vol%
SAFE-SOLV 148 Displacement solvent • • • • 3-10 vol% N
STARGLIDE Lubricant and ROP enhancer • • • • 1-3 vol%
VERSA-OUT/NOVA-OUT Breaker system for VERSAPRO and NOVAPRO • • System Y
VERSA-WAY/NOVA-WAY Invert-emulsion breaker system • • System Y for VERSAPRO and NOVAPRO
VERSAPRO Oil-base RDF system • System
VERSAPRO LS Low-solids oil-base RDF system System
WELLZYME A Enzyme breaker with biocide for water-base RDF fluids • • 2-5% N N
WELLZYME III Enzyme breaker without biocide for water-base RDF fluids • • 2-10% N N
1309off_63 63 9/4/13 4:34 PM
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Description
Productname D
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Non
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d
Satu
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64 Offshore September 2013 • www.offshore-mag.com
NOV FLUIDCONTROL
CLEAN DRILL C Drill-in fluid - calcium carbonate system • •
CLEAN DRILL HD Drill-in fluid (high density brines) - • calcium carbonate system
OLEON N.V., PQ CORP., PRIME ECO GROUP INC., Q’MAX, QUARON N.V., SUN DRILLING PRODUCTSFor complete listings, visit the online survey at www.offshore-mag.com.
TETRA TECHNOLOGIES, INC.
PAYZONE DIF/GP clean-up • • CLEANUP TRMT
PAYZONE CMT-X MgCl2 cement contaminant control • •
PAYZONE DF SLICK PILL Solids free fluid • •
PAYZONE DF-CC DF using CaCO3 bridging mtl. • • Y
PAYZONE DF-LT Low toxicity fluid • • Y
PAYZONE DF-SS DF using NaCl bridging mtl. • Y
PAYZONE GRAVEL DIF/GP simultaneous clean-up • • PACK TRMT
WEATHERFORD INTERNATIONAL LTD.
ALPHA 4138 Emulsifier •
ALPHA 4180 Emulsifier •
E M U L S I F I E R S
ARCHER DANIELS MIDLAND For complete listings, visit the online survey at www.offshore-mag.com.
BAKER HUGHES DRILLING FLUIDS
CARBO-MUL HT High-temperature emulsifier and wetting agent • 2.9 - 23.8 L/m3
CARBO-MUL HT-N High-temperature emulsifier and • 2.9 - 23.8 L/m3 wetting agent for Norway
NEXT-MUL HT High Temperature, primary emulsifier • • 9.5-18 L/m3 for invert emulsion system
MP-MUL Primary emulsifier for invert emulsion system
ECCO-MUL R Emulsifier for invert-emulsion systems • 0.5-0.75gal/bbl
CARBO-MUL LT Low-temperature emulsifier and wetting agent • 0.5-1.5 ppb
CARBO-TEC High-temperature anionic emulsifier • 14.3-40.5 L/m3
CARBO-TEC LT Low Temp. supplemental emulsifier • Up to 14.3 L/m3
CARBO-TEC “S” Supplemental emulsifier and viscosifier • • Up to 14.3 L/m3
ECCO-MUL E Emulsifier for invert-emulsion systems • 12-36 L/m3
MAGMA-VERT Emulsifier for MAGMA-TEQ extreme • • 12-45 L/m3 Y HPHT emulsion system
NEXT-MUL Primary emulsifier for the NEXT-DRILL system • • 9.5-18 L/m3
OMNI-MUL High temp. emulsifier and wetting agent • • 12-36 L/m3 Y Y for synthetic muds
OMNI-MUL 2 Emulsifer for synthetic drilling fluids • • .5-1 gal/bbl
OMNI-TEC Anioic emulsifier for synthetic drilling fluids • • 14-40 L/m3
OMNI-VERT Supplemental emulsifier • 0.5-1.5 PPB
BAROID FLUID SERVICES
BAROMUL 290, 303 Oil mud emulsifier • 2.0-12.0
BROMI-MUL Brine-in-oil emulsifier • • 6 Y
DRILTREAT Oil wetting agent • • 0.25-2.0 Y Y Y
EZ MUL Oil mud emulsifier • 2.0-12.0
EZ MUL 2F Oil mud emulsifier • • 2.0-12.0
EZ MUL NT Oil mud emulsifier • 2.0-12.0 Y Y
EZ MUL NS Oil mud emulsifier • 2.0-12.0
EZ MUL R Oil mud emulsifier • 2.0-12.0
EZ-CORE Fatty acid passive emulsifier for all-oil • • 1.0-4.0 Y
FACTANT Oil mud emulsifier/filtration control agent • • 1.0-4.0 Y Y
FORMULADE Emulsifier for synthetic fluids • • 2.0-8.0
FORTI-MUL Oil mud emulsifier • 2.0-12.0
INVERMUL Oil mud emulsifier • 4.0-12.0
INVERMUL NT Oil mud emulsifier • 4.0-12.0 Y Y
LE SUPERMUL Emulsifier for synthetic fluids • 2.0-12.0 Y
PERFORMUL Oil mud emulsifier • • 2.0-12.0 Y Y
DRILLSAFE JANEL, EMERY, LAMBERTI SPA, LAMBERTI USA, MESSINAFor complete listings, visit the online survey at www.offshore-mag.com.
M-I SWACO
ACTIMUL RD Dry emulsifier and wetting agent in diesel • • 6-10
ECOGREEN P Primary emulsifier for ECOGREEN system • 2-6 Y N
ECOGREEN S Secondary emulsifier for ECOGREEN system • 2-6 Y N
EMUL HT HTHP emulsifier for VERSADRIL and • • 4-8 N N VERSACLEAN systems
FAZE-MUL Emulsifier for FAZEPRO system • • 8-12 N N
FAZE-WET Wetting agent for FAZEPRO System • • 2-4 N N
M-I 157 Supplemental emulsifier • • 0.5-2 N N
MEGAMUL Basic emulsifier and wetting agent • 4-12 in MEGADRIL system
MUL HTP Primary emulsifier for negative alkalinity system • • 1-4 N N
NOVAMUL Primary emulsifier & wetting agent for synthetic fluids • 2-8 N N Y
NOVAPRO P/S Primary emulsifier • 6-10
NOVAWET Wetting agent for synthetic muds • 1-5 N N Y
NOVATEC P Primary emulsifier for NOVATEC system • • 2-6 N N
NOVATEC S Secondary emulsifier for NOVATEC system • • 2-6 N N
ONE-MUL emulsion stability, wetting agent, • 8-10 filtration control, and temperature stabilizer
OILFAZE Sacked oil-base concentrate • 50 N N
PARAMUL Primary emulsifier for OBM and SBM PARA systems • • 6 -10.2
SUREMUL Primary emulsifier for SBM systems • 6-10.2 N N Y
SUREMUL EH Primary emulsifier for SBM systems • 6-10.2
SUREMUL PLUS Primary emulsifier in RHELIANT PLUS system • 8-10
VERSACOAT Wetting agent & emulsifier in VERSA• Oil systems • 1-8 N N
VERSACOAT HF Organic surfactant emulsifier for oil muds in HT • 1-8 N N
VERSACOAT NA High flash point emulsifier for oil muds • 1-8 N N
VERSAMUL Primary emulsifier & wetting agent, liquid blend • 4-10 N N of emulsifiers, wetting agents, gelling agents and fluid stabilizers
VERSAPRO P/S Primary emulsifier, secondary wetting agent • 6-10 N N in VERSAPRO system
VERSAWET Wetting agent for OBM • 1-4 N N
NEWPARK DRILLING FLUIDS
CYBERCOAT Surfactant & supplimental emulifier • 0.5-2 Y
CYBERMUL Low toxicity emulsifier • 4-6 Y
CYBERPLUS Low toxicity emulsifier • 8-12 Y
CYBERTROL Polymeric HPHT filtration control agent • 1-5 Y
OPTIMUL Organic emulsifier • 2-8
OPTIPLUS II Organic emulsifier • 2-8
OPTITHIN Organic thinner • 0.1-5
OPTIWET Blend of emulsifying & wetting agents • 0.25-8
NOV FLUIDCONTROL
PETRO-MUL I Primary emulsifier • 2-8
PETRO-MUL II Secondary emulsifier • 2-8
ECO-SYN PE Primary emulsifier for synthetics • 2-8
ECO-SYN SE Secondary emulsifier for synthetics • 2-8
OLEON N.V., PRIME ECO GROUP, Q’MAX, SPECIAL PRODUCTS, SUN DRILLING PRODUCTSFor complete listings, visit the online survey at www.offshore-mag.com.
WEATHERFORD INTERNATIONAL LTD.
ALPHA 1386 Wetting liquid, low tox.. • • 1-5
ALPHA 3930 Viscosifier fatty acid, low tox.. • 1-4
ALPHA 6151 Lubricant/primary emulsifier, low tox.. • • 1-10
ALPHA 6156 Lubricant/drill oil fluid, low tox.. • • 1-10
ALPHA 6177 Secondary emulsifier/surfactant • • 0.5-5
ALPHA 6280 Primary/secondary emulsifier, low tox.. • • 1-10
ALPHA 6450 Oil mud thinner • 0.5-3
ALPHA 6662 Primary/secondary emulsifier, low tox.. • • 1-10
ALPHA 6666 Primary/secondary emulsifier, low tox.. • • 1-10
F I LT R A T I O N C O N T R O L A G E N T S
AKZO NOBEL For complete listings, visit the online survey at www.offshore-mag.com.
AQUALON
AQUAFLO LV High viscosity Standard Polyanionic cellulose • • • • 0.25-2 Y Y
AQUAFLO HV Low viscosity Standard Polyanionic cellulose • • • • 0.25-2 Y Y
AQUAPAC LIQUID Environmental friendly anhydrous AquaPAC suspension • • • • 0.50-4 D Y Y
AQUAPAC LV Low viscosity Premium Polyanionic cellulose • • • • 0.25-2 Y Y
AQUAPAC REGULAR High viscosity Premium Polyanionic cellulose • • • • 0.25-2 Y Y
AQUAPAC ULV Ultra Low viscosity Premium Polyanionic cellulose • • • • 0.25-2 Y Y
ECODURA PLONOR rated aqueous HEC suspensions • • • • 1-10 Y Y
NATROSOL 180 GR Low viscosity Hydroxyethyl cellulose • • • • 0.25-2 Y Y
NATROSOL 210 HHX Ultra High viscosity and Fast hydrating HEC • • • • 0.5-2.5 Y Y
NATROSOL 250 EXR Low viscosity Hydroxyethyl cellulose • • • • 0.25-2 Y Y
NATROSOL 250 GXR Low viscosity Hydroxyethyl cellulose • • • • 0.25-2 Y Y
NATROSOL 250 HHR-P Ultra High viscosity HEC • • • • 0.5-2.5 Y Y
NATROSOL 250 LR Ultra low viscosity Hydroxyethyl cellulose • • • • Y Y
NATROSOL LIQUID Environmental friendly anhydrous HEC suspension • • • • 1-5 D Y Y
NATROSOL HI-VIS Ultra High viscosity HEC • • • • 0.5-2.5 Y Y
XXTRADURA Extreme temperatures filtration control additive • • • • 1-5 Y Y
ASAP FLUIDS For complete listings, visit the online survey at www.offshore-mag.com.
BAKER HUGHES DRILLING FLUIDS
BD-FL 44 High-temperature starch • • 2-6
BIO-LOSE Complexed polysaccharide • • • • 2-4 pb Y
BIO-PAQ Organic derivative providing filtration control • • • • 1-4 ppb Y
BIO-PAQ AR High performance fluid loss control biopolymer • 1-4 ppb
CARBO-TROL Clay swelling & hydration suppressant • varies
CARBO-TROL 375 High-temperature filtration reducer for CARBO-DRILL • • 2-6 ppb
CARBO-TROL A-9 Non-asphaltic/polymeric HTHP filtration reducer • • 5-10 ppb
CHEMTROL X HT filtration control agent for water-base fluids • • • 2-6 ppb
DELTA-TROL HT Starch for PERFFLOW system • • • • 4-7 ppb
ECCO-PAQ LV Filtration control additive for freshwater systems • • • • 0.5-2 ppb Y
FC-30 Flake carbonate •
KEM-SEAL Co-polymer for high-temp. filtration control • • • • 0.25-6 ppb Y
KEM-SEAL PLUS Co-polymer for HT filtration control • • • • 1-2 ppb Y
MAGMA-SEAL Fluid loss and sealing additive for MAGMA-TEQ • • 4-8 ppb extreme HPHT emulsion system
MAGMA-TROL Polymeric fluid loss additive for MAGMA-TEQ • • 0.5-7 ppb extreme HPHT emulsion system
MAX-TROL Sulfonated resin • • • • 2-8 ppb Y
MIL-PAC LV Low-viscosity polyanionic cellulose • • • 1-4 ppb
MIL-PAC LVT Low visc. tech-grade polyanionic cellulose • • • 0.5-2 ppb
MIL-PAC LV PLUS Saltwater tolerant low-viscosity polyanionic • • • • 0.25-2 ppb cellulose that meets API specifications
MIL-PAC R PLUS Saltwater tolerant polyanionic cellulose, • • • • 0.25-4 ppb regular viscosity
MIL-PAC R Polyanionic cellulose, regular viscosity • • 0.25-4 ppb Y
MIL-PAC RT Technical grade polyanionic cellulose, • • • 0.5-3 ppb regular viscosity, API spec
MIL-PAC ULV Ultra-low visc. polyanionic cellulose • • • 0.5-2 ppb
MILSTARCH Pregelatinized starch • • • • 1-5 ppb Y
MP-TROL Fluid loss control additive for invert emulsion systems • • 1-2ppb
NEW-TROL Sodium polyacrylate • • • • 0.5-4 ppb Y
NEXT-TROL Fluid loss control additive for invert emulsion systems • • 1-2ppb
PERMA-LOSE HT Non-fermenting polymerized starch • • • • 1-5 ppb Y
PYRO-TROL FR and lubricant in extreme HPHT • • • • 0.25-2 ppb Y water base applications
W-313 Filtration reducer for PERFFLOW system • • • 5-7 ppb Y Y
XCD POLYMER Bipolymer • • • • As needed E Y
BAROID FLUID SERVICES
ADAPTA Oil mud filtration control copolymer • • 1.0-6.0 Y Y
ADAPTA 450 Extreme HTHP IEF filtrate reducer • • 1.0-6.0
AK-70 Asphaltic blend • • • • • • 5.0-15.0 Y
BARABLOK Powdered gilsonite, wallcake enhancer • • • • • • 5.0-35.0 Y Y Y
BARABLOK 400 Hi-temp powdered gilsonite • • • • • • 5.0-35.0 Y Y Y
BARANEX Modified lignin polymer • • • 2.0-6.0 Y Y
BARO-TROL PLUS Shale stabilizer • • • • 2.0-6.0 Y
BORE-PLUS Shale inhibitor • • • 1.0-4.0 Y
BXR Borehole stabilizer • • • • 4.0-20.0 Y
BXR-L Borehole stabilizer suspension • • • • 8.0-40.0 Y
1309off_64 64 9/4/13 4:34 PM
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1309off_65 65 9/4/13 4:34 PM
Description
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Description
Productname D
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Non
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d
Satu
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d sa
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Fres
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Oil-
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Synt
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66 Offshore September 2013 • www.offshore-mag.com
CARBONOX Leonardite • • • • 2.0-12.0 Y Y Y
DEXTRID Modified starch with biocide • • • • 2.0-6.0 Y
DEXTRID E Modified starch • • • • 2.0-6.0 Y Y
DEXTRID LT Modified starch with biocide • • • • 2.0-6.0 Y
DEXTRID LTE Modified starch with biocide • • • • 2.0-6.0
DRILL STARCH Pregelatinized starch • • • • 2.0-8.0 Y
DURATONE E Oil mud filtration control additive • 2.0-20.0 Y Y
DURATONE HT Oil mud filtration control additive • • 2.0-20.0 Y
DURENEX PLUS Hi-temp filtration control additive • • 1.0-3.0 Y
FACTANT Oil mud emulsifier/filtration control agent • • 1.0-4.0 Y Y
FILTER-CHEK Fermentation-resistant modified starch • • • • 1.0-5.0 Y Y Y
IMPERMEX Pre-gelatinized starch • • • • 2.0-8.0 Y Y Y
LIQUITONE Liquid polymeric filtrate reducer • • 1.0-4.0 Y Y
N-DRIL HT PLUS Modified starch 2.0-5.0 Y Y Y
PAC-L & PAC-LE Low viscosity polyanionic cellulose • • • • 0.5-3.0 Y Y Y
PAC-R & PAC-RE Regular polyanionic cellulose • • • • 0.5-2.0 Y Y Y
POLYAC PLUS Polyacrylate • • • • 0.25-3.0 Y
THERMA-CHEK High temperature filtrate reducer • • • • 1.0-8.0 Y Y
BASF, BOYSENBLUE/CELTEC INTERNATIONAL, CHEMSTAR PRODUCTS, CHEMTOTAL, DEEP SOUTH CHEMICAL, DRILLING SPECIALTIES CO., DRILLSAFE JANEL, GRAIN PROCESSING CORP., GUMPRO, IMPACT FLUID SOLUTIONS, KELCO OIL FIELD GROUP, KEMTRON TECHNOLOGIES, LAMBERTI SPA, LAMBERTI USA, MAYCO WELLCHEM, MESSINAFor complete listings, visit the online survey at www.offshore-mag.com.
M-I SWACO
ASPHASOL Blend of sulfonated organic resins • • • 4-10 N N Y
ASPHASOL D Sulfonated organic blend, partially water soluble • • • 2-10 N N
ASPHASOL SUPREME Sulfonated asphalt • • • • • 3-6 N N
CALOVIS FL FL Control and Secondary Viscosifier • • • 2-5 for ENVIROTHERM system
CALOVIS HT FL Control and Secondary Viscosifier • • • 2-6 for ENVIROTHERM system
CAUSTILIG Causticized ground lignite • • • 1-15 N N Y
DI-TROL FCA for the DIPRO system • 8
DUAL-FLO FCA for the FLOPRO NT system • • • 4-6 N N Y
DUAL-FLO HT FCA for high-temperature applications • • • 2-7
DURALON Filtration control high-temperature polymer • • • • 1-8 N N
ECOTROL 717D Filtration control resin for diesel • 2-4
ECOTROL L Liquid filtration control for paraffin-, • • 0.5-2.0 mineral oil- and synthetic oils
ECOTROL RD Version of ECOTROL used in PARALAND system • • 2-4
ECOTROL HT Synthetic Co-Polymer in all oil • • 2-4 high-temperature applications
FILTER FLOC Flocculant for displacements 0.01-2%
FLO-PLEX Filtration control additive for the DRILPLEX system • • 2-6 Y N Y
FLO-PLEX PLUS Filtration control additive for the DRILPLEX system • • 4-6
FLO-TROL Starch derivative for FLOPRO NT systems • • • • 2-4 Y Y Y
HIBTROL FCA & secondary shale inhibitor • • • 1-5 Y N
HIBTROL HV FCA & secondary shale inhibitor • • • 1.4-7 N N
HIBTROL ULV Ultra-low vis FCA and secondary shale inhibitor • • • 2.1-7
K-17 Potassium causticized lignite • • • • 1-15 N N Y
KLAFLOC II Cationic filtration control for floc water drilling • 1-4 vol%
LO-WATE Acid soluble, powdered calcium carbonate • • • • • • 10-40 N N
M-I 157 Supplemental emulsifier • • 0.5-2 N N
M-I PAC R Pure PAC polymer, technical grade • • • 2-5 Y Y
M-I PAC UL Pure PAC polymer, low viscosity • • • 2-5 Y Y
MEGATROL Filtration control in Diesel based systems • 0.5-3
MUL HTP Primary emulsifier for negative alkalinity system • • 2-6 N N
MY-LO-JEL Pregelatinized corn starch • • • • 4-8 Y Y
OILFAZE Sacked oil-base concentrate • 50 N N
ONETROL HT Amine-treated tannin • • 4-10
PARATROL HT High-temperature gilsonite • 2-8
PERF-N-PEEL WBM FL/damage control system • • System for perforated completions
POLYPAC ELV Extra-low viscosity PAC • • • • 0.5-2 Y N
POLYPAC R Polyanionic cellulose • • • • 0.5-2 Y Y Y
POLYPAC SUPREME R PAC, premium grade • • • • 0.5-2 Y N
POLYPAC SUPREME UL PAC, premium grade, ultra-low viscosity • • • • 0.5-2 Y N
POLYPAC UL PAC, ultra low-viscosity • • • • 0.5-2 Y N
POLY-SAL Non-fermenting starch • • • • 2-6 N N Y
POLY-SAL HT High-quality, preserved polysaccharide • • • • 2-6
POLY-SAL T Non-fermenting tapioca starch derivative • • • • 2-6 N N
POROSEAL Latex-modified starch polymer • • • • 2-5vol%
RESINEX High-temperature synthetic resin • • • • 2-6 N N Y
RESINEX II High-temperature synthetic resin • • • • 2-10 N N
RESINEX EH High-temperature synthetic resin • • • • 2-10 N N
SAFE-CARB Sized ground marble • • • • • • 10-50 Y N
SAFE-LINK Filtration control agent for completion fluid systems • System N N
SAFE-LINK 110 Filtration control agent for completion fluid systems • .5 pail/perf ft N N
SAFE-LINK 140 Filtration control agent for completion fluid systems • .5 pail/perf ft N N
SAFE-LINK 150 Cross link polymer LCM • 32 pails/10 bbl
SAFE-VIS Brine viscosifier • • • • 0.5-4 Y N
SAFE-VIS E Liquid viscosifier for brines • 5-10 Y N
SAFE-VIS HDE Liquid viscosifier for high-density brines • • • 14-29 N N
SAFE-VIS LE Liquid viscosifier for brines • 0.6-1.2 gal/bbl
SAFE-VIS OGS Specially formulated liquid HEC • .6-1.2 gal/bbl
SHALE-CHEK Shale control additive • • • • 5 N N
SP-101 Sodium polyacrylate polymer • • • • 0.5-2 N N Y
TANNATHIN Ground lignite • • • • 1-15 N N Y
THRUCARB Carbonate for the FLOTHRU system • • 5-12
THRUTROL Organicphillic starch for the FLOTHRU system • • 10-15
TROL-PLEX Modified starch in DRILPLEX AR PLUS • 4-6
UNIPAC SUPREME R Dispersible high-viscosity PAC • • • • 0.25-1
UNIPAC SUPREME UL Dispersible regular-grade PAC • • • • 0.25-1
UNITROL Improved version of THERMPAC • • • • 0.25-1.5
VERSALIG Amine-treated lignite • 2-12 Y N Y
VERSATROL Naturally occurring gilsonite • 2-8 Y N
VERSATROL HT High-temperature gilsonite • 2-8
VERSATROL M Medium softening point Gilsonite • 2-8
VERSATROL NS Lignite/Gilsonite blend for HTHP filtration • 2-8
VINSEAL FCA & electrical stability additive • • • • • 2-20
XP-20 K Potassium causticized chrome lignite • • • 1-15 N N Y
XP-20 N Chrome lignite, neutralized • • • 1-15 N N
MONTELLO
MON PAC Polyanionic cellulose • • • • 0.25-2 Y
MON PAC ULTRA LO Polyanionic cellulose • • • • 0.25-2 Y
NEWPARK DRILLING FLUIDS
DYNALOSE W White starch • • • • 2-6 Y
DYNALOSE Y Yellow starch • • • • 2-6 Y
DYNANITE Gilsonite • • • • • • 2-6 Y
DYNAPLEX Resin • • • • 1-8 Y
EVOTROL Modified starch • • • • 1-8 Y
GAGETROL Fluid loss control • • 4 Y
NEWLIG Lignite • • • • 2-5 Y
NEWPAC LV Polyanionic cellulose • • • • 0.25-2 Y
NEWPAC PLV Premium-grade polyanionic cellulose • • • • 0.25-2 Y
NEWPAC PR Premium-grade polyanionic cellulose • • • • 0.25-2 Y
NEWPAC R Polyanionic cellulose • • • • 0.25-2 Y
OPTI G Filtrate control agent • 2-6
OPTILIG Amine treated lignite • • 1-12
OPTITROL Polymeric HPHT filtration control agent • 1-5 Y
NOV FLUIDCONTROL
AMZINC VIS I Liquid viscosifier • 3%
AMZINC VIS II Liquid viscosifier • 3
AMZINC VIS III Liquid viscosifier • 3
AQUA-FILM CM Carboxymethyl starch • • • • 2-6 Y
CMC HV Carboxymethyl cellulose • • • • .2-2
PETRO-GIL Asphalt • • • • • • 1-6
MAGMA FIBER Lost circulation material • • • • 0.5-25
NOV CARB C Calcium carbonate • • • • • •
NOV CARB F Calcium carbonate • • • • • •
NOV CARB M Calcium carbonate • • • • • •
NOV LIG Lignite • • • • 2 -6
NOV PAC LV Polyanionic cellulose • • • • 0.5-2 Y
NOV PAC Polyanionic cellulose • • • • 0.5-1 Y
ECO-SYN FLR Filtration control additive • • 1-6 Y
NOV TROL Viscosifier - liquid • • 0.25-4
NOV XAN D Viscosifier - dry powder • • 0.25-4
POLY-SPA Sodium polyacrylate • • • • 1-2
PETRO-GIL Liquid Liquid gilsonite blend • • • • 4-6
AQUA-FILM CM Carboxymethyl starch • • • • 2-6 Y
AQUA-FILM HT High temperature fluid loss agent • • 2-6 Y
STARTROL Sulfonated asphalt blend • • • • 2-6
PRIME ECO GROUP INC., PT. INDOBENT WIJAYA MINERAL, Q’MAX, QUARON N.V., SETAC, SPECIAL PRODUCTS For complete listings, visit the online survey at www.offshore-mag.com.
STRATA CONTROL SERVICES, INC.
STRATA-SCM FINE Blended micronized cellulose fiber • • • • • • 2-6 Y
STRATA-TROL Precoupled gilsonite/resin • • • • • • 2-6 Y
SUN DRILLING PRODUCTS, TBC-BRINADDFor complete listings, visit the online survey at www.offshore-mag.com.
TETRA TECHNOLOGIES, INC.
ACTIVIS Liquid viscosifier • •
BIOPOL Dry viscosifier • •
BIOPOL HT Dry viscosifier • •
BIOPOL L Liquid viscosifier • •
CT FOAM Coil tubing additive • •
HYDROGEN PEROXIDE Oxidizer • •
PAYZONE 750 Temperature stabilizer • •
PAYZONE HPS High performance starch • • • •
PSEUDOPOL Synthetic polymer • • •
PSEUDOPOL D Synthetic polymer • • •
PSEUDOPOL HT Dry viscosifier • • •
PSEUDOPOL HT Liquid Hi prof liquid viscosifier • • •
TETRAVIS Dry HEC polymer • •
TETRAVIS BREAKER Viscosity breaker • •
TETRAVIS EXTENDER Temperature stabilizer • •
TETRAVIS L Liquid HEC polymer • •
TETRAVIS L PLUS Double strength liquid HEC viscosifier • •
TURBO-CHEM INTERNATIONAL,VENTURE CHEMICALSFor complete listings, visit the online survey at www.offshore-mag.com.
WEATHERFORD INTERNATIONAL LTD.
DRILL-IT 300 Anionic drilling polymer • • 0.25-1 lb/bbl
DRILL-IT 315 Anionic drilling polymer • 0.5-3 lb/bbl
DRILL-IT 500 Anionic drilling polymer • 0.5 lb/bbl
F L O C C U L A N T S
BAKER HUGHES DRILLING FLUIDS
MF-1 High molecular weight non-ionic selective flocculant •
BAROID FLUID SERVICES
BARAFLOC Flocculant for drilling fluids • 0.01-0.25 Y
CLAY GRABBER Liquid flocculant for HYDRO-GUARD • • • • 0.5-2.0 Y
CRYSTAL-DRIL Flocculant for clear water drilling • • • 0.2-1.0
ENVIRO-COG C Inorganic coagulant • • • • 0.05-1.0
ENVIRO-COG S Inorganic coagulant • • • • 0.05-1.0
ENVIRO-FLOC 104 Polymeric flocculant • • • • 0.01-0.25
ENVIRO-FLOC 109 Polymeric flocculant • • • • 0.01-0.25
EZ-FLOC Flocculant blend • • • • 0.01-0.25
FLO-CLEAN MD Flocculant for calcium brines 1-3 vol%
FLO-CLEAN Z Flocculant for zinc brines 1-3 vol%
BASF For complete listings, visit the online survey at www.offshore-mag.com.
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CABOT SPECIALTY FLUIDS
4MATE-VIS-HT HT formate viscosifier • 5-8 NC Y
KELCO OIL FIELD GROUP, KEMTRON TECHNOLOGIES, LAMBERTI SPA, MESSINAFor complete listings, visit the online survey at www.offshore-mag.com.
M-I SWACO
FILTER FLOC Flocculant for displacements • • 0.01-2.0 vol%
FLOXIT Organic flocculant • • 0.1-2 N N Y
GELEX Polymer bentonite extender • • 0.05-0.2 N N Y
KLA-FLOC I Low-cost shale inhibitor for floc water drilling • • 1-4 vol%
KLA-FLOC II Cationic flocculant for flow water drilling • • 1-4 vol%
POLY-PLUS High M.W. PHPA polymer • • • 0.5-4 Y N Y
POLY-PLUS DRY Dry PHPA polymer • • • .25-2 N N
POLY-PLUS LV Low-viscosity PHPA polymer • • • .25-2 N N
POLY-PLUS RD Readily dispersible powdered high m. w. PHPA • • • 0.5-4 Y N Y
SAFE-FLOC I Surfactant / flocculant solvent blend • • 1-4% N N
SAFE-FLOC II Surfactant / solvent blend • • 1-4% N N
NOV FLUIDCONTROL
TRU-FLUSH Surfactants and flocculants • • • • • 0.55 Y
ISO-DRILL RD Nonionic PHPA • • • 0.5-0.2 Y
Q’MAX, SPECIAL PRODUCTS For complete listings, visit the online survey at www.offshore-mag.com.
TETRA TECHNOLOGIES, INC.
TETRA DIRT MAGNET Well bore cleaner • • • • • •
F R I C T I O N R E D U C E R F O R C O I L T U B I N G
DRILLING SPECIALTIES CO. For complete listings, visit the online survey at www.offshore-mag.com.
G E L L I N G A G E N T S / V I S C O S I F I E R S
AKZO For complete listings, visit the online survey at www.offshore-mag.com.
AQUALON
AQUAFLO HV Low viscosity Standard Polyanionic cellulose • • • • 0.25-2 Y Y
AQUAPAC LIQUID Environmental friendly anhydrous • • • • 0.50-4 D Y Y
AquaPAC suspension
AQUAPAC REGULAR High viscosity Premium Polyanionic cellulose • • • • 0.25-2 Y Y
ECODURA PLONOR rated aqueous HEC suspensions • • • • 1-10 Y Y
GALACTASOL 251 High viscosity straight guar • • • • 0.25-2 Y Y
GALACTASOL 252 Straight guar • • • • 0.25-2 Y Y
GALACTASOL 267 Diesel slurriable guar • • • • 0.25-2 Y Y
GALACTASOL 284 Self hydrating dispersible straight guar • • • • 0.25-2 Y Y
GALACTASOL 286 Diesel slurriable high viscosity guar • • • • 0.25-2 Y Y
GALACTASOL 288 Fast Hydrating High Viscosity guar • • • • 0.25-2 Y Y
GALACTASOL 289 Fast Hydrating High Viscosity guar • • • • 0.25-2 Y Y
GALACTASOL 290 Fast Hydrating High Viscosity guar • • • • 0.25-2 Y Y
GALACTASOL 467 Diesel slurriable Hydroxypropyl guar • • • • 0.25-2 Y Y
GALACTASOL 474 High viscosity Hydroxypropyl guar • • • • 0.25-2 Y Y
GALACTASOL 476 Buffered High viscosity Hydroxypropyl guar • • • • 0.25-2 Y Y
GALACTASOL 477 Self hydrating dispersible Hydroxypropyl guar • • • • 0.25-2 Y Y
GALACTASOL 638 Fast hydrating high viscosity Carboxymethyl • • • • 0.25-2 Y Y
Hydroxypropyl guar
GALACTASOL 650 Carboxymethyl Hydroxypropyl guar with adipic acid • • • • 0.25-2 Y Y
GALACTASOL 651 Carboxymethyl Hydroxypropyl guar • • • • 0.25-2 Y Y
GALACTASOL 653 Diesel slurriable Carboxymethyl guar • • • • 0.25-2 Y Y
NATROSOL 210 HHX Ultra High viscosity and Fast hydrating HEC • • • • 0.5-2.5 Y Y
NATROSOL 250 HHR-P Ultra High viscosity HEC • • • • 0.5-2.5 Y Y
NATROSOL LIQUID Environmental friendly anhydrous HEC suspension • • • • 1-5 D Y Y
NATROSOL HI-VIS Ultra High viscosity HEC • • • • 0.5-2.5 Y Y
ARCHER DANIELS MIDLAND, ASAP FLUIDSFor complete listings, visit the online survey at www.offshore-mag.com.
BAKER HUGHES DRILLING FLUIDS
BENEX Bentonite extender 2 lb/5-8 banf sacs
CARBO-GEL Organophilic clay for solids suspension • • 1-5
CARBO-GEL II Quick-yielding organophilic clay for solids suspension • • 4-8
MAGMA-GEL Organophilic clay for MAGMA-TEQ • •
extreme HPHT emulsion system
MAGMA-GEL SE Suspension Enhancer for MAGMA-TEQ • •
extreme HPHT emulsion system
MILGEL Wyoming bentonite meeting API specifications • • • • 0-25 Y
MILGEL NT Untreated Wyoming bentonite meeting API specs • • • • 0-25 Y
MP-HOLD A unique organophilic clay for cuttings suspension • • 5-14ppb
MP-LIFT Rheology modifier for invert emulsion systems 1-2ppb
NEXT-HOLD A unique organophilic clay for cuttings suspension • • 5-14ppb
NEXT-LIFT Rheology modifier for invert emulsion systems 1-2ppb
OMNI-PLEX High-performance, anionic, synthetic polymer • •
PRIME VIS HT Viscosifier for high temperature displacements
QUICK VIS Liquid brine viscosifier - multi-salt systems • • As needed E Y
QUICK VIS HT Liquid brine viscosifier - HT environment • • As needed
RHEO-CLAY Fast yielding organophilic clay • • 2-4
for RHEO-LOGIC deepwater system
RHEO-CLAY PLUS Temperature-stable organophilic clay • • 2-4
for RHEO-LOGIC deepwater system
SALT WATER GEL Attapulgite clay meeting API specifications • • • 20 Y
SUPER-COL Exrta-high-yield bentonite • • 0.5-5 Y
ULTRAVIS Liquid brine viscosifier -single salt systems • • As needed E Y
VIS Pure synthetic polymer • • • • 0.2-4.0
W.O. 21 Hydroxethyl cellulose • • • • 1-3
W.O. 21L Liquid HEC viscosifier • • • • 0.15-2.1 gal/bbl
W.O. 21LE Liquid HEC viscosifier for workover fluids - • • • 0.3-1 gal/bbl
environmentally safe
W.O. 21 LE PLUS Liquid HEC in environmentally friendly base • • • 0.3-1 gal/bbl
XAN-PLEX Xanthan gum polymer • • • • 0.2-2 Y
XAN-PLEX C Clarified Xanthan gum polymer • • • • 0.2-2
XAN-PLEX eL Clarified Xanthan gum polymer • • 0.5-3.0
XAN-PLEX D Xanthan gum polymer • • • • 0.2-2 Y
XAN-PLEX L Liquid xantham gum polymer 0.5-3.5
XAN-PLEX T Technical grade xanthan gum polymer
XAN-PLEX TD Technical grade dispersed xanthan gum polymer
XCD POLYMER Fresh or brine-water viscosifier • • 0.5-3.0 E Y
BAROID FLUID SERVICES
AQUAGEL Wyoming bentonite • • • • 5.0-25.0 Y Y Y
AQUAGEL GOLD SEAL Untreated Wyoming bentonite • • • • 5.0-25.0 Y Y Y
BARACTIVE Polar activator for all-oil systems • • 4.0-7.0 Y Y Y
BARAPAK Oil-soluble polymer • • 2.0-3.0 Y
BARARESIN-VIS Oil mud viscosifier • • • 3-20
BARAVIS Modified cellulose • • • • 1-3 Y Y
BARAZAN Xanthan gum • • • • 0.1-2.0 Y Y Y
BARAZAN D Dispersion enhanced xanthan gum • • • • 0.1-2.0 Y Y
BARAZAN L Xanthan suspension • • • • 0.5-4.0 Y Y
BARAZAN D PLUS Premium dispersion-enhanced xanthan • • • • 0.1-2.0 Y Y Y
BAROLIFT Synthetic monofilament fiber • • • • • • 0.1-0.5 Y Y
BORE-VIS II Modified bentonite-BOREMAX system • 5.0-15.0
BROMI-VIS Pre-dispersed polymer suspension • • 5.0-20.0 Y
GELTONE Oil mud viscosifier • • 2.0-5.0 Y
GELTONE II Oil mud viscosifier • • 2.0-15.0 Y Y
GELTONE V Oil mud viscosifier • • 1.0-15.0 Y
LIQUI-VIS EP Non-ionic polymer dispersion • • • • 0.2-9.0 Y
MUD GEL Treated, premium grade sodium bentonite • • • • 2.0-25.0
N-VIS Biopolymer • • • • • • 1.0-3.0 Y
N-VIS HI Mixed metal silicates • 1 Y
N-VIS HI PLUS Mixed metal silicate complex • 0.5-2.0 Y
N-VIS L Liquid xanthan gum • • • • 0.2-9.0 Y
N-VIS O Organophilic clay • • 1.0-6.0
N-VIS P PLUS Polymer Blend • • • 1.0-4.0 Y Y Y
RHEMOD L Modified fatty acid • • 1.0-4.0 Y Y
RHEOBOOST Oil mud viscosifier • • 0.5-4.0 Y
RM-63 Rheology modifier • • 0.5-2.0 Y Y
SUSPENTONE Organophilic clay • • 0.1-5.0 Y Y
TAU-MOD Amorphous/fibrous material • • 0.5-5.0 Y Y
TEMPERUS Modified fatty acid • • 0.25-2.5 Y Y
THERMA-VIS Synthetic inorganic viscosifier • • • • 1.0-4.0 Y Y
X-TEND II Bentonite extender • • • • 0.01-0.05 Y
VIS-PLUS Organic viscosifier • • 1.0-5.0 Y
ZEOGEL Attapulgite • • • • 5.0-30.0 Y Y Y
BASF, BOYSENBLUE/CELTEC INTERNATIONAL For complete listings, visit the online survey at www.offshore-mag.com.
CABOT SPECIALTY FLUIDS
4 MATE-VIS-HT High temperature formate viscosifier • 4-8
CHEMSTAR PRODUCTS, CHEMTOTAL, CRODA, DEEP SOUTH CHEMICAL, DRILLING SPECIALTIES CO., DRILLSAFE JANEL, ECOFLUIDS, EMERY, GUMPRO, KELCO OIL FIELD GROUP, LAMBERTI SPA, LAMBERTI USA, LIQUID CASING, MAYCO WELLCHEM, MESSINAFor complete listings, visit the online survey at www.offshore-mag.com.
M-I SWACO
ACTI-BUILD Polar activator for Eastern Hemisphere • •
DI-BALANCE Viscosifier for the DIPRO system • 0.25-2
DI-BOOST Secondary viscosifier for DIPRO system • .03-.06 gal/bbl
DIPRO LD Low-density, DIPRO system • System
DRILPLEX Viscosifier for DRILPLEX system • • 1-3 Y
DRILPLEX HT MMO viscosifier for high temperature • • 2-7 N N N
DRILPLEX LT MMO viscosifier for low temperature • • 1-3 N N N
DUO-TEC Xanthan gum polymer • • • • 0.25-2 Y N
DUO-TEC NS Xanthan gum polymer, non-dispersible for North Sea use • • • • 0.25-2 Y N Y
DUO-VIS Xanthan gum dispersible polymer • • • • 0.25-2 Y N Y
DUO-VIS L Liquified Xanthan gum, non-clarified • • • • 0.25-0.5 Y N
DUO-VIS NS Xanthan gum, non-dispersible for North Sea use • • • • 0.5-2.5 Y N Y
DUO-VIS PLUS Premium Grade of Xanthan gum • • • • 0.25-2 Y N Y
DUO-VIS PLUS NS Premium Grade of Xanthan gum, • • • • 0.25-2 Y N N
non-dispersible for North Sea use
DUROGEL Sepiolite clay • • • • 5-30 N N Y
FLO-TROL Starch derivative for FLOPRO NT systems • • • 2-4 Y Y Y
FLO-VIS L Non-dispersible clarified Xanthan gum • • • • .25-.5 gal/bbl
FLO-VIS NT Non-dispersible, non-clarified Xanthan gum • • • • 0.25-2.5
FLO-VIS PLUS Premium clarified Xanthan for FLOPRO NT systems • • • • 0.75-2.25 N N
GELEX Polymer bentonite extender • • 0.05-0.2 N N Y
GELPLEX Viscosifier for the DRILPLEX system • 7-10
HIBTROL HV Fluid loss additive and secondary shale inhibitor • • • 1.4-7
HRP Liquid viscosifier & gelling agent for oil muds • 1-6 N N
ISOLOK Viscosifier for ISOTHERM Insulating Packer Fluid • 0.25 - 1.0%
ISOVIS Viscosifier for ISOTHERM Insulating Packer Fluid • 0.25 - 1.0%
M-I GEL Premium grade treated Wyoming bentonite • • • • 5-35 Y Y
M-I GEL SUPREME Non-treated bentonite, API spec • • • • 5-35 N N Y
M-I GEL SUPREME Non-treated API Wyoming bentonite • • • • 5-35 N N Y
WYOMING
M-I GEL WYOMING API-spec bentonite Wyoming source only • • • • 5-35 N N
M-I PAC R Pure PAC polymer, regular grade • • • 2-5 Y Y
NOVAMOD Low-shear rate viscosifier • 1-5 N N Y
NOVATEC M Low-end rheology modifier • 1-3 N N
POLYPAC R Polyanionic cellulose • • • • 0.5-2 Y Y Y
POLYPAC SUPREME R Polyanionic cellulose, premium grade • • • • 0.5-2 Y N
POLY-SAL Non-fermenting starch • • • • 2-6 N N Y
POLY-SAL HT High-quality, preserved polysaccharide • • • • 2-6
POLY-SAL T Non-fermenting tapioca starch derivative • • • • 2-6 N N
POWER VIS Viscosifier: creates less pump pressure • 0.875-1.25
& thermal convection
POWER VIS L Liquid version of POWER VIS viscosifier • .125-.5 gal/bbl
RHEBUILD Viscosifier for RHELIANT system • 0.25-0.5
RHEFLAT Rheology modifier for RHELIANT system • 0.5-3
RHETHIK Rheology modifier for RHELIANT system • 0.25-1
SAFETHERM-VIS L Viscosifier in SAFETHERM system • 0.25-0.5 gpb
SAFE-VIS Brine viscosifier • • • • 0.5-4 Y N
SAFE-VIS E Liquid HEC • 5-10 Y N
SAFE-VIS HDE Liquid HEC for high-density brines • • • 14-29 N N
SAFE-VIS LE Liquid viscosifier for brines • 0.6-1.2 gpb
SAFE-VIS OGS Specially formulated liquid HEC • 0.6-1.2 gpb
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SALT GEL Attapulgite clay • • • • 5-35 Y Y Y
SUPRAVIS Viscosifier for the ULTRADRIL system • • 0.25-2
SUREMOD Viscosifier for SBM systems • 1-4 N N Y
SURETHIK Rheological modifier • 0.25-1 N N
TARVIS L Liquid viscosifier for the SAGDril system • 0.25-0.5 gpb N N
TRUVIS Primary viscosifier for TRUDRIL systems • 0-8 N N
UNIPAC SUPREME R Dispersible, high-viscosity PAC • • • • 0.25-1
VERSAGEL HT Hectorite • 0-8 Y N
VERSAMOD Oil mud gelling agent and viscosifier • 1-3 N N
VERSAMUL Primary emulsifier and wetting agent • 2-10 N N
VERSAPAC Thermally activated organic thixotrope • • 5-30 N N
VG-69 Organophilic clay • • 2-10 N N Y
VG-PLUS Improved organophilic clay • • 2-10 Y N
VG-SUPREME Organophilic clay for the NOVA systems • 2-10
NOV FLUIDCONTROL
NOV TROL Viscosifier - liquid • • • • 0.25-4 Y
AMZINC VIS I Liquid viscosifier • 3%
AMZINC VIS II Liquid viscosifier • 3
AMZINC VIS III Liquid viscosifier • 3
ECOGEL H Organophilic hectorite viscosifier • • 4-10 Y
ECOGEL M Organophilic clay • • 4-10
NOV GEL Bentonite • • • • 6-35
NOV GEL NT Bentonite, non-treated • • • • 6-35 Y
SALT GEL Attapulgite • • • • 6-35 Y
NOV XAN Xanthan gum • • • • 0.25-4 Y
NOV XAN D Xanthan gum • • • • 0.25-4 Y
OLEON N.V., PRIME ECO GROUP INC., PT. INDOBENT WIJAYA MINERAL, Q’MAX, QUARON N.V.For complete listings, visit the online survey at www.offshore-mag.com.
STRATA CONTROL SERVICES, INC.
STRATA SUPER SWEEP Ground filament materials • • • • • • 0.3-0.6 Y
SUN DRILLING PRODUCTS , TBC-BRINADDFor complete listings, visit the online survey at www.offshore-mag.com.
TETRA TECHNOLOGIES, INC.
ACTIVIS Liquid viscosifier • •
ATAPULGITE Saltwater gel • •
BENTONITE Freshwater gel • •
BIOPOL Dry viscosifier • • • • Y
BIOPOL HT Dry viscosifier • • • • Y
BIOPOL L Liquid viscosifier • • • • Y
PAYZONE 750 Temperature stabilizer • •
PAYZONE HPS High performance starch • • • • Y
PSEUDOPOL Synthetic polymer • • •
PSEUDOPOL D Synthetic polymer • •
PSEUDOPOL HT Dry viscosifier • •
PSEUDOPOL HT LIQUID Hi prof liquid viscosifier • •
TDSP I <12 LB/GAL Viscosified weighted spacer • • • • • •
TDSP I <15 LB/GAL Viscosified weighted spacer • • • • • •
TDSP I <19 LB/GAL Viscosified weighted spacer • • • • • •
TDSP III - 11.6 CACL2 Viscosified sweep • • • • • •
TDSP III - FRESHWATER Viscosified sweep • • • • • •
TDSP III - SALTWATER Viscosified sweep • • • • • •
TETRA HELP Temperature extender - • • basic amine-glycol mixture
TETRAFLEX 110 Cross linked gelled polymer • • • • POLYMER
TETRAFLEX 135 Cross linked gelled polymer • • • • POLYMER
TETRAVIS Dry HEC polymer • • • • Y
TETRAVIS EXTENDER Temperature stabilizer • •
TETRAVIS L Liquid HEC polymer • • • • Y
TETRAVIS L PLUS Double strength liquid HEC viscosifier • • • •
TURBO-CHEM INTERNATIONAL For complete listings, visit the online survey at www.offshore-mag.com.
WEATHERFORD INTERNATIONAL LTD.
HGA-37 Hydrocarbon base gelling agent • 0.5-1.0%
HGA-44 Cross-linker for HGA-37 and HGA-715 • 0.5-1.0%
HGA-48 Cross-linker for HGA-37, 70, 702 • 0.5-1.0%
HGA-61 Delayed cross-linker for HGA-70, 71, 702 • 0.5-1.0%
HGA-65 Cross-linker for HGA-70, -71, -702 • 0.3-1.0%
HGA-70 Hydrocarbon base gelling agent, HT • 0.3-1.0%
HGA-71 Hydrocarbon base gelling agent, HT • 0.5-1.0%
HGA-702 Hydrocarbon base gelling agent, HT • 0.3-1.0%
HGA-715 Hydrocarbon base gelling agent • 0.5-1.0%
HGA-S61 Cross-linker for HGA-70, 71, 702 • 0.5-1.0%
POLYMER K Water-soluble drilling polymer • 1.5-3 lbs/bbl
WGA-1 Water gelling agent • • 1-8 Y
WGA-2 Water gelling agent • • 1-8 Y
I N T E R V E N T I O N F L U I D S
M-I SWACO
FLODENSE AP High density displacing fluid for casing • 17.5-20.5 ppg Y pressure remediation
FLOPRO CT Coiled tubing drilling / intervention fluid • • • 8.5-9.5 ppg Y
L O S S C I R C U L A T I O N , S E A L I N G M A T E R I A L S
ASAP FLUIDS For complete listings, visit the online survey at www.offshore-mag.com.
BAKER HUGHES DRILLING FLUIDS
BAKER-SQUEEZ Single sack lost circulation solution • • • • varies E Y Y
SEAL F, M & C Sized calcium carbonate • • • • 5-50
CARBO-SEAL Modified hydrocarbon LCM for sealing • • varies Y
CHEK-LOSS Complex cellulosic LCM • • • • 4-8+ ppb Y
CHEK-LOSS COARSE Coarse, complexed cellulosic for loss of circulation • • • • • • 4-8+ ppb Y
CHEK-LOSS PLUS High-lignin cellulosic LCM particularly for • • 4-8+ ppb Y OBM/NAF with less adverse effect on PV and ES
ECCO-FIBER Fine Environmentally friendly cellulosic LCM • • • • as needed
ECCO-FIBER Medium Environmentally friendly cellulosic LCM • • • • as needed
ECCO-SHELL SERIES Environmentally friendly LCM • • • • as needed
FLO-GUARD-L Drilling fluid and cement LCM system • • E Y
FLO-GUARD-LC Drilling fluid and cement LCM system • •
FLOW-CARB SERIES Multiple grind size series of calcium carbonate • • • • varies
LC-LUBE Sized, synthetic graphite • • • • • • 2-8 ppb Y
LC-LUBE FINE Sized, synthetic graphite • • • • • • 2-8 ppb Y
LC-SHEILD Sized, calcined petroleum coke • • • • • • 6-20 ppb
LC-SHEILD FINE Sized, calcined petroleum coke • • • • • • 6-20 ppb
MAGNA-PLUS Acid soluble bridging material • • • As needed E Y
MIL-CARB SERIES Sized ground calcium carbonate • • • • • • 1-50 ppb Y
MIL-CEDAR FIBER Shredded cedar bark • • • • 5-10 ppb Y
MILFLAKE Shredded cellophane • • • • varies
MILMICA Muscovite mica • • • • • • 5-10 ppb Y
MIL-PLUG Ground nut shells • • • • • • 5-10 ppb Y
MIL-SEAL Blended LCM product available in 3 grind sizes • • • • 5-10 ppb Y
NEXT-SEAL LCM/HPHT control agent in all invert • • Seepage loses emulsions fluids 0.1 to 0.25ppb
POLY-FX Polymeric LCM low density brines • • • • •
SOLUFLAKE D Flaked calcium carbonate for drilling • • • • • • 2-8 ppb Y
SOLUFLAKE Flaked calcium carbonate • • • • • • 2-8 ppb Y SF, F, M, C, D
SOLU-SQUEEZE Acid-soluble LCM • • • • • • varies
TEKPLUG XL Cross linked polymer (no zinc) • Gold Y
TEKPLUG XL HD Cross linked polymer high density •
THERMO-PLUG I Crosslinked LCM system •
THERMO-PLUG II Crosslinked LCM system •
W.O. 30 Sized, ground calcium carbonate • • • • • • 5-40 ppb Y (Multiple grind sizes available)
X-LINK Cross-linked polymer system • • • • • •
XL STABILIZER pH control additive •
BAROID FLUID SERVICES
BARACARB 5, 25, 50, Sized acid-soluble marble • • • • • • 5-60 Y Y Y 150, 400, 600, 1200
BARACARB DF 5, 25, Sized acid-soluble marble • • • • • • 5-60 Y Y Y 50, 150, 600
BARAFLAKE M, L Flaked calcium carbonate • • • • • • 5-20 Y Y Y
BARA-PERFLUID Blend specially for use in perforating • • • • • • As needed
BARAPLUG 20, Sized salt • • 5-60 Y Y Y 50, 6/300
BARARESIN Sized oil soluble bridging agent-F, M, C • • 5-20 Y
BAROFIBRE Seepage-loss additive, regular & coarse • • • • • • 5-50 Y Y Y
BAROFIBRE SUPERFINE Seepage-loss additive, fine • • • • • • 5-50 Y Y Y
BAROFIBRE O Oil wet Seepage-loss additive • • • • • • 5-50
BARO-SEAL Classic Sized LCM blend • • • • 5-50 Y Y
BARO-SEAL Coarse Sized LCM blend • • • • 5-50 Y Y
BARO-SEAL Fine Sized LCM blend • • • • 5-50 Y Y
BARO-SEAL Medium Sized LCM blend • • • • 5-50 Y Y
DUO-SQUEEZE H, R, SA Dual size blend for high loss zones • • • • • • 40-100
EZ-PLUG Acid soluble LCM Blend • • • • • • 5-90 Y
FUSE-IT Synthetic polymer-based blend • • • • • • Pill form Y
HYDRO-PLUG Hydratable polymeric blended material • • • • • • Pill form Y
HYDRO-PLUG NS Hydratable polymeric blended material • • • • • • Pill form Y Y Y
N-PLEX Activator for N-SQUEEZE • • • • • • As needed Y Y
N-SEAL Inorganic LCM • • • • • • As needed Y
N-SQUEEZE Lost circulation material • • • • • • As needed Y Y
PLUG-GIT Processed cedar fiber • • • • • • 3-10 Y Y Y
PLUG-GIT H Processed hardwood fiber • • • • • • 3-10 Y Y Y
STOP-FRAC D Pelletized blend of LCM • • • • • • 10-15 Y
STOP-FRAC S Pelletized blend of coarse LCM • • • • • • 50-70 Pill
STEELSEAL 50, 100, Dual composition carbon compound • • • • • • 5.0-30 Y Y Y 400, 1000
WALL-NUT Ground walnut shells -- F, M, C • • • • • • 10-40 Y Y Y
BOYSENBLUE/CELTEC INTERNATIONAL, DRILLING SPECIALTIES CO., DRILLSAFE JANEL, GUMPRO, IMPACT FLUID SOLUTIONS, KELCO OIL FIELD GROUP, KEMTRON TECHNOLOGIES, LIQUID CASING, M&D INDUSTRIES OF LOUISIANA, MAYCO WELLCHEM, MESSINAFor complete listings, visit the online survey at www.offshore-mag.com.
M-I SWACO
C-SEAL Coke FLCA • • • • • • 15-20 N N
C-SEAL F Coke FLCA - fine grind • • • • • • 15-20 N N
CLEANPERF Fluid-loss system for perforating operations • • System Y
FORM-A-BLOK High-performance, high-strength blend • • • • • • 20-40
FORM-A-PLUG II Pumpable lost circulation plug • • • • • • 100%
FORM-A-PLUG ACC Accelerator for FORM-A-PLUG pill • • • • • • 3.5-10.5
FORM-A-PLUG RET Retarder for FORM-A-PLUG pill • • • • • • 3.5-17.5
FORM-A-SET Polymeric lost circulation material • • • • • • 25-50 Y N
FORM-A-SET ACC Accelerator for FORM-A-SET pill • • • • • • 1-5 N N
FORM-A-SET AK Polymeric LCM • • • • • • 25 N N
FORM-A-SET AKX Variant of FORM-A-SET AK pill for water shutoff • • • • • • 11-17.5 N N
FORM-A-SET RET Retarder for FORM-A-SET pill • • • • • • 0-20 N N
FORM-A-SET XL Crosslinker for FORM-A-SET pill • • • • • • 1-2 N N
FORM-A-SQUEEZE High-solids, high-fluid loss plug • • • • • • 80
G-SEAL Coarse-sized graphite • • • • • • 15-20 Y Y
G-SEAL FINE Fine-sized graphite • • • • • • 15-20
G-SEAL HRG High-resiliency graphite • • • • • • 5-10
G-SEAL HRG FINE High-resiliency graphite • • • • • • 5-10
G-SEAL PLUS Coarse-sized plugging agent • • • • • • 15-20
G-SEAL PLUS C Blend for lost circulation and wellbore strengthening • • • • • • 15-20
LO-WATE Sized ground limestone • • • • • • 10-40 N Y
M-I CEDAR FIBER Shredded cedar bark fiber • • • • 5-30 Y N
M-I SEAL LCM for fractured or vugular formations • • • • • • 5-20 N N
M-I-X II Ground cellulosic fibers • • • • • • 5-20 Y Y
M-I 198 Coarse-ground high-temp Gilsonite •
NUT PLUG Ground nut shells • • • • • • 5-50 Y Y Y
OPTISEAL I Loss prevention material • • • • • • 30-70
OPTISEAL II Loss prevention material • • • • • • 30-70
OPTISEAL III Loss prevention material • • • • • • 30-70
OPTISEAL IV Loss prevention material • • • • • • 30-70
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70 Offshore September 2013 • www.offshore-mag.com
RESEAL Highly compressive graphite • • • • • • 15-20
SAFE-CARB Sized ground marble • • • • • • 10-50 Y N
SAFE-LINK Cross linked polymer (no zinc) • 32pails/10bbl N N
SAFE-LINK 110 Cross linked polymer (no zinc) • 32pails/10bbl N N
SAFE-LINK 140 Cross linked polymer high density • 32pails/10bbl N N
SEAL-N-PEEL Removable loss control pill • • 8.4-17.5 ppg
THRUCARB Organophilic bridging agent for FLOTHRU system • • 5.0 - 12.0
VERSAPAC Thermally activated organic thixotrope • • 5-30 N N
VERSATROL Naturally occurring asphalt • 2-8 Y Y
VINSEAL Filtration control additive particularly effective • • • • • • 2-5 in depleted zones
NEWPARK DRILLING FLUIDS
CYBERSEAL Fiberous seepage control agent • • 10-35 Y
DYNAFIBER Micronized cellulose • • • • • • F, M, C Y
NEWBRIDGE Sweep / bridging material • • • • • • 2-15 Y
NEWCARB Sized calcium carbonate • • • • • • F, M, C Y
NEWCARB ULTIMIX Coarse calcite / marble • • • • • • 25-50 Y
NEWPLUG Nut shell • • • • • • 2-20 Y
NEWSEAL Sized carbonaceous seepage agent • • • • • • 5-15 Y
X-PRIMA One-sack, high-solids squeeze • • • • • • Y
NOV FLUIDCONTROL
NOV TROL Viscosifier liquid • • 0.25-4
AMVIS Viscosifier • • 0.25-4 dry powder
KWIK SEAL Granules, flakes, fibers • • • • 25 Y
MAGMA FIBER Lost circulation material • • 5-25
MICA Mica • • • • 25 Y
NOV CARB C Calcium carbonate • •
NOV CARB F Calcium carbonate • •
NOV CARB M Calcium carbonate • • • • 30 Y
NOV FIBER Ground plant fibers • • • • 4 Y
NOV PLUG Nutshells • • • • 10-30
NOV PLUG X Sized Organic Blend • • • • 20 Y
STARPLUG Crosslink polymer blend • • • • • • Pill Form
STARSQUEEZE Crosslink polymer blend • • • • • • Pill Form
SURESEAL Graded carbon compound • • • • • •
PRIME ECO GROUP INC., Q’MAX, QUARON N.V., SETAC, SPECIAL PRODUCTS For complete listings, visit the online survey at www.offshore-mag.com.
STRATA CONTROL SERVICES, INC.
FRAC-ATTACK Package high filtration squeeze pill • • • • • • 80 Y
STRATA-FLEX FINE Resilient elastomeric sealant materials • • • • • • 2-6+ Y
STRATA-FLEX MEDIUM Resilient elastomeric sealant materials • • • • • • 2-20+ Y
STRATA-LCM MEDIUM Medium grade blended cellulose fiber • • • • • • 2-20+ Y
STRATA-SCM FINE Fine grade blended cellulose fiber • • • • • • 2-6+ Y
STRATA-VANGUARD Package LCM pill mixed in mud • • • • • • 50-100 Y
SUN DRILLING PRODUCTS, TBC-BRINADDFor complete listings, visit the online survey at www.offshore-mag.com.
TETRA TECHNOLOGIES, INC.
PAYZONE 530 Med grind, acid soluble fiber • • • • Y
PAYZONE 532 Fine grind, acid soluble fiber • • • • Y
PAYZONE CARB PRIME Broad PSD - fine grind CaCO3 • • • • • Y
PAYZONE CARB ULTRA Ultra fine grind, CaCO3 • • • • • Y
PAYZONE FLC Premixed gelled polymer pill • • FLEXSEAL
PAYZONE FLC SLURRY Severe lost circulation pill • •
PAYZONE FLC Calcium carbonate pill • • SMARTSEAL
PAYZONE FLC-CC Calcium carbonate pill • •
PAYZONE FLC-SS Sodium chloride pill •
PAYZONE HPS High performance starch • • • • Y
PAYZONE SS PRIME Broad PSD - fine grind NaCl • • • Y
PAYZONE SS ULTRA Ultra fine grind, NaCl • • • Y
TETRA FLEX 110 Cross Linked Gelled polymer • •
TETRA FLEX 135 Cross Linked Gelled polymer • •
TETRA SS COARSE Size controlled, coarse NaCl • • • Y
TETRA SS FINE Select grind, fine grind NaCl • • • Y
TETRA SS MEDIUM Size controlled, med size NaCl • • • Y
TETRACARB COARSE Size controlled, coarse CaCO3 • • • • • • Y
TETRACARB FINE Select grind, fine CaCO3 • • • • • • Y
TETRACARB FLAKE Sized calcium carbonate
TETRACARB MEDIUM Size controlled, medium CaCO3 • • • • • • Y
TETRA MAGMAFIBER Med grind, acid soluble fiber • • • • Y REG
TETRA MAGMAFIBER Fine grind, acid soluble fiber • • • • Y FINE
TURBO-CHEM INTERNATIONAL, VENTURE CHEMICALS For complete listings, visit the online survey at www.offshore-mag.com.
P O LY M E R B R E A K E R S
TBC-BRINADD For complete listings, visit the online survey at www.offshore-mag.com.
S H A L E C O N T R O L
AKZO NOBEL, AMERICAN GILSONITE For complete listings, visit the online survey at www.offshore-mag.com.
AQUALON
AQUAFLO LV High viscosity Standard Polyanionic cellulose • • • • 0.25-2 Y Y
AQUAFLO HV Low viscosity Standard Polyanionic cellulose • • • • 0.25-2 Y Y
AQUAPAC LIQUID Environmental friendly anhydrous • • • • 0.50-4 D Y Y AquaPAC suspension
AQUAPAC LV Low viscosity Premium Polyanionic cellulose • • • • 0.25-2 Y Y
AQUAPAC REGULAR High viscosity Premium Polyanionic cellulose • • • • 0.25-2 Y Y
AQUAPAC ULV Ultra Low viscosity Premium Polyanionic cellulose • • • • 0.25-2 Y Y
ASAP FLUIDS For complete listings, visit the online survey at www.offshore-mag.com.
BAKER HUGHES DRILLING FLUIDS
AQUA-COL Glycol used to control sensitive shales, increase • • • 3% Y lubricity and lower HT-HP filtrate in freshwater and saltwater systems
AQUA-COL B Cloud-point glycol for shale control • • 3-5% Y in medium-salinity systems
AQUA-COL D Glycol used to control sensitive shales, • • 3% Y increase lubricity and lower HT-HP filtrate in moderate to high-salinity systems
AQUA-COL S Glycol used to control sensitive shales, • • 4% Y increase lubricity and lower HT-HP filtrate in high-salinity systems
CHEK-TROL Clay swelling & hydration suppressant • • • • 2-3%
CLAY-TROL Amphoteric surfactant • • • • 4-8 ppb Y
CLAY-TROL XPR Temperature stable shale hydration suppressant • • • • 4-6%
ECCO-BLOK Water-dispersible natural resinous material • • • • 2-6 ppb for shale stabilization
ECCO-GLYCOL Glycol for shale control • • • • varies
MAX-GUARD Clay hydration suppressant • • • • 1-7 ppb
MAX-PLEX Aluminum and resin complex for shale stability • • • • 1-5 ppb
MAX-SHIELD Deformable sealing polymer for shale stability • • • • 2-4% Y
MAX-SHIELD NS Deformable sealing polymer • • • • 2-4%
NANOSHIELD Dry deformable sealing polymer for shale stability • • • • 1-5 lb/bbl
NEW-DRILL High-molecular weight anionic liquid polymer • • • • 1.5-2% Y
NEW-DRILL HP Powdered polymer for improved shale control • • • • 1.5-2 ppb Y
NEW-DRILL LV Low viscosity PHPA • • • • 1-3 ppb
NEW-DRILL LV STICK Low viscosity polymer Stick • • • • as needed
NEW-DRILL NY Cuttings encapsulant approved for use in Norway • • • • 1-3 ppb
NEW-DRILL PLUS Powdered, high-molecular weight, partially • • • • 1-3 ppb Y hydrolyzed polyacrylamide
NEW-DRILL STICK Polymer Stick • • • • as needed
PROTECTOMAGIC Oil-soluble, air-blown asphalt used with oil • • • • 2-8 ppb
PROTECTOMAGIC M Water-dispersible, air-blown asphalt • • • • 2-8 ppb Y
SHALE-BOND Water-dispersing, naturally-occurring asphalt • • • • 2-6 ppb Y
SHALE-PLEX Aluminum complex for shale stability • • • • 1-4 ppb
SULFATROL Sulfonated asphaltic material • • • • 2-6 ppb Y
TERRA-COAT Deformable sealing polymer for TERRA-MAX • • • • • 2 ppb Y
BAROID FLUID SERVICES
AK-70 Asphaltic blend • • • • • • 5.0-15.0 Y
BARABLOK Powdered gilsonite, wallcake enhancer • • • • • • 5.0-35.0 Y Y
BARABLOK 400 Hi-temp powdered gilsonite • • • • • • 5.0-35.0 Y
BARACAT Cationic polymer solution • 1.0-3.0 Y
BARASIL-S Sodium silicate solution • 2-10% Y Y
BARO-TROL PLUS Enhanced shale stabilizer • • • 2.0-6.0 Y
BORE-HIB Shale inhibitor blend-BOREMAX system • 1-2 vol%
BORE-HIB II Liquid inorganic salt blend • • •
BORE-PLUS Shale stabilizer-BOREMAX system • 0.2-3 Y
BXR Borehole stabilizer • • • • 4.0-20.0 Y
BXR-L Borehole stabilizer suspension • • • • 8.0-40.0 Y
CLAY FIRM Shale stabilizer-HYDROGUARD system • 5.0-8.0 Y
CLAY GRABBER Shale encapsulator • • • • 0.5-2.0 Y
CLAY SYNC Shale stabilizer-HYDROGUARD system • 2.0-4.0 Y Y
CLAY SYNC II Shale stabilizer-HYDROGUARD system • 2.0-4.0 Y
CLAYSEAL Amphoteric compound shale stabilizer • • • • 4.0-8.0 Y
CLAYSEAL PLUS Amphoteric compound shale stabilizer • • • • 4.0-8.0 Y Y
EZ-MUD Shale stabilizing polymer solution • • • • 1.0-4.0 Y
EZ-MUD DP Powdered shale stabilizing polymer • • • • 0.25-1.5 Y Y
EZ-MUD GOLD Beaded shale stabilizing polymer • • • • 0.25-1.5 Y Y
GEM CP Polyglycol • • • • 5-7% Y Y
GEM GP Polyalkylene glycol • • • • 2-6% Y Y
GEM SP Polyglycol • • • • 2.0-15.0 Y
MEGAGEN Sodium silicate solution • 2-10%
PERFORMATROL Shale inhibitive polymer • • • 2-3% Y Y
BASF For complete listings, visit the online survey at www.offshore-mag.com.
CABOT SPECIALTY FLUIDS
CESIUM ACETATE Density to 2.3 sg (19.2 ppg) • •
CESIUM FORMATE Density to 2.3 sg (19.2 ppg) • • E N
CESIUM FORMATE/ Density to 2.42 sg (20.18 ppg) • • ACETATE BLEND
MIXED FORMATES Densities from 1.0 sg to 2.3 sg • E Y
POTASSIUM FORMATE Density to 1.57 sg (13 ppg) • E Y N
SODIUM FORMATE Density to 1.3 sg (10.8 ppg) • E Y Y
CESCO CHEMICAL
CESCO C-G Pretreated gilsonite • • • • 4-6 Y
DEEP SOUTH CHEMICAL, DRILLING SPECIALTIES CO., DRILLSAFE JANEL, EMERY, GRAIN PROCESSING CORP., GUMPRO, IMPACT FLUID SOLUTIONS, KELCO OIL FIELD GROUP,LAMBERTI SPA, LAMBERTI USA, LIQUID CASING, MAYCO WELLCHEM, MESSINAFor complete listings, visit the online survey at www.offshore-mag.com.
M-I SWACO
ASPHASOL Blend of sulfonated organic resins • • 4-10 N N Y
ASPHASOL D Sulfonated organic blend • • • 4-10 N N
ASPHASOL SUPREME Sulfonated asphalt • • • • • 2-8
DI-INHIB Shale inhibitor for the DIPRO system • 3 vol%
DRILPLEX Viscosifier for DRILPLEX system • • 1-3 Y
DRIL-KLEEN Low-toxicity detergent • • • • 0.2-1 N N Y
ENVIROBLEND Salt for ENVIROVERT system •
FLOXIT Clay flocculant • • 0.1-2 N N Y
GLYDRIL GP Polyalkylene glycol with low cloud point • • • • 7-17.5 Y N
GLYDRIL HC Polyalkylene glycol with high cloud point • • • • 7-17.5 N N
GLYDRIL LC Polyalkylene glycol with low cloud point • • • • 7-17.5 Y N
GLYDRIL MC Polyalkylene glycol with medium cloud point • • • • 7-17.5 Y N
HIBTROL Fluid loss additive & secondary shale inhibitor • • • 1-5 Y N
HIBTROL HV Fluid loss additive & secondary shale inhibitor • • • 1.4-7
HIBTROL ULV Ultra-low vis filtration control additive and • • • 2.1-7 secondary shale inhibitor
IDCAP D Polymeric shale inhibitor • • 1-4 Y N Y
INHIBYCOL XT Wide-molecular-weight glycol • • • • 7-17.5
K-17 Potassium lignite • • • 1-15 N N Y
K-52 Non-chloride potassium supplement • • • • 1-5 N N Y
KLA-CURE Hydration suppressant • • • 4-8 Y N Y
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KLA-CURE II Hydration suppressant and detergent • • • • 4-8
KLA-GARD Shale inhibitor & hydration suppressant • • • 4-8 Y N Y
KAL-GARD B Salt-free KLA-GARD • • • 4-8 N N Y
KLA-HIB Liquid amine shale inhibitor • • • 4-10
KLA-PLEX Potassium-base shale inhibitor • •
KLA-SENTRY Shale inhibitor for lignosulfonate muds • 4-10
KLA-STOP Shale inhibitor • • • 2-4vol% N N
KLA-STOP NS Shale inhibitor • • • 2-4vol%
KLAFLOC I Low-cost shale inhibitor for floc water drilling • 1-4vol%
M-I PAC R Pure PAC polymer, technical grade • • • 2-5 Y Y
M-I PAC UL PAC polymer, low viscosity, technical grade • • • 2-5 Y Y
PARAMIX A Salt for the PARALAND system • 25-40%wt
PARAMIX N Salt for the PARALAND system • 25-40%wt
POLYPAC R Polyanionic cellulose • • • • 0.5-2 Y Y Y
POLYPAC ELV Extra-low-viscosity PAC • • • • 0.5-2 Y N
POLYPAC SUPREME R PAC, premium grade • • • • 0.5-2 Y N
POLYPAC SUPREME UL PAC, premium grade, ultra-low viscosity • • • • 0.5-2 Y N
POLYPAC UL PAC, ultra-low viscosity • • • • 0.5-2 Y N
POLY-PLUS High m.w. PHPA polymer • • • 0.5-4 Y N Y
POLY-PLUS DRY Dry PHPA polymer • • • 0.25-2
POLY-PLUS LV Low-viscosity PHPA polymer • • • 0.25-2 N N
POLY-PLUS RD Readily dispersible PHPA dry powder • • • 0.5-4 Y N Y
POROSEAL Latex-modified starch polymer • • • 2-5vol%
SHALE-CHEK Shale control additive • • • • 5 N N
SILDRIL D Dry sodium silicate • • • 9-15% Y Y
SILDRIL K Potassium silicate version of SILDRIL • • • 8-12%
SILDRIL L Liquid sodium silicate • • • 5-8% Y Y
SP-101 Sodium polyacrylate polymer • • • • 0.5-2 N N Y
TARCLEAN Anticrete agent for heavy oil • 100% app
ULTRACAP Encapsulator for ULTRADRIL system • • 1.5-3
ULTRACAP NS Biodegradable shale encapsulator • • 1.5-3
ULTRACAP PLUS Polymeric shale inhibitor for ULTRADRIL system • • 2-4
ULTRAHIB Shale inhibitor for ULTRADRIL system • • 2-4 vol%
ULTRAHIB NS ULTRAHIB variant for North Sea • • 2-4vol%
UNIPAC SUPREME UL Dispersible, regular-grade PAC • • • • 0.25-1
XP-20K Potassium causticized chrome lignite • • • 1-15 N N Y
XP-20 N Chrome lignite, neutralized • • • 1-15 N N
MONTELLO
MON PAC Polyanionic cellulose • • • • 0.25-2 Y
MON PAC ULTRA LO Polyanionic cellulose • • • • 0.25-2 Y
NEWPARK DRILLING FLUIDS
DEEPDRILL INHIBITOR Proprietary HPWB shale inhibitor • • • • 3-20 vol% Y
FLEXFIRM Potassium silicate shale stabilizer • • 0.1-4 Y
HIPERM Amine shale inhibitor • • • 0.3-0.6 vol%
LST-MD Liquid sulfonated asphalt • • • • 2-3 vol%
NEWPHASE Blend of polyglycerines • • 1-10
NEWPHALT Sulphonated asphalt blend • • • • • 2-8
NEWPHPA PHPA • • • • 0.2-2 Y
NEWPHPA D PHPA • • • • 0.25-1 Y
NEWPHPA DLMW Low molecular weight anionic PHPA • • • • 1-3 Y
NEWPHPA DSL Very low molecular weight PHPA • • • • 1-4 Y
NOV FLUIDCONTROL
PETRO-TITE Gilsonite • • • • • 2-8 Y
K-TROL Potassium acetate, liquid • • • 2-6
NOV TEX Proprietary Blend • • • • • 1-5 Y
POTASSIUM CHLORIDE Salt • • As needed
SOLTEX Asphalt • • • • 4-8 Y
PETRO-TITE LIQUID Gilsonite blend liquid • • • • 2-6
STARTROL Asphalt blend • • • • 2-6
TRIPLE A Anti-accretion agent • • • • .5-3.0 % Y
OLEON N.V., PQ CORP., PRIME ECO GROUP INC., Q’MAX, QUARON N.V., SETAC, SPECIAL PRODUCTS, SUN DRILLING PRODUCTS, TBC-BRINADD For complete listings, visit the online survey at www.offshore-mag.com.
TETRA TECHNOLOGIES, INC.
PAYZONE STAY Clay Stabilizer • •
PAYZONE STRATAFIX Shale/clay stabilizer • •
TURBO-CHEM INTERNATIONAL, VENTURE CHEMICALSFor complete listings, visit the online survey at www.offshore-mag.com.
WEATHERFORD INTERNATIONAL LTD.
ALPHA 9206 Shale control amine • • • 0.01-1
CC-200 Polymer/formate shale control • • • 0.002 Y
CC-300 Copolymer/formate shale control • • • 0.2%-0.5% Y
SC-900 Shale control copolymer • 1000-2000 ppm
S P O T T I N G F L U I D S , L U B R I C A N T S
ASAP FLUIDS For complete listings, visit the online survey at www.offshore-mag.com.
BAKER HUGHES DRILLING FLUIDS
AQUA-MAGIC Differential sticking preventative for depleted zones • • • • 2-4% Y
AQUA-MAGIC XPR Oil-free differential sticking preventative • • • • 2-4% Y
BIO-DRILL Polyol-based drilling/ROP enhancer • • • • 2-4% Y
BIO-SPOT Non-hydrocarbon, low toxicity spotting fluid • • • • as needed Y Y
BIO-SPOT XPR nontoxic, oil-free, water-soluble fluid • • • • as needed Y
for freeing stuck pipe
BLACK MAGIC Oil-base spotting fluid • • • • as needed
BLACK MAGIC CLEAN Environmentally-safe spotting fluid • • • • as needed Y
BLACK MAGIC LT Low-toxicity, oil-base spotting fluid • • • • as needed
BLACK MAGIC Spotting fluid without asphalt • • • • • • as needed Y
PHALT FREE
BLACK MAGIC SFT Oil-base spotting fluid concentrate • • • • as needed Y
ECCO-LUBE WBM lubricant • • • • 0.5-2%
LATILUBE High temperature lubricant • • • 2-4%
LATIMAGIC Wellbore stabilizer and lubricant • • • 5-10 ppb
LATIRATE Rate of penetration enhancer and lubricant • • • 2-4%
for water-based fluids
LC-GLIDE Spherical carbon material for torque and drag reduction • • • • • • 2-12 ppb Y Y
LC-LUBE Sized, synthetic graphite • • • • • • 2-8 ppb Y
LC-LUBE FINE Sized, synthetic graphite • • • • • • 2-8 ppb Y
LUBE-622 WBM lubricant • • • • 2-4% Y
LUBRI-GLIDE COARSE Spherical CPC friction reducer • • • • • • As needed
LUBRI-GLIDE FINE Spherical CPC friction reducer • • • • • • As needed
MIL-GLIDE Spherical glass drilling bead used • • • • • • 2-6 ppb
as a boundary lubricant
MIL-GLIDE FINE Fine grade spherical glass drilling bead • • • • • • 2-6 ppb
MIL-GLIDE CP Spherical copolymer drilling bead used • • • • • • 2-12 ppb
as a boundary lubricant
MIL-GLIDE CP FINE Fine spherical co-polymer drilling bead • • • • • • 2-12 ppb
MIL-GRAPHITE Graded graphite used primarily to enhance • • • • • • 5-20 ppb
lubricity and sliding
MIL-LUBE Vegetable oil-base boundary and extreme • • • • 2-4% Y
pressure lubricant
NF2 Gas hydrate inhibitor • • • • 10-40% Y Y
NF3 Gas hydrate inhibitor • • • • • 5-40% Y
OMNI-LUBE EP lubricant for emulsion systems • • 2.5-4%
OMNI-LUBE V2 Lubricant for invert emulsion drilling fluids • • 2.5-4%
PENETREX ROP enhancer & anti-bit balling/accretion additive • • • • 2-3% Y
PENETREX NS ROP enhancer—designed for North Sea applications • • • • 2-3% Y
PENETREX XPR ROP enhancer formulated for offshore use • • • • • • 2-3%
PLUG-DRILL FR Friction reducer for plug-drill outs • • 1-2.5 ppb
PROTECTOMAGIC Oil soluble, air-blown asphalt used with oil • • • • 2-6 ppb
PROTECTOMAGIC M Water-dispersible, air-blown asphalt • • • • 2-6 ppb Y
SUPER INSULGEL Insulating packer fluid for deepwater • • As needed
TEQ-LUBE II Environmentally-acceptable lubricant for WBM • • • 3-5%
TEQ-LUBE NS Environmentally-acceptable lubricant • • • 3-5%
for WBM in the North Sea
TERRA-RATE ROP enhancer for TERRA-MAX • • • 1-4%
TERRA-RATE XPR ROP enhancer for TERRA-MAX • • • 2-6%
BAROID FLUID SERVICES
BARO-LUBE GOLD SEAL Surfactants/lubricant blend • • • • 2.0-6.0 Y
BARO-LUBE NS Surfactants/lubricant blend • • • • 2.0-6.0 Y Y
CMO-568 Oil mud lubricant • 2.0-6.0 Y
DRIL-N-SLIDE ROP enhancer • • • • 2.0-5.0% Y Y
EZ SPOT Spotting fluid concentrate • • • • as needed
ENVIRO-TORQ Broad-spectrum lubricant • • • • 2.0-6.0 Y
EP MUDLUBE Extreme-pressure lubricant • • • • 2.0-6.0 Y
EZ GLIDE Lubricant • • 1.0-3.0 Y
GRAPHITE Carbon platelets • • • • • • 5.0-40.0 Y Y Y
LIQUI-DRIL ROP enhancer • • • < 1.0 Y
LUBRA-BEADS Copolymer bead lubricant, F and C • • • • • • 4.0-8.0 Y
NXS-LUBE Extreme-pressure lubricant • • • • 2.0-8.0 Y
QUIK-FREE High performance spotting fluid • • • • As needed Y
STICK-LESS 20 Spherical glass beads • • • • • • 4.0-8.0 Y Y Y
TORQ-TRIM 22 Lubricant • • • • 2.0-6.0
TORQ-TRIM II Lubricant • • • • 2.0-6.0 Y Y
TORQ-TRIM II PLUS Lubricant • • • • 2.0-6.0 Y Y
TORQUE-LESS DI-170 Spherical glass beads • • • • • • 4.0-8.0 Y Y Y
XLR-RATE ROP enhancer • • • 1.0-4.0 Y
BASF, BOYSENBLUE/CELTEC INTERNATIONAL, CRODA, DRILLSAFE JANEL, EMERY, GUMPRO, KEMTRONTECHNOLOGIES, LAMBERTI SPA, LAMBERTI USA, LIQUID CASING, MAYCO WELLCHEM, MESSINAFor complete listings, visit the online survey at www.offshore-mag.com.
M-I SWACO
ALPINE SPOTTING Lubricating beads • • • • 8-12
BEADS
D-D Drilling detergent • • • • 0.5-6 N N Y
DRILFREE High-performance lubricant, anti-sticking agent • • • • 1-3% Y N
DRIL-KLEEN Anti bit balling agent • • • • 0.2-1.0 N N Y
DRIL-KLEEN II Anti bit balling agent • • • • 0.2-0.5 N N
FLO-LUBE Lubricant for coiled tubing applications • • • 0.5-1.5%vol
FLO-LUBE II High-performance lubricant for land drilling • • • 1.0-3.0%vol
GLYDRIL GP Polyalkylene glycol with low cloud point • • • • 7-17.5 Y N
GLYDRIL HC Polyalkylene glycol with high cloud point • • • • 7-17.5 N N
GLYDRIL LC Polyalkylene glycol with low cloud point • • • • 7-17.5 Y N
GLYDRIL MC Polyalkylene glycol with medium cloud point • • • • 7-17.5 Y N
G-SEAL Coarse sized graphite • • • • • • 15-20 Y Y
IDLUBE XL Extreme pressure lubricant • • • • 1-6vol%
LOTORQ Lubricant for FLOPRO system in Alaska • • • • 1-3 vol%
LUBE-PLEX Lubricant for enhanced DRILPLEX system • 1-3vol%
LUBE XLS Extreme pressure lubricant • • • • 1-6vol% Y
LUBE-100 Low-toxicity lubricant • • • • 4-6 N N Y
LUBE-167 Lower-toxicity lubricant • • • • 4-16 Y N Y
LUBE-776 Lubricant for LSND muds • 1-3 vol%
LUBE 945 WBM lubricant • • • • 4-16
M-I LUBE General-purpose lubricant • • • • 1-3% N N
PIPE-LAX Stuck pipe surfactant • • • • • 8.3 N N Y
PIPE-LAX ENV Low-toxicity stuck pipe solution • • • • 100% N N Y
PIPE-LAX ENV WH Water soluble low toxicity stuck pipe solution • • • • 100%
PIPE-LAX OB Stuck pipe solution for Invert Emulsion systems • • 100%
PIPE-LAX W EXPORT Stuck pipe solution concentrate • • • • • 30.3 N N Y
SAFE-LUBE Water-soluble brine lubricant • 0.6vol% N N
SAFE-LUBE CW Water-soluble brine lubricant for cold weather • 0.6vol%
SCREENKLEEN Screen cleaner for drilling tar sands 1
SILDRIL EPL Silicate-base extreme pressure lubricant • • • 5-8% N N
SIL-LUBE Lubricant for SILDRIL system • • 1-3% N N
STARGLIDE Lubricant for WBMs • • • • 1-3 vol%
STAR-LUBE Brine Lubricant • 2 vol%
STEEL LUBE EP Extreme-pressure lubricant • • • • 1-3 vol%
ULTRAFREE ROP Enhancer for the ULTRADRIL system • • • 1-2 vol%
ULTRAFREE L Low-cost anticrete • • • 1-2vol%
ULTRAFREE NH Non-hydrocarbon version of ULTRAFREE • • • 1-2vol%
VERSALUBE Oil-soluble lubricant • • 1-3vol% N N
MONTELLO
HME ENERGIZER Selective non-ionic wetting agent • • • • 0.1-1 Y
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NEWPARK DRILLING FLUIDS
TOPSPOT Non-toxic organic blend • • • • X
DYNAFREE Blend of lubricants & surfactants • • • • X
DYNAVERT SFT One-sack blend of emulsifiers & gellants • • • •
EVOLUBE DPE HPHT Drilling Performance Enhancer • • 2-4 vol% X
EVOLUBE S Modified ester ROP enhancer • • • • 2-5 vol% X
NEW100 Blend of polyglycerines • • • • • • 3-4 vol% X
NEW100 N Blend of polyglycerines • • • • • • 3-4 vol% X
NOV FLUIDCONTROL
DE-2000 ROP Enhancer • • • •
DL-100 EP Lubricant • • • •
ECOSPOT Environmentally safe spotting fluid • • • • Y
TRAXX TC Metal Adhereing Lubricant • • • • Y
OLEON N.V., Q’MAX, SETAC, SPECIAL PRODUCTSFor complete listings, visit the online survey at www.offshore-mag.com.
STRATA CONTROL SERVICES, INC.
STRATA-LUBE Fatty acid based liquid lubricant • • • • 0.5-3.0
SUPER GLIDE BEADS Glass beads F-M-C • • • • • • 1-20+ Y
STRATA-FLEX Fine Resilient Elastomeric Material • • • • • • 1-20+ y
SUN DRILLING PRODUCTS, TBC-BRINADDFor complete listings, visit the online survey at www.offshore-mag.com.
TETRA TECHNOLOGIES, INC.
CT 100 FR Friction reducer •
CT 200 FR Friction reducer •
PAYZONE FLC SLICK Solids free pill • •
PAYZONE Solids free pill • • SMARTSEAL PAD
PAYZONE STRATA Lubricant • • GLIDE
TETRAGLIDE Water-soluble brine lubricant • 0.6vol% N N
TURBO-CHEM INTERNATIONAL, VENTURE CHEMICALSFor complete listings, visit the online survey at www.offshore-mag.com.
WEATHERFORD INTERNATIONAL LTD.
ALPHA 6111 Low toxicity spotting fluid • • 0.5-2
ALPHA 6151 Lubricant/spotting fluid • • 0.5-2
ALPHA 6156 Lubricant/spotting fluid • • 0.5-2
ALPHA 6177 Dispersant lubricant, low tox. • • 0.5-2
S U R FA C TA N T S
ARCHER DANIELS MIDLAND, AQUA-CLEAR, ASAP FLUIDSFor complete listings, visit the online survey at www.offshore-mag.com.
BAKER HUGHES DRILLING FLUIDS
AMPLI-FOAM FW Freshwater foaming agent • 1-2 gal/10 bbl
AMPLI-FOAM SW Saltwater foaming agent • 1-2 gal/10 bbl
BAKER CLEAN 5 WB casing cleaning system for removal 80-100 L/m3 Y of WB and OBM contaminants
BAKER CLEAN 6 A casing cleaning system and stabilizer 60-80 L/m3 Y for Baker Clean 5 in a viscosified system
BIO-COTE Wetting agent for synthetic systems • • 2.4-24 L/m3 Y
CLAY-COTE HT Wetting agent and secondary emulsifier • • 0.25-2 ppb
CLEAN-THREAD Pipe dope remover • • varies
MD Biodegradable drilling fluid detergent • • • • • .02-.04 gal/bbl
MD-II Biodegradable drilling fluid detergent • • • • • .02-.04 gal/bbl
MICRO-PRIME OBM Displacement System • •
MIL-CLEAN Water-soluble, biodegradable detergent/rig wash • • • • • • 1%
MIL-CLEAN E Biodegradable cleaner/degreaser • • • • • 1%
MIL-CLEAN SEA North Sea approved rig wash detergent • • 1%
MICRO-CURE AF E2 Acid-free mesophase remediation •
MICRO-CURE E2 Mesophase remediation •
MP-COTE Wetting agent for invert emulsion systems • • • 0.2-4.0lb/bbl
MUL-FREE RS Non-emulsifying surfactant 0.25-0.75%
NEXT-COTE Wetting agent for invert emulsion systems • • • 0.2-4.0lb/bbl
NOMUL Z Non-emulsifier for calcium / zinc brines 0.5-1.0 vol %
OMNI-COTE Wetting Agent all emulsion fluids • • • 0.1-1 gal/bbl
PACK-MUL Wetting agent for OMNI-PACK system • • 6-10 ppb
PRIME 200HT Wellbore cleaning product • • Varies for high temperature displacements
PRIME VIS HT Viscosifier for high temperature displacements • • 3-10 ppb
TECHNICLEAN 4570 Casing wash for oil and synthetic mud • • • As needed
TECHNICLEAN 4575 Casing wash for oil and synthetic mud • • • As needed
ULTRA FLUSH Weightable WBM/OBM casing wash • • • • As needed
WELL WASH 100 Casing wash for water-based fluids • • 2-20%
WELL WASH 120 Casing wash for water-based fluids • • 2-20%
BAROID FLUID SERVICES
AKTAFLO-S Non-ionic surfactant • • • • 0.5-7.0 Y
AQUATONE-S Non-ionic surfactant • • • • 0.5-7.0 Y
BARAKLEAN Degreaser and oil mud remover As needed Y
BARAKLEAN FL Wellbore cleaner for displacement 5% in H20 Y
BARAKLEAN FL PLUS Wellbore cleaner for displacement 5% in H20 Y Y
BARAKLEAN GOLD Wellbore cleaner for displacement 5% in H20 Y Y
BARAKLEAN NS PLUS Wellbore cleaner for displacement 5% in H20 Y Y
N-FLOW BREAKERS Delayed, in-situ filter-cake breakers • • • • • • as needed Y Y
CON DET Mud detergent • • • • 0.25-1.0 Y
CON DET E Surfactant blend • • • • 0.25-1.0 Y
DHT FOAM Foaming agent 0.02-2.0%
DRILFOAM Foaming agent 0.1-1.0% Y
DRILTREAT Oil wetting agent • 0.25-2.0 Y Y Y
EXTENSOL Salt crystal growth inhibitor • 0.2-0.5
PIPESCRUB Pipe dope remover As needed Y
QUIK-FOAM Foaming agent 0.02-2.0% Y
BASF, CRODA, DRILLSAFE JANEL, GUMPRO, KEMTRON TECHNOLOGIES, LAMBERTI SPA, LAMBERTI USA, MAYCO WELLCHEM, MESSINA For complete listings, visit the online survey at www.offshore-mag.com.
M-I SWACO
CLEAN UP Surfactant blend • • • • • • 1-100% N N
D-D Drilling detergent • • • • 0.5-6 N N Y
D-SPERSE Surfactant • 0.25-1 vol%
DEEPCLEAN Solvent/surfactant wash chemical O/SBM • • 5-20% Y Y Y
DEEPCLEAN NS Solvent/surfactant wash chemical O/SBM • • 5-20% Y Y
DRILFREE Lubricant, anti-sticking agent • • • • 1-3% Y N
DRIL-KLEEN Low-toxicity detergent • • • • 0.2-1 N N Y
DRIL-KLEEN II Anti bit balling agent • • • • 0.2-0.5 N N
DRILZONE ROP enhancer • • • 1-2vol%
DRILZONE L Low-cost anticrete • • • 1-2vol%
DRILZONE NS ROP enhancer • • • 1-2vol%
DRILZONE II ROP enhancer • • • 1-2vol%
ECOGREEN P Primary emulsifier • 2-6 Y N
ECOGREEN S Secondary emulsifier • 2-6 Y N
ECOKLEEN Anticrete for tar applications
ENVIROBLEND Salt for ENVIROVERT system •
FAZE-OUT Delayed breaker system for FAZEPRO system • System Y
FAZE-MUL Emulsifier for FAZEPRO System • • 8-12 N N
FAZE-WET Wetting agent for FAZEPRO system • • 8-12 N N
GLYDRIL DG Water-miscible glycol hydrate inhibitor • • • • 3-20% N N
HYDRABLOK Deepwater hydrate inhibitor • • • • 5 vol%
KLEEN UP Surfactant cleaner • •
LUBE-167 Low-toxicity lubricant • • • • 4-16 Y N Y
M-I 157 Supplemental emulsifier • • 0.5-2 N N
MUD WASH Rig wash 2-10vol%
NOVAMUL Primary emulsifier and wetting agent for synthetic fluids • 2-8 N N Y
NOVATHIN Thinner for synthetic muds • 0.5-2 N N Y
NOVAWET Wetting agent for synthetic muds • 1-5 N N Y
NOVAWET CN Capped wetting agent •
NOVAWET PLUS Capped wetting agent •
PARAWET Wetting agent for OBM & SBM • • 1-5
SAFE-FLOC I Surfactant / flocculant solvent blend • • 0.01-2.0% N N
SAFE-FLOC II Surfactant / solvent blend • • 0.01-2.0% N N
SAFE-LUBE Water-soluble brine lubricant • 0.6vol% N N
SAFE-LUBE CW Water-soluble brine lubricant for cold weather • 0.6vol%
SAFE-SOLV E Pipe dope pickle solvent • 2-20% Y N
SAFE-SOLV OM Dispersible solvent for OBMs and SBMs • • 2-20% N N
SAFE-SURF E Non-ionic wellbore cleaning agent for OBM and WBM • • • • • • 2-15 vol%
SAFE-SURF NS Wash chemical • • 5-20 vol%
SAFE-SURF O Concentrated surfactant for wellbore clean-up • 2-20% N N
SAFE-SURF O II Displacement wash chemical for WBM • • • • 1-10% N N
SAFE-SURF W Surfactant-base detergent • • • • 2-10% N N
SAFE-SURF WE Non-ionic surfactant blend • • 2-10% N N
SAFE-SURF WN Displacement wash chemical for WBM • • • • 2-10% N N
SAFE-T-PICKLE Pipe dope solvent • • • • 1
SCREENKLEEN Stops screen blinding from tar & heavy oil • • • • 0.5-1 vol%
STARGLIDE Lubricant for WBMs • • • • 1-3 vol%
SUREMUL Primary emulsifier for synthetic systems • 2-8 N N Y
SUREMUL EH Non-dispersive emulsifier for SBM • 2-8
SURETHIN Thinner for synthetic systems • 0.5-2 N N Y
SUREWET Wetting agent for SBM systems • 1-5 N N Y
SWA EH OBM wetting agent for high-brine-content systems • 1-5 N N
TARLIFT Solvent for the SAGDril system • 0.1-2 vol%
TARSURF Water-wetter for the SAGDril system • 0.02-0.5 vol%
ULTRAFREE ROP enhancer for ULTRADRIL system • • • 1-2vol%
ULTRAFREE L Low-cost anticrete • • • 1-2vol%
ULTRAFREE NH Non-hydrocarbon version of ULTRAFREE • • • 1-2vol%
ULTRAFREE NS ROP enhancer for WBM • • 1-2 vol%
ULTRAFREE II ROP enhancer for ULTRADRIL system • • 1-2 vol%
VERSACOAT Wetting agent & emulsifier • 1-8 N N
VERSACOAT HF Emulsifier for OBM • 1-8 N N
VERSACOAT NA High flash point emulsifier for oil muds • 1-8 N N
VERSATRIM Reduces oil on cuttings for OBM • 2-6
VERSAWET Wetting agent for OBM • 1-6 N N
MONTELLO
HME ENERGIZER Wetting agent, coupler for gilsonite • • • • 0.1 - 0.5 PPB N N Y
NOV FLUIDCONTROL
TRU-FLUSH Well wash • • 55/100
HME Surface active agent • • • •
TENSION-EZE Drilling mud detergent • • • • 0.1-0.4 Y
OLEON N.V., Q’MAX, SPECIAL PRODUCTS For complete listings, visit the online survey at www.offshore-mag.com.STRATA CONTROL SERVICES, INC.
STRATA-COUPLER Liquid coupler for gilsonite, asphalt,etc • • • • 0.01 - 0.03 Y
SUN DRILLING PRODUCTS, TBC-BRINADDFor complete listings, visit the online survey at www.offshore-mag.com.
TETRA TECHNOLOGIES, INC.
TDSP II OMD Surfactant wash • •
TDSP II O-SOL Surfactant wash • • • •
TDSP II O-SOL PLUS Surfactant wash • • • •
TETRA OMD Surfactant wash • •
TETRA O-SOL Surfactant wash • • • •
TETRASOL Surfactant wash • • • •
WEATHERFORD INTERNATIONAL LTD.
ALPHA 6177 Low toxicity. dispersant • • 0.1-0.4
ALPHA CLEAN O Casing wash/pipe dope, low toxicity •
ALPHA CLEAN W Casing wash, toxicity •
CAT-FOAM Cationic foaming agent • • .02-.2 gal/bbl
CWF-311RC Multi-purpose air-foam drilling surfactant • • .02-.2 gal/bbl
CWF-418 All-purpose, oil-tolerant air-drilling surfactant • • .02-.2 gal/bbl
CWF-419 Oil-tolerant surfactant for high TDS brines • • .02-.2 gal/bbl
CWF-511 Fresh water air-drilling surfactant • .02-.2 gal/bbl
FW-FOAMER Fresh water air-drilling surfactant • .02-.2 gal/bbl
T H I N N E R S / D I S P E R A N T S
AQUALON
AQU D-3536 Cellulosic dispersant and fluid loss additive • • • • 1-3 Y Y
ASAP FLUIDS For complete listings, visit the online survey at www.offshore-mag.com.
1309off_72 72 9/4/13 4:34 PM
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Description
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Description
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74 Offshore September 2013 • www.offshore-mag.com
BAKER HUGHES DRILLING FLUIDS
ALL-TEMP Water-base deflocculant/rheological stabilizer • • • • 0.5-2 ppb Y with special applications in HT environments
ALL-TEMP XPR Economy water-base deflocculant/rheological stabilizer • • • • .25-1 ppb
LIGCO Ground leonardite • • 2-8 ppb Y
LIGCON Ground causticized leonardite • • 2-8 ppb Y
MIL-TEMP Contamination-resistant HPHT rheological • • • • 1-2 ppb Y stabilizer for WBM, > 500°F
NEW-THIN Synthetic deflocculant • • • • 0.14 L/m3 Y
UNI-CAL Chrome-modified sodium lignosulfonate • • • 2-6 ppb Y
UNI-CAL CF Chrome-free lignosulfonate • • • • 1-5 ppb Y
BAROID FLUID SERVICES
ATC All temperature thinner • 1.0-3.0 Y
BARAFOS Sodium polyphosphate compound • 0.1-1.0 Y
BARATHIN-PLUS Modified lignosulfonate • • • • 2.0-6.0 Y
CARBONOX Leonardite • • • • 2.0-12.0 Y Y Y
COLDTROL Cold temperature thinner • 1.0-3.0 Y
DEEP-TREAT Wetting agent • • 1.0-6.0 Y
ENVIRO-THIN Chrome-free lignosulfonate • • • • 2.0-6.0 Y Y Y
IRON-THIN Iron lignosulfonate • • • • 2.0-6.0 Y
LIGNOX PLUS Lignosulfonate thinner for lime muds • 2.0-10.0
OMC Oil mud conditioner • • .25-1.5
OMC 42 Oil mud conditioner • • .25-1.5 Y Y
OMC 2 Oil mud conditioner • • 0.1-0.5 Y
OMC 3 Oil mud conditioner • • 0.1-1.0 Y
QUIK-THIN Ferrochrome lignosulfonate • • • 1.0-8.0 Y
QUIK-THIN PLUS Chrome lignosulfonate • • •
SAPP Sodium acid polyphosphate • • 0.1-0.5 Y Y
THERMA-FLOW 500 High temperature dispersant • • 1-4 vol% Y
THERMA-THIN High temperature deflocculant • • • • 0.1-4.0 Y Y
BASF, BOYSENBLUE/CELTEC INTERNATIONAL, CRODA, DRILLING SPECIALTIES CO., DRILLSAFE JANEL, EMERY, GRAIN PROCESSING CORP., GUMPRO, KELCO OIL FIELD GROUP,KEMTRON TECHNOLOGIES, LAMBERTI SPA, LAMBERTI USA, MESSINAFor complete listings, visit the online survey at www.offshore-mag.com.
M-I SWACO
CAUSTILIG Causticized ground lignite • • • 1-15 N N Y
CALOTHIN HT ENVIROTHERM system Thinner • • • 2-6
CALOSPERSE ENVIROTHERM system Thinner • • • • 4-16
CALOSPERSE ZR ENVIROTHERM system Thinner • • • • 4-16
IDSPERSE XT High temp polymeric dispersant • • • 1-6 Y N
K-17 Potassium causticized lignite • • • • 1-15 N N Y
NOVATHIN Thinner for synthetic muds • 0.5-2 N N Y
NOVAWET Wetting agent for synthetic muds • 1-5 N N Y
PTS-200 Polymeric temperature stabilizer • • • 2-5
PTS-530 Alkalinity control agent • • • • 0.1-1vol%
RESINEX High-temperature synthetic resin • • • • 2-6 N N Y
RESINEX II High-temperature synthetic resin • • • • 2-10 N N Y
RHEDUCE Thinner and conditioner for the RHELIANT system • 0.1-0.2
RHEOCHEK Chrome-free lignosulfonate • • • 1-12
RHEOSPERSE Polymeric high-temperature deflocculant • • • 1-5 N N
SHALE CHEK Shale control & gumbo additive • • • • 5 N N
SPERSENE Chrome lignosulfonate • • • 1-12 N N Y
SPERSENE CFI Iron lignosulfonate • • • 1-12 N N
SPERSENE I Ferrochrome lignosulfonate • • • 0.5-8 N N Y
SURETHIN Thinner for synthetic RDF systems • 0.5-2 N N Y
SUREWET Wetting agent for syn. RDF systems • 1-5 N N Y
TACKLE Sodium polyacrylate • • • 0.1-1 N N Y
TACKLE DRY Dry sodium polyacrylate • • • 0.1-2 N N
TANNATHIN Ground lignite • • • • 1-15 N N Y
THI-2000 Hardness indicator •
THINSMART Organic FCA and rheological additive • • • • 1-6
VERSATHIN Surfactant thinner for high-solids OBM • 0.5-2 N N
VERSATHIN HF Version of VERSATHIN made with VERSACOAT HF • 0.5-2 N N
XP-20 N Chrome lignite, neutralized • • • • 1-15 N N
XP-20K Potassium causticized chrome lignite • • • • 1-15 N N Y
NEWPARK DRILLING FLUIDS
DYNADET Detergent • • • • 0.1-3 X
EVOCON Fluid conditioner • • • • 0.1-2 X
FLEXTHIN HTZ High-temperature thinner • • • • 0.5-10 X
GAGECON Anion surpressor • • 0.1-4 X
NEWFLOW Ferrochrome lignosulfanate • • • • 2-5 X
NEWLIG Lignite • • • • 2-10 X
NEWSTABIL Fluid stabilizer • • • • 0.1-6 X
OPTICLEAN Blend of surfractants • NOV FLUIDCONTROL
LIQUI-THIN Polymeric deflocculant • • • • 1-4 Y
CHEMSPERSE Chrome lignosulfonate • • 2-6 Y
DESCO Modified tannin • • • • 3 Y
DRILLTHIN Organic mud thinner • • • • 0.25-3 Y
ECO-SPERSE Modified lignosulfonate • • • • 0.25-5 Y
NOV LIG Processed lignite • • • • 6 Y
SAPP Sodium acid pyrophosphate • • 0.1-0.25 Y
PRIME ECO GROUP INC., Q’MAX, SPECIAL PRODUCTSFor complete listings, visit the online survey at www.offshore-mag.com.
TETRA TECHNOLOGIES, INC.
FERROBAN Organic iron reducer and sequestrant • •
PAYZONE NE 200 Emulsion preventor • •
PAYZONE NE 300 Emulsion preventor • •
PAYZONE 1320 Penetrant, wetting agent • • •
TURBO-CHEM INTERNATIONAL For complete listings, visit the online survey at www.offshore-mag.com. WEATHERFORD INTERNATIONAL LTD.
ALPHA 6450 Oil mud thinner • 0.5-3
W E I G H T I N G A G E N T S
ASAP FLUIDS For complete listings, visit the online survey at www.offshore-mag.com.
BAKER HUGHES DRILLING FLUIDS
AMMONIUM CHLORIDE Solid salt for NH4Cl fluids to 9 ppg • • As needed E Y
CALCIUM BROMIDE Solid salt for 15.3 ppg • As needed E Y
CALCIUM CHLORIDE Solid salt for 11.6 ppg • As needed E Y
DEEP SWEEP Coarse ground barite to improve hole cleaning • • • • • •
HEMATITE Iron oxide • • • • • • As needed E Y
HYCAL I Calcium chloride solution to 11.6 ppg • As needed E Y
HYCAL II Calcium chloride/calcium bromide solution to 15.1 ppg • As needed E Y
HYCAL III Calcium chloride/calcium bromide/ • As needed B zinc-bromide solution to 19.2 ppg
MIL-BAR Barite meeting API specifications • • • • • • Y
MIL-BAR 410 Barite with 4.1 specific gravity • • • • • • Y
MIL-BAR UF Ultra fine grind barite • • • • • • As needed
POTASSIUM CHLORIDE Solid salt for NoCal fluids to 9.7 ppg • As needed E Y
POTASSIUM FORMATE Dry KCOOH for weight up to 13.1 ppg • E Y
SODIUM BROMIDE Powder for NoCal fluids to 12.7 • As needed E Y
SODIUM CHLORIDE Solid salt for fluids to 10 ppg • As needed E Y
SODIUM FORMATE Dry NaCOOH for weight up to 11 ppg • E Y
W.O. 30 Sized, ground calcium carbonate • • • • • • Y (Multiple grind sizes available)
BAROID FLUID SERVICES
BARACARB 5, 25, Sized calcium carbonate • • • • • • 5.0-60.0 Y Y Y 50,150, 600
BARAPLUG Sized salt • • As needed Y Y Y 20, 50, 6/300
BARAWEIGHT Iron carbonate powder • • • • • • As needed Y
BARODENSE Hematite • • • • • • As needed Y
BAROID Barite • • • • • • As needed Y Y Y
BAROID 41 4.1 specific gravity barite • • • • • • As needed Y Y Y
BAROID F10 10 micron average diameter barite Y Y Y
HEMATITE Iron oxide • • • • • • As needed Y
SWEEP-WATE Selectively sized barite • • • • • • As needed Y Y Y
BOYSENBLUE/CELTEC INTERNATIONAL For complete listings, visit the online survey at www.offshore-mag.com.
CABOT SPECIALTY FLUIDS
CESIUM ACETATE Density to 2.3 sg (19.2 ppg) • •
CESIUM FORMATE Density to 2.3 sg (19.2 ppg) • • E N
CESIUM FORMATE/ Density to 2.42 sg (20.18 ppg) • • ACETATE BLEND
MIXED FORMATES Densities from 1 sg to 2.3 sg • E Y
POTASSIUM FORMATE Density to 1.57 sg (13 ppg) • E Y N
SODIUM FORMATE Density to 1.3 sg (10.8 ppg) • E Y Y
CHEMTOTAL, DRILLSAFE JANEL, ELKEM AS, MATERIALS, GUMPRO, MAYCO WELLCHEM, MESSINAFor complete listings, visit the online survey at www.offshore-mag.com.
M-I SWACO
FER-OX API hematite • • • • • • 1-500 Y Y Y
FLO-WATE Sized salt • 40-60 N N
LO-WATE Sized ground limestone • • • • • • 10-40 N Y
M-I BAR API barite • • • • • • 1-600 Y Y Y
M-I WATE 4.1 sg barite • • • • • • 1-600 N N
SAFE-CARB Sized ground marble • • • • • • 10-50 Y N
WARP Micron-sized weighting agent • • • • • • System
NOV FLUIDCONTROL
CALCIUM BROMIDE Salt • • As needed
CALCIUM CHLORIDE Salt • • As needed
HEMATITE Hematite • • • • • • Y
NOV BAR Barite • • • • • • Y
NOV CARB C Calcium carbonate • • • • As needed
NOV CARB F Calcium carbonate • • • • As needed
NOV CARB M Calcium carbonate • • • • As needed
POTASSIUM CHLORIDE Salt • • As needed
SODIUM BROMIDE Salt • • As needed
SODIUM CHLORIDE Salt • • As needed
SPECIAL PRODUCTS For complete listings, visit the online survey at www.offshore-mag.com.
STRATA CONTROL SERVICES, INC.
STRATA-COUPLER Coupler for gilsonite, asphalt and oil • • • • Y
TBC-BRINADD For complete listings, visit the online survey at www.offshore-mag.com.
TETRA TECHNOLOGIES, INC.
BARITE Insoluble weighting agent
CABR2 Calcium bromide, 95% • •
EXPRESS, 94% Calcium chloride, 94% • •
KCL Potassium chloride, 99% • •
NABR Sodium bromide, 97% • •
NACL Drillers’ Salt
NACL Sodium chloride evaporated salt • •
TETRA SS COARSE Size controlled, coarse NaCl • • • Y
TETRA SS FINE Select grind, fine grind NaCl • • • Y
TETRA SS MEDIUM Size controlled, med size NaCl • • • Y
TETRACARB COARSE Size controlled, coarse CaCO3 • • • • • • Y
TETRACARB FINE Select grind, fine CaCO3 • • • • • • Y
TETRACARB FLAKE Sized calcium carbonate
TETRACARB MEDIUM Size controlled, medium CaCO3 • • • • • • Y
CALCIUM CHLORIDE Stock fluid • • 11.6 ppg
CALCIUM BROMIDE Stock fluid • • 14.2 ppg
ZNBR2/CABR2 Stock fluid • • 19.2 SOLUTION
ZNBR2/CABR2 Stock fluid • • 20.5 SOLUTION
WEATHERFORD INTERNATIONAL LTD.
CLEARFORM K Potassium formate solution • • • • • E
CLEARFORM S Sodium formate dry powder • • • • • E
FOOTNOTES: PLONOR STATUS ONLY GIVEN FOR MATERIALS REGISTERED FOR USE IN THE NORTH SEA
1309off_74 74 9/4/13 4:34 PM
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1309off_75 75 9/4/13 4:34 PM
76 Offshore September 2013 • www.offshore-mag.com
ENGINEERING, CONSTRUCTION & INSTALLATION
Deepwater work in Gulf of Mexico spurs
strong platform supply vessel marketAs feet grows, day rates and utilization remain strong
Over the past year, the platform supply vessel (PSV) market in the US Gulf of Mexico has experienced great times. Vessel owners have seen utili-zation remain high for PSVs of all siz-
es, and day rates in the US Gulf are trending upward, even as the supply of PSVs grows due to new deliveries or vessels returning from other markets.
PSVs are used for a variety of jobs in the oilfeld sector, providing support and supply work at various stages, from seismic surveys to exploration to construction to production to decommissioning. However, the major demand driver for PSVs in the US Gulf is drilling support, and drilling in the US Gulf is more and more a deepwater activity.
As rigs have moved into deeper waters, the PSVs required to support them have become larger, with bigger cargo capacities and newer technologies for station-keeping and propulsion. While 10 years ago a 220-ft
(67-m) PSV would have been the top of the line, operators now look for PSVs that can be more than 300 ft (91 m) in length. High deadweight tonnages, deck cargo, dry bulk, and liquid mud capacities are needed to han-dle the large amount of supplies needed for a deepwater drilling campaign. Additionally, a dynamic positioning system for maintain-ing position has become necessary, with a strong preference for DP-2 systems that have inbuilt redundancy.
The movement toward deepwater has cre-ated a two-tier vessel market. Older vessels, which tend to be 200 ft (61 m) or smaller and
may lack dynamic positioning systems, are now mainly employed on the shelf of the US Gulf, supporting drilling or workover activi-ties, minor supply jobs, and production sup-port at offshore facilities in shallow waters. Newer, bigger vessels with high deadweight tonnages and liquid mud capacities take the deepwater jobs, which promise much higher day rates. Large, DP-2 PSVs can com-mand day rates in the mid-$40,000s, while a 180-ft (55-m) PSV with no dynamic position-ing would earn in the $3,500 to $8,000 range.
As new PSVs enter the market, they tend to have the effect of pushing older vessels out of more lucrative jobs. A 290-ft (88-m), 4,000-plus dwt PSV replaces a 200-ft, 2,000-plus PSV on a drilling support job. The smaller vessel in turn pushes out an older, 180-ft, 1,000-plus PSV which has been work-ing short-term jobs on the shelf.
Market conditions are strong enough at this time that PSVs of all types are in high
Matthew Donovan
IHS Petrodata
Average day rates in the Gulf show a general trend upward for PSVs
of all sizes over the past few years, with some of the most significant
movement seen in rates for PSVs of 3,000 to 3,999 deadweight tonnages.
(Courtesy IHS Petrodata)
The total number of PSVs in the US Gulf has grown to more than 300 ves-
sels currently from a low experienced in 2011 when many vessels exited the
market due to difficult conditions in the post-Macondo US Gulf. Term utiliza-
tion, when vessels have charters of more than 30 days, has increased along
with supply. (Courtesy IHS Petrodata)
1309off_76 76 9/4/13 4:34 PM
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Advisory Board Chairman Welcome: Mr. Matt Lamey, Project Manager, Lucas, Anadarko Petroleum
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Keynote Address: Mr. Don Vardeman, VP Worldwide Projects, Anadarko Corporation
Operator Perspective: Mr. Joe Gregory, General Manager, Major Capital Projects, Chevron
North America, Exploration and Production Corporation
A View From Washington: Mr. Randall Luthi, President, National Ocean Industries Association
(NOIA)
Industry Outlook: Mr. Kenneth B. Medlock II, James A. Baker and Susan G. Baker
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78 Offshore September 2013 • www.offshore-mag.com
ENGINEERING, CONSTRUCTION & INSTALLATION
demand, though the greatest growth in day rates and utilization is for larger vessels. As older PSVs outlive their usefulness in the US Gulf oilfeld market, they may often be sold to vessel companies operating in regions such as West Africa or Central America, with some fnding a new life in cargo transporta-tion, fshing, or dive support roles.
New constructionThe Jones Act requires goods transport-
ed between US ports to be carried by US-fagged vessels built at domestic shipyards. To satisfy demand and Jones Act require-ments, the US Gulf is going through a build-ing boom cycle, with more than 60 PSVs cur-rently under construction at various yards and newbuild options for more available. Vessels currently under construction range in length from 190 ft to 320 ft (58 m to 98 m), with most boasting large liquid mud capaci-ties, dynamic positioning, and deadweight tonnages of more than 6,000. More than 50 new US-fagged PSVs have been delivered to owners over the past three years.
Hornbeck Offshore Services announced a major newbuild program in late 2011, which has grown to 20 PSVs and four MPS-Vs. Since then, other companies, including Edison Chouest Offshore, Tidewater, Gulf-Mark Offshore, and Harvey Gulf Interna-tional Marine, have added to their own new-build programs.
The burgeoning market has also seen the entry of some new players in the deepwater sector via newbuild activity. Bordelon Ma-rine and Jackson Offshore Operators both announced newbuild programs of three and four PSVs, respectively. Previously, the two companies focused on smaller fast supply or mini supply vessels, but will enter the deepwater market upon delivery of recent orders.
A recent decision by Hornbeck may in-dicate that the current wave of newbuild orders has crested. Hornbeck decided to let further shipyard options for 310 and 320 Class PSVs expire. Hornbeck Chairman, President and CEO Todd Hornbeck stated that one of the main reasons the company let its options go was that they see the market being “fully built out” and that announce-ments of newbuilds by Edison Chouest Offshore and other competitors effectively flled the order book and satisfed expected demand in the domestic PSV market.
Vessel purchases and feet consolidation
Harvey Gulf International Marine has been the major purchaser of PSVs in the US Gulf in recent years. In 2012, Harvey Gulf purchased nine PSVs from Bollinger Ship-yards affliate Bee Mar. In May 2013, Har-
vey Gulf acquired a number of vessels from Gulf Offshore Logistics, including six PSVs.
All of the PSVs Harvey Gulf bought in 2012 and 2013 are DP-2 PSVs measuring 210 ft to 294 ft (64 m to 90 m). The vessels are all relatively new, delivered from 2009 through this year. These purchases have helped lift Harvey Gulf to one of the top vessel compa-nies in the US Gulf.
These acquisitions are focused on increas-ing a company’s share of high-spec tonnage, in both cases by the complete acquisition of another vessel company’s deepwater assets. However, other vessel companies have sold older vessels that may not suit either the current US Gulf PSV market or the vessel company’s strategy.
This summer, Aries Marine sold a 185-ft (56-m) PSV that had been cold stacked for around three years. At the beginning of the year, Aries Marine sold a 166-ft (51-m) PSV and 185-ft PSV, both of which had also been stacked for an extended period. In both cases, the non-DP vessels went to buyers outside the US Gulf and are no longer being used for traditional oilfeld supply work.
Hornbeck Offshore Services has begun selling its 220 Class PSVs, with two of the 220-ft vessels sold to smaller independent vessel companies. Four more vessels re-main to be sold. Hornbeck said the vessels, which were built between 1997 and 2000, do not ft the company’s strategy of focusing on larger, high-specifcation vessels. However, in contrast with the Aries Marine vessels, the two 220 Class PSVs that were sold still work in the US Gulf. The vessels have gone from the lower end of Hornbeck’s feet to the largest PSVs a smaller company owns, and are currently working shelf jobs.
Upgraded vesselsWith larger PSVs commanding the high-
est day rates and experiencing the strongest demand in the US Gulf, many vessel owners have taken the opportunity to upgrade some of their smaller or slightly older PSVs to be more competitive. These upgrades can be as simple as improving a vessel’s dynamic positioning system, but can also involve major work such as lengthening the vessel and increasing liquid mud and deck cargo capacities.
Upgrading an existing vessel is faster and less expensive than ordering an entirely new PSV, so upgrade programs allow owners to meet demand for high-spec units in a more timely fashion and to make their vessels more suitable for deepwater work. Vessel owners with newly upgraded PSVs in US wa-ters report increased day rates and longer charters for their PSVs, compared to those earned before the improvements. Though an upgrade can take a PSV out of the mar-
ket for several months and has its own as-sociated costs, the investment has proven worthwhile for many owners.
GulfMark Offshore completed the frst phase of its stretch program this year, which involved six PSVs being taken from 190 ft to 225 ft (58 m to 69 m), with liquid mud capac-ity increases of around 2,000 bbl. During 2Q 2013, GulfMark started a new stretch pro-gram which will take PSVs from 210 ft to 260 ft (64 m to 79 m). The frst of 10 PSVs which could be stretched under this program is now in the yard. Looking ahead, GulfMark has said that four more 190-ft PSVs will be-come candidates for upgrade in 2015.
Hornbeck Offshore Services is well into its own 200 Class retroft program, which was announced last year. Bollinger Ship-yards is upgrading and stretching six Horn-beck PSVs, lengthening them from 200 ft to 240 ft, boosting deadweight tonnage by 600 metric tons, doubling liquid mud capacity to 8,000 bbl, and changing dynamic positioning from DP-1 to DP-2. Work on the frst two of these vessels is complete, and all six vessels should be redelivered by the end of the year. Harvey Gulf International Marine has made plans to upgrade fve of the PSVs acquired from Bee Mar in 2012. The 210-ft PSVs are to be lengthened to 270 ft (82 m), with liquid mud capacity increased from 6,300 bbl to around 10,000 bbl and deadweight tonnage going up by around 1,000 metric tons.
Return of PSVsFollowing the Macondo blowout in April
2010, the subsequent drilling moratorium, and the following slow pace of well permit-ting in the US Gulf, many PSVs left the re-gion to fnd work in Brazil, Mexico, West Africa, and other parts of the world. How-ever, with US-fagged vessels now in high demand, a number of PSVs have returned to the region.
Since the beginning of 2013, eight US-fagged PSVs of more than 230 ft (70 m) have returned to US waters from multi-year charters overseas. PSVs owned by Harvey Gulf, Otto Candies, Tidewater, and Horn-beck have come back, with many of these vessels securing long-term contracts that begin soon after arrival.
Some vessel owners indicate more US-fagged PSVs could return to the US Gulf to capitalize on current demand, either at the end of current contracts or by being replaced on overseas jobs with a foreign-fagged vessel.
Advantages to US vessel owners of bring-ing PSVs back to the US Gulf can include higher day rates for their vessels, a more stable regulatory regime, and greater ac-cess to repair and maintenance facilities for their vessels. •
1309off_78 78 9/4/13 4:34 PM
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1309off_79 79 9/4/13 4:34 PM
80 Offshore September 2013 • www.offshore-mag.com
P R O D U C T I O N O P E R AT I O N S
Prototype AUV advances
deepwater inspection capabilities
Field trial shows that system can detect anomalies on platforms
Roy LongNational Energy
Technology LaboratoryUS Department of EnergyU
nder the Energy Policy Act of 2005 (Sec. 999), the DOE’s National Ener-gy Technology Laboratory (NETL) is charged with funding and imple-menting programs aimed at develop-
ing the nation’s deepwater, unconventional, and mature assets in line with projected energy needs for the 21st century. The Re-search Partnership to Secure Energy for America (RPSEA) is a key component of this effort.
Administered through a nonproft orga-nization, RPSEA emphasizes governmental, private, and academia partnerships to de-velop medium to long lead time solutions to challenges in deepwater and unconventional resources development.
Recent events in the Gulf of Mexico have led to even greater emphasis on safe and environmentally benign technologies within the program for deepwater development, leading NETL to impose a safety and envi-ronmental sustainability overlay on its ongo-ing Sec. 999-funded R&D.
The focus here is the results of one such effort, an autonomous underwater vehicle (AUV) designed to inspect deep and ultra-deepwater structures and seafoor anomalies.
Research projectA research project directed by Lockheed
Martin has developed and is testing an AUV capable of sophisticated equipment inspec-tion and monitoring in deepwater. The re-search project, with funding from NETL, recently tested the AUV on structures in the Gulf of Mexico.
Deepwater inspection challenges
Management of deepwater felds requires routine general inspection of critical infra-structure. To date, the only means of conduct-ing such inspections has been through the use of remotely operated vehicles (ROVs). Deepwater ROV spreads are big and heavy, requiring large support vessels with dynamic positioning capability and a signifcant num-ber of personnel at sea. AUV capabilities have been improved to the point that they can now conduct unassisted detailed inspection of
subsea facilities. Benefts of autonomous in-spection include:
• Reduced cost of operations • Faster inspection • Automatic change detection • Geo-registered inspection data • Simultaneous operations from a single
support vessel • Large standoff distances from the facil-
ity being inspected • Increased operations safety • Reduced environmental impact • Reduced specifcation requirements on
support vessel • Smaller deck footprint • Dynamic positioning not required • Fewer personnel at sea • Reduced mobilization costs • Faster response to emergency inspections. The operational concept is to have an AUV
autonomously inspect an offshore oil and gas platform with minimal user input. The user sim-ply chooses the platform facility, and specifes how much of the platform is to be inspected
using a command and control user interface. The AUV autonomously plans the inspection path around the platform, executes this path to collect sonar data, builds a 3D model of the platform in real-time, and executes change de-tection to identify anomalies.
Feedback of the path of the AUV and the detected anomalies is provided to the operator in near real-time. The in situ 3D model of the platform constructed from the current inspec-tion, along with 3D models of the anomalies, are available to the operator upon recovery of the AUV. These models can be exported to a variety of formats to address the needs of in-
The Lockheed Martin Marlin AUV deploying for
trials in the Gulf of Mexico.
Platform model and Marlin flight path, unprocessed 3D Sonar image, and real-time processed sonar
image (onboard Marlin) with highlights showing positive and negative changes.
1309off_80 80 9/4/13 4:34 PM
dividual users. The Offshore Platform Inspec-tion System (OPIS) is composed of three pri-mary subsystems: the Marlin vehicle system, an autonomous perception system, and an autonomous response system.
The integration of the major autonomy com-ponents is achieved via well-defned interfaces. These allow for the independent development of key autonomy technologies as well as the rapid insertion of plug-and-play capabilities. These interfaces follow the ASTM F25411 draft autonomy standard where applicable. This standard defnes a messaging interface in terms of message content without regard to transmission protocols or mechanisms. Initial testing and development of the integrated sys-tem was performed in a simulation laboratory which provides vehicle dynamics, 3D imaging sonar data, and inertial navigation data. This lab testing addressed many integration issues early in the integration process, thereby reducing the need for expensive sea trials.
Vehicle systemThe Marlin AUV is a mature Lockheed
Martin product which has been used on multiple missions. The system consists of the AUV; an operations and maintenance (O&M) van; a launch and recovery system; and a shipboard cradle assembly.
The O&M van, launch and recovery crane, and the shipboard cradle assembly is each con-fgured with standard 20-in. ISO fttings, which simplifes shipping and shipboard mounting. Mobilization is straightforward, and the entire system can be installed in three lifts. This sim-ple and effcient confguration is operated and maintained by three people: a vehicle operator, a crane operator, and a deck hand. Marlin’s pat-ented autonomous underwater homing capture and lift provides a robust and simple approach to vehicle recovery, unlike the sometimes risky and weather-dependent surface recovery meth-ods. The small footprint of the AUV system also allows for deployment on a smaller, less expen-sive vessel when compared to a standard ROV spread.
Data collection and processing
The autonomous perception system trans-forms the sensor data into information. Autono-mous perception technologies have been dem-onstrated in the air and ground domains using ladar point clouds. These are similar in format, though not in quality, to the data available from a 3D imaging sonar. Lockheed Martin autono-mous response and perception technologies are modifed and adapted to the undersea envi-ronment to achieve the goals of the OPIS.
The perception system is responsible for processing the 3D imaging sonar data to gen-erate 3D models of the offshore oil and gas platform. During structural surveys, the sonar
1309off_81 81 9/4/13 4:34 PM
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P R O D U C T I O N O P E R AT I O N S
Verification and validation exercises were
performed in the Gulf of Mexico using decommis-
sioned offshore oil and gas platforms.
is compared to a prior model of the platform to detect changes. Because of the uncertainty in the vehicle pose (and hence the sensor pose) provided by the navigation unit, the sonar data must frst be properly aligned to the prior model before it is assembled into a changed model. This alignment is performed using a random sample consensus (RANSAC) over
the sonar points to fnd the pose adjustment that aligns the largest number of sonar points to the model. The prior models are built using this same alignment approach, but incoming sonar data is aligned to the model built so far from the earlier data. This process is typically guided by a human operator to insure the quality of the resulting model.
NavigationAutonomous response is responsible for
guiding the vehicle safely through the in-spection mission. The response system pro-vides mission planning, high-level guidance and contingency detection, assessment, and response capabilities for the AUV. Mission planning is separated into two phases.
First, a high-level planner narrows the user-defned search area to a tractable planning space while ensuring each section of the platform is visible to the sonar. Then, a detailed planner generates an optimized trajectory for the vehicle which ensures maximum sonar frustum cover-age while maintaining a desired distance from the platform. (In 3D computer graphics, the frus-tum is the region of space in the modeled world that may appear on the screen.)
The detailed planner accounts for vehicle constraints and sea currents to ensure that the planned path is dynamically feasible. The high-level guidance module directs the vehicle along the planned trajectory. This module attempts to minimize deviation from the path while maximizing time spent with the vehicle in the
1309off_82 82 9/4/13 4:34 PM
www.offshore-mag.com • September 2013 Offshore 83
P R O D U C T I O N O P E R AT I O N S
planned orientation along the path. The former is needed to ensure the vehicle maintains the desired distance from the platform, while the latter is required to ensure that the planned so-nar frustum coverage is achieved.
Even with effective planning and guidance, unexpected events can occur. The contingen-cy detection system identifes these events. This module is decoupled from the guidance and navigation software, and allows for lever-aging tested and proven software components from existing systems. The contingency de-tection, assessment, and response system is based on the Lockheed Martin Mission Ef-fectiveness and Safety Assessment (MENSA) system. A separate contingency assessment and response system provides the ability to implement multi-tiered responses to detected contingencies.
Tests and feld trialsIntegration of the three primary OPIS
components – vehicle, autonomous response system, and autonomous perception system – was initially evaluated in the simulation laboratory. Performance of the autonomy al-gorithms was validated on tactical hardware in a low-risk, reduced-cost environment that allowed for robust verifcation and testing of the system before offshore trials. This allowed the team to proceed offshore with increased confdence that the system would perform as designed, with a reduced risk of losing or damaging the vehicle or structures being inspected.
The team also performed verifcation and validation exercises in the Gulf of Mexico using decommissioned offshore oil and gas platforms. These exercises prove that the system is capable of quickly, accurately, and safely completing a structural survey of an offshore oil and gas platform with minimal operator interaction and oversight.
Through these exercises, the team verifed the system’s ability to build a model of a plat-
form and detect anomalies in an operational environment. This combination of technolo-gies is an improvement over current state-of-the-art offshore inspection capabilities.
The Marlin’s inspection capabilities con-tinue to be improved. Future capabilities will include:
• Level II platform inspection • Inspection of risers, mooring lines, touch-
down points, and strakes • Pipeline inspection including position,
crossover, scouring, and corrosion po-tential
• Wellhead, PLET, PLEM, fowline and UTA inspection, leak detection, thermal and debris survey
• Incorporation of a high-resolution laser inspection system capable of generating highly precise stick diagrams suitable for CAD/CAM software to generate “as built” drawings. (If this capability had been pres-ent during Macondo, an accurate drawing of the wellhead, suitable for capping stack design, could have been made in one day.)
NETL deepwater portfolioThis project is representative of the R&D
work being undertaken via the Section 999 Program to ensure safe and effcient develop-ment of the nation’s deepwater and ultra-deep-water assets. Altogether, NETL has over 30 active deepwater and ultra-deepwater projects in various stages of progress, with another 17 to be added from the 2012 program. Proposals for research under the 2011 Ultra-Deepwater Program are in negotiations following awards. Requests for proposals (RFPs) for the 2012 Ultra-Deepwater Program have been posted on RPSEA’s website at www.rpsea.org. Cur-rent information for the 2012 RFP solicitation can be accessed on the Current Request for Proposals page under the “Business with RP-SEA” menu button. Proposals for Round 1 of the 2012 Ultra-Deepwater Program R&D proj-ects are due on Sept. 25, 2013. •
3D sonar constructed platform model, viewing a decommissioned platform from a subsurface
perspective.
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84 Offshore September 2013 • www.offshore-mag.com
P R O D U C T I O N O P E R AT I O N S
Detailed imaging and careful measurement
boost field recovery rates
Enhanced recovery plan should be considered long before it is needed
Great philosophers almost universally maintain that we learn more from our mistakes than from our successes. This quirk of human nature prob-ably explains why many automobile
owners go to great lengths to coax one more year out of their ancient vehicles, when it would have been wiser to have taken bet-ter care of them in the frst place. Sadly, the analogy also applies to our own bodies, as many of us have experienced.
Reservoirs are no different. Their pro-duction behavior after a couple of decades refects the care they were given when they were frst developed and completed. When they fnally stop producing on their own, we come up with all sorts of techniques to extend their economic life. These include artifcial lift, water fooding, pressure main-tenance, and in-fll drilling projects. Some-where near the end of the line are enhanced oil recovery (EOR) schemes. The current favorite, by a large margin, is thermal, fol-lowed by chemical and biological, or micro-bial.
With all these techniques at the com-mand of the world’s producing companies,
one would think we are at the brink of near total recovery of every drop of hydrocarbon from our reservoirs. In fact we are far from it. Although some conventional natural gas reservoirs have recovery factors near 80%, most reservoirs reach their economic limits somewhere short of 40%.
The lesson for success at improved re-covery has been staring us in the face for a century. On Jan. 10, 1901, Patillo Higgins and his partners brought in the infamous Spindletop gusher that blew an estimated 100,000 barrels of oil into the Southeast Tex-as sky. Lesser gushers were the distinctively un-scientifc way oil producers recognized success. About 20 years later the Schlum-berger brothers invented a way to assess the potential of subsurface reservoirs without having them spew a large volume of their potential profts onto the lease. Logging, or electrical coring as it was known at the time,
could help an operator by answering a few basic questions: Are hydrocarbons present? Where are they? Will they produce? How much? The Schlumberger inventions were accompanied by drilling and well control technology that quelled the gushers that had up to that point characterized discovery.
The fact that critical reservoir knowledge could be obtained remotely without losing control of the well intrigued drillers, espe-cially with the development of the dipmeter log, which answered a ffth, and very impor-tant, question: Where should we drill the next well?
Subsurface measurement
This is the point where a critical lull oc-curred in reservoir knowledge. Logs were able to tell geoscientists and engineers many valuable facts about the formations pierced by the drill bit, but they could not tell what was really inside the reservoir, between the wells. Conventional wisdom at the time was that wells could be accurately correlated, and that the intervening geol-ogy was simply a continuation of what was observed in the wells. The only techniques that shed light on the reservoir volumes ex-isting between the wells were seismic and well-testing. However, both had their limita-tions. Inter-well knowledge was enhanced by the introduction of production logs that could be run into producing wells through tubing to measure dynamic production pa-rameters that shed light on reservoir behav-ior. Still, the ultimate solution was elusive.
The evolution of subsurface measure-ment technology took decades. In the mean-time, several early reservoirs were reaching their limits: they either produced unaccept-able water cuts, or coned gas, or petered out altogether due to loss of reservoir pressure. Operators reasoned that residual hydro-carbons could be harvested by applying artifcial lift, water fooding, or gas-cap pres-surization. These techniques worked, up to a point. It soon became obvious that water injected in one well was simply being pro-duced from a neighboring well. Both would be shut in as operators moved on to greener pastures.
Dick Ghiselin
Contributing Editor
Powerful production simulators like PipeSIM help operators understand how a subsea reservoir is
draining so that recovery can be maximized. (Illustration courtesy Schlumberger)
1309off_84 84 9/4/13 4:34 PM
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86 Offshore September 2013 • www.offshore-mag.com
P R O D U C T I O N O P E R AT I O N S
But when reservoir engineers compared cumulative production from the reservoir to original-oil-in-place (OOIP) estimates, it became obvious that as much as 70% of the OOIP was still in the reservoir. Analysis re-vealed that the residual oil was trapped by a variety of geological or petrophysical condi-tions. High oil viscosity was a big factor, and this paved the way for the thermal, chemi-cal, and biological recovery techniques that achieved reasonable success over the years. However, many were cost-prohibitive in all but the giant reservoirs. Another factor was relative permeability. Relative permeability modifers have been successful in reducing water cut and allowing residual oil to fow through water-wet pores.
But the biggest factor restricting hydro-carbon production is reservoir heterogene-ity—in other words, the unknowns between the wells. Reservoir heterogeneity appears as undetected compartmentalization, or at worst, as highly complex mineralogy. En-gineers agreed that it would be extremely valuable to have this knowledge in advance.
Building a knowledge baseRecently, time-lapse techniques have en-
abled reservoir managers to deduce how hydrocarbons move through the reservoir. 4D seismic imaging has seen success, par-ticularly where gas is involved. Cross-well tomography has enabled inter-well resistiv-ity imaging with enough precision to allow the siting of infll wells or steering of side tracks to improve sweep effciency. The big-gest disadvantage to time-lapse techniques is that they are reactive processes; achieving maximum reservoir productivity requires predictive processes.
Leaseholders today are fnding that they can improve reservoir productivity by im-proving their base knowledge. That means building the highest quality 3D reservoir model possible using all the measurements taken during the exploration, drilling, and completion processes. Any physician will tell you that the chances of detecting and treat-ing the diseases and infrmities of later life are greatly improved by a good set of base images taken before you start having prob-lems. The same is true for hydrocarbon res-ervoirs. With a high-quality 3D base model, the most subtle changes are highlighted in subsequent images. These provide clues on how the hydrocarbons are moving toward
the producing wells, any obstacles they are encountering, and any signifcant volumes of residual hydrocarbons.
Planning is the best way to assure maxi-mum early recovery, and to predict what will likely occur as the reservoir continues to drain. This allows operators to take reme-dial steps to manage their production, avoid-ing many pitfalls.
Timing is keySome may argue that all this planning and
measurement-taking costs too much. How-ever, it is better to spend money up front to build an accurate knowledge base than to wait until problems occur, which can neces-sitate far more costly interventions or reme-dial work. Also, some of the most valuable data can only be obtained by open-hole log-ging and sample-taking. Once casing is set, the opportunity to acquire the data is gone, or at least severely compromised. Measure-ments taken during exploration, drilling, and initial completion can be capitalized as part of fnding and development costs. How-ever, remedial work to improve well perfor-mance is considered lifting costs, and must be expensed.
A good example can be found in Califor-nia’s San Joaquin valley. Years ago, when production from the famed Kern River feld waned, the reactive decision was to estab-lish a food program to sweep the remaining oil toward designated producing wells. The fresh water steam used to food the reser-voir swept some of the oil as expected, but left hundreds of thousands of barrels be-hind, trapped in isolated pockets. Resistivity tools deployed to fnd these pockets were unable to discriminate between the highly
resistive oil and the equally resistive fresh condensed steam. Only recently has a new logging tool been introduced that can differ-entiate between oil and fresh water, but in the meantime millions of dollars have been spent trying to solve the problem.
With quality measurements, modern reservoir or production simulators can be used to predict future conditions, quantify the implications of problems, and even dry-test proposed solutions. Reservoirs must be managed and solutions designed using a holistic approach. The performance of each well affects that of all other wells in the production unit whether the other wells are producers or injectors.
Perhaps the combination of available new technology in the form of more precise mea-surements, the capability of running several different logs on a single trip through uni-versal combinability, and increasingly so-phisticated LWD tools will encourage better understanding of our offshore reservoirs.
Giant deepwater discoveries represent huge investments. Operators may be loath to pass up any measurement that could af-fect subsequent reservoir management plans for maximum recovery and so maxi-mum return on their investment. Offshore seismic, logging, well testing and reservoir modeling have reached world-class status in terms of accuracy, resolution, and reliability. Operators can use these to enhance their reservoir knowledge before production problems occur. Engineered solutions based on good data will enable better recovery fac-tors. In the past, EOR was implemented as a last resort, when all else failed. However, for maximum effectiveness, EOR must be part of the game plan from the beginning. •
The recently introduced Dielectric Scanner is
the first logging device that can discriminate oil
from fresh water, allowing operators to charac-
terize and make effective EOR decisions about
reservoirs that have undergone water or steam
injection. (Photo courtesy Schlumberger)
1309off_86 86 9/4/13 4:35 PM
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A comparison of liquid meters.
Meter Type Features Benefts
Turbine •Verylinearandrepeatable •Idealforproving •Costeffectivemeter •Goodempiricaldata •Largeinstallationbase
Ultrasonic •Nointrusiveparts,canbeused •Lowmaintenancecosts ondirtyfluids •Conditionbasedmonitoring •Verylowpressureloss •Wideoperatingrange •Self-diagnosticcapability •Insensitivetoviscositychanges
Coriolis •Measuresmassflowratedirectly •Idealforassetmanagementbilledinmass •Toleranceofgasentrainment •Providescontinuousqualitymeasurement
Positive •Highturndown •Idealforhighviscosityduties displacement •Goodforlowflow-rates
88 Offshore September2013•www.offshore-mag.com
P R O D U C T I O N O P E R AT I O N S
Metering can extend production
on aging platforms
Optimizing uncertainty may pay off in longer asset life
As evolving technologies enable North Sea platforms to produce beyond their original design life, many opera-tional factors come into play. Issues that directly impact productivity and
downtime are a high priority. Among these, metering systems should be regarded as critical. They determine the quantity and quality of oil and gas recovered, and their control systems effectively form the “cash register” of the whole production process. In the UK, they also act as the fscal tax point with the Department of Energy & Climate Change (DECC). Consequently, unreliable, poorly designed, or obsolete metering sys-tems can result in signifcant fnancial expo-sure.
Thirty years on from the North Sea boom of the 1980s, many platforms remain viable, but produce far less than in their heyday. Metering technologies from the ’80s gener-ally perform best when fow rates are at the higher end of their design spectrum. Pro-duction declines stretch the limits of their operating envelopes. It follows that metering systems on these aging platforms are likely to have diminishing performance from a me-tering uncertainty perspective.
Whether metering for allocation on a shared network (as is common in the North Sea), for custody transfer (where tax liabili-ties are calculated), or for operational pur-poses, optimum measurement uncertainty is vital. When loading a large crude carrier, a 0.5% measurement uncertainty typically equates to more than $2 million. If an offcial audit discloses a measurement error, DECC must be alerted. From that point, the opera-tor has three weeks to identify the problem. DECC will calculate how the miscalculation applies to royalties and consult with the op-erator to agree an acceptable solution and timescales.
Good oilfeld practice dictates that when the original operating range changes, a re-view should be undertaken to ensure the metering system remains ft for purpose. This is a specifc requirement of the Mea-surement Model Clause of petroleum pro-duction licenses in the UK. What’s more, it protects the operator’s bottom line.
Repeated metering system failure or poor audit performance usually indicates that at-tention is needed. However, selecting the most appropriate course of action is not sim-ple. There are many factors involved, includ-ing the weight, space, and time constraints familiar to all offshore hardware designers.
When upgrading or replacing metering systems on existing platforms, the usual challenges are compounded by the fact that original sales agreements from the plat-form’s inception need to be considered. Of-ten, these infexible contracts involve mea-surement principles that do not dovetail with today’s best available technologies. Specify-ing metering systems for aging platforms is almost as much about contract interpreta-tion and mediation as it is about engineering skill. Historic measurement standards and contracted agreements need to be consid-ered alongside production challenges, good oilfeld practice, and appropriate technolo-gies to ensure a good ft.
The fact that metering instruments are mounted on skids along with other equipment also has a bearing on their design and selec-tion. Integrator engineers plan and build every system as a bespoke project because each ap-plication is individual. Sometimes with aging platforms, decisions surrounding metering technologies are shaped by the dimensions or accessibility of an existing component on the skid. This scenario can infuence whether to
retroft or replace equipment.Despite these challenges, specifying me-
tering systems for an existing platform has one critical advantage over the same chal-lenge for a greenfeld site. Available empiri-cal data enables engineers to predict the fow rates likely to be experienced over time. Typically, engineers consider the projected productivity of a platform over fve years, and develop a solution equipped for shifting fow rates as well as likely pressure and tem-perature changes. This knowledge informs technology choices and enables integrators to optimize system design and confguration.
DECC guidelinesAny metering strategies or instruments
changes need to bear witness to offcial guidelines from DECC. However, the guid-ance is not prescriptive and does not approve or recommend specifc meters. Rather, it should be expertly interpreted by metering specialists, in consultation with both the op-erator and DECC representatives.
Prior to feld start-up, operators provide DECC with a Functional Design Specifca-tion for the agreed measurement approach. This includes diagrams of piping systems immediately upstream and downstream of metering and sampling systems, as well as details of calculations, software, calibration procedures, and uncertainty analyses. When metering systems are upgraded or replaced,
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A comparison of gas meters.
Meter Type Features Benefts
Ultrasonic •Nointrusiveparts,canbeusedondirtyfluids •Lowmaintenancecosts •Verylowpressureloss •Conditionbasedmonitoring •Self-diagnosticcapability •Wideoperatingrange •Additionalmeasurementcapability
Orifice •LargeInstalledbase •Doesnotneedtobesentawayforcalibration •Fieldverification •Minimaloperationskillssetrequired
P R O D U C T I O N O P E R AT I O N S
DECC must be consulted and notifed of the strategy and its justifcation. Upon success-ful completion, installation, calibration, and testing of the new system, DECC issues a “notice of non-objection” to the operator for use with custody transfer systems.
DECC’s recommendations are best de-scribed as an “ethos.” To quote the guide-lines, their purpose is to “provide operators with guidance on DECC’s expectations as to what constitutes ‘Good Oilfeld Practice’, as required by the Measurement Model Clause of an operator’s Petroleum Produc-tion Licence, for the full range of fscal mea-surement scenarios that are likely to be en-countered in practice.”
That is to say, if a platform produces sev-eral million barrels per day, it needs to use the best available metering systems appro-priate to the application, with the lowest lev-els of uncertainty.
Uncertainty versus accuracyOil and gas metering involves intricate sta-
tistical analysis surrounding uncertainty val-ues. The words “accuracy” and “uncertainty” are sometimes interchanged, but the actual difference between them is signifcant.
“Accuracy of measurement” is the older
phrase and its internationally agreed defni-tion is “…the closeness of the agreement between the result of a measurement and a true value of the measurand” (the medium being measured). The defnition also notes that “accuracy is a qualitative concept” – it can be high or low, for example, but strictly speaking should not be used quantitatively.
However, in practice it is often used quanti-tatively by bending the defnition to something like “the difference between a measured value and the true value.” This leads to the use of phrases like “accurate to ±X.” Unfortunately this unoffcial defnition breaks down because it inherently assumes that a “true” value can be defned, known, and realized perfectly.
Even the fnest national measurement labora-tories cannot realize perfect values.
“Uncertainty of measurement” acknowl-edges that no measurements can be perfect, and is defned as a “parameter, associated with the result of a measurement, that char-acterizes the dispersion of values that could reasonably be attributed to the measurand.” It is typically a range in which the value is estimated to lie, within a given statistical confdence, but it does not attempt to defne or rely on a unique, “true” value.
So, common usage of the word “accuracy” for quantitatively describing the characteristics of measuring instruments is incompatible with its offcial meaning. What’s more, its common
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90 Offshore September 2013 • www.offshore-mag.com
P R O D U C T I O N O P E R AT I O N S
usage defnition is signifcantly cruder than the proper metrological term “uncertainty.”
Evaluating uncertainty An important facet of metering best prac-
tice lies in understanding and interpreting ISO 5168, the international standard for evaluating uncertainty of a fuid fow rate or quantity. This standard provides a global landmark and creates a level playing feld for all oil and gas metering specialists and operators. ISO 5168 looks at contributing components and uses sophisticated statisti-cal methods to determine whether metering values comply with project specifcations. It establishes common principles for proce-dures surrounding uncertainty calculations and forms the basis of the DECC guidelines.
A clear alignment with ISO 5168 from the outset of system development brings advan-tages. Understanding and referring to its principles throughout the engineering pro-cess can inform the selection and justifca-tion of different technologies integrated into a metering system. It enables recommenda-tions to be qualifed and can provide strong, evidence-based rationale for any deviations from the initial client brief for a project.
On an ongoing basis, metering special-ists can assist operators in scheduling audits and calibrations. This helps prolong the life of older systems or maximize the working life of new systems while maintaining an ac-ceptable level of uncertainty.
Condition-based monitoring is becoming more mainstream, using available data to ascertain whether a system is behaving as it should. Typically, software uses the data to generate diagnostic information and sound alarms for early detection of imminent fail-ures or possible measurement errors. This is an advantage, but the extent to which it can be accomplished depends on the available di-agnostic data from the instrumentation.
Metering best practiceWhen uncertainty measurements regu-
larly exceed the agreed level, any equip-ment upgrade or replacement decisions are dictated partly by opex relative to the asset. There is a clear synergy between operator and DECC requirements. The more produc-tive the platform, the more the operator can lose if uncertainty is too high. Likewise, a high-production platform pays a larger pe-troleum revenue tax (PRT) to DECC.
The combined challenges of aging plat-form performance, existing sales contract restrictions, and DECC guidance make me-tering best practice a balancing act. Even within these tight parameters there is a range of variables that can make the differ-ence between a satisfactory metering sys-tem and an outstanding one.
Initially, specialist metering engineers con-duct a detailed front-end engineering design study that analyzes past metering reports and log fles. Understanding historic fow rates facilitates predictions of production trends over time. It is useful to see how productivity fuctuates as well as the upper and lower fow rates expected. Metering specialists normally collaborate with the operator’s engineers to understand weight and size restrictions, as well as other practicalities surrounding in-stallation. The logistics of removing obsolete equipment and shipping and maneuvering the new systems has a bearing on design. It is often necessary to manufacture skids in seg-ments, since their route across the platform is as signifcant as the fnal space envelope.
Metering control systems need to follow the same philosophy of design strategy. Thor-ough, up-front understanding of operational and reporting requirements can ensure the system is intuitive and provides full data ac-countability.
Consideration of existing infrastructure and data reporting is paramount to facilitate integration. Comprehensive electrical and instrumentation design can ensure expen-sive, time-consuming installation work is at a minimum through measures such as reus-ing existing feld cabling. And use of long life, standard form-factor servers designed for in-dustrial/commercial use – as opposed to PCs – reduces the risk of obsolescence.
Technology choicesVarious factors infuence the selection, as-
sembly, and confguration of a metering sys-tem. Making the most effective technology choices to minimize uncertainty is an impor-tant part.
Good repeatability – the ability of an in-strument to produce the same result when measuring the same quantity – is one con-sideration. However, repeatability should not be confused with accuracy, since an in-strument can be repeatedly wrong.
In addition to good design and careful manu-facture, metering system performance depends on accurate and traceable calibration at an ac-credited laboratory. Complete metering sys-tems need a traceability chain for every item that contributes to the fnal measurement. The uncertainty of all the relevant devices then must be combined in the correct manner and in the correct proportions to calculate the uncertainty for the whole system.
Further practical considerations include viscosity of process medium, pressure and temperature ranges, and fuctuation in typical fow rates and quantities. Decisions are also infuenced by associated sampling and analy-sis technologies, which need to be precisely integrated to enhance overall performance. The quality of oil or gas produced – in terms
of viscosity, density, and composition – can be as important as the quantity. For instance, the extent of any contamination (e.g. basic sedi-ment and water in crude) impacts its value.
Different technologies have different ben-efts and features. Turbine meters are cost-effective with good short-term linearity for in-situ verifcation against a volumetric prover. Positive displacement meters are used for some high-viscosity liquids, but their mainte-nance costs make them bad choices for other fuids. The latest generation of proven tech-nologies includes both ultrasonic meters with diagnostic capabilities, and coriolis meters, which generally are more tolerant of gas en-trainment and provide a direct mass output.
To maintain a system’s uncertainty cre-dentials, a proving system often is integrat-ed for in-situ verifcation of the liquid meter performance. Typically this involves a bi-directional prover, but other solutions may be more suited to the footprint available on an aging platform.
Dissemination of data must also be con-sidered. Metering control systems can pro-vide a wealth of information far beyond just totalized fow. With access to the entire spec-trum of data from metering instruments, control systems can provide full traceability of operational alarms and events.
Industry collaborationIndustry-wide collaboration to address
metering challenges objectively is the surest way to enhance future metering performance on aging platforms.
Consultation on international standards is one important area. This helps ensure a more level playing feld between aging plat-forms, with their associated challenges and limitations (such as older contracts), and newer platforms being developed both on nearby felds and globally.
The science of measurement is always evolving, and in the face of increased North Sea asset longevity, operators seek greater re-sponsibility from metering specialists. Clearly the deployment of proven fow measurement technologies is one part of this. But it goes beyond the supply of integrated packages to include involvement in the complete chain of the metering process, from concept through operational support.
Offshore metering is on the cusp of a signif-icant new phase in its development to secure the extended life of older platforms. Long-term performance and traceability remain paramount, but pinpointing the right time to intervene where reduced measurement un-certainty is evidenced or predicted is also a key factor. More intelligent, expert-led meter-ing strategies can bring signifcant bottom-line benefts to forward-thinking operators seek-ing to optimize aging offshore assets. •
1309off_90 90 9/4/13 4:35 PM
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92 Offshore September 2013 • www.offshore-mag.com
S U B S E A
Drilling riser studies focus on unknowns
of loading and frontier operations
Drilling in harsh environments imposes strains on risers, conductors and well-heads. Stress levels can be predicted, but results don’t always match the reality of prolonged exposure to buf-
feting waves and surging currents. This is a major concern in frontier deepwater regions with little prior drilling history, and also for operations pushing the boundaries of jackup drilling in established hostile plays.
It is possible, however, to defne and then refne the parameters for safe drilling based on information from the feld. This is what Ac-teon companies 2H Offshore Engineering and Pulse Structural Monitoring (Pulse) are doing on current projects involving jackups in the North Sea and deepwater rigs operating West of Shetland and offshore East Africa.
2H was formed in the early 1990s, a time when knowledge of riser motions and inter-actions with conductors was very limited and assessment processes were very sim-plistic, according to director John McGrail. Over the years since the company has been at the forefront of evaluating new types of drilling and production riser systems, and promoting the need for structural monitor-ing to consolidate design knowledge with measurements offshore.
In the late 1990s 2H created a monitoring division for this purpose which developed the INTEGRI range of sensors and data loggers. These were frst deployed in 1998-99 on steel catenary risers for the Allegheny platform in the Gulf of Mexico as part of the STRIDE joint industry project. Around the same time, the UK-based UWG group acquired 2H, re-branding itself as Acteon in 2005. Five years later, due to the growing scale of 2H’s activi-ties, the monitoring division was turned into a separate company, Pulse, providing complete structural monitoring solutions.
Today 2H and Pulse often work in collabora-tion, sometimes with sister company Claxton, a project systems integrator for specialist drill-ing risers, particularly for high-pressure/high-temperature applications. Subsea Riser Prod-ucts (SRP), another Acteon company, designs and builds components for these risers.
West ElaraIn the Norwegian North Sea, Statoil has
Seadrill’s newbuild heavy-duty jackup West
Elara on a long-term assignment, drilling new wells or performing workovers. Two recent wells on the Gullfaks feld required use of a high-pressure riser in 132 m (433 ft) water depth, around 30 m (98 ft) above the typical limit for jackup drilling. All four Acteon com-panies co-operated to develop a detailed de-sign and engineering solution, with Claxton managing the project and SRP manufacturing sections of the riser and supplying the spider.
The relatively deep water, and the poten-tial for fatigue brought on by year-round drilling in a region characterized by sus-tained current and wave loading, compli-cated the design, as did the 12,000-psi (827-bar) specifcation – 3-5,000 psi (207-345 bar)
Jeremy BeckmanEditor, Europe
West Elara riser monitoring
system and associated
topsides connections.
is more typical for North Sea operations. Well control considerations during HP op-erations also necessitate use of a large BOP, which increases the loading on the riser.
Drilling risers are designed to minimize the risk of failure and to comply with design codes and standard safety margins. But when the lo-cal operating factors are not well understood, the conventional design approach often veers towards caution. “The challenge in this case,” McGrail explained, “was to more accurately evaluate the global response of the HP riser and the knock-on loading effect on the subsea well conductor and the interface to the jackup topsides at the Texas deck. The increased size and stiffness of this type of riser means that high conservatism in predictions cannot be tolerated in the system design.”
The analytical predictions of the riser response raised concerns over long-term fatigue performance, particularly with re-gard to loading on the subsea well conduc-tor. “This forms the foundation of the well, and yet it can’t be inspected. So integrity of the well conductor is a paramount concern, as is any fatigue damage in the drilling riser
1309off_92 92 9/4/13 4:35 PM
www.offshore-mag.com • September 2013 Offshore 93
S U B S E A
– typically the client expects to re-use the riser for 10 years or longer.”
Analytical fndings indicated that measures to improve the fatigue re-sponse of the riser were required that included adding special fairings to re-duce vortex-induced vibration (VIV); employing forged rather than welded joints in high-stress and fatigue-prone areas; and upgrading the tensioning system to 500 t. In addition, a riser response monitor-ing system was necessary to validate the ana-lytical predictions and confrm that the riser was responding as expected.
“To defne the requirements of the riser monitoring system we start by identifying key performance indicators [KPIs] by which we categorize the system response,” McGrail explained. “Based on these KPIs we develop specifcations for what we think should be measured, to validate behavior during drill-ing operations. We may recommend measur-ing the level of strain, defection or accelera-tion at different points of the riser to most accurately understand the system behavior.
“The extent and complexity of monitor-ing must be acceptable to the client, but we must also ensure that our clients have a clear understanding of their own objectives for the monitoring, and whether these are primary or secondary objectives. Their main goal may be to not exceed a critical loading or defection limit during an offshore operation; however, validation of analytical predictions to improve the overall understanding of the behavior of such systems may also be important.”
For the West Elara instrumentation system, designed and supplied by Pulse, Statoil opted for online monitoring via subsea sensors to provide real-time processing of measured data, including fatigue build-up and loading on the riser and tensioning system. Motion sensors were also placed topside, to enable the motions of the rig itself to be determined, and the impact on the riser measured.
The system involved a hard-wired connec-tion to the rig, confgured in a traffc-light for-mat with KPIs built into the software. “A green light indicated that all parameters were within normal limits,” said Pulse Marketing Coordi-nator Edward Elletson. “If one parameter was outside specifcation the amber light came on, while a red light showed if any parameter was outside the critical operating limits.” McGrail added: “The client’s objective was to have real-time assurance of safe operations. Statoil recog-nized that this operation was beyond the typical envelope for jackup drilling. In deeper water, it is expected that a jackup would move around a lot more, and when combined with the harsh environment and high pressures involved in
this development the additional assurance pro-vided by a real-time monitoring system was key to managing risk.”
Pulse’s system provided acceleration and strain monitoring of the riser response, to measure the effect of wave loading and iden-tify whether currents that might shed off the riser were causing oscillations. “We monitored wave and current, and compared the motions in the riser and the rig,” Elletson explained. “In the lower part of the riser we had strain moni-toring which could be used to evaluate well-head fatigue. If we know the level of strain in the riser, we can infer strain on the conductor. And from the number of strain cycles we can calculate accurately the ongoing accumulation of fatigue damage in critical components.”
“The measurements obtained provided a good correlation with 2H’s prediction in terms of fatigue accumulation, and from the fndings it is possible to defne the factor of conserva-tism in the analytical prediction” McGrail said. Statoil plans to use the data to gain greater as-surance and confdence in using HP drilling ris-ers in similar settings, and Pulse has recently fnished a follow-up monitoring campaign for West Elara on the Norwegian Valemon feld.
West of Shetland/East Africa2H and Pulse have also devised and de-
ployed systems to monitor deepwater drill-ing riser VIV responses in high current re-gions such as West of Shetland and offshore Tanzania and Mozambique. Aside from be-ing frontier E&P regions, there are similari-ties in operating conditions.
West of Shetland conditions are most severe, with strong currents channeled from the Atlan-tic Ocean due to the location in between the UK continental shelf and Faroese plateaux. Current velocities can regularly exceed 2 m/s (6.6 ft/s), and the area has strong tidal fows.
According to Elletson, in these regions VIV behavior is often observed on the semi-submersible rig’s marine riser during drilling, raising concerns about the impact on the sub-sea well and conductor. And most predictive tools, McGrail added, employ relatively sim-plistic approaches modeling the complexities of VIV-induced lock-on (the process by which current vortex shedding around the riser pipe can excite vibration and riser modal vibration
frequency). So with Pulse, 2H have de-livered monitoring campaigns to capture and evaluate the actual occurrence of VIV on drilling risers: the main aims are to use the data to predict the accuracy of VIV onset with measured currents and to determine the impact of the drilling cam-paign on the conductor’s fatigue life.
Typically Pulse’s system comprises one motion logger measuring motion and the angular rate of the riser in the moonpool, with another logger record-
ing motion and angular rate on the lower fex joint. Additionally, up to 10 ROV-retrievable motion loggers linked to strain gauges on the riser monitor VIV at various locations along the riser joints, while other loggers may also be deployed to measure motion and angular rate of the BOP and permanent guide base. An acoustic current Doppler profler mea-sures the current profle every 10 minutes.
“Using the readings from the Pulse data log-gers we can accurately measure acceleration of the drilling riser,” McGrail explained, “and from this we can determine how VIV response varies in amplitude on the riser in particular currents. We often fnd that while the modeled response is accurate in determining how fre-quently VIV may occur, often the magnitude of the VIV response is over-estimated.”
Other major operators have commissioned further studies for their East Africa programs. Here the deepwater drilling locations (up to 3,000 m, or 9,842 ft)) are sandwiched in be-tween the East African coast and the island of Madagascar, forming a large channel. Warm water from the northern Indian Ocean is forced through this channel to cooler water offshore South Africa, leading to very strong currents.
Pulse has provided instrumentation in this region for two operator’s ongoing explo-ration drilling campaigns to gauge the sever-ity of VIV response. “This is a frontier area, meaning that little data existed previously,” Elletson explained. “Where environmental data is lacking, analysis must cover this with suffcient safety margins.”
One system supplied comprised 11 mo-tion data loggers capable of measuring tri-axial acceleration and 2° angular rate, with magnetic interfaces for ROV deployment and retrieval. Loggers are distributed along the riser and on the BOP stack, with two pre-cision accelerometers for BOP monitoring. Measurements are used to calculate inclina-tion, VIV, linear displacement, and accelera-tion of the BOP and drilling riser.
While the results do not have an immedi-ate bearing on the current exploration drill-ing, the information gathered on the cur-rents and riser response will be of beneft in planning future drilling activity and the de-sign of the wells which will be required for upcoming developments in these areas. •
The jackup West Elara.
(Photo courtesy Seadrill)
1309off_93 93 9/4/13 4:35 PM
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B U S I N E S S B R I E F S
96 Offshore September 2013 • www.offshore-mag.com
People Secretary of the Interior Sally Jewell has
named former Vice Adm. Brian Salerno as
director of the Bureau of Safety and Environ-
mental Enforcement.
The board of Royal Dutch Shell plc an-
nounced that Ben van Beurden will succeed
Peter Voser as CEO, effective Jan. 1, 2014.
Chevron Corp. has named Joe M. Naylor
corporate vice president of strategic planning.
John T. McCormack, executive vice presi-
dent and COO of McDermott International,
has chosen to retire
after 10 years with the
company.
TAM International
has promoted Ray
Frisby to vice president
of technology.
Alex Cruickshank
has joined Reftrade UK
as general manager.
KBR has appointed
Jan Egil Braendeland
as president of its oil and
gas business unit, Ivor Harrington as group
president of gas monetization, Mitch Dauzat
as group president of services, and Karl Rob-
erts as chief business development offcer.
Forest Oil Corp. has promoted Victor A.
Wind to executive vice president, CFO, and
treasurer.
Hydro Group has appointed Gabriel Tan as
technical support supervisor at the Singapore
offce.
Graham McKay has been promoted to
COO of Unique Wellube Nigeria Ltd.
Gareth Allen has joined Oil Consultants
Ltd. as business delivery and development
director for the Middle East and Africa.
Sodexo Remote Sites UK has promoted
Ian Russell to managing director.
Duoline Technologies has appointed Abel
Mbeh as product engineer.
CGG has appointed Catherine Leveau
as senior vice president, Investor Relations.
She replaces Christophe Barnini who has
become senior vice president, Group Com-
munications.
Survitec Group has appointed Fiona
MacLeod as sales director for its services UK
division.
Summit ESP has hired Mark Neinast as
director of marketing.
Ceona has appointed Graeme MacDougall
as vice president of projects and engineering.
Sylvia Halkerston has joined the SPEX
board of directors. The company has named
Carole Innes business communications man-
ager and Jacqui Duncan HR manager.
Maroun Semaan, president and executive
director of Petrofac, has decided to retire at
the end of the year after more than 22 years
with the company.
Pulse Structural Monitoring has hired Paul
Chittenden as business development man-
ager for production riser and pipeline systems,
and Joseph Bramande as business develop-
ment manager for marine systems, including
mooring lines and subsea infrastructure.
Kongsberg Maritime Inc. has appointed
Jon Holvik as president.
Robin Hodgson has joined Fine Tubes as
oil and gas business development manager.
Oilgen has named Ismail Labed staff
reservoir engineer.
HB Rentals has appointed Peter Arm-
strong as vice president of business develop-
ment, Brad Hirst as sales and marketing
manager, and Mike Christie as technical
manager.
David Bleackely has joined Petrotechnics
as vice president of sales.
Steve Bullock has been appointed co-
chairman of Step Change in Safety, and Alan
Johnstone co-chair of the Asset Integrity
Steering Group.
Per Wullf will succeed Fredrik Halvorsen
as CEO of Seadrill Management Ltd.
Wendy Barnes has joined the BMT Group
Ltd. board of directors as a non-executive
director.
BMT Asia Pacifc Pte Ltd. has appointed
Andrew Bridson as business development
manager.
John R. Kemp III has announced that he
intends to retire as Kosmos Energy’s chair-
man, but will continue to serve in his current
capacity until a successor is named.
Produced Water Absorbents has appointed
Ian Robertson as engineering manager.
Simon Hounsome has joined Flexlife’s Ab-
erdeen headquarters as integrity and projects
director, and Jon Hawes has joined as senior
project manager of the company’s on-going
Apache contracts.
Alderley Process Technologies has hired
Andrew Palmer as
regional sales direc-
tor for produced water
treatment for the Middle
East region.
Seatronics do Brazil
has appointed Thiago
Montanari as sales
manager.
Devin International
has promoted Andrew
Riojas to location super-
visor and will oversee
the day-to-day opera-
tions at the Lafayette,
Louisiana, offce.
Foster Marketing has
appointed Laurel Hess
as an account executive
and Julie Welch as a
public relations account
executive.
Bibby Offshore has
appointed Graeme
Wood as offshore sup-
port services director.
Archer’s board of
directors has appointed
David King as CEO and
has elected John Reyn-
olds as chairman.
Tim Brown has
joined UniversalPegasus
International as senior
vice president, business
development.
BG Group has ap-
pointed Simon Lowth
as CFO and an executive
director.
Itera Oil and Gas Co.
has appointed Alexan-
der Popov as director
general.
Greene’s Energy
Group has named Tracy
Cummins director of
business development
within the rental and products business unit.
James A. Watson has joined ABS as presi-
dent and COO of the Americas division.
F. Jay Schempf, an award-winning petroleum indus-try writer/editor, has passed away. He was 71 years old. Schempf held editorial positions with industry trade journals and busi-ness publications. He served as an associate editor, news editor, and freelance writer for Offshore for more than 40 years. For the last 10 years he was a primary editor for the Custom Publishing division of the PennWell Petroleum group. One of the highlights of his tenure with PennWell Custom Publishing was as the author of “Pioneering Offshore: The Early Years” published in 2007 for the Offshore Energy Center. He earned a bachelor’s degree in journalism from Texas Chris-tian University.
In MemoriamGeorge P. Mitchell, a pioneer in
the development of technology that unleashed the shale boom, has passed away. He was 94 years old.
Patrick J. Campbell, founder of Blowout Tools Inc. and one of the principals in Wild Well Control Inc., has died. He was 68 years old.
Frisby
Riojas
Hess
Welch
Cummins
1309off_96 96 9/4/13 4:35 PM
B U S I N E S S B R I E F S
www.offshore-mag.com • September 2013 Offshore 97
Pellerin Energy Group has named Scott
Pellerin operations manager of its water solu-tions business unit.
Dana Gas has appointed Patrick Allman-
Ward as CEO.LUX Assure has appointed Charles
Cruickshank as CEO.Mario Azar has been appointed CEO of
the solutions business unit in the oil and gas division of Siemens’ Energy Sector.
Badger Explorer ASA has appointed Steinar Bakke as CEO.
Spectraseis has appointed Todd Chuckry as CEO.
Nexans has appointed Arnaud Poupart-
Lafarge as COO.Gazprom’s board of directors has elected
Viktor Zubkov as chairman and Alexey
Miller as deputy chairman.Jay Hollingsworth has joined Energistics
as chief technology offcer.Capt. Thomas Sparks has assumed du-
ties as the federal on-scene coordinator for the Gulf Coast Incident Management Team from Capt. Duke Walker.
Trouvay & Cauvin UK has promoted Jon
Mason to external sales product manager, covering Scotland and central and northern England.
RSC Bio Solutions has appointed Mark
Miller as executive vice president of sales.
Tyler Burger has joined the PMI Industries mechanical engineering team. Al
Schiazza has joined the company as senior project engineer.
Independent Risk Management Systems B.V. has appointed Dennis Zaal and Marco Noorlander as project managers, Sander Everstein as engi-neering manager, and Kate Fath and Marie
Goddard as engineers.SPIR STAR Ltd. has hired Carolina San-
chez and Keith Tierney as sales representa-tives.
Company newsDelta Rigging & Tools has acquired Hol-
loway Wire Rope, a supplier of wire rope, below-the-hook lifting devices and rigging supplies headquartered in Tulsa, Oklahoma.
McDermott and Ocean Installer have reached a mutual agreement to dissolve the interim North Sea project-specifc alliance the two companies entered into in December 2012. Opportunities under the alliance have not materialized and in recent months it has become apparent that the long-term strategic aims of both companies are not aligned.
Niche Products has created a new division named Niche Products Australia with manufacturing in Perth and storage in Darwin.
Palfnger Marine has received ISO 14001 certifcation.
BassDrill Ltd. has changed its name to Atlantica Tender Drilling Ltd.
BMT Reliability Consultants has received OHSAS 18001 and ISO 14001 certi-fcations.
Glacier Energy Services’ offshore divi-sion has opened its frst international base in Singapore.
James Young has established Energy Ser-
vice Partners, an oilfeld service company specializing in wireline pressure control equipment.
Oil Consultants Ltd., a recruitment agency for the oil and gas industry, was presented with the Queen’s Award for Enter-prise: International Trade in recognition of its achievements in exports over the past three years.
GE Oil & Gas says it will establish its new global headquarters in London. The global headquarters for GE Oil & Gas Turboma-
chinery Products & Services will remain in Florence, Italy.
Expro has entered into a strategic sales representative agreement in the Asian and Australian markets, through its subsidiary Expro Meters Inc. Under the terms of the agreement, KROHNE Australia Pty Ltd. will act as a reseller of Expro Meters’ sonar based fow monitoring systems for upstream and midstream oil and gas applications.
ALS has entered into an agreement to acquire Reservoir Group for $533 million.
Halliburton has completed acquisition of the assets of Optiphase Inc., a provider of interferometric fber optic sensing solutions including distributed acoustic sensing inter-rogation systems.
QTEC has launched a new regulatory compliance service for the US market in response to the heightened environmental focus on operations in the Gulf of Mexico. The service aims to ensure clients’ drilling activities meet current and proposed legisla-tion; that contamination, spills and other more serious incidents are prevented; and that the waste streams from worksites are suitably contained.
Acteon has completed the acquisition of J2
Engineering Services Ltd.
Clariant will open a new Center of Excel-lence lab for its oil services business in Kuala Lumpur, Malaysia.
Sagentia Group plc has acquired OTM
Consulting Ltd., an international technology management consultancy.
FloaTEC has received ISO 9001-2008 certifcation for project management and engineering.
Offshore chemical engineering company Aubin has launched a new integrity manage-ment and subsea division.
Badger Explorer ASA has sold 70% of its shares in its subsidiary Calidus Engineer-
ing Ltd. for £936,335 ($1.4 million) to Severn
Glocon Group plc. Under the agreement, Severn Glocon will acquire another 15% of the shares in 2015 and the remaining 15% in 2016 on an earn-out model.
The board of directors of Noble Corp. has approved changing the place of incor-poration of the publicly traded parent of the Noble group of companies from Switzerland to the UK. The company’s shareholders will be asked to vote to approve the proposed change.
Caterpillar Inc. has signed a defnitive agreement to acquire Johan Walter Berg
AB. Headquartered in Öckerö Islands, Swe-den, Berg has designed and manufactured heavy-duty marine thrusters and controllable pitch propellers since 1929.
Herkules has acquired Norwegian headquartered oilfeld technology specialist Petroleum Technology Co.
Mubarak Awaida Al-Hajri (right), operations manager-offshore fields for Qatar Petroleum, presents the certificates of appreciation and gifts to the awardees at its annual awards cer-emony. Mubarak serves as the Advisory Board Chairman of PennWell’s Offshore Middle East Conference & Exhibition.
Miller
1309off_97 97 9/4/13 4:35 PM
21-23 JANUARY 2014
International Conference Centre, Accra, Ghana
EXPANDING WEST AFRICAíS
OFFSHORE POTENTIAL
CONFERENCE AND EXHIBITION
Presented by:Owned & Produced by: Supporting Publication:
18TH EDITION Follow Offshore Events on:
INVITATION TO ATTEND
The 18th annual Offshore West Africa conference and exhibition returns to Accra, Ghana on 21-23 January 2014, delivering the premier technical forum focused exclusively on West African offshore exploration and production. The conference will provide attendees with the latest technological innovations, solutions and lessons learned from leading industry professionals.
Offshore West Africa remains the leading source of information on new technology and operating expertise for this booming deepwater and subsea market.
This is your opportunity to join over 1,500 offshore professionals by attending the leading conference and exhibition dedicated to the offshore oil & gas industry in the region.
REGISTER TODAY AT WWW.OFFSHOREWESTAFRICA.COM
SAVE UP TO $250 WITH YOUR EARLY BIRD DISCOUNT
For more information on exhibiting and sponsorship please contact:
Europe, Africa & Middle East:Tony B. Moyo
T: +44 (0) 1992 656 658F: +44 (0) 1992 656 700E: [email protected]
Nigeria:Dele Olaoye
T: +234 802 223 2864E: [email protected]
The Americas:Desiree Reyes
T: +1 713 963 6283F: +1 713 963 6212
South East AsiaMike Twiss
T: +61 437 700 093E: [email protected]
HOW YOU WILL BENEFIT:
Network and do business with major and independent E&P companies focusing specifcally on West Africa
Visit and participate in the exhibition showcasing new technologies and capabilities to support improvements in African E&P operations
Learn from expert opinions on new issues, challenges and solutions associated with the expanding African exploration & production activity
1309off_98 98 9/4/13 4:35 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)
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• EURASIA
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INDIA
Interads Ltd., A-113, Shivalik, New Delhi 110 017 PHONE +91 11 628 3018 • FAX +91 11 622 8928
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NIGERIA/WEST AFRICA
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
AADE .....................................................75www.aade.org
Adalet ..................................................... 15adalet.com
Aker Solutions ......................................21www.akersolutions.com
Avondale ................................................ 19www.hii-avondale.com
B
Baker Hughes Incorporated .............9, 49www.bakerhughes.com
Bluebeam Software, Inc. ......................29www.bluebeam.com
C
Cameron ............................................... C2www.c-a-m.com
CGG .......................................................27www.cgg.com
Chevron ................................................. 11chevron.com
CJ Winter ...............................................81cjwinter.com
Co.L.Mar. S.r.l. .......................................56www.colmaritalia.it
Cudd Energy Services .........................31www.cudd.com
Curoil NV ...............................................42www.curoil.com
D
Damen Shipyards Group ......................40www.damen.com
Delmar Systems, Inc. ............................34www.delmarus.com
Delta Subsea ...........................................7deltasubsea-rov.com
Dril-Quip ............................................... C3www.dril-quip.com
F
Frank Mohn Flatoy AS .......................... 17www.Framo.com
G
GE Air Filtration ....................................73www.ge-energy.com/filtration
GE Oil & Gas .........................................25www.geoilandgas.com
GVA Consultants AB ............................ 14www.gvac.se
H
Halliburton .............................................23www.halliburton.com
Hardbanding Solutions byPostle Industries ...................................51
www.hardbandingsolutions.comHarris CapRock Communications (CAP) ..........................3
www.harriscaprock.com
J
JD Neuhaus Group ...............................35www.jdngroup.com
L
LAGCOE ................................................54www.lagcoe.com
Lincoln Electric .....................................55www.lincolnelectric.com
M
M-I SWACO ........................................... C4www.miswaco.com
M&D Industries .....................................59DrillLab.com
Magnetrol International ........................53www.magnetrol.com
META ......................................................57www.metadownhole.com
N
National Oilwell Varco. ..........................65www.nov.com
Newpark Drilling Fluids. .......................61www.newparkdf.com
Nylacast. ................................................83www.nylacast.com
O
Oceanic Marine Contractors ................39www.oceanicmc.com
OneSubsea ............................................37www.onesubsea.com
Orion Instruments ................................69www.orioninstruments.com
P
PennWell Deep Offshore Technology Conference & Exhibition .................77
www.deepoffshoretechnology.com Deepwater Operations Conference & Exhibition ..... 85, 94-95
www.deepwateroperations.com Offshore Group ......................4, 79, 82
www.offshore-mag.com Offshore West Africa Conference & Exhibition ......................................98
www.offshorewestafrica.com PennEnergy Research .....................56
www.PennEnergyResearch.com PennWell Books .................................8
www.PennWellBooks.com Subsea Tieback Forum & Exhibition ................................85, 87
www.subseatiebackforum.com Topsides, Platforms & Hulls Conference & Exhibition ...........85, 91
www.topsidesevent.comPOLARCUS DMCC ................................45
www.polarcus.com
R
REPSOL .................................................89www.repsol.com
S
Siemens AG ........................................... 13www.siemens.com
Society of Petroleum Engineers ..........50www.spe.org
Spectrum Geo, Inc. ...............................43www.spectrumasa.com
Superior Energy Services ....................47superiorenergy.com
T
Tenaris ...................................................33www.tenaris.com
V
Vallourec & Mannesmann USA..............1www.vam-usa.com
W
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
1309off_99 99 9/4/13 4:35 PM
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].
100 Offshore September 2013 • www.offshore-mag.com
B E Y O N D T H E H O R I Z O N
The statement “there is no more easy oil” is commonplace in the oil and gas industry. It is an interesting observation: what the indus-try now considers “easy” was anything but when the technologies were introduced that opened up what now are considered easy-to-produce felds. The technologies that have allowed heavy oil produc-tion, ultra-deepwater drilling, and foating production were essential to the growth of the industry.
Today, work continues on the next generation of research and de-velopment, which includes disciplines that have never before been associated with oil and gas operations. One of the most interesting and promising of these is nanotechnology.
R&D efforts are taking place on a number of fronts. Houston’s Rice University, for example, is involved in developing “nanoreport-ers” that are designed to change their molecular makeup depend-ing on the medium they encounter (water, petroleum, or hydrogen sulfde) and to report data, including the temperature and pressure readings. Tags attached to the nanoreporters allow the scientists tracking the devices to determine how long the nanoreporters have been deployed.
Saudi Aramco has invested heavily in similar research through its Exploration and Petroleum Engineering Center – Advanced Re-search Center (EXPEC ARC) in Dhahran, Saudi Arabia. Research-ers at EXPEC ARC are developing reservoir robots, or “resbots,” designed for deployment in oil and gas reservoirs for the purpose of reporting data from the reservoir to the surface for improved reser-voir management.
Additional industry research is focused on developing advanced coatings applications, including coatings for drill bits, lubricants and drilling mud, and pipelines.
Classifcation societies have embraced emerging technology, in-cluding nanotechnology, which has led to increased investment and greater cooperation with other stakeholders through pioneering joint development projects.
One example is work ABS has undertaken with George Wash-ington University on nanosurface profling technologies to develop and test ice-phobic coatings to mitigate ice accretion. By profling the surface at the nano scale, researchers can modify the contact angle for water droplets such that they do not adhere, which means the droplets will not wet a treated surface. This technology could mitigate the risk of ice buildup in arctic conditions.
The aim of this project is to develop a testing standard to evaluate ice-phobic coating performance and will encompass an assessment
not only of ice adhesion, but also of abrasion resistance, durability, and UV resistance. It is a trickier problem than it appears, in part because there are so many variables. For instance, the type and composition of ice accreted can be expected to differ between com-ponents and locations on the same vessel. This also is true for the same component installed on different vessels.
The potential application of ice-phobic surfaces is far reaching and includes the ability to liberate critical components such as lifeboat release mechanisms and navigation equipment from the debilitating effects of freezing sea spray and precipitation.
This ambitious project holds bold promise for improving safety in the Arctic developments that are anticipated in the next few years. Applying nanotechnology that will expand the operational window of Arctic operations has the potential to increase productivity con-siderably and to reduce operational interference due to inclement conditions.
In choosing to invest in nanotechnology R&D, ABS investigated the merits of 16 projects in the disciplines of energy effciency, sub-sea, and offshore technology. While the ice-phobic nanostructured coatings project eventually won out, a project that nearly came out on top was one that addressed energy effciency and weight-savings – a concern equally vital to the industry.
While fber glass polymer matrix (FRP) structures are fnding greater acceptance, they have some obvious drawbacks. One of these is the diffculty of accurate in-service inspection, and another is a greater vulnerability to impact than conventional building ma-terials. Spurred on by successes in aerospace, researchers now believe they can develop an FRP that can repair itself. The repair works when resin and hardener nanocapsules lying dormant in their embedded state within the matrix are fractured by an event such as the formation of a micro-crack. The capsules release their contents, which cure to seal the crack. This is proving to be particularly ap-pealing for large-scale FRP CNG pressure vessels.
The potential scope for applying these new technologies is broad, but more research is needed. As industry prepares to take on new challenges, technology is working to close the gaps.
Continued cooperative research efforts will be the key to develop-ing the solutions that will extend the boundaries of what is possible in offshore exploration and development.
James Bond
Elli Lembessis
ABS
Oil and gas industry research
targets nanotechnology
1309off_100 100 9/4/13 4:35 PM
1309off_C3 3 9/4/13 4:35 PM
miswaco.com/deepwater
DEEPWATERCHALLENGES
Deepwater drilling fl uids and services leadership – By far, for yearsM-I SWACO drilling fl uids technology, engineering and drilling waste management services have
helped deliver an average of 139 deepwater wells per year for the last 7 years. This is more than
twice the number of any other provider, and includes 290 wells classifi ed as ultra-deepwater.
It’s an unrivalled track record that demonstrates the proven performance of our deepwater-certifi ed
specialists and our technical portfolio in the most challenging drilling environments.
1309off_C4 4 9/4/13 4:35 PM
Fo r t he i ndu s t r y ’ s c a r e e r - m ind e d p r o f e s s i ona l s SUMMER 2013
A sup p l emen t t o P ennWe l l pub l i c a t i on s | w w w. P ennEne r g yJ O B S . c om
New Horizons:
The Growth of
Offshore Wind
Around the World
FROZEN ASSETS:
The Artic Push
in Offshore
Oil & Gas
INDUSTRY INSIGHTS
Offshore Energy: Mitigating Risk
TRAINING INSIGHTS
Empowering our Troops: AEP Career Initiatives for Veterans
ENERGY 101
Wave & Tidal Power
1308pejew_C1 1 8/20/13 2:58 PM
1308pejew_C2 2 8/20/13 2:58 PM
2 EDITOR’S LETTER
Offshore Energy: Towards the Great Horizon
Dorothy Davis Ballard, PennWell
3 NEW HORIZONS
The Growth of Offshore Wind Around the World
Dorothy Davis Ballard, PennWell
5 FROZEN ASSETS
The Artic Push in Offshore Oil & Gas
Hilton Price, PennWell
6 INDUSTRY INSIGHTS
Offshore Energy: Mitigating Risk
Matthew Gordon, Viking SeaTech
8 CAREER INSIGHTS
Regulatory Experts: Career Opportunities Galore
Volker Rathman, Collarini Energy Staffng
10 TRAINING INSIGHTS
Empowering our Troops: AEP Career
Initiatives for Veterans
Dorothy Davis Ballard, PennWell and Scott
Smith, American Electric Power
12 ENERGY 101
Wave & Tidal Power
PennEnergy.com
w w w . P e n n E n e r g y J O B S . c o m
SUMMER 2013
A PENNWELL PUBL ICAT ION
Stacey Schmidt, Publisher
Dorothy Davis Ballard, Content Director
Hilton Price, Editor
Cindy Chamberlin, Art Director
Daniel Greene, Production Manager
Tommie Grigg,
Audience Development Manager
PennWell Corporation
1421 South Sheridan Road
Tulsa, Oklahoma 74112
918 835 3161
PennWell.com
Recruitment Advertising Sales:
Courtney Noonkester
Sales Manager
918 831 9558
Ad ve r t i s e r s ’
I ndex Chevron �������������������������������������������������������������������������������������������������������������� C2
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Sou
rce:
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En
ergy
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1308pejew_1 1 8/20/13 2:57 PM
2 Summer 2013 | FOR JOB OPPORTUNITIES, VISIT www.PennEnergyJOBS.com | EnergyWorkforce
Ed i to r ’ s
Le t t e r
THE world’s oceans and vast waterways have always evoked feelings of wonder
and piqued the adventurous spirit. Teeming with life and uncharted depths,
these fuid bodies are awe inspiring in the way they are so vast and yet joining together
everything.
In the ancient world the challenge was to transverse these great expanses, to fare
into the horizon of the unknown for sustenance and wealth. Today, the world beyond
our shores holds the promise of new bounties. We turn again towards the great horizon,
abundant with the promise of resources to fuel all we have developed.
In this issue of Energy Workforce we delve into offshore energy as it is moving
ahead in great leaps and
bounds. We begin with an
overview of offshore wind
power on page 3, highlighting
the incredible global growth
of this industry as it moves
towards becoming a truly
competitive resource.
Next, we look to the
offshore oil & gas industry
and its renewed push into artic territories on page 5, followed by a timely editorial on
mitigating risk on page 6 as offshore exploration & production moves to tap these once
unreachable resources.
With a focus on career development, we hear from an industry expert on expanding
opportunities for regulatory experts on page 8 and speak with an executive of U.S.
energy major AEP about initiatives for veterans in energy on page 10.
We close this issue with another round from our Energy 101 series, this time a brief
introduction to the evolving wave and tidal power industry on page 12.
We hope you enjoy these insights and encourage you to keep us on your summer
reading list to stay ahead with the latest energy news, research, and jobs at PennEnergy.
com and PennEnergyJobs.com.
Carpe diem!
—Dorothy Davis Ballard
Towards the Great Horizon
“Today, the world beyond our shores holds
the promise of new bounties. We turn again
towards the great horizon, abundant with
resources to fuel all we have developed.”
1308pejew_2 2 8/20/13 2:57 PM
Cover STORY
EnergyWorkforce | FOR JOB OPPORTUNITIES, VISIT www.PennEnergyJOBS.com | Summer 2013 3
The Growth of Offshore
Wind Around the WorldBy Dorothy Davis Ballard
AS more countries around the
globe realize the potential of
offshore wind, new turbines
are being installed off of our coasts.
In 2012, 1,296 megawatts of new off-
shore capacity were installed — a 33
percent increase from 2011, according
to the Global Wind Energy Council
(GWEC). The world now has at least
5,415 MW of offshore wind energy gen-
erating around the globe.
Offshore wind represents about 2 per-
cent of global installed energy capacity,
but that number could, and is expect-
ed to, increase rapidly. This renewable
resource, which is able to generate far
more power than onshore wind tur-
bines, could meet Europe’s energy de-
mand seven times over, highlights the
GWEC. While in the United States, off-
shore wind has the potential to provide
four times the energy capacity needed.
Europe’s lead in offshore wind
Currently, more than 90 percent of the
globe’s offshore wind power is installed
off the coast of northern Europe in the
North, Baltic and Irish seas. There is
now also a solid presence in the English
Channel. Last year, the United King-
dom took the lead in new wind capacity,
adding 854.20 MW of offshore wind
power assets. Denmark added 46.8 MW
in 2012 and Belgium 184.5 MW.
As of this article, Europe has a total
of 4,336 MW generating from 1,503 off-
shore wind turbines at wind farms locat-
ed across 10 countries. The European
Union has set a goal to generate 20 per-
cent of its electricity from renewable
sources by 2020, and offshore wind is
slated to play a major role in making
that a reality.
In early July, the offshore wind in-
dustry celebrated a milestone: Dong
Sou
rce:
DO
NG
En
ergy
A/S
1308pejew_REV_3 3 8/28/13 1:13 PM
4 Summer 2013 | FOR JOB OPPORTUNITIES, VISIT www.PennEnergyJOBS.com | EnergyWorkforce
Energy inaugurated the world’s largest
offshore wind power facility. The proj-
ect, which includes 175 Siemens wind
turbines, is called London Array and lo-
cated 12.4 miles off the Kent and Essex
coast in the Thames estuary. It has a to-
tal capacity of 630 MW, enough to pow-
er 500,000 households.
The UK’s Department of Energy &
Climate Change recently approved an-
other major offshore wind project, which
will add to Europe’s expanding wind en-
ergy output. The 1.2 GW Triton Knoll
project will be led by RWE and located
off the Lincolnshire and Norfolk coast.
Along with supplying clean, alternative
energy, the project is expected to gener-
ate more than $5.5 billion of investment
in the region and create about 1,130 jobs.
Germany, too, has had its sights set
on the development of alternative ener-
gies like wind and solar as part of a na-
tional commitment towards the phase
out of nuclear power. The country add-
ed 80 MW of offshore wind energy to the
electric grid in 2012, and another six util-
ity scale offshore wind projects are under
construction. Petrofac, and Siemens En-
ergy also recently entered into a $53 mil-
lion contract to build two major offshore
wind projects in the North Sea off the
coast of Germany - one totaling 576 MW
and another set for 800 MW.
US makes commitment to offshore wind
North America is aiming to add some
6.5 GW of wind power this year, and the
United States is looking to be a major con-
tributor. While there are no offshore wind
farms in the U.S. at the moment, the fed-
eral government has recently completed
its frst-ever round of auctions for offshore
wind leases. Deepwater Wind,
a company based in Rhode Is-
land, came in with the highest
bid of $3.8 million for two ar-
eas totaling more than 164,000
acres off the coasts of Massa-
chusetts and Rhode Island. The
auction was viewed as a histor-
ic moment for the U.S.’s future
commitment to clean energy.
The federal government is
expected to hold another auc-
tion in September for a possi-
ble wind project off the coast of
Virginia. Areas offshore Mary-
land, New Jersey and Massa-
chusetts have also been sited
as possible locations for future
wind developments.
PensionDanmark announced in June
it will be funding $200 million in capi-
tal for the planned Cape Wind project
expected to include up to 130 Siemens
turbines of 3.6 MW each. If completed,
the project off the coast of Massachu-
setts’ Cape Cod would become one of
the world’s largest offshore wind farms.
Asia will boost wind output
According to the GWEC, Asia will con-
tinue to boost its wind energy output an-
nually, reaching 25.5 GW by 2017. When
it comes to offshore wind energy, Japan
reached 25.3 MW last year. Meanwhile,
South Korea reached 5 MW of offshore
wind generation.
China holds the third spot for most
offshore wind capacity, with 258.4 MW
installed. China is also home to the frst
commercial offshore wind project outside
Europe. The Shanghai Donghai Bridge
project was installed in 2010 and totals
102 MW. China hopes to have 5 GW
of offshore wind by 2015 and 30 GW by
2030, according to the GWEC.
Cheaper costs will drive demand
A major challenge for expanding off-
shore wind development is the current
high costs of the technology. Deep wa-
ters far offshore, higher waves and steeper
construction costs can make these proj-
ects somewhat cost prohibitive. Howev-
er, like other renewable energy sources
being developed around the globe, off-
shore wind technology is steadily improv-
ing to boost its overall return on invest-
ment. Investment remains strong across
the broader wind power industry with
2012 marking several milestones. It ap-
pears with continued cost reductions and
the growing push towards renewable re-
sources, offshore wind is positioned to be
a key player in meeting global energy de-
mand through the next decade. ⊗
Sou
rce:
DO
NG
En
ergy
A/S
1308pejew_REV_4 4 8/28/13 1:14 PM
EnergyWorkforce | FOR JOB OPPORTUNITIES, VISIT www.PennEnergyJOBS.com | Summer 2013 5
Frozen Assets
Despite immense challenges, the Arctic can’t
keep away exploration and drilling.
By Hilton Price
WHEN U.S. arctic waters saw
a drillship for the frst time
in 2 decades, it seemed the
return to a bygone era of exploration
had begun. Although Shell was ready
to usher in a new age for exploration
in those icy waters, process hurdles,
equipment issues, and natural obstacles
left the company’s dream unrealized.
Immediately after, as word of techni-
cal violations added insult to injury, it
seemed potential reservoirs in U.S. arc-
tic waters would remain unexplored for
at least a little while longer.
The frigid waters of the arctic present
one of the greatest challenges for any ex-
ploration company. These natural hin-
drances, combined with ongoing legis-
lation from the countries that lay claim
to those waters, make it a massive un-
dertaking. Shell lost billions in its failed
2012 campaign, and as the season end-
ed the company announced it would not
attempt a return in 2013.
However public Shell’s struggle in
the region may be, it is only a set-back.
2014 looms, and there is still no word
whether Shell will attempt a return to
the Arctic, but it is looking likely.
Shell is planning specialized surveys
of the area, using ships deployed to ar-
eas in the Chukchi and Beaufort seas.
This kind of data collection will be in-
valuable to potential future exploration
campaigns, and could save Shell in both
cost and risk if it chooses to return.
The same success Shell is hoping for
in U.S. arctic waters is being realized by
other companies in other areas of the
tumultuous region.Offshore Norway is
proving successful for numerous compa-
nies exploring the area. In the UK, three
of the country’s “Big 6” energy compa-
nies are planning Arctic drilling. E.On,
Centrica, and RWE Npower are all ex-
pressing interest in the region.
Likewise, there is a growing interest
offshore Russia, where legislation is loos-
er than the U.S. and reservoir potential
just as high. Shell has turned its atten-
tion to this area. If the company is suc-
cessful there, it could affect U.S. arctic
drilling policy, and possibly open the re-
gion further in the future.
In the U.S., however, there is an-
other element that could swing the
pendulum the other way, and close
off the country to further arctic ex-
ploration. The U.S. shale exploration
boom is changing the global energy
landscape. The country is expected to
become a major exporter in the com-
ing decades, and successful produc-
tion of these unconventional resources
could affect the interest in traditional
exploration. It could end the return to
the U.S. arctic before it truly begins.
There is a growing call for environ-
mental stewardship, the same kind that
brought an end to U.S. arctic drilling
decades ago. That concern for our natu-
ral environments isn’t likely to fade. Any
company heading to the area must show
respect for the land, and for those who
fght for it, or risk an evaporation of sup-
port for its work in the region.
Arctic drilling is hardly over. In ar-
eas offshore Norway, it thrives as much
as ever. In U.S. arctic waters, the pro-
cess may be stalled, but across the
sea in Russia’s arctic waters, oppor-
tunities are increasing. Success there
could further push exploration inter-
est here, and possibly overcome the
fnancial and legal hurdles that stand
in the way.
Meanwhile, success with shale oil
and gas could turn U.S. interests away
from the arctic, and back on land. But
that isn’t stopping companies from re-
viewing the region, and critically an-
alyzing collected data. For an area of
the Earth where even basic exploration
means a multi-billion dollar campaign,
every move matters and every decision
is crucial. ⊗
1308pejew_5 5 8/20/13 2:57 PM
6 Summer 2013 | FOR JOB OPPORTUNITIES, VISIT www.PennEnergyJOBS.com | EnergyWorkforce
INDUSTRY Insights
Offshore Energy: Mitigating Risk
By offering an integrated offshore support package, variant
forms of risk can be avoided, according to Viking SeaTech
Survey’s General Manager Matthew Gordon.
By Matthew Gordon
POST-MACONDO, there has been
an increased focus on the miti-
gation of risk. The industry has
reviewed operational practices from top
to bottom. Everyone from the
operators to offshore specialists
has been affected by the major
incident.
As a result, there has been an
increase in the contractual tug
of war between operators and
contractors in relation to the ac-
ceptance of risk and liabilities.
This has led to lengthy nego-
tiations as legal teams look to
reach middle ground, resulting
in increased administration,
time and cost.
It could be said that offering
an integrated and streamlined service re-
duces administration, costly contract ne-
gotiation and indemnities. Expanding in-
house services could not only hold the
key to unlocking cost savings, but also
to reducing risk in a risk wary industry.
Bringing new thinking to an old problem
Offshore service businesses are reinforc-
ing their position in the marketplace
by providing a fully integrated package.
Previously, smaller companies offered
a niche service that was considered sat-
isfactory twenty years ago. But as the
large corporations’ priorities adapt in
line with supply and demand, support
companies have risen to the task.
Viking SeaTech has looked at how
a new business stream can be injected
into a maturing and heavily saturated in-
dustry, in order to meet the changing re-
quirements of their clients.
By offering more services under a sin-
gle contract, including survey services,
we can provide a convenient package that
offers all the benefts, minus the opera-
tional burden. Our integrated approach
supports our efforts to make rig-moving
safer, faster, cheaper and eas-
ier to execute.
Reducing the
operational burden
Contract negotiations can
be time consuming; la-
bor intensive, costly and
can often impact project
scheduling. This is multi-
plied by having several con-
tracts to set up and manage
simultaneously.
An integrated approach
works towards removing
these barriers. It is highly advantageous
to the client to have a single contract in
place for service provision. This equates
to a single point of contact, invoice and
company-specifc set of terms and condi-
tions to manage.
The benefts of such a contracting ap-
proach are realized when an issue arises.
Instead of managing multiple contactors,
it takes one call to a single organization to
1308pejew_6 6 8/20/13 2:57 PM
EnergyWorkforce | FOR JOB OPPORTUNITIES, VISIT www.PennEnergyJOBS.com | Summer 2013 7
Matthew Gordon joined Viking SeaTech in November 2012 as General Manager, Viking SeaTech Survey. His role is to oversee the development of the newly created Survey division. He is responsible for initial recruitment, project management and contracting, proft and loss. Matthew joined the company from Subsea 7, where he was a Client Account Manager overseeing sales for the UK, Ireland and the Netherlands. Previously, he was in a general management position with VERIPOS and a project engineer with Fugro. He specializes in hydrographic survey positioning, project management, ROV and TDU operations, business development and personnel development. Matthew has an MSc in Management Studies from The Robert Gordon University and a BSc in Electronic Engineering from Glasgow Caledonian University.
remove the issue. If a single contractor is
working towards a shared goal, the time
taken to resolve the issues is also reduced.
The rig moving food chain
Operational effciency is improved when
operators use the integrated approach,
and also removes the need for multiple
contractors. By having numerous disci-
plines working together in-house, com-
munication is strengthened and it is en-
tirely realistic to suggest that the risk to
client operations is reduced.
From a quality assurance perspective,
Viking SeaTech Survey is involved at ev-
ery stage of the life cycle, from design
to evaluation and through working with
other disciplines. This process identifes
errors that may not be uncovered until
much later in the job, resulting in proj-
ect delays and increased cost.
Eradicating the blame culture
Contractor confict can trouble clients.
We have found that the greatest issue for
our clients is managing multiple contrac-
tors, especially when they are in confict,
as this can often lead to spending vast
amounts of time acting as arbitrator.
This is understandably irksome and
often it is the client who pays for this in
the form of lost time and additional costs.
An Integrated service approach can re-
move much of the operational burden
and the single contractor can resolve
problems on the client’s behalf. This
approach allows the client to spend their
valuable time working on other things,
while we deal with the issue at hand. This
is becoming even more important as or-
ganizations become fatter and individ-
uals within those companies have more
responsibility, meaning that time is a pre-
cious commodity.
Bespoke options
Large frms have the option of using
the offshore support specialist for their
rig moving operations expertise. It may
seem obvious, but advising clients at the
earliest point in the process is fundamen-
tal to the success of the job at hand. Step-
ping in at the initial engineering and de-
sign stages makes things easier later in
the job. Once these specifcations have
been approved by the client, a list of ma-
rine procedures can be made. This step-
by-step guide advises as to how the boats
and personnel will move the rig from
start to fnish.
Our potential clients may have fve
or six different options from multi-
ple contractors. To make the decision
easier, we tailor the options to ft the
client exactly. By offering multiple ser-
vices, operational burden is lifted and
risk is less likely. The more links in the
operational chain, the more things that
can go wrong. We are trying to bring it
down to just two links, us and the client.
Furthermore, uniform policies and pro-
cedures lead to a safer operation. A unit-
ed quality system that clearly informs all
personnel of operational methods will
drive a safer practice.
Looking to the future
The integrated service model brings end-
less possibilities. Removing the burden
for the operator is not only advantageous
in terms of costs, time and schedule, but
it can remove the incidence of risk within
an operation. Risk comes in many forms,
but can be reduced by using a stream-
lined business with one goal, the swift,
safe, coordinated and accurate comple-
tion of a contract.
I foresee integrated services becom-
ing more common place as the indus-
try continues to adapt. The often long
and drawn out processes attached to
drawing up contracts between opera-
tors and contractors, and subsequent
legal associations, has proved costly in
the past. Integration will become the
norm once the industry realizes this
effcient business prototype is one to
be utilized. ⊗
Risk comes in many forms, but can be reduced by using
a streamlined business with one goal, the swift, safe,
coordinated and accurate completion of a contract.
1308pejew_7 7 8/20/13 2:57 PM
CAREER Insights
8 Summer 2013 | FOR JOB OPPORTUNITIES, VISIT www.PennEnergyJOBS.com | EnergyWorkforce
Regulatory Experts Career Opportunities Galore
Evolving regulatory systems in the petroleum industry
provides an emerging career path
By Volker Rathman, Collarini Energy Staffng
WITH the drilling moratorium
lifted, the oil and gas indus-
try is trying to fgure out how
to deal with the onslaught of new regu-
lations. The effects on the job markets
have already been felt: Thousands of
jobs in the offshore industry were tem-
porarily lost after the moratorium was
put in place in the wake of the Macondo
incident.
We say “temporarily,” since over time
many of these jobs will come back. This
is in no way belittling the effect the loss of
jobs has had on those involved and their
families. It is stating a belief that our in-
dustry is resilient and will come back –
stronger and better.
Well over 80 percent of this country’s
energy comes from hydrocarbons. No
number of alternative or renewable energy
sources will change that percentage quick-
ly. Oil and gas are here to stay; and, frank-
ly, the country needs us to produce hydro-
carbons for them, even if the importance
is not always realized by many Americans
outside of our industry.
So our take on the future job market
is positive. Regulations about to be dealt
with by the industry will have an increas-
ing effect on job creation, since many
1308pejew_8 8 8/20/13 2:57 PM
EnergyWorkforce | FOR JOB OPPORTUNITIES, VISIT www.PennEnergyJOBS.com | Summer 2013 9
more people will be needed to under-
stand what the new rules mean and to
develop the best practices to implement
them. Regulatory experts and analysts
may apply here!
The role of the regulatory analyst has
expanded in all sectors of the oil and gas
industry as a result of proposed, new and
revised legislation.
• A regulatory analyst’s position may in-
clude such responsibilities as:
• Preparing and submitting permitting
requests for all new operations activi-
ty and any revisions to prior approvals
• Monitoring and reporting gas and oil
production and inventory for compa-
ny-operated wells
• Managing and updating regulatory in-
formation and forms
• Interfacing with local, state and feder-
al regulatory agencies
An experienced analyst will have pri-
or regulatory permitting and reporting
experience for full cycle development
planning, drilling completion, workover
operations, and feld abandonment. The
role also requires knowledge of permitting
specifc to the governing agency and geo-
graphic area.
Additionally with conventional on-
shore drilling, the process of shale ex-
traction is regulated under a number of
laws, most notably at the federal level,
the Environmental Protection Agen-
cy, The Clean Water Act, The Safe
Drinking Water Act, and The Nation-
al Environmental Policy Act. While
the federal agencies administer a gen-
eral “one-size-fts-all” set of guidelines,
the regulatory bodies at the state and
local levels may be distinctly different
due to geographic location, hydrology,
population density, wildlife, climate
and local economics.
This stew of agencies and rules cre-
ates career opportunities for experts in
each area and for generalists keeping an
eye on the big picture and the interface
among all parties.
Experts in this feld will be needed in
the permitting processes. This will create
employment opportunities particularly in
the context of:
• Greenhouse gas and air emissions
• Noise pollution
• Erosion and sediment control and
• Environmental threats to endangered
and threatened species
We do not know how the regulatory
scene will play out. We are certain, how-
ever, that regulatory compliance needs
will not decrease; this could create a boon
for those professionals seeking a switch
in their careers.
Tis fast-growing sector of the indus-
try holds promise to any regulatory pro-
fessional due to the diversity of agency
interface, geographic variety and environ-
mental concerns. As industry technolog-
ical developments and practices improve
and legislative requirements continue to
evolve, so will the unique opportunities
in these regulatory roles. ⊗
Volker Rathmann is the President of Collarini Energy Staffng Inc. Prior to joining the frm
in 2001, he held the position of Chief Financial Offcer for INTEC Engineering, a provider
of specialized engineering services in global frontier and deepwater projects. Before INTEC
Engineering, Volker held a number of leading positions in operations, marketing and fnance
within the Daimler AG. Volker earned a Bachelor’s degree in business administration in
Berlin, Germany.
The role of the regulator y analyst has expanded
in all sectors of the oil and gas industr y as a
result of proposed, new and revised legislation.
1308pejew_9 9 8/20/13 2:57 PM
10 Summer 2013 | FOR JOB OPPORTUNITIES, VISIT www.PennEnergyJOBS.com | EnergyWorkforce
Empowering our Troops: AEP Career Initiatives for Veterans
HEADQUARTERED in Colum-
bus, Ohio, American Electric
Power (AEP) is one of the
largest electric utilities in the United
States, delivering electricity to more
than 5.3 million customers in 11 states.
AEP has a long history of community
engagement and has established itself
as one of the top employers for military
men and women.
As a leading utility, AEP partners
with veterans’ organizations and job pro-
grams, provides special benefts to vet-
eran employees, and supports veteran
employees and their families through
mentoring and recognition programs.
Recently, PennEnergy was invited to
learn more about AEP’s veterans’ ini-
tiatives and given the opportunity to
engage Scott Smith, AEP Senior Vice
President for Transmission Strategy and
Business Operations.
A former U.S. Army captain and com-
bat engineer, Smith serves as an execu-
tive sponsor for AEP’s Military Veteran
employee resource group. Smith collab-
orated with PennEnergy content direc-
tor, Dorothy Davis, to offer greater in-
sight into AEP’s veterans’ initiatives and
how they beneft our military heroes,
the energy industry, and the communi-
ties they serve.
PennEnergy (PE): What percentage of
AEP’s current workforce is represented
by veterans?
Scott Smith (Smith): Veterans com-
pose 10 percent of AEP’s workforce, with
1,770 military veterans working through-
out our 11-state service territory.
PE: When did AEP’s veteran outreach
initiatives begin and what prompted
them?
Smith: Though AEP has a long his-
tory of supporting military veterans, it
became even more pertinent in recent
years as we increasingly realized that the
skills military veterans could bring to the
workplace closely match the skills we are
seeking for new employees. Many vet-
erans have the job-related training we
need to operate equipment and to per-
form other technical functions, along
with the personal attributes we value,
including leadership skills, f lexibili-
ty, adaptability, dedication and team-
work. We also have recognized the
signifcance of building a skilled work-
force pipeline that will help us meet the
future needs of our ever-evolving indus-
try. With this in mind, we have placed
increasing attention on our military re-
cruiting efforts as well as on our compa-
ny pay and benefts policies that support
Reservists and National Guard members
who are called into active duty.
PE: What programs does AEP have
in place for helping to recruit and
transition veterans into civilian ener-
gy careers?
Smith: At AEP, we have taken a
number of approaches to target the vet-
eran community and transition them
to successful careers at AEP. For exam-
ple, instead of fltering through thou-
sands of resumes, which can be time
consuming, we work with veterans’ or-
ganizations and national and state jobs
programs to locate veterans who have
the skill sets that match utility jobs.
This spring, AEP hosted an open
house at the AEP Transmission train-
ing facility near Columbus, Ohio, for
an up-close and personal view of the
daily activities of linemen, station tech-
nicians, protection and control elec-
tricians and other jobs. The event,
co-sponsored with veterans groups,
TRAINING Insights
1308pejew_REV_10 10 8/28/13 1:14 PM
EnergyWorkforce | FOR JOB OPPORTUNITIES, VISIT www.PennEnergyJOBS.com | Summer 2013 11
provided an orientation about the types
of careers available at AEP. Several AEP
military veterans served as mentors dur-
ing the event. AEP seeks out veterans at
traditional recruiting events, too. For ex-
ample, we participate in Hire Our He-
roes, a U.S. Chamber of Commerce-
sponsored job fair.
In addition, AEP is one of a handful of
utilities that directs ex-military job appli-
cants to an online “military occupational
specialty” decoder that translates military
skills, capabilities and training into civil-
ian terms. The decoder helps veterans
recognize the meaning and value that
their military skills and training have in
the civilian workforce.
PE: What impact has AEP’s veteran
program had on the company and its
service communities?
Smith: For 10 consecutive years, AEP
has been ranked among the top “mili-
tary friendly” employers in the country
by GI Jobs Magazine. Our program has
not only increased the number of veter-
ans in our ranks, but it has helped veter-
ans transition successfully through men-
toring and company support.
I serve as an executive sponsor for
our Military Veteran employee resource
group, which was launched on Veterans’
Day in 2012. The group not only men-
tors newcomers, but it also supports em-
ployees by assisting their families while
the employees are away on active duty.
The resource group partners with veter-
ans groups and sponsors events to honor
veterans throughout AEP’s 11-state ser-
vice territory. Ultimately, we want to show
our employees and our service commu-
nities that we value the service of veter-
ans who have fought to protect our free-
doms and want to help them secure the
economic prosperity, ongoing support,
and respect they deserve.
PE: How does AEP envision the role
of veterans in evolving energy industry?
Smith: When we look at the veter-
an community, we see a skilled, disci-
plined workforce that can help our in-
dustry succeed as we begin a period of
rapid infrastructure modernization and
expansion. Nationwide, utilities will
need to replace an estimated 200,000
skilled Baby Boomers expected to retire
in the next fve years – a third of the ener-
gy workforce. At the same time, utilities
across the U.S. are expected to invest $50
billion to modernize electric transmis-
sion infrastructure through 2020. This
estimate could surpass $100 billion if
additional investments are made to en-
hance communications and cyber secu-
rity capabilities.
Through 2020, AEP alone plans to
spend billions to build around 480 new or
enhanced transmission substations and
roughly 1,800 miles of new transmission
lines. We plan to rebuild another 3,900
miles of transmission lines between 2013
and 2015. We also are focused on prepar-
ing ourselves for success in a competi-
tive transmission business environment,
which will require us to move quickly and
fnish projects on time and on budget.
As a result, targeting military veter-
ans who are transitioning to civilian ca-
reers makes sense since their capabilities
match the qualities necessary for us to
succeed in a rapidly growing, competi-
tive transmission landscape.
PE: What is ahead for AEP’s veteran
initiatives?
Smith: As we seek to recruit more
veterans into our ranks, we have looked
at how we can best support this popu-
lation of employees, particularly those
who continue to serve. AEP recently an-
nounced it will make up the difference
between an employee’s military pay and
his or her AEP base wage when the em-
ployee is off work for required training.
Additionally, we are supporting indus-
try-wide efforts to leverage the talents of
the veteran community. AEP helped es-
tablish the Troops to Energy Jobs pro-
gram, a product of the Center for En-
ergy Workforce Development. The
Center recently published a 54-page na-
tional model to help energy companies
develop a comprehensive program for
military outreach, education, recruit-
ing and retention. Through such col-
laborative efforts, we are determined to
help more veterans by providing a road-
map to civilian employment in the en-
ergy industry. In turn, we are ensuring
that we have the skilled workforce need-
ed to continue generating and deliver-
ing the reliable electricity that is essen-
tial to American homes, businesses and
national security. ⊗
“When we look at the veteran communit y,
we see a skilled, disciplined workforce...”
To learn more visit: AEP – A Military Friendly Employer
For career resources in the power and petroleum sectors visit: PennEnergyJobs.com
1308pejew_11 11 8/20/13 2:57 PM
12 Summer 2013 | FOR JOB OPPORTUNITIES, VISIT www.PennEnergyJOBS.com | EnergyWorkforce
Energy 101: Wave & Tidal EnergyPennEnergy.com
WAVE and tidal energy is
a predictable form of re-
newable energy that uses
the power and movement of wave
and tidal fows to generate electric-
ity. With the use of underwater tidal
turbines, energy from the sea is cap-
tured to create a non-polluting form
of electricity.
A dam approach with hydraulic
turbines is the most modern tech-
nology being used across the world
to harness tidal power. Tidal dams
are most effective in bays with nar-
row openings. Gates and turbines are
installed at certain points along the
dam, and when an adequate differ-
ence in water elevation on the dif-
ferent sides of the barrage occurs,
the gates open, creating a “hydrostatic
head,” the Ocean Energy Council re-
ported. During this process, water fows
through the turbines to create electric-
ity. The technology used at tidal ener-
gy facilities is similar to that used at
traditional hydroelectric p ower plants.
Wave and tidal power is one of the
oldest forms of energy used by humans,
with tide mills used by the Spanish,
French and British as early as 787 A.D.
It’s estimated the world’s potential for
ocean tidal power is 64,000 megawatts
electric, the OEC reported. However,
tidal power has a low capacity, usually in
the range of 20 to 30 percent. The tech-
nology for tidal energy is also expensive,
though powerful. It is estimated that if
a barrage was placed across a high-tid-
al area of the Severn River in western
England, it could provide 10 percent of
the country’s electricity needs, accord-
ing to the OEC.
Growing popularity
Tidal and wave energy technology is ad-
vancing rapidly as more countries are
beginning to realize the renewable en-
ergy’s benefts.
In the United States alone, there are
about 2,110 terrawatt-hours of wave en-
ergy being generated each year. Yet, ac-
cording to the Renewable Northwest
Project, this is just 25 percent of how
much the U.S. could be generating on
its coasts from tidal power.
Using special buoys, turbines or
other means, the country is captur-
ing the power in waves and tides from
the ocean - power that can be more
predictable than wind. Because tidal
energy reacts to the gravitational pull
of the moon and sun, experts can pre-
dict their arrival centuries in advance.
Oregon and Washington experience
the strongest waves in the lower 48
states. In Washington’s Puget Sound,
the U.S. could develop wave and tidal
technology that could capture sever-
al hundred megawatts of tidal power.
The U.S. Department of Energy
also recently unveiled a foating off-
shore wind platform that uses under-
water turbines to capture tidal energy
and create electricity, Forbes report-
ed. Another wave project that includes
10 buoys is being tested off the coast of
Oregon. It is expected to generate 1.5
MW. U.S. regulators see projects like
this as a smart and valuable solution to
diversify the country’s energy mix with
greener technologies. These regulators
also see wave and tidal power as more
predictable than wind and solar.
The United Kingdom also sees tidal
power as a viable alternative to fossil fuel
power. The U.K. is seen as a world lead-
er in wave and tidal stream technologies
due to its abundance of marine energy
resource. It is estimated that tidal tech-
nologies could generate up to 300 MW
of power by 2020. However, overall po-
tential is between 25 and 30 gigawatts. ⊗
1308pejew_12 12 8/20/13 2:58 PM
Actionable data for the Power industry:
Make your next step your BEST step.
Power Generation
Renewable Energy
Transmission & Distribution
Smart Grid
...and much more
www.PennEnergyResearch.com
DIRECTORIES SURVEYS FORECASTS INDUSTRY ANALYSISSTATISTICAL TABLES CUSTOM RESEARCH
1308pejew_C3 3 8/20/13 2:58 PM
We’ve got people.
PennEnergy JOBS is the key to attracting the
energy industry professionals you need to hire to
meet your business goals. Our process puts your
recruitment message in front of the industry’s best
talent whether it’s online, in print, or at an event.
This approach offers you the f exibility to create
custom recruitment advertising campaigns best
suited to meet your budget and objectives.
| Learn More |
Visit: www.PennEnergyJOBS.com
Call: 1-800-738-0134
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