Pluto Project Puts Offshore LNG on the Map Saudi ... - OTCnet.org

www.OTC.com WEDNESDAY, MAY 8, 2013 

OTC2013 

SM 

OFFSHORE TECHNOLOGY CONFERENCE | HOUSTON, TEXAS 

| THE OFFICIAL 2013 OFFSHORE TECHNOLOGY CONFERENCE NEWSPAPER | DAY 3 

<strong>Pluto</strong> <strong>Project</strong> <strong>Puts</strong> 

<strong>Offshore</strong> <strong>LNG</strong> on the Map 

BY MARK THOMAS 

Western Australia has become the world’s No. 1 hot 

spot for offshore <strong>LNG</strong> mega-projects, with Woodside 

Energy’s US $15 billion <strong>Pluto</strong> deepwater gas development 

leading the way. 

e greenfield development in the Carnarvon Basin 

saw the Australian operator take it from initial discovery 

in 2005 to first <strong>LNG</strong> production in just seven years, a 

major achievement for a world-class project. 

According to 

Feisal Ahmed, executive 

vice president, 

technology, at 

Woodside, Australia’s 

first deepwater 

gas development 

features some significant 

firsts, including 

the longest 

gas well subsea 

tieback (210 km) to 

the onshore <strong>LNG</strong> 

Feisal Ahmed 

plant on the Burrup 

Peninsula, along with being the first <strong>LNG</strong> project to use 

pre-fabricated mega modules. It also saw the operator use 

only five big bore wells to feed the gas plant. 

e main source of the dry gas is the 5 Tcf <strong>Pluto</strong> field, 

with further reserves to come from the nearby Xena field, 

discovered in 2006 and which will be tied into the subsea 

infrastructure at a future point. 

“We are currently going through a basis of design 

process at present on that,” he said. Both fields lie in water 

depths of about 800-1,000 m (2,625-3,281 ), with the 

gas tied back to a 15,000 tonne fixed jacket riser platform 

sitting in 85 m (279 ) of water. 

Ahmed highlighted the current crop of major <strong>LNG</strong> 

projects under way in Western Australia, with seven having 

had a final investment decision for about 13 <strong>LNG</strong> 

trains. Other nearby <strong>LNG</strong> projects include the North 

West Shelf hub, the Wheatstone hub, the Gorgon hub and 

the recently confirmed Scarborough <strong>LNG</strong> project. “But 

<strong>Pluto</strong> was the first,” he said. 

e company recently shipped its 50th cargo of <strong>LNG</strong>, 

having delivered the first one mid-2012. 

Saudi Aramco Pushes 

for Breakthroughs 

n e company is expanding into chemicals, deepwater exploration, 

unconventional development, and nanotechnology, and is opening three 

US research centers. 

See PLUTO 

continued on page 3 

BY DARREN BARBEE 

Aer years of relying on outside know-how, Saudi 

Aramco is striving to bring technology in-house as 

it focuses on R&D to explore underground, undersea, 

and in reservoirs using robots one-thousandth the size 

of a human hair. 

e globally dominant oil company aims to change 

and re-engineer itself into a fully integrated energy and 

chemicals company. 

“Saudi Aramco is undergoing a major … transformation 

spanning every function of the company and including 

major new businesses,” Khaled Buraik, vice president 

of Petroleum Engineering and Development, Saudi 

Aramco, said at OTC 2013 on May 6. 

During Buraik’s three decades in the oil and gas industry, 

he has witnessed many positive developments in the 

quest to meet the increase demand for global energy. 

Yet, “as rewarding as all these moments have been, I 

must say that I consider the present moment to be the 

MOZAMBIQUE 

TACKLES TOUGH 

CHALLENGES IN 

DEVELOPING 

GAS RESERVES 

BY SCOTT WEEDEN 

Due to the recent discoveries of an estimated 170 

Tcf of gas-in-place offshore Mozambique, the 

government has decided to adapt and update all the 

legal papers and regulations for oil and gas development 

since <strong>LNG</strong> projects were not included in the 

original laws. 

“e Mozambique Petroleum Law, regulations, 

and exploration, production, and concession contract 

(EPCC) will all be updated,” Carlos Zacarias, minister 

of the National Institute of Petroleum in Mozambique, 

told participants in a topical breakfast on 

“Investment Opportunities in Mozambique <strong>Offshore</strong> 

Oil and Gas” at OTC 2013 on May 7 in Houston. 

Zacarias described the two main sedimentary 

basins currently being developed in Mozambique. 

e Mozambique basin in the southern part of the 

country is both onshore and offshore. e Rovuma 

basin in the north is shared with Tanzania. <strong>Offshore</strong> 

blocks are operated by Anadarko, Eni, Petronas, and 

Statoil. In total, about 150 wells have been drilled in 

Mozambique - 85 wildcat wells, 24 production wells, 

and 40 appraisal wells. 

“Mozambique joined the club of gas producing 

countries in 2004 with gas from the Temane field 

being sold to South Africa,” he continued. “In the last 

two years, we have had amazing gas discoveries in the 

Rovuma basin. ere have been 12 discoveries in a 

50-km (30-mile) radius.” 

e country’s reserves have gone from about 5 Tcf 

in 2009 to an estimated 170 Tcf in 2013. “Mozambique 

will become a major gas producer and exporter 

in the next 10 years. e main discoveries have been 

in areas 1 and 4. Other companies are still exploring 

other areas for more gas,” Zacarias said. “Our neighbor, 

Tanzania, has major gas discoveries and exploration 

is going on in Kenya.” 

Mozambique wants to take advantage of all of its 

gas and coal resources. e country is developing a 

gas utilization plan, which will address options for 

pricing structures and mechanisms for using the gas 

revenue stream for Mozambique. e plan considers 

using gas domestically for fertilizer, petrochemicals, 

See SAUDI ARAMCO continued on page 3 See MOZAMBIQUE continued on page 31

Editorial Director 

PEGGY WILLIAMS 

E&P Group Managing Editor 

JO ANN DAVY 

Executive Editor 

RHONDA DUEY 

Senior Editor, <strong>Offshore</strong> 

MARK THOMAS 

Senior Editor, Drilling 

SCOTT WEEDEN 

Senior Editor, Production 

JENNIFER PRESLEY 

OTC2013 

Wednesday, May 8 

SM 

7:30 a.m. to 5 p.m. ...................................Registration 

7:30 a.m. to 9 a.m. ...................................Topical/Industry Breakfasts 

9 a.m. to 10 a.m. ......................................Coffee 

9 a.m. to 5 p.m. ........................................University R&D Showcase 

9 a.m. to 5:30 p.m. ...................................Exhibition 

9:30 a.m. to 12 p.m...................................Technical Sessions 

12:15 p.m. to 1:45 p.m..............................Topical Luncheons 

2 p.m. to 4:30 p.m. ...................................Technical Sessions 

3 p.m. to 4 p.m. ........................................Happy Hour 

SCHEDULE 

OF EVENTS 

4 p.m. to 6 p.m. ........................................<strong>Project</strong> Management Networking Event 

Chief Technical Director, 

Upstream 

RICHARD MASON 

Associate Editors 

VELDA ADDISON 

MARY HOGAN 

Contributing Editors 

JOHN BRADBURY 

DOUG MARTI 

JOAO ˜ CARLOS PACHECO 

Corporate Art Director 

ALEXA SANDERS 

Senior Graphic Designer 

JAMES GRANT 

PHOTOS BY GARY BARCHFELD 

PHOTOGRAPHY 

Production Director 

& Reprint Sales 

JO LYNNE POOL 

Director of 

Business Development 

ERIC ROTH 

Group Publisher 

RUSSELL LAAS 

HART ENERGy LLLP 

President and 

Chief Operating Officer 

KEVIN F. HIGGINS 

Chief Executive Officer 

RICHARD A. EICHLER 

The OTC 2013 Daily is produced 

for OTC 2013. The publication 

is edited by the staff of Hart 

Energy. Opinions expressed 

herein do not necessarily 

reflect the opinions of Hart 

Energy or its affiliates. 

Hart Energy 

1616 S. Voss, Suite 1000 

Houston, Texas 77057 

713-260-6400 

main fax: 713-840-8585 

Copyright May 2013 © 

Hart Energy Publishing LLLP 

PLUTO continued from page 1 

e company’s use of big bore wells was a novel approach, although 

Ahmed says that the company only uses three to feed the 

plant, with the other two essentially acting as spares. e big bore 

wells in about 850 m (2,789 ) of water enable the company to 

achieve flow rates of up to 400 MMcf/d per well, which feed the 

4.3 MM tonnes per annum onshore <strong>LNG</strong> train via a 36-in. 

pipeline. 

Much of the project’s success in terms of scheduling came 

down to Woodside’s attention to detail, especially with regard to 

the pace of both the onshore and offshore work. “We really put 

a lot of effort into the coordination of the offshore and onshore 

pace so that we really would get startup on schedule,” said 

Ahmed. 

Woodside was also able to use its experience from its other 

<strong>LNG</strong> projects, such as its Angel project, where it also employed 

big bore wells to essentially get more gas from fewer wells. It also 

decided to use 7-in. expandable sand screens in the wells. 

Looking ahead beyond <strong>Pluto</strong>, Ahmed went on to flag up the 

company’s interest in both subsea processing and floating 

<strong>LNG</strong> solutions for future projects. “Subsea processing is the 

future, in many ways, and that’s what we will be pursuing. How 

SAUDI ARAMCO continued from page 1 

most exciting time in my memory of the oil industry at large and 

for Saudi Aramco specifically,” he said. 

Saudi Aramco is gearing up its research and development, incorporating 

nanotechnology to explore unconventional gas and 

investing in research centers in Houston, Massachusetts, and 

elsewhere. 

“We are pursuing R&D to bring out breakthrough achievements, 

not simply merely incremental enhancements,” Buraik said. 

Buraik said the company has an urgency and optimism about 

where it’s headed. It is striving to become fully integrated in gas production, 

including unconventional plays, refining and chemicals. 

Upstream technology in particular is an area where Buraik 

wants to break new ground. 

“At Saudi Aramco, we are pushing from a traditional role as 

buyer and consumer of technology to our own global technology 

and R&D strategy,” he said. “We envision becoming an enabler 

and center of new technologies in the business that we do.” 

e goal, ultimately, is the same. e company wants to develop 

its oil and gas fields to maximize reservoir performance 

and add to the value chain. However, time and money are now 

flowing to specializations such as geology, geophysics, drilling, 

production, engineering, and geophysical modeling. 

e company is striving to answer key questions crucial to its 

ambitions: “Can we acquire four times the data from seismic 

(readings) in 50% of the time, 50% of the cost,” Buraik said. Similarly, 

the company is striving to up reservoir recoveries, perhaps 

by 15% to 20%. 

Saudi Aramco is also continuing its reservoir nano particle 

program. e reservoir robots, or Resbots, move through water 

and into reservoirs to capture data about their makeup and may 

be used to increase recovery. 

much further beyond 200 km can we go? Can we go 300 km, 

even 400 km, and basically eliminate platform structures?” he 

commented. 

He also highlighted the company’s recent decision to change 

its plans for the Browse <strong>LNG</strong> project, also offshore Western Australia, 

in which it ditched plans for an onshore <strong>LNG</strong> plant and 

went back to the drawing board to consider other potential solutions, 

including a floating <strong>LNG</strong> option. 

“This project is 400 km offshore, and when it got to the 

costs we got to an end point where it was not feasible to proceed 

with that plan, which had three floating dry tree platforms. 

We are now going to recycle that and look at other 

technologies.” 

The company also has its 5 Tcf Sunrise <strong>LNG</strong> project in the 

Timor Sea currently under discussion. Woodside wants to 

use Shell’s F<strong>LNG</strong> technology for the project, like it is considering 

for Browse, and is hoping for a resolution to move it 

forward. 

It also has reached an agreement with Noble Energy and its 

partners to enter the Leviathan project offshore Israel in the eastern 

Mediterranean Sea. 

Woodside operates <strong>Pluto</strong> with a 90% interest, with its partners 

being Tokyo Gas (5%) and Kansai Electric (5%). n 

Perhaps most significant for Saudi Aramco, the company is 

producing the technology itself. 

“We have already conducted a major field test in house manufacturing 

of nano particles,” Buraik said. “is year we will conduct 

two major field tests. One will focus on enhanced reservoir 

characterization, the other enhanced recovery.” 

Saudi Aramco is also making a shi from its historic R&D 

focus on conventional oil and gas. 

“Now we are moving to a new frontier, which is the unconventional,” 

Buraik said. “e pursuit of the uncononventional 

gas is one of our most exciting new efforts. 

Saudi Aramco is focusing on areas in the Northwest, tight gas 

in the East and the Southeast. 

“Technology has revolutionized the industry,” he said. “Given 

our local infrastructure, the availability of water is also a challenge.” 

Research is under way for different water use. 

Technology has also come into play in the Red Sea, where 

Saudi Aramco is undertaking deepwater exploration. 

“In the past few years, we have completed seismic tests in the 

Red Sea,” he said. “Now we are drilling our first deepwater well.” 

But because the prospect is below a thick salt section, the company 

has adopted an integrated approach to exploration using 

seismic, electromagnetic, and high-precision gravity to better 

define the substructure behind the salt. 

To meet its technological goals, Saudi Aramco is embarking 

on investment in several research centers, including three in 

the US. 

The Houston center will span upstream disciplines while a 

Cambridge, Mass., center adjacent to the Massachusetts Institute 

of Technology (MIT) will several research initiatives, 

including nanotechnology. “Our resources are not unlimited, 

so when we cannot go alone we will collaborate and team up 

with others.” n 

OTC SHOW DAILY | MAY 8, 2013 | WEDNESDAY 

3

OTC 2013 Delegates Seek Subsea on the Seafloor 

BY RICHARD MASON 

At precisely 8 a.m. on Monday, May 6, the first delegates 

hit the beach at Houston’s Reliant Center as OTC 2013 

officially engaged. 

at initial wave exited busses, shuttles, pickups, and tens 

of thousands of four-wheeled landing cra to ambulate 

across a parking lot with more acreage than a modern shale 

play before weaving dely through bag inspection stations 

and a wall of registrars. 

Delegates queued up in long lines for coffee and, thus fortified, 

commenced the assault on an exhibition floor heavily 

buttressed on a foundation of perennial trade show optimism 

this year with West Texas Intermediate prices vaulting 

back above US $95. e international spotlight shined on 

the offshore sector in all its wondrous manifestations, from 

custom-manufactured bolts to the sophisticated subsea systems 

that are bringing the promise of deepwater oil and gas 

to an energy-hungry market. 

That assault soon coalesced around exhibitors displaying 

subsea equipment, proof that the conveyor belt 

of recent deepwater discoveries in the Gulf of Mexico, 

offshore West and East Africa, Brazil, and elsewhere 

will manifest in expanding order books for subsea vendors 

(and the bolt manufacturers that tie 

it all together). 

e large volume of delegates at the 

Cameron Schlumberger OneSubsea exhibit, 

a joint venture the two firms formed in November 

2012, verified the theme, as did 

standing-room-only crowds at the FMC 

Technologies theater. 

In fact several exhibitors, including National 

Oilwell Varco, hosted seated theaters 

this year, complete with the comfort food 

aroma of fresh popcorn and enough showing 

times to service the crowds at a suburban 

Cineplex. 

Other knots of delegates were found 

around exhibits featuring downhole tools 

that provide real-time formation evaluation 

during the drilling process as the industry 

expands the horizontal exploitation 

of tight formation plays onshore. 

A recurring offshore theme includes 

anything that will reduce nonproductive 

time (NPT), while onshore it is all about 

drilling efficiency. Both are opposite 

sides of a coin that suggest the industry 

will be doing much more with much less 

in the future. 

Steven Rodriguez, a programmer in the 

research and development division at 

Omrom Oilfield and Marine Inc., configures 

screens on the company’s driller 

console that features an integrated joystick 

system and touchscreen technology 

for controlling rig operations. (Photos by 

Richard Mason) 

Fortunately, the technology doctors 

have an arsenal of solutions to limit the 

capital debilitating effects of NPT. At 

Omron Oilfield and Marine Inc. one portion 

of the exhibit space was built around 

a multiscreened captain’s chair that featured 

two joystick controls on the arm 

rests and enough computer monitors to 

staff a trading floor on Wall Street. The 

chair serves as a high-tech driller’s console 

and integrates the hardware, electronic 

communications, and software that 

enable a driller to control a rig with a soft 

touch and enough real-time information 

to impress Star Trek’s Jean-Luc Picard, 

captain of the Starship Enterprise. 

4 WEDNESDAY | MAY 8, 2013 | OTC SHOW DAILY

Omron currently is building nine console systems, including 

one traditional DE-SCR electric system destined for 

Ecuador. e rest are earmarked for Tier I technology rigs. 

“Everything is custom today,” Martin Royse, Omron’s electrical 

design manager, said. “e customers tell us what they 

want, and we build it.” Omron also is creating efficiencies by 

reducing the number of cables that deliver information to 

the driller’s console without diminishing the flow of data 

from the rig to the driller’s eyes. 

e high-tech captain’s chair is replacing the standard 

floor brake handle and boxy metal console on conventional 

rigs, which features a confusing panel of push 

buttons, analog dials, and levers. e new 

chair is giving rise to the term “joystick rig” 

whenever contractors discuss the Tier 1 technology 

units that have become a standard 

part of horizontal drilling over the last 

decade. 

Brian DeCaires, (right) senior application engineer for 

Caterpillar Inc.’s global petroleum marine and petroleum 

power division, discusses emissions control technology 

with O. James Asehinde (left), an engineer with Entergy 

Services Inc. in Jackson, Miss., and Emeka Igboanugo 

(center), a Caterpillar marketing consultant from Peoria, 

Ill. The 3512E 2,500 HP engine meets EPA Tier 4 emissions 

standards and is designed to be included as a 

turnkey kit on hydraulic fracturing pumping units. 

See SEAFLOOR continued on page 46 

Matthew Crump, product line manager 

for Openhole Packers and Lower Completions 

at Weatherford International’s Well 

Completion Technologies division, 

demonstrates an open-hole sliding sleeve 

assembly that uses a single-sized ball 

and mechanical counters to trip the 

sleeve for hydraulic fracturing operations. 

Across the hall from Omron, Matt Crump, 

the product line manager for Weatherford International’s 

openhole packers, fielded questions 

from several teams of international 

delegates who were examining a mock-up of 

a ball-drop sliding sleeve on display at the 

booth. 

Sliding sleeves have become a breakthrough 

solution in extended-reach horizontal 

laterals over the last two years. e 

industry previously was limited to fewer than 

20 fracture stages using sliding sleeves because 

of limits on the decreasing size of individual 

balls used as the sleeve-activating 

mechanism. Several tool manufacturers have 

developed technologies to expand the number 

of downhole sleeves to roughly 40 stages 

currently. Sliding sleeves reduce costs and 

completion cycle time vs. standard plug and 

perf (PNP) methodology. 

According to Crump, about 20% of domestic 

horizontal wells are currently completed 

with sliding sleeves, which are 

commonly used in tight oil formations like 

the Bakken shale. But operators have used 

traditional PNP methods for isolating zones 

in dry gas basins like the Haynesville or Marcellus. 

In contrast to the US, in Canada sliding 

sleeves comprise nearly 60% of 

completions. 


5

Royal Delegation Visits OTC 

HART ENERGY STAFF REPORT 

Their Royal Highnesses Crown Prince Haakon and 

Crown Princess Mette-Marit of Norway visited OTC 

on Monday, May 6. e Norwegian delegation is celebrating 

the 40th anniversary of its participation at OTC. 

During his remarks at the annual awards dinner on Sunday, 

May 5, the Crown Prince noted that the relations between 

the US and Norway are strong and long-lasting. 

"In 1973, Norway was a very young oil and gas nation," 

he said. "e first large discovery in the Norwegian continental 

shelf had started producing only a couple of 

years earlier. At that time Norway had no experience in 

upstream oil and gas. US oil companies and contractors 

participated from the very beginning. 

"In 2010 it was our turn to assist the US. More than 30 

Their Royal Highnesses Crown Prince 

Haakon and Crown Princess Mette-Marit 

of Norway were escorted by OTC executive 

director Stephen Graham (second 

from right) and OTC chairman Steve 

Balint (right). (Photo by Gary Barchfeld 

Photography) 

Norwegian companies were involved in the 

response to the Deepwater Horizon oil spill in 

the Gulf of Mexico," he said. 

e Crown Prince pointed out that thousands 

of years ago, the Norwegian explorer Lief 

Ericson crossed the Atlantic, and in 1969 the 

Ekofisk field, the first commercial oil field in 

Norway’s part of the North Sea, was discovered 

by Philllips Petroleum. "So here we are: a Norwegian 

discovered America — at least that’s 

what we like to think — and an American oil 

company discovered Norwegian oil. I hope and 

believe that once again [OTC] will prove to be 

a valuable arena for exchanging new technologies, 

ideas, problem solving, and further develop 

international collaboration." n 

WORLEYPARSONS 

HOSTS PREMIER OF 

NEWFOUNDLAND AND 

LABRADOR 

The 

Honorable 

Kathy Dunderdale, 

Premier of 

Newfoundland and 

Labrador, made an 

official visit to the 

WorleyParsons OTC 

booth 1181 on Monday, May 6. 

Kathy Dunderdale became the 10th 

Premier of Newfoundland and Labrador 

in 2010. On October 11, 2011 she became 

the first female ever elected premier 

of the province, and the second 

woman elected to a premiership in 

Canada. Following her election to the 

House of Assembly as Member for Virginia 

Waters in 2003, Premier Dunderdale’s 

first Cabinet appointment was 

as Minister of Innovation, Trade, and 

Rural Development and Minister Responsible 

for the Rural Secretariat. In 

October 2008 she was appointed as 

Deputy Premier, as well as Minister of 

Natural Resources, Minister Responsible 

for the Forestry and Agrifoods Agency, 

and Minister Responsible for the Status 

of Women. n 


More Regulation Ahead For Industry 

BY VELDA ADDISON 

Predicting future action from the nation’s capital is not 

typically crystal clear, but one thing is certain: ere 

will be more regulation. 

The energy industry should expect rules concerning 

well control equipment, specifically BOPs, safety 

culture recommendations, and production system 

rules for operators in the US Outer Continental Shelf 

(OCS), according to Randall Luthi, president of the 

National Ocean Industries Association. Direct regulation 

of contractors – who could face penalties depending 

on the type of violation committed and 

associated level of harm and threat posed – also is 

forthcoming by the Bureau of Safety and Environmental 

Enforcement. 

Speaking on “Washington Politics: <strong>Offshore</strong> Consequences” 

during OTC 2013, Luthi told a crowd 

gathered May 7 that he believes overall production in 

the Gulf of Mexico will continue to pick up. And 

communication between regulators and the industry 

appears to have improved following the Deepwater 

Horizon accident. 

“I think the regulators have a much better understanding 

of what is expected, and industry has a 

much better understanding of what the 

federal regulators are looking for. is is 

being done through increased communication,” 

Luthi said. “I cannot underline the 

importance of the ability for industry and 

the regulators to communicate. e federal 

agency can only regulate the industry well 

if it understands that industry well.” 

Randall Luthi 

Meanwhile, in the US Congress several 

pieces of proposed legislation are making 

their way through the legislative process. 

Luthi spoke of an effort to increase the 

amount of revenue coastal states receive 

from offshore oil and gas development. 

He called the Fixing America’s Inequities 

with Revenues (FAIR) Act, proposed 

jointly by US Sen. Mary Landrieu (D- 

La.) and Sen. Lisa Murkowski (R- 

Alaska), a good thing but noted the 

government would have to come up with 

a way to make up the lost federal revenue. 

The act would give 37.5% off offshore 

revenue to the states. 

“Probably the best way to make up that 

lost revenue is to actually increase the 

areas that are available for offshore development,” 

Luthi said. “That could be the 

eastern Gulf of Mexico, … unlikely that 

it will be California. You could increase 

sales off Alaska. But that is one of the 

reasons that we think the FAIR Act is a 

good idea.” 

ose efforts could include opening the 

Atlantic Ocean to drilling. e move has 

been gaining support as government officials 

including governors in Virginia, 

South Carolina, and North Carolina push 

See REGULATION 



Curbing the Appetite for Stolen Crude 

BY JENNIFER PRESLEY 

Speaking to a sold-out lunch crowd, Andrew 

Yakubu, managing director for the Nigerian National 

Petroleum Corp., provided an update on West 

Africa Development at an OTC 2013 topical luncheon 

on May 6. Nigerian Minister of Petroleum Resources 

Diezani Alison-Madueke was unable to make the trip 

to Houston, citing the need to attend to pressing matters 

of state. 

Nigerian oil resources stressed 

As the largest oil producer in the region, Nigeria’s true 

potential is oen under fire by those within its borders. 

“Nigeria is richly endowed with oil and gas resources 

with over 25 Bbbl of proven oil reserves and 1.87 tcf of 

proven gas reserves,” Yakubu said. “It is projected using 

current industry trends that crude oil production will 

rise over 3 MMb/d and 10 MMcf/d by 2015.” 

In 2011, Nigeria produced about 2.53 MMbbl/d of 

total liquids, according to a report by the Energy Information 

Administration (EIA). This number is “well 

below its oil production capacity of over 3 million 

b/d,” the report said, with disruptions in production 

cited as the cause for the decline. The 

disruptions are due to pipeline damage 

caused by oil theft. 

Oil production began to decline in 2006 

due to increased violence from militant 

groups that forced companies to shut in 

production, according to the EIA. In late 

2009 the government declared an amnesty 

with the militants where weapons were exchanged 

for cash payments and job training 

opportunities. 

According to Yakubu, oil production is 

expected to rise as the government works 

to reduce oil the. “e industry has witnessed 

a significant drop in crude oil the 

by close to 50% since the Nigerian government 

began an amnesty program,” he said. 

Efforts are currently under way to “curb 

the appetite for stolen Nigerian crude.” 

“We’re employing scientific methods to 

trace our crude to its destination because 

we believe if there is no market for this 

crude, then there is no the,” he said. “In 

curbing the appetite for those that thirst for 

Nigerian crude, it will discourage those 

that come to steal it.” 

Nigerian refined products demand is 

also growing, Yakubu said, adding that it 

has almost doubled in since the late 1980s 

to near 25 million liters. “ere is no doubt 

there is a need for additional refining capacity, 

but there is no point in adding additional 

refinery capacity if we do not 

address existing assets,” Yakubu said. 

e four state-owned refineries have a 

combined capacity of approximately 445,000 

b/d, according to the EIA. Poor maintenance, 

the, and fire have prevented these 

refineries from being fully operational. 

Nigerian natural gas future 

At the end of 2011, Nigeria had an estimated 

180 Tcf of proven natural gas reserves 

according to the EIA. Yakubu noted 

that Nigeria has one <strong>LNG</strong> plant with plans 

in the works for two additional. 

“is will give the country a capacity of 

about 40 million tons of <strong>LNG</strong> annually 

when [the two plants] are completed,” he 

noted. “e long term plan is for Nigeria 

to become the gas hub for the region.” 

Lack of infrastructure in the oil fields for 

gas production and transportation has resulted 

in a significant amount of flaring. 

Yakubu addressed flaring concerns 

“e key players in the industry and the 

government have embarked on an aggressive 

gas flaring program,” he said. “Gas 

flaring has dropped to about 15% of the gas 

we produce. is is a significant step in the 

right direction.” n 


Emerging Markets Offer Economic 

Uplift for Local Populations 

BY RICHARD MASON 

Canada is prepared to pursue alternative outlets if the 

Keystone XL pipeline to the US Gulf Coast fails to 

win approval, while Petrobras seeks to double its size in 

seven years as Brazil become a net exporter of 4.2 

MMb/d of oil by 2020. 

Meanwhile, Angola is struggling to leverage the development 

of fossil fuels and renewable energy in a mutually 

beneficial arrangement with western firms to bring jobs 

and economic growth to its rural countryside. 

Representatives from all three countries spoke Tuesday 

to an overflow crowd at the panel, “Global Energy Outlook: 

Shaping the Future,” during OTC 2013. 

All three countries faced similar issues, though in 

widely divergent locales. ose issues include 

developing sizeable fossil fuel resources 

for global markets in remote or 

challenging areas while converting resources 

into a socially beneficial stimuli for 

economic development and improved 

prosperity for each country’s respective 

local populations. 

Maria das Gracas Silva Foster 

David Ramsay, minister of industry, 

tourism, and investment for Canada’s 

Northwest Territories, expressed his country’s 

frustration over lack of progress with 

the Keystone XL pipeline, which has become 

a focal point for environmental activism 

in the US. 

“If Keystone flounders and doesn’t get 

the necessary state and federal approvals, 

we will have options to put on the table,” 

Ramsay said in a prepared statement. “We 

are interested in the development of our 

own resources and getting those resources 

to market.” 

Possible outlets include a 1942 American-built 

pipeline from the Northwest Territories 

through the mountains to the 

Pacific Coast as well as an existing pipeline 

to neighboring Alberta. 

e size of the prize in the Northwest 

Territories, thanks to oil sands, shale oil in 

the Central MacKenzie River Valley, and 

natural gas in the Mackenzie Delta, is enormous. 

e Northwest Territories, a region 

twice the size of Texas with just 43,000 inhabitants, 

is a gateway to the Arctic where 

reserves in the Beaufort Sea rival those in 

the Gulf of Mexico, according to Ramsay. 

More than 16 Tcf of gas and 1.2 Bbbl of 

oil have been discovered in the Northwest 

Territories, and operators have committed 

US $1.8 billion in expenditures over the 

next two years to projects in the Beaufort 

Sea, the central Mackenzie River Valley, 

See EMERGING 



NOCs Rival IOCs 

in Today’s E&P 

Business 

BY SCOTT WEEDEN 

National oil companies (NOCs) have moved beyond 

the limited role these companies used to have. 

NOCs have learned from the international oil companies 

(IOCs) and “are now developers and operators of our 

own and overseas assets,” said Dato Wee Yiaw Hin, executive 

vice president, EP Business, Petronas. 

“NOCs are now truly global and integrated oil and gas 

companies. We have started to go overseas in competition 

with the IOCs. NOCs own 80% of global reserves,” 

he told participants at a topical lunch on “e Role of 

NOCs in the Energy Sector” on May 6 at OTC 2013. 

Petronas, for example, now has a very broad and diverse 

portfolio across 55 countries. e 

company produces about 2 MMb/d and is 

set to grow at a rate of 2.5% per year for 

the next five years, he continued. Petronas 

is an operator in 23 countries and has 60 

global partners. 

“Our domestic ventures are very vibrant. 

We have a very aggressive EOR program to 

increase production. In natural gas and 

<strong>LNG</strong>, we have projects in Canada and Australia. 

We expect to be producing 14 million 

metric tons per year overseas by 2020,” Dato 

Wee said. “Our upstream gas and <strong>LNG</strong> business 

is end-to-end, including drilling, producing, 

<strong>LNG</strong>, shipping, and marketing.” 

e company also has a position in unconventional 

resources such as shale oil 

and oil sands. 

As an NOC, Petronas supports the development 

of local skills and expertise to 

supply services to the oil and gas industry. 

“When we support the service industry, we 

see a 10-fold increase in economic activity 

in our country,” he explained. 

“We want to increase the presence of international 

service contractors in Malaysia 

in an effort to encourage the transfer of 

technology to the local companies. 

rough joint partnerships, we encourage 

international service companies to invest. 

We hope that through these partnerships 

the local service contractors can make 

moves to be a global service provider,” he 

continued. 

Spotlight Awards 

Draw Applause 

OTC 2013 recognized 15 new and innovative offshore 

E&P technologies during the Spotlight on 

New Technology awards at a special presentation on 

Monday. Steve Balint, OTC 2013 chairman, called the 

awards one of the highlights of the conference for 

showcasing the industry’s innovative spirit though new 

technologies. “Each provides a quick answer to the 

question of how can we find and produce oil and natural 

gas in even more remote, deeper, harsher, more 

difficult environments around the world in a safe and 

responsible way?” 

Spotlight Award Committee Chair Helge Hove 

Haldorsen compared the industry’s willingness to 

provide solutions to complex challenges to athlete 

Roger Bannister’s ability to break the 4-minute-mile 

barrier 59 years ago on May 6. “I think the 15 winners 

today are all kind of like Roger Banister in 

breaking that barrier and making what we’re doing 

in our industry better.” 

e awards process was very competitive, Haldorsen 

said, with a tremendous number of nominations this 

year. “We were very impressed with the entries and the 

range of technology that was covered,” he said. All 

award-winning technologies are less than two years 

old, innovative in design, and proven through fullscale 

application and address a broad need in the industry, 

he noted. 

For a complete list of the Spotlight Award winning 

technologies, visit the OTC 2013 website or see the 

Preview and Tuesday editions of the show dailies. n 

Dato Wee Yiaw Hin 

Petronas is able to grow its business 

strategies and operations without the restrictions 

of any government agency, he 

said. e company works on a commercial 

business model. 

“We believe this model allows us to 

work globally and in Malaysia. We are 

able to be treated equally with IOCs. We 

can be competitive and efficient,” Dato 

Wee added. n 


13

Steelmaker Tata Optimistic About 

More Business in the Gulf of Mexico 

BY DARREN BARBEE 

In March, Anadarko Petroleum Corp. generated buzz 

with the discovery of 1,000 net feet of oil pay in the 

Gulf of Mexico (GoM). 

Such discoveries can be worth billions, but in the deepest 

parts of the GoM the payoff happens only if the pipe 

is right. 

Companies such as Tata Steel, based in the United 

Kingdom, see the GoM as a key market, as it has been 

for years. And they like the prospects ahead. 

Activity in the GoM is promising and “we are optimistic 

it will continue, especially around the Keathley 

Canyon,” said Richard Broughton, commercial manager 

for pipelines and petrochemical at Tata Steel, one of the 

largest steel companies in the world. 

One of hundreds of exhibitors at OTC 

2013, Tata Steel recently completed a US 

$150 million project to provide pipe for the 

Discovery Producer Services L.L.C. (Discovery) 

gas pipeline in Keathley Canyon, 

in the GoM. Discovery is a 60-40 joint venture 

between Williams Partners LP and 

DCP Midstream Partners LP. 

Tata Steel supplied Discovery’s Keathley 

Canyon Connector with 214 miles of 20- 

in.-diameter submerged arc welded line 

pipe, weighing more than 110,000 metric 

tonnes, which was manufactured at the 

company’s mill in Hartlepool, United 

Kingdom. e pipe was laid at water 

depths of up to 7,380 – more than a mile 

down – and is designed to meet the specifications 

for deepwater conditions. 

“ere are some very good plays that are 

being developed at the moment in the 

Gulf,” Broughton said. “We’re quietly optimistic 

that something will come out of this.” 

At OTC, Tata Steel is showcasing its success 

in providing line pipe for deepwater 

conditions in the GoM, Brazil, the UKCS, 

and Russia, Broughton said. e company 

has won contracts based on the company’s 

tolerance control, enabling it to offer enhanced 

deepwater anti-collapse properties, 

easy fit-up, and fast lay rates. 

Tata Steel’s pipeline packages include 

double submerged arc welded (DSAW) line 

pipe, manufactured at the 42-in. mill in 

Hartlepool, which the company says is 

equipped with the strongest edge crimping 

and “O” press combination in the world. 

e process using hydraulics and not heat, 

Broughton said. 

Tata’s process enables the manufacture of 

thicker-wall DSAW pipes. Even in small diameter 

pipes, walls can be thicker to withstand 

the extreme collapsing pressures in 

the deepest waters. 

e company’s pipes range from 16 to 42 

inches in diameter, Broughton said. Tata 

can also manufacture for small diameter 

items, such as 16 to 20 inches. For instance, 

an 18-in. pipe with a 37-mm wall thickness 

“is very beneficial to deepwater developments. 

“e pipe has superb collapse resistance 

properties which is ideally suited for deepwater 

developments,” he said. 

For the Perdido Norte pipeline project, 

Tata Steel was the sole supplier of 18-in. 

line pipe for one of the deepest large diameter 

export pipelines in the world. e 

See STEELMAKER 



Indonesia Activity Ramps Up 

BY JENNIFER PRESLEY 

Winds of change are blowing in Indonesia as the 

country’s upstream industry shis from oil to natural 

gas resource exploration and development. At the 

OTC 2013 topical breakfast May 7 on “Indonesia: <strong>Offshore</strong> 

Economic Development,” H. Hardiono, executive 

expert to the chairman of the Special Task Force for Upstream 

Oil and Gas Business Activities (SKK Migas), provided 

the audience a brief glimpse into the country’s 

development plans for the coming years. 

Established by the government in 2013, SKK Migas is 

an institution assigned to manage the upstream oil and gas 

business activities under a cooperation contract. e main 

purpose of the institution is to ensure that “the exploitation 

of the state’s oil and gas natural resources will be able to 

generate maximum benefits and revenue to the state for 

the greatest welfare of the people,” according to its website. 

Shi in focus 

In opening his presentation, Hardiono noted that the 

country was on the precipice of great change as leaders 

there seek to answer questions like how to safely develop 

the vast reserves located in eastern Indonesia. 

“We are moving from the western to the eastern part 

of Indonesia for our exploration activities,” he said. In addition 

to the market shi, the country is turning more of 

its gas allocation from the export to the domestic market. 

“Indonesia contributes 19% of total Asian Pacific gas 

reserves and 1.3% of the world’s gas reserves,” Hardiono 

noted. Currently, total oil production in Indonesia in 

2012 was 974,000 b/d and gas production was 2,693 bcf 

with exports at about half or 1,366 bcf, according to the 

US EIA. “Our economic operating environment has 

changed so we changed up our production dynamic to 

support the growth,” he said. 

Active projects 

Currently, there are 18 major oil and gas development 

projects in the works, with 15 of the 18 focused on natural 

gas. Chevron, Indonesia's largest oil producer, has 

three projects in progress. According to the company, 

2012 net production in the country averaged 

158,000 boe/d and 236 MMcfd. e 

company operates in partnership with SKK 

Migas through production sharing contracts. 

Chevron’s Bangka field has two subsea 

wells producing from an estimated reserves 

of 143 Bcf, according to Hardiono. e 

Gehem hub features 11 subsea wells producing 

from estimated reserves of 932 Bcf. 

Hardiono featured in his presentation 

the Abadi gas field project that is located in 

the Masela Block in the Arafura Sea. e 

project is operated by Inpex Masela and 

will feature a F<strong>LNG</strong> unit. Initial production 

is expected to begin in 2016. And when 

Eni’s Jangkrik project in the Makassar 

Strait commences first production in 2015 

it will be from the 1.9 tcf in reserve. n 

EMERGING 

continued from page 12 

and the Mackenzie Delta, where the industry 

has been dealing with stranded natural 

gas for more than 40 years, Ramsay said. 

Further south in the western hemisphere, 

Brazil’s Petrobras faces significant 

challenges to promote the development of 

world-class resources, including adding 

another 17 offshore rigs to the 41 at work 

in 2013. 

“e government’s policies of inclusion 

are creating large demand for energy in 

Brazil,” Maria das Gracas Silva Foster, CEO 

for Petrobras, said. Brazilian energy consumption 

has increased at an average 2.5% 

per year, compared to 1.3% globally, while 

gasoline consumption in a nation that sees 

44% of its energy supplies generated by renewable 

resources is growing at 4.7% per 

year vs. 1.3% worldwide. 

Production from 17 presalt wells has 

reached 300,000 b/d since 2006. Petrobras 

will invest $236.7 billion over the next four 

years, including $137.5 billion in E&P. e 

goal is to double the size of Petrobras by 

2020 as Brazil closes in on production of 

5.7 MMb/d of oil with 4.2 MMb/d of oil 

destined for export. Petrobras would produce 

83% of the country’s output. 

e panel began with Jose de Vasconcelos, 

Angola’s minister of petroleum, who 

outlined the country’s intentions to participate 

in exploitation of its offshore resources 

“through the development of local 

content and training of Angolan technicians.” 

e country, which produced 1.7 

MMb/d of oil in 2012, hopes to become 

self-sufficient in energy in 2013. n 


Federal Policies Are Holding Back Energy Industry 

BY CAROLINE EVANS 

Six Republican governors, each a fierce advocate for 

jobs and industry, joined forces for a short time at 

OTC 2013 on Monday, May 6, to take aim at the federal 

government for what they say are policies designed to 

hinder the energy industry in their home states and 

American economic growth in general. 

Alaska Governor Sean Parnell told the sold-out room that 

“11.7 million Americans are unemployed. Are we okay with 

that? No. Are we satisfied with tepid economic growth? No.” 

He was joined in his sentiments by Texas Governor 

Rick Perry, Mississippi Governor Phil Bryant, Alabama 

Governor Robert Bentley, South Carolina Governor 

Nikki Haley, and North Carolina Governor Pat McCrory, 

each of whom sits on the Outer Continental Shelf (OCS) 

Governor’s Coalition, which advocates for oil, gas, and 

wind development offshore. ey were joined by Martin 

Kent, chief of staff to Virginia Governor 

Bob McDonnell, and Garret Graves, 

Coastal Protection and Restoration Authority, 

who reports to Governor Bobby 

Jindal of Louisiana. 

“We’re not in this to just get a massive 

amount of oil or gas or to harness the 

wind,” Parnell continued. “We’re in this to 

create opportunity for our people.” 

Most of the governors expressed a desire 

for shorter processing times, expanded offshore 

revenue sharing— which, according 

to the OCS website, only includes four 

states: Texas, Louisiana, Mississippi, and 

Alabama— and less interference from the 

federal government concerning natural resources 

management. 

“I think everyone has suffered from the 

seemingly endless wait on permit processing,” 

Perry said, later adding that the current 

boom in oil and gas production in the US 

is due to technological advances and “certainly 

not because of any federal policies.” 

McCrory singled out President Obama 

as the main impediment to his state’s energy 

advancement. “It’s not Congress. It’s 

our president,” he said. 

According to the Gulf Permit Index, the 

average federal approval time for new 

plans in March was 109 days. 

Haley remarked that the federal government 

should trust the states not only to recover 

their own natural resources, but also 

to care for their own communities. 

“Charleston, South Carolina was named 

the number one tourist destination in the 

world,” Haley said. “I’m not going to do 

anything that’s going to mess up the number 

one tourist destination in the world. 

We’re going to be overly careful.” 

Graves echoed this sentiment, pointing 

out that Louisiana has a large seafood industry 

that the state government hopes to protect. 

“We can have energy production and 

we can have a safe seafood industry,” he said. 

But in what could have become a federal 

government gab session, Bentley offered a 

more moderate view. “I don’t fixate on the 

federal government,” he said. “I fixate on 

what we can accomplish in our state.” 

And in comparison with Perry’s description 

of America’s dependence on foreign 

oil as “crippling,” Bentley offered a 

more optimistic view. 

“Our dependence on foreign oil is declining,” 

he said. 

Haley and Parnell also expressed optimism 

regarding newly appointed Secretary 

of the Interior Sally Jewell. 

“I do think she is willing to listen,” 

Haley said. n 

The <strong>Offshore</strong> Energy Development panel on Monday, May 6, focused on improving federal and state cooperation and 

featured (left to right) Governor Pat McCrory of North Carolina, Governor Nikki Haley of South Carolina, Governor 

Sean Parnell of Alaska, Governor Rick Perry of Texas, Governor Phil Bryant of Mississippi, and Governor Robert 

Bentley of Alabama. (Photo by Gary Barchfeld Photography) 


17

Norway Ramping Up the <strong>Project</strong> Pace 


Norway’s total recoverable petroleum resources are 

estimated at 13.6 Bcm of oil equivalents (at year-end 

2012), and it remains Europe’s largest oil producer and 

second biggest gas exporter. Recent estimates say it has 

so far only delivered about 40% of its expected total oil 

and gas resources on its continental shelf. 

But despite its mature years, the Norwegian sector has 

several major multibillion dollar projects in progress, 

bolstered both by new exploration successes in its mature 

areas, the opening up of its northern and arctic seas to 

new exploration, and the implementation of some truly 

ground-breaking subsea technologies. 

It also earlier this year launched its 2013 APA (Awards 

in Pre-defined Areas) licensing round, with an application 

deadline set for September this year and awards to 

follow in 2014. 

Interest in the country’s licensing rounds has picked 

up significantly following the succession of major projects 

and discoveries made offshore Norway, where finds 

such as the Aldous and Avaldsnes discoveries – now 

named Johan Sverdrup – hold up to 3.3 Bbbl of oil, which 

made it the world’s biggest oil find in 2011. 

is has also has helped to alleviate any concerns about 

the long-term future for the Norwegian sector, which remains 

one of the world’s largest offshore markets (with 

around US $220 billion in total offshore E&P spending 

forecast for the five-year period from 2013 to 2017). 

Apart from the giant Johan Sverdrup development, 

which is estimated will have a total cost of around NOK 

100 billion (US $17.54 billion), at least 14 other significant 

new projects are coming through, including Aasta 

Hansteen, which will be a pioneering first spar development 

for Norway, while Ivar Assen, Edvard Grieg, and 

Martin Linge will all be fixed platform-based. All have 

received their Final Investment Decisions and are proceeding 

on schedule. e pioneering Skrugard and Havis 

oil fields project (now renamed Johan Castberg) in the 

Barents Sea around 100 km north of the Shohvit field is 

also nearing approval. 

Statoil, as always, is involved in virtually all of Norway’s 

key projects including Johan Sverdrup. An FID on the 

field is planned for the end of 2013, with up to 12 further 

exploration wells to be drilled over the next three years. 

With the reservoir covering a 180 sq km area it is expected 

to feature multiple production and processing 

platforms as well as the innovative introduction of full 

electrification of the installations from shore – an initiative 

driven by the Norwegian Ministry of Energy for all 

future platforms on the NCS. 

e forecast capital expenditure for Johan Sverdrup’s electrification 

project alone is around US $1.5 billion. e field 

itself is expected to come onstream by the end of 2018. 

Another key technology soon to be 

added to Norway’s offshore tool box is the 

already well-established (elsewhere) Spar 

production platform. Somewhat surprisingly 

it is only now that a spar has been selected 

for the first time for use in its waters 

on the Aasta Hansteen field. 

Statoil has seized the opportunity and 

taken it further – the first Spar on the NCS 

will be the world’s largest (deck weight of 

21,000 tonnes; substructure weight 40,000 

tonnes), will be the first with gas condensate 

storage, and will sit in a water depth of 1,300 

m (4,265 ). e facility will be used to develop 

the field in the northern Norwegian 

Sea, where the rough weather and sea conditions 

and limited weather windows will 

make it one of the most challenging projects 

the operator has undertaken for some time. 

Statoil describes Aasta Hansteen as an 

“opportunity enabler,” with the facility 

planned to act as a hub for future developments, 

with built-in spare area and weight 

capacity, riser slots, and subsea tie-in connections. 

Gas processing capacity has been 

set at 812 MMcf/d. In addition the development 

will also see a 480-km pipeline 30 to 

36 in. in diameter stretch from the field to 

an onshore processing facility at Nyhamna 

in Norway. It is expected onstream in 2016. 

ese projects are not the operator’s sole 

focus, of course. It remains concentrated 

on unlocking the potential of its northern 

waters – and for those who think this is a 

recent trend, it’s worth pointing out that 

Statoil has been exploring in the Barents 

for more than 30 years and been involved 

in 88 out of the 92 wells drilled in the area 

in total. So its understanding of the hydrocarbon 

systems in the region is unmatched. 

e company will drill nine wells by the 

end of this year in its Barents Sea acreage, 

as well as tripling its Arctic technology research 

budget this year to NOK 250 million 

($43 million) compared to last year. 

e Norwegian Pavilion is located at 

booths 5031, 5041, 5055, 5129, 5141, 5155, 

5235, and 5241. n 

First Aid is located 

in the Medical Center 

in Reliant Center Lobby 

C, level 1, and in 

Reliant Arena 

Hall B 


Falklands’ Focus Back on Oil and Gas 

BY JOHN BRADBURY 

For the immediate future, the focus on the Falkland 

Islands and their offshore territory is all about oil and 

gas aer residents recently voted 99.8% in favor of remaining 

a British Overseas Territory. is was thanks to 

the breakthrough discovery made by Rockhopper Exploration 

in May 2010 when it confirmed its Sea Lion oil 

discovery to the north of the Falklands. e 14/10-2 well, 

drilled by the Ocean Guardian semisubmersible, turned 

a prospective energy future for the islands into reality. 

Logging at Sea Lion confirmed 53 m (174 ) of net pay 

in multiple zones with the thickest measuring 25 m (82 

). Following the discovery, Rockhopper embarked on a 

series of appraisal wells. Further drilling from April 2010 

to January 2012 resulted in seven successful wells out of 

10 drilled, with three oil and three gas discoveries. One 

Sea Lion appraisal produced 9,600 b/d on test. 

In 2011, Rockhopper declared that the 

Sea Lion main fan complex could contain 

between 608 and 1,279 MM bbl of oil in 

place across two licenses (PL032 and 

PL034) in the North Falklands Basin, 220 

km (137 miles) north of the Islands. 

Sea Lion is now estimated to contain 

contingent resources of between 194 and 

446 MM bbl, and adjacent discoveries at 

Casper and Casper South have increased 

contingent resources to between 225 and 

515 MM bbl. 

Current development plans revolve 

around an FPSO (floating production, storage, 

and offloading) vessel that would be 

moored in a water depth of 450 m (1,480 

) with associated gas to be used as a fuel 

or re-injected, and shuttle tanker oil offloading. 

Rockhopper, which until recently was 

the field operator, plans 22 production 

wells, plus 13 water injection and gas injection 

wells, to be drilled from three subsea 

drilling centers, using insulated flowlines 

and risers to take production to the FPSO. 

Gross plateau production is forecast at 

80,000-85,000 boe/d. 

Assuming the FPSO is bought rather 

than leased, Rockhopper says capital expenditure 

for the Sea Lion development 

would total around US $3 billion. 

By the middle of this year Rockhopper 

and its partner Premier – now the operator 

– aim to finalize the development concept 

for the field. <strong>Project</strong> sanction is 

scheduled for mid-2014, with first oil to 

follow in 3Q 2017. 

Continued on next page 

PHOTOGRAPHY, 

RECORDING 

REMINDERS: 

Still photographers may 

cover the exhibition floor 

without an OTC press 

representative 

Photographers must ask 

permission of exhibitors 

before shooting in any 

exhibition 

Audio and video recordings 

of technical sessions are not 

permitted 


Continued from page 20 

Attendees 

Engage 

Through 

Social 

Media 

BY ANTHONY DARBY 

OTC 2013 is in full swing and so is 

the conversation and engagement 

on social media platforms. With representatives 

from more than 110 countries 

and 2,700 plus exhibiting 

companies, what else would you expect 

from the world’s foremost event for the 

offshore industry? Check out the some 

of the popular conversations taking 

place online below. 

Facebook: It’s no question that Facebook 

is the hub for anything and everything 

OTC. When the photo of OTC Chairman 

Steve Balint sitting in an F1 racecar 

was posted to Facebook, even Balint 

joined the conversation, chatting with attendees 

and community members alike. 

www.Facebook.com/OTCevents 

Twitter: From food options to networking 

activities to technical sessions 

and beyond, #OTCHOUSTON is 

being used by attendees and exhibitors 

to share and communicate. Join us. 

www.Twitter.com/OTCHOUSTON 

YouTube: OTC-TV is on-site. Subscribe 

to our YouTube channel and view daily 

highlights, key interviews, technical session 

recaps, attendee reactions, and 

more. www.YouTube.com/eOTCvideos 

LinkedIn: Take your learnings and 

contacts with you aer you leave OTC. 

In our LinkedIn group, many attendees 

are taking advantage of the dedicated 

business networking focused platform 

by connecting with individuals they 

have met at the conference. Search 

“<strong>Offshore</strong> Technology Conference 

(OTC)” in the groups search field to 

join the community. n 

Market inquiries are under way among potential FPSO 

providers for either a conversion or a newbuild, Rockhopper 

indicated last month. Technical studies are ongoing 

to review crucial issues such as FPSO fatigue life 

for the South Atlantic, which is a particularly harsh marine 

environment. Mooring turret designs and offloading 

operability are also being studied. 

Concurrently, design studies are continuing for topsides 

and for using towed bundle installation for flowlines. 

Evaluation of contractors for a subsea Front End 

Engineering and Design study is also under way, and rig 

contractors are discussing development drilling options. 

Last October, Rockhopper completed the sale of 60% of 

its interests in its North Falklands Basin licenses to Premier 

for close to $1 billion. Premier became operator, involving 

an initial $231 million payment, an exploration carry of 

$48 million and a $722 million carry for development planning. 

For Premier, the deal meant a 51% year-on-year increase 

in reserves and resources from 513 to 773 MMboe. 

A search is now underway to find further Falklands reserves. 

Rockhopper’s future focus is on the evaluation of 

the Casper, Casper South, and Beverley prospects as potential 

Sea Lion tiebacks. 

“Several prospects with multiple targets are now considered 

to be drill-ready and locations are being developed 

to test these reservoirs utilizing the smallest 

number of wells,” Rockhopper disclosed last month. An 

invitation to tender for a rig is already under way. 

“We are working closely with the Rockhopper team to 

define the targets for the next exploration program, now 

expected in late 2014 or early 2015,” Premier disclosed 

in March. 

ere are plenty of other prospects as well, including 

Rhea, Chatham and Chatham South, Jason, George, 

Zebedee – mapped as being in communication with 

Casper South – and Jayne East. Chatham has been suggested 

as an early tieback for Sea Lion, aer it was encountered 

with the 14/10-1 appraisal well, which found 

a thin, poor quality reservoir, but with good oil shows, 

Rockhopper has indicated. “icker sands could be developed 

within the main channel system and Chatham 

would be a strong candidate for an early tieback to the 

Sea Lion FPSO,” the company suggested. 

Meanwhile, south of the Falklands, Borders and Southern 

Petroleum is pondering how to progress its 200 MMboe 

Darwin gas and condensate discovery, drilled in April 2012 

via the 61/17-1 well, which encountered a good quality 

reservoir with 67.8 m (222 ) of net pay and average porosity 

of 22%. Aer Darwin, BOS drilled the 61/25-1 Stebbing 

prospect. is was plugged and abandoned, ending its twowell 

program with the Leiv Eiriksson semisubmersible. 

is rig was then assigned to Falkland Oil and Gas 

(FOGL) for two more wells. Last September, FOGL confirmed 

its 42/07-1 Loligo well was a gas discovery, in the 

northern sector of the East Falklands basin. Gas was encountered 

over a 1,300 m (4,264 ) interval. Last November 

the 31/12-01 Scotia well encountered a 50 m (164 ) 

hydrocarbon-bearing interval with low permeability and 

a formation test failed to flow hydrocarbons. 

Borders and Southern Petroleum is seeking farmin 

partners for its southern Falklands acreage. The company 

has just completed acquisition of infill seismic 

data around Darwin, aiming for further drilling late 

2014 or 2015. n 


21

Intelligent Production System for 

UDW with Short-Hop Wireless Power 

CONTRIBUTED BY THE NATIONAL 

ENERGY TECHNOLOGY LABORATORY 

Aproject being conducted by Tubel LLC in partnership 

with the University of Houston and 

funded by the National Energy Technology Laboratory 

(NETL) seeks to develop a sensor and power deployment 

system for horizontal wells and lateral 

sections in ultra-deep water (UDW) to control and 

monitor hydrocarbon production. This next-generation 

system also can be used to provide power in 

lower completions to bring gauges near the perforations 

on an upper and lower completion well. The 

new technology will provide a unique method for optimizing 

multilateral well performance in a number 

of areas, including: 

Increasing the production of UDW oil and gas resources. 

Today a large portion of the wells drilled in 

ultra-deep water are multilateral wells, or they use 

lower and upper completions deployed separately. 

The inability to deploy hydraulic lines and electrical 

cables in laterals and lower completions prevents the 

use of intelligent completion systems in those laterals 

and lower completion strings, potentially reducing 

hydrocarbon production and reducing the production 

life of the wells since production is done with little 

knowledge of the production pressures, water 

movements, reservoir status, and hydrocarbon production 

sources in the well and laterals. Therefore, it 

is necessary to intervene in the wells using production 

logging tools to determine the reservoir and production 

status. These interventions are costly, 

requiring that the well is shut in and creating the potential 

for stuck tools. In addition, tools have to be 

deployed in the wells to open or close flow-control 

devices, a costly and potentially risky operation. This 

proposal outlines a next-generation intelligent production 

system (IPS) with ultra low-power modules 

and wireless power transfer. The system is deployed 

inside laterals in ultra-deepwater wells for remote 

production control, The IPS can also be deployed in 

lower and upper completions in deep wells. 

The IPS transfers power wirelessly from the mainbore 

into the lateral to power gauges, flow control systems, 

and communications modules. Short-hop 

two-way communication between the mainbore and 

the laterals allows for data and commands to be transferred 

between a remote location at the surface and 

the laterals. Ultra low-power gauges provide 

real-time status information on the 

reservoir and production, while multiple 

electrically operated flow-control systems 

manage hydrocarbon transfer from 

the reservoir into the production tubing. 

The system also will significantly reduce 

the completion costs and complexity due 

to the elimination of multiple hydraulic 

lines deployed in the well. Instead, single 

electric line will provide power and 

communications. The system also will 

reduce the number of penetrations required 

in subsea wellheads. 

Reducing the costs to produce UDW oil 

and gas resources. Some of the main 

areas of significant costs for the production 

in UDW include water production 

and processing, intervention in wells requiring 

production shut-in, and intervention 

risks associated with the 

deployment of equipment in the well. 

The IPS will reduce these costs since it 

will eliminate and/or delay interventions 

into the wellbore by controlling production 

remotely in the laterals as well as 

being able to reduce, delay, and sometimes 

eliminate the production of water 

to the surface. 

Increasing the efficiency of exploitation 

of such resources. The ability to monitor 

the reservoir and production tubing 

events and to remotely control the flow 

of hydrocarbons and water from the 

reservoir to the production tubing can 

significantly increase production efficiency 

and reduce the time required to 

identify problems in production operations. 

Improving safety and environmental performance 

by minimizing environmental impacts 

associated with UDW exploration and 

production. e ability to reduce the number 

of wells drilled and minimize the number 

of interventions in the well will 

positively affect the environment and increase 

significantly safety during the production 

of hydrocarbons. 

<strong>Project</strong> description 

The system will be composed of the following 

modules: 

1. A low-power electrically operated 

flow control system will open, close, or 

choke the flow of hydrocarbon from the 

reservoir into the production tubing. Multiple 

flow control systems will be deployed 

in the horizontal section of the well to divide 

the lateral into multiple zones and to 

Continued on next page 



equalize the pressure in the lateral. e equalization will 

allow for the production from all sections of the lateral 

instead of having the production coming primarily from 

the entrance of the lateral. 

2. An instrumentation system will be composed of 

the following sensors: 

a. Pressure gauge – This will provide pressure information 

from the reservoir and production 

tubing using a new micropower technology; 

b. Gamma ray detector – This will monitor water 

production since there has been some evidence 

that gamma activity in the formation increases 

with higher water production; 

c. High resolution quartz temperature sensors – 

These will provide a distributed temperature system 

throughout the lateral using micropower 

electronics and digital addressing; and 

d. Flow meter – is will utilize a small pressure 

change methodology to track fluid flow. e pressure 

detectors will be deployed in clusters where 

fluctuations in pressure generated by 

the flow in the tubing can be converted 

into flow measurements. 

3. A two-way communications system. 

All modules deployed in the laterals and 

mainbore will have a two-way communications 

module to allow for digital interface 

between the surface downhole 

for transfer of commands and data. 

4. Wireless power and communications 

transfer — is will provide power transfer 

from the mainbore to the lateral as well as a 

short-hop two-way data transfer to and from 

the lateral and the lower completion. e 

power transfer will allow for power to be 

available in the lateral for the operation of 

sensors and flow control systems to optimize 

production from the laterals and to stop the 

areas that produce water. Electromagnetic 

techniques developed over the past 18 

months will provide the foundation for wireless 

power transfer and communications. 

5. A power and communications 

mainbore system will perform the following 

functions: 

a. Receive commands from the surface 

via cable and transfer the commands 

via wireless electromagnetic 

wave short-hop communications 

into the lateral; 

b. Receive data from the laterals via 

short-hop communications and 

transfer the data to the surface via 

electrical cable; and 

c. Convert DC power from the cable 

into AC power and transfer the power 

from the mainbore into the lateral 

using electromagnetic technology. 

8. A surface system will generate the DC 

power and also send commands into the 

well via electrical cable. e system also 

will monitor data from downhole to the 

surface and decode, store, and transfer the 

received data to a remote location. 

Key deliverables associated 

with the project 

The development will allow for the construction 

of a system composed of the 

following modules. There will be two 

complete system prototypes manufactured 

for the project that will be used for 

field tests. 

1. Surface SCADA system for data acquisition 

and transfer as well as command 

issues; 

2. A mainbore wireless power transfer 

and control and communications system; 

3. A complete set of instruments to monitor 

reservoir and production status in the 

lateral such as micropower quartz pressure 

gauge, gamma ray detector, and flow measurement; 

4. A micropower, electronic-based flow control system; 

5. A wireless power and communications module 

for lateral installation; and 

6. A downhole cable splicer unit. 

Potential impact of the project 

The project will create the next-generation IPS to 

control horizontal and lateral sections of a wellbore. 

The system also will allow for gauges and flow control 

in the lower completion in wells with a permanent 

lower completion and an upper completion. The system 

will provide the following benefits: 

a. Decrease in the number of interventions in the 

wellbore; 

b. Optimization on the production of hydrocarbons; 

c. Minimization of the production of water; 

d. Full control of the laterals; 

e. Instrumentation of the entire lateral; 

f. Increase in the amount of hydrocarbons produced 

over the life of the well; 

g. Deployment of gauges closer to the perforations 

in lower completions for deep wells; 

h. Ability to power the lower completion from 

the upper completion to place gauges and control 

devices near the perforations; and 

i. Ability to reduce the number of penetrations in the 

wellheads by eliminating hydraulic lines control 

and utilizing a single electrical line in the well. 

Other participants 

The University of Houston will continue the research 

on the wireless power transfer and focus the research 

for the deepwater environment. The research will 

provide the following: 

1. Information on the distance and efficiency on the 

wireless transfer; 

2. Design of the coils for optimum transmission of 

power; and 

3. Wireless data transfer to and from the laterals. 

For further information, contact James Pappas 

(jpappas@rpsea.org). n 


23

COS Set to Arm Leaders with 

Good Safety Practices 

BY VELDA ADDISON 

The Center for <strong>Offshore</strong> Safety (COS), created aer 

the Deepwater Horizon accident put offshore drilling 

safety into the spotlight, plans to roll out its first good 

practice document within two weeks. 

Targeting leadership site engagement, the document 

will provide guidance on how senior and intermediatelevel 

leaders should plan their visits to field sites, rigs, or 

platforms, keeping in mind safety and environmental 

management systems (SEMS) to foster and develop a 

good safety culture. 

“This document is really about things to think about 

in preplanning your visit – what you’re going to talk 

about, what’s going on at that location, key SEMS elements 

that you want to ask about, what questions you 

might want to discuss to demonstrate your commitment, 

interest and level of understanding of SEMS in 

the visit,” Charlie Williams, the center’s executive director, 

said. It also helps leaders assess the location’s 

safety culture and how SEMS are being implemented. 

“It’ll be our first good practice document that we’ve 

completed.” 

His words came a few weeks aer the US Bureau of 

Safety and Environmental Enforcement released the 

SEMS II final rule. e rule mandates a third-party audit 

of SEMS for offshore oil and gas operators, encourages 

personnel to report violations, and promotes environments 

that empower field-level personnel with safety 

management decisions. 

e rules are meant to enhance the original SEMS rule 

– known as the Workplace Safety Rule – issued in October 

2010. at rule became effective Nov. 15, 2010. SEMS 

II includes three documents created by the COS concerning 

auditor certification, auditor qualifications, and 

how people will be accredited when they have their 

SEMS systems audited, Williams said. 

“e accident was really a wakeup call for the industry,” 

Williams said during a May 1 media briefing. “People 

that have ongoing safety programs have gone back 

and relooked at those programs [to determine] how they 

can make those programs even more effective.” 

Organizations and task groups formed with focuses on 

improving subsea containment, spill cleanup, well design, 

and well operational processes. As a result, new 

standards were written for the industry, Williams said, 

noting the center resulted from one of the groups. 

“As we … identify gaps and needs, we’re going to develop 

best practices to close those gaps and 

help the industry continuously raise the bar 

for safety,” Williams said. “We also have a 

mission to develop tools and help companies 

make their safety management systems 

even more effective.” 

Although SEMS-required audit results 

from the round are not in yet, Williams 

said he anticipates companies will want to 

enhance work in record-keeping and hazard 

analysis. “It is really fundamental to the 

process of identifying where you need to 

make barriers to major hazards. 

“Going forward, it’s about taking the 

good systems and making them better and 

taking the systems that are evolving and 

bringing all of these up to the same level,” 

he said. 

In the future Williams said he would like 

SEMS to include more on safety involving 

operator-contractor relationships. He also 

wants to see more emphasis in the document 

on human factors, or human behaviors, 

in safety culture. 

Among the biggest future offshore safety 

challenges over the next 10 years, Williams 

said, will be equipping staff, contractors, 

and operators with needed skills and 

knowledge to work safely with increasingly 

complex technology, particularly offshore 

and in deep water. 

“It’s key that the oil and gas industry continue 

to provide reliable and affordable energy 

from our domestic supplies, but 

obviously that has to be done and delivered 

safely and in a way that protects the environment, 

protects the public, and protects 

all of our stakeholders,” Williams said during 

the briefing. “It’s really the goal for the 

Center for <strong>Offshore</strong> Safety and the programs 

that we have to … continuously raise 

the bar of how we manage safety.” 

Williams spoke about the center and its 

purpose during a networking event Monday, 

May 6. He will address contractor-operator 

relationships and the importance of 

SEMS during a technical session today, 

May 8, and will discuss the future of SEMS 

on ursday, May 9. n 

OTC BRASIL 

2013 

October 29-31 

Rio de Janeiro 


Engineered Solution for Lost Circulation 

CONTRIBUTED BY SCHLUMBERGER 

Schlumberger is showcasing its Losseal family of reinforced 

composite mat pills, which are designed to 

reduce nonproductive time (NPT) caused by lost circulation 

during drilling and cementing operations. e pills 

are an engineered blend of fibers and optimally sized 

solids that create a strong impermeable grid to stop 

drilling or cementing fluids from flowing into permeable 

thief zones. e technology is suitable for a wide range 

of environments, including natural fractures, dolomite, 

and carbonate zones. It is suitable for deployment as a 

pill while drilling or in spacers ahead of cement slurries. 

e Losseal system can be designed to pump through 

bottomhole assembly nozzles as small as 10/32 in., eliminating 

the need to pull out of hole. 

Traditional lost circulation fiber materials have oen 

required information about fracture width for effective 

bridging and plugging. e Losseal design 

combines fibers with different mechanical 

properties and high solids content. is engineered 

design makes it less sensitive to 

fracture sizes because the particle size of the 

solids is optimized to plug the network 

fibers rather than the fractures themselves, 

so it can be applied effectively without the 

need for detailed formation measurements. 

e Losseal pill is a combination of flexible 

and structural additives that can plug 

natural fracture formations and fissures 

with a fracture width ranging from 1 mm 

to 5 mm. It is normally applied to nonreservoir 

formations. Placement can be 

done in circulation mode, and experience 

indicates that 30 minutes of soaking time 

provides optimal and sustained plugging 

performance, especially if some squeeze 

pressure can be applied. It creates an impermeable 

grid strong enough to withstand 

additional pressure from mud or 

cement density increases and any future 

drilling or cementing operations. 

An international oil and gas company 

encountered severe lost circulation problems 

while drilling a well in an unconsolidated, 

faulted formation in deep water 

offshore Malaysia. Drilling fluid was being 

lost through the unconsolidated and 

faulted zones in the tophole riserless section. 

Aer switching the fluid from seawater 

to heavier mud, no returns were 

observed at the seabed. e loss of fluid to 

the formation presented well construction 

cementing challenges because any fluid 

heavier than seawater could cause circulation 

losses and compromise the structure 

required to secure the BOP stack. Proper 

cementing was critical to ensuring that the 

casing and formation would support the 

weight of the wellhead, BOP, and riser. It 

also would allow the operator to drill the 

subsequent hole sections. 

Aer conventional methods of establishing 

full circulation proved to be ineffective, 

Schlumberger proposed Losseal W composite 

mat pills to plug the thief zones. In 

addition, CemNET advanced fiber technology 

to control losses was added to the 

DeepCRETE cement system. e Deep- 

CRETE deepwater cement slurry reduces 

waiting-on-cement time because it isolates 

the formation and rapidly develops compressive 

strength, even in cold deepwater 

environments. e CemNET fiber additive 

is engineered to an optimal size for sealing 

loss zones. It is an inert, reticular material 

capable of forming a network across the 

loss zone. e use of this fiber additive 

eliminated the cost of excess cement that 

Fluid returns to seabed and matching pressure profiles 

confirmed structural well integrity on the deepwater 

cementing project. (Image courtesy of 

Schlumberger) 

would otherwise have flowed into fractures, fissures, 

vugs, or highly porous zones. 

Fluid returns to seabed and matching pressure profiles 

confirmed structural well integrity on the deepwater 

Malaysia cementing project. e job pressure profile 

showed that the final displacement pressure met expectations. 

e engineered fiber technologies had controlled 

fluid losses, and top-of-cement reached the 

desired depth despite the loss of circulation prior to cementing. 

e combination of engineered fiber-based 

technologies in the spacer and cement fluids enabled 

structural casing support to be achieved. e treatment 

saved thousands of barrels of fluid during placement and 

reduced NPT caused by lost circulation. Compared with 

similar wells that had failed due to lost circulation problems, 

the oil and gas company reduced drilling time and 

avoided at least two days of remedial cementing operations. 

To learn more about solutions to lost circulation, 

visit Schlumberger at booth 4441 or go to slb.com/lostcirculation. 

n 


25

Boosting Rig Efficiency Through 

Tubular Management 

CONTRIBUTED BY WEATHERFORD 

In the ongoing search for technologies and services 

that improve safety and efficiency in offshore well construction, 

operators are increasingly focusing their attention 

on tubular running and handling. Historically one 

of the largest contributors to well costs, efficiency and 

safety enhancements in tubular handling programs are 

traditionally focused around rig floor operations, adding 

to rig time and increasing the risk of injuries. 

Weatherford’s tubular management service was developed 

to specifically address these efficiency and safety 

concerns by streamlining operations and taking as many 

tubular preparation and makeup activities off the rig 

floor as possible. e service also contributes to longterm 

well stability by ensuring that the integrity of each 

tubular joint is maintained at the highest 

level possible, from before it leaves the yard 

to aer it has been set at the desired depth 

in the wellbore. An outgrowth of the company’s 

tubular running services, the tubular 

management service is designed to 

reduce rig time and safety hazards with 

services normally applied at the rig floor, 

including inventory management, pipe 

cleaning and tallying, thread inspection 

and lubrication, offline makeup, and racking 

and transportation. 

One recent offline advancement in the 

service offering is the ability to make up 

two to three joints of pipe into a double or 

triple stand using bucking machines outfitted 

with torque/turn recording systems. A 

torque process control unit regulates 

makeup speed and provides the visual data 

required to comply with connection 

makeup parameters that ensure premium 

and API connection integrity. By reducing 

pipehandling and preparation at the well 

site, this service prepares tubulars in a more 

controlled environment to reduce the impact 

and exposure to the rig floor and its 

personnel without compromising connection 

integrity. 

This service was provided to save semisubmersible 

rig time on an extended 

deepwater exploratory program in the 

Gulf of Mexico. Single pipe joints were 

cleaned, inspected, drifted, doped, and 

laser-tallied onshore before being moved 

to a dockside location for bucking into 

doubles. The first pipe out of the bucking 

facility was a 5,182-m (17,000-ft) string 

of casing that was 14-in. by 13⅝-in. and 

was run in 26 hours. In the previous well 

a similar 4,267-m (14,000-ft) string run 

in singles required 41 hours. The 15 

hours of rig time saved by running doubles 

translated to a cost savings of nearly 

US $625,000. 

<strong>Offshore</strong> northwest Australia casing and 

running times aboard a semisubmersible 

rig were improved by running double joints 

rather than single joints. A bucking unit 

with torque/turn process control systems 

was sited at the operators’ onshore support 

base to make doubles of three sizes of tubulars 

– 9⅝ in., 7 in., and 4½ in. 

e tubulars were cleaned, inspected, 

and dried, and threads were cleaned and 

doped. e tubulars were then bucked into 

doubles, laser-tallied, and tagged. read 

protectors were reinstalled, and the tubulars 

were ready for shipment to the rig for 

installation. 

The operator estimated that running 

doubles saved an average of 4 hours per 

tubing running operation for a total of 32 hours, resulting 

in a savings of more than $1.6 million. In addition, 

preparing pipe offsite saved an estimated 

$400,000. 

In another six-well program the same operator installed 

a top-loading hydraulic mobile bucking unit onboard 

the rig for makeup and breakout of bottomhole 

assemblies such as hole openers and running and jetting 

tools. Compared to the alternative of using manual 

tongs at the rotary table, the system saved an estimated 

$6.9 million. 

Weatherford representatives will be available at booth 

413 in Hall B to answer questions and provide more information 

about how comprehensive tubular management 

services can drive safe operations and greater rig 

efficiency while helping to ensure well integrity. n 

One recent offline advancement in the Tubular 

Management Service is the ability to make up two to 

three joints of pipe into a double or triple stand. 

(Image courtesy of Weatherford) 


Tackling the Challenge of Local Content in Brazil 

BY JOÃO CARLOS PACHECO, ABS GROUP 

With the enormous reserves identified offshore 

Brazil, many international companies are looking 

to establish local operations. Having identified 

Brazil as a priority growth market, companies are setting 

up offices, facilities, and research centers to better 

access and serve the region. 

The main value of having a local presence is to allow 

international companies to increase their participation 

in the Brazilian market. Among other things, having a 

local presence allows foreign companies to interact directly 

with Brazilian companies and universities and 

provides a base of operations from which to recruit 

employees. 

For the Brazilian government the reasons for requiring 

local content cover a broad spectrum. Partnerships 

between Brazilian and foreign companies create an environment 

that fosters technology transfer, which can 

convey to local companies the knowledge they need to 

improve technology offerings that will result in their 

ability to better meet local demands. And it can provide 

training opportunities that have the potential to 

improve the skill sets of Brazilian workers. Another 

goal of the local content requirements is to boost local 

employment by creating new jobs. 

The Agência Nacional do Petróleo (ANP), the national 

petroleum agency, establishes and enforces local 

content rules. The rules, which are outlined officially 

in four administrative acts, include rules for local content 

certification, rules for entity accreditation for local 

content certification, rules for auditing certifying entities, 

and rules for local investment reports. 

While technicalities make meeting local content a 

complicated undertaking, foreign companies have no 

choice but to find ways to meet their obligations. They 

have to determine how they will establish their fabrication 

and construction plants in Brazil and fulfill the 

minimum percentage domestic content requirement 

for equipment, materials, and personnel. 

When it comes to navigating the requirements and 

securing certification, there is nothing more helpful 

than experience. Companies new to navigating local 

content requirements in Brazil are at a disadvantage if 

they are not familiar with the culture, are not attuned 

to the expectations of the population, and do not speak 

Portuguese. 

ABS established its first permanent office in Brazil 

in 1948 when it began providing services to the Brazilian 

shipbuilding industry and Brazilian shipowners. 

The company eventually added offerings for the offshore 

industry, which today is at the forefront of global 

deepwater development. ABS has established a local 

offshore research center to participate in and support 

this development. The Brazil <strong>Offshore</strong> 

Technology Center (BTOC) was created 

in 2010 and has a cooperative agreement 

with the Alberto Luiz Coimbra Institute 

for post-graduate and research studies in 

engineering at the Federal University of 

Rio de Janeiro (COPPE/UFRJ). 

Today ABS and ABS Group employ 

more than 300 people operating out of several 

offices all over Brazil. By investing locally 

and growing organically, ABS became 

deeply rooted in Brazil. When it became 

evident that local content requirements 

would be put in place, ABS Group had 

boots on the ground and was able to mobilize 

a local team that has pioneered 

processes that companies can depend on to 

achieve their certification needs. Since the 

formation of the local content department, 

the company has invested in expanding the 

team and bolstering infrastructure to increase 

support of a wide range of certification 

projects along the entire oil and gas 

production chain. 

To effectively meet local content requirements, 

companies that hope to work in 

Brazil need help from established, credible, 

and knowledgeable companies that know 

how to succeed in Brazil. ABS Group has 

been in Brazil for decades and is accredited 

by the ANP to certify companies to local 

content requirements. e company holds 

contracts for local content certifications for 

major large oil and gas projects, including 

the drillships and FPSO vessels recently ordered 

by Petrobras. n 

INTERNET/ 

COMPUTER 

ACCESS 

• Email stations are located in 

the Reliant Center Hall A 

entrance, level 1. 

• Free, low-bandwidth wireless 

internet access is available 

in the lobbies of 

Reliant Center, levels 1 and 

2, and the lobby of Reliant 

Arena. The network name is 

Free Internet. 

• Wireless access in the 

meeting rooms is available 

for US $12.95 per day. 


27

A Buoyant Market for Floaters 


All the evidence for the future of the floating production 

system (FPS) market supports the strong 

growth forecasts that abound. e industry’s deepwater 

momentum continues to grow, while the offshore sector 

as a whole is increasing its overall share of global oil and 

gas production levels. 

ere is a virtual conveyor belt of FPSs getting the go 

ahead, coming onstream, or being identified as an operator’s 

favored solution. Already in 2013 the industry has 

seen major projects progress including the Aasta 

Hansteen spar project offshore Norway, for which operator 

Statoil submitted its plan for development and operation 

in January; BP’s PSVM project offshore Angola, 

which began flowing first oil to its FPSO earlier this year; 

Petrobras’ Sapinhoá field FPSO Cidade de São Paulo in 

Brazil’s deep waters, which began flowing in January; and 

Inpex’s Abadi floating <strong>LNG</strong> (F<strong>LNG</strong>) development, which 

moved into the FEED stage. 

Statoil also unveiled its semisubmersible platform solution 

for its Skrugard development in the Barents Sea, Borders 

& Southern outlined its conceptual plans for an FPSO 

on the Darwin discovery offshore the Falkland Islands, 

and Shell confirmed its conceptual plans for an FPSO on 

the Stones discovery in the US Gulf of Mexico and a floating 

deepwater production hub on Appomattox. 

A spar platform has been 

chosen as Statoil’s preferred 

facility for its 

Aasta Hansteen development 

in 1,300 m (4,265 

ft) of water and will be 

the first spar installation 

offshore Norway. The 

plan for development 

and operation was recently 

submitted in January. 

(Image courtesy of 

Statoil) 

Pressure growing 

e pressure is growing on the relatively small number 

of floating production specialists to meet the challenges 

presented by the ever-more advanced technological demands 

of deepwater and ultra-deepwater projects and 

heightened environmental considerations. 

ere also are very real increased financial risks and 

challenging financing constraints for both leasing contractors 

and smaller E&P companies as a result of the 

global financial situation and the larger, more expensive, 

more complex facilities being required. 

In addition, according to a recent report on the sector from 

analyst Infield Systems, with FPS demand predominately 

being driven by countries in Latin America (essentially Brazil) 

and West Africa, significant local content requirements exist. 

is means construction companies are being increasingly 

challenged to create employment opportunities 

for the local work forces. According to Infield, 

over the short to medium term this may 

affect the capital cost and timeframes for floating 

platform developments. 

When it comes to floating platforms, it is 

predominantly FPSOs that are taking the 

lion’s share of the active market. In terms of 

total projects the FPSO is by far the favored 

solution of offshore operators, making up 60% 

of all current developments compared to the 

rival designs of semisubmersibles (19%), tension-leg 

platforms (TLPs, 10%), spars (7%), 

and others. 

Based on existing demand only, the FPSO 

sector is primed for solid growth in the coming 

years with a compound annual growth 

rate in the 5% to 7% range, according to SBM 

<strong>Offshore</strong>. Over the next three years it has forecasted 

that more than 60 FPSO project awards 

for both lease and sale units will be made for 

field developments globally. SBM itself is targeting 

around 20 of those, the company said 

in its latest strategic presentation. 

Unpredictable business 

e FPSO business is an unpredictable 

beast. Norwegian floater specialist BW <strong>Offshore</strong> 

has suffered sharply rising costs on 

its challenging conversion project on the 

FPSO P-63 facility destined for the deepwater 

Papa Terra heavy oil field offshore 

Brazil. It is currently forecasting US $450 

million to complete the engineering, procurement, 

and construction project, representing 

a substantial hike from the 

previous figure of $375 million. 

e problems are well known and have 

mainly been linked to increased engineering 

and steel replacement; completion of boiler 

systems; increased construction, procurement, 

and commissioning costs; and higher 

yard costs associated with the extended 

schedule. BW said the project had been delayed 

“as a consequence of increased work 

scope compared with initial plans.” 

Final integration work on topsides modules 

on the converted FPSO is expected to 

be completed soon, however, before the facility 

is installed on the field to start operations 

for Petrobras by July. 

Despite the company’s experiences, optimism 

still reigns. e outlook for the energy 

market in general and the FPSO 

business in particular remains good, BW 

said in its recent results presentation, with 

the number of FPSOs expected to grow significantly. 

ere are a large number of 

prospects and flat or slightly increasing de- 

continued on next page 


The BW Pioneer FPSO began producing oil and gas 

from the Cascade Chinook project in the Walker Ridge 

area for Petrobras America in early 2012. It was the 

first-ever FPSO used in the US Gulf of Mexico, has a 

disconnectable turret buoy, and sits in 2,500 m (8,202 

ft) of water. (Image courtesy of BW <strong>Offshore</strong>) 


mand in terms of contracts expected in the near term. e 

number of active competitors is still decreasing, and yard 

capacity also is very good due to lower ship building activity, 

the company added. 

Positive fundamentals 

Another market player, Fred. Olsen Production, 

also flagged the positive FPSO 

market fundamentals as a result of high 

global energy demand, sustainable oil 

prices, and a more consolidated supply 

side in its latest results presentation. 

However, new projects continue to be 

delayed. e company said that 2012 had 

the lowest number of FPSO lease contract 

awards since 2004, with only four new ones 

awarded and none awarded in 4Q 2012. 

<strong>Project</strong>s in West Africa remain very limited, 

but improved inquiry flow in the region 

and new mid-size discoveries by 

“bankable oil companies” toward year-end 

2012 indicate a long-awaited recovery of 

this market. Brazil is still dominated by 

megaprojects, with high local content requirements, 

while Asia has a steady level of 

activity with medium and small projects. 

e overall macro perspective remains 

the same, the company said: 

• e FPSO lease market is solid with 

growth predicted; 

• e number of contracts actually 

awarded continues to fall short of 

prognoses due to delays in awards; and 

• Excluding the “giga-projects” of 

Brazil and West Africa, the market is 

slow but steady. 

According to the latest data from analyst 

International Maritime Associates, there are 

235 FPS projects in the planning stage around 

the world. More than a quarter (27%) are in 

ultra-deep water of 1,500 m (4,921 ) and beyond, 

with 15% in water depths of 1,000 m to 

1,500 m (3,281 to 4,921 ) and 58% in less 

than 1,000 m (3,281 ). 

About 25% of the projects are in the bidding 

or final design stage, with a further 171 in the 

planning or study phase. e company forecast 

up to 192 floater orders over the next five 

years, averaging between 26 and 38 annually. 

A total of 73 floating production units 

are on order, with the backlog consisting 

of 44 FPSOs, seven production semisubmersibles, 

four TLPs, four spars, four 

F<strong>LNG</strong> units, and 10 floating storage and 

regasification units. In the backlog are 43 

units using purpose-built hulls and 30 

units based on converted tanker hulls. 

e number of planned projects also is 

growing. e amount in the planning stage 

is 12% higher than a year ago and 64% 

higher than five years ago. In November 

2011 there were 210 floating production 

projects in the planning stage, while a year 

earlier the figure was 194. 

$91 billion floater capex 

e forecast expenditure figures for the FPS sector as a 

whole are huge. According to analyst Douglas-Westwood’s 

latest report, between 2013 and 2017 a total of $91 billion 

in capex will be spent on these systems, representing an 

increase of 100% over the preceding five-year period. 

is growth is being driven by factors such as a larger 

proportion of newbuilds and conversions compared to redeployments, 

a greater degree of local content resulting in 

increased costs, and general offshore industry cost inflation. 

Floating production is a versatile solution that is firmly 

established as a cost-effective method for developing oil 

and gas fields, and in water depths beyond 500 m (1,640 ) 

it is one of the few options available to operators – an increasingly 

important factor as production moves into 

deeper waters. Douglas-Westwood forecasts that 63% ($58 

billion) of FPS market spend will be on deepwater projects. 

FPSOs easily represent the largest segment of the market 

both in terms of numbers (94 installations) and forecast 

capex (80%) over the 2013 to 2017 period. Semisubmersible 

production facilities account for the second largest 

capex segment of 10%, followed by TLPs and then spars. 

Driven by the industry’s need to access more offshore reserves 

to meet energy demand, FPSs remain a key enabler 

to access these resources. Despite the shorter term issues, the 

long-term outlook for this dynamic sector is buoyant. n 

is article first appeared in the March issue of E&P. 

BP’s converted FPSO is situated on the Plutao, Saturno, 

Venus, and Marte (PSVM) development in Block 31 offshore 

Angola, where the facility began initial oil production 

in January from Plutao. The FPSO is the first in 

Angola’s ultra-deep waters and will produce around 

150,000 b/d within a year. (Image courtesy of BP) 


29

Gaining USCG Approval for 

Fire-Suppression Equipment 

BY DOUG MARTI, TRELLEBORG 

OFFSHORE AND CONSTRUCTION 

While technological developments have revolutionized 

deepwater drilling and production in 

recent years, the need for high-performance, robust, 

and dependable solutions has never been greater. This 

is because in the harsh environments presented by the 

offshore world, the need for equipment to operate 

safely and effectively while providing peace of mind is 

paramount. 

Critical to delivering onboard safety is the fire deluge 

system, which, designed to protect areas where fire is 

likely to spread rapidly, is now commonplace on offshore 

facilities. While relatively simple in design and 

installation, its operation is essential for the safety of 

New rubber-based solutions for fire-deluge 

systems have been successfully used 

throughout the world’s offshore oil and 

gas regions in recent years. 

(Image courtesy of Trelleborg) 

onboard personnel, asset protection, and 

preventing event escalation. 

In the offshore oil and gas sector 

where the risk of rapid fire spread is 

greater than most, the fire-deluge system 

needs to provide full assurance to the 

onboard team that it will not fail to deliver 

on any critical firewater or utility 

piping installations. 

However, traditionally used carbon steelfabricated 

deluge systems are prone to corrosion 

when carrying saltwater, which can 

restrict or even block flow as rust forms, reducing 

the effectiveness of the system. is 

has resulted in the industry suffering from 

costly shutdowns, repairs, and, in the 

worst-case scenario, risk of failure in an 

emergency. 

As such, the industry has seen an increase 

in corrosion-free alternatives that 

prevent such issues and give peace of 

mind to the offshore oil and gas sector. 

This next generation of fire-deluge systems, 

which uses synthetic rubber instead 

of traditional materials such as 

rigid steel, titanium, copper-nickel, and 

fiberglass piping, has now been successfully 

installed and used in many regions 

across the globe. 

By using synthetic rubber, these systems 

are noncorroding and can withstand jet 

fires with a heat flux of 390 kW/sq m (36 

kW/sq ), temperatures above 1,400°C 

(2,552°F), and flame speeds that exceed the 

speed of sound. is makes it an ideal material 

choice for use in deluge and sprinkler 

systems on offshore oil and gas installations 

and ships as well as in other hazardous environments. 

Meeting regulation 

While these new solutions have been 

successfully used throughout the world’s 

offshore oil and gas regions in recent 

years, one area that has yet to benefit 

from them is the US Gulf of Mexico 

(GoM). 

is is because all offshore platforms, 

drilling ships, and FPSO vessels in this area 

must receive an approval from the US 

Coast Guard (USCG) before they can be 

installed, and currently approved piping 

products only include either metal or fiberglass 

systems. 


MOZAMBIQUE continued from page 1 

gas-to-liquids, power generation, methane, and <strong>LNG</strong>, 

he noted. 

ere will be a new bidding round aer the new petroleum 

law is enacted. Exploration areas will likely include 

deep water east of areas 4, 5, and 6, and new 

concessions off the southern end of the country. “In 

2014, we will make an announcement of the bidding 

round,” he added. 

Anadarko advances <strong>LNG</strong> project 

With about 3,000 km (1,800 miles) of coastline, 

Mozambique has a lot of offshore area to explore, said 

John Peffer, president, Anadarko-Mozambique. And, 

“the government has done a good job of providing a 

platform for investment. e country is politically and 

economically stable.” 

Anadarko announced its first discovery in December 

2009 and completed testing in January 2010. e company 

now has two major complexes to develop - Prosperidade 

and Golfinho - with 35 Tcf to 65 Tcf of recoverable 

reserves. at is more than enough for the first two 

trains of the Afguni <strong>LNG</strong> Park development. Anadarko 

will be working with Eni to develop what could eventually 

be a 10-train, 50-million-metric-ton-per-year <strong>LNG</strong> 

plant. If all 10 trains are built, Mozambique would be the 

third largest <strong>LNG</strong> producer in the world. 

“We are focused on Prosperidade, which would supply 

the 12 Tcf for the first two trains. e Afguni <strong>LNG</strong> 

Park would be built onshore near Palma. We are in the 

front-end engineering and design phase. 

“We have the gas resource and cost advantage in 

being a long-term, strategic supplier for premium markets 

in Asia,” he emphasized. “We can also supply markets 

in the Atlantic basin. 

“First cargoes are expected in 2018. We are submitting 

the environmental impact assessment (EIA) next 

week (May 13-17). We are now finalizing the translation. 

We are making good progress on the commercial, 

financial, and marketing sides of the project,” he continued. 

Anadarko recognizes the need for educating all the 

local constituents about how mega-projects are developed. 

at is one of the major challenges facing the 

company. “e government recognizes these projects 

take a long time and a lot of hard work before we get 

there,” Peffer said. 

However, the local communities have higher expectations 

for a more immediate impact from the development. 

“Anadarko continues to work to educate the 

communities. 

“<strong>LNG</strong> is the company’s first priority. We don’t have a 

domestic use clause in our existing EPCC,” Peffer said. 

Peffer did praise the government for its current 

EPCC. However, “there are a lot of changes happening. 

Some changes are needed. e government has a requirement 

in its constitution that provides consultation 

on any changes in the law. ey do listen even if they 

don’t act on the consultation. at is unusual in many 

governments. Change has created uncertainty. A stable 

See MOZAMBIQUE continued on page 46 

To be qualified for use in the region, 

products and systems must undergo the 

required testing for their category. It is 

only aer the successful completion of the 

required testing and aer all necessary 

drawings, specifications, and proof of a follow-up 

program have been received, reviewed, 

and approved by the USCG that a 

certificate of approval will be issued to the 

applicant manufacturer. e certificate is 

valid for five years, and the approval will 

be listed on the Internet for review and to 

act as guidance for offshore operators. 

The approval of new corrosion-free 

rubber-based solutions could mean a 

wealth of new opportunities in the GoM. 

With an estimated 3,858 active platforms 

and a total of 98 different companies 

with listed assets that use fire-deluge systems 

in the area, the USCG approval of 

an alternative offshore piping system 

would allow operators working in the 

area to easily and quickly increase offshore 

safety and provide peace of mind 

for the entire operation. 

Dated infrastructure 

e importance of new rubber-based solutions 

gaining USCG approval is further 

demonstrated by the high number of aging 

platforms that currently reside in the GoM 

and are in desperate need of upgrading in 

order to meet the new, extended lifetime 

of projects. 

Roughly half (more than 3,000) of the 

region’s oil and gas production platforms 

have been operating longer than their designers 

intended, with roughly one-third 

dating back to the 1970s or earlier, long before 

development of modern construction 

standards. 

This has a significant effect on safety 

since equipment is often severely 

degraded or corroded after so many 

years of use. This means that older 

structures are more prone to accidents, 

especially fires, and as such are much 

more dangerous for workers; platforms, 

which are subjected to extreme ocean 

currents, corrosive saltwater, and frequent 

hurricanes, are not mobile and 

cannot simply be brought back to shore 

for repairs. 

It is clear that across the GoM there are 

many aging platforms and rigs still in use 

that are in need of a reassessment of onboard 

safety equipment – in particular, 

the fire-deluge system – for the peace of 

mind of onboard teams now and in the 

future. n 


31

Meeting the Completion Challenges 

of Extended-Reach Wells 

CONTRIBUTED BY WELLTEC 

Cementing is the conventional completion solution, but 

advances in drilling technology are facilitating deeper 

and more complex well designs, rendering the capabilities 

of cement insufficient. In addition, the global demand for 

energy is increasing, calling for ways to enhance recoveries 

and exploit reservoirs that previously were not feasible. 

Swellable packers have emerged to become an accepted 

alternative completion method as installation 

times are significantly reduced; however, the degradable 

nature of polymers poses a risk in the typically harsh and 

unforgiving environment of a well. 

To overcome these completion challenges, Welltec has 

developed the Flex Well, enabling operators to construct 

a fit-for-purpose completion that may be as minimalistic 

or as intricate as needed to achieve optimal reservoir 

drainage. It is designed to deliver cement assurance, zonal 

isolation, and/or cementless completion in all types of 

well environments and allows long-term flexibility for future 

workover, sidetrack, and eventual well abandonment. 

Central to this new completion solution is the Welltec 

Annular Barrier (WAB). is is an all-metal expandable 

barrier with a large expansion ratio and can withstand 

high delta pressures (up to 10,000 psi) and temperatures 

up to 250°C (482°F). It addresses many of the inadequacies 

of traditional completion methods including swellable 

packers and provides lasting quality even in HP/HT environments. 

Because of inherent HSE advantages, higher reliability, 

reduced installation time, and the opportunity for 

early production, the capex associated with deploying 

WABs is lower than with conventional methods. 

A WAB is shown being run into the well. 

(Image courtesy of Welltec) 

e Flex Well concept offers increased recoveries and 

allows for multilateral well design and an 

unlimited number of zones across the 

reservoir. It can enable the operator to 

overcome current and future drilling, deployment, 

and production challenges by 

creating a complete, intelligent, extendedreach 

well with extreme reservoir contact 

capabilities. 

e WAB for cement assurance can be 

set in wet cement or at a later time in sections 

that are not cemented. It is installed 

as part of the liner or casing string and positioned 

at depths where cementing is 

deemed difficult. e liner (or casing) is 

hung off, and the cement operation is completed 

as usual. 

When setting in wet cement while the 

cement plug is being bumped, additional 

pressure is applied to the well to expand the 

WAB prior to curing. e hydraulic expansion 

extrudes the cement away, leaving 

only a WAB-to-formation contact and 

eliminating the risk of cement channels 

compromising isolation and of microannuli 

between the casing and cement. e 

relative high plasticity of the formation in 

comparison to the steel will ensure that 

steel-to-formation contact remains aer 

the release of the expansion pressure. Any 

cement trapped between the WAB and the 

formation will not experience relaxation of 

pressure when drilling mud is displaced. 

Removal of microannuli will deter the migration 

of fluid or gas behind the cemented 

casing and liners. 

When used for cementless completion, 

the WAB assembly is mounted on the exterior 

of the liner or casing, enabling a maximum 

diameter fullbore liner with rotational 

capability to be deployed. Aer setting the 

liner hanger and under surface control, the 

outer high-grade steel alloy sleeve is hydraulically 

expanded to contact and conform 

to the open hole while simultaneously 

working to harden the alloy. During the setting 

sequence, arrays of pressure-activated 

seals are energized against the formation, 

providing a hydraulic seal that allows the 

WAB to deliver a metal barrier with deltapressure 

capability across the entire borehole 

for the lifespan of the well. 

e WAB for zonal isolation has been developed 

in conjunction with a number of 

global operators to address the issue of completely 

compartmentalizing zones. It is critical 

to protect the zones from intrusive cross 

flow or the introduction of contaminants, 

which may be caused by cementing operations 

or the cement slurry itself. Cementless 

completion is a way to resolve this issue, 

safeguarding the lifespan of the well. n 


Modular Systems, Chemical Tanks 

Provide Solutions in the GoM 

CONTRIBUTED BY SWIRE OILFIELD SERVICES 

Swire Oilfield Services announced two new products 

for use in the Gulf of Mexico (GoM). Addressing the 

industry’s need for offshore work space solutions and 

more advanced offshore fluid storage and transport, 

Swire’s modular systems and compact SAFE Tanks will 

be on display at OTC 2013. e company is now expanding 

its product offering to the GoM region. 

e modular systems are made up of a comprehensive 

range of both pressurized and nonpressurized modules 

that can provide work space and storage solutions. Initial 

offerings in the GoM will include 4-m (12-), 5-m (16- 

), and 6-m (20-) pressurized offices along with 3-m 

(10-) and 4-m (14-) nonpressurized workshops. 

ese modules are structurally, mechanically, and electrically 

customizable. Each module offers the 

option to incorporate tailored internal specifications 

for use as offices, mud-logging units, 

labs, and control rooms. All customizations 

are made prior to shipping, which can minimize 

the need for onsite adjustments. A plugand-play 

design seeks to promote the highest 

level of operator safety while ensuring operations 

can begin immediately. 

Each module is certified and tested to industry 

standards prior to leaving the company’s 

facilities, including Det Norske 

Veritas standards 2.7-1 and 2.7-2 for pressurized 

units. ey are ATEX-certified and 

rated to the latest US Federal Trade Commission 

codes. e modules also incorporate 

designs that have been tried and tested 

in harsh offshore environments. 

ese modules span the full range of fire 

and hazardous area ratings and are built for 

operation in Zone I, Zone II, or safe areas 

offshore, which can allow clients to select 

appropriate designs based on circumstances 

and environment. All pressurized 

modules include redundant air-conditioning 

units. 

e SAFE Tank also is being introduced 

to the GoM region for the first time during 

OTC. e 1,000-gal-capacity compact tank 

is engineered to carry a full range of oilfield 

chemicals. 

By reducing the tank’s overall height to 

1.5 m (5 ) and making it fully operable 

from the ground level, personnel can check 

fluid levels and operate the vent and discharge. 

e tank’s design eliminates the 

need to climb on the unit to operate the 

tank or to check fluid levels. 

e product is designed to use more of 

the empty space in the frame. e lower 

height and slotted fork-liing pockets can 

minimize the chance of dropping incidents 

and can make stacking of the tanks easier 

and safer during transportation. 

To learn more about Swire’s Modular 

Systems and SAFE Tanks, visit 

swireos.com or stop by OTC booth 324 

(outdoor exhibit). n 

Modular 

systems can 

provide work 

space and 

storage solutions 

and are 

now being 

offered in the 

GoM region. 

(Image courtesy 

of Swire 

Oilfield 

Services) 

Event tickets may be 

purchased online or at the 

registration counters until an 

event is sold out. Once an event 

is sold out, a waitlist will be 

started and/or tickets sold 

at the door. 


33

Trelleborg and Saipem Join Forces to Launch 

Innovative New <strong>LNG</strong> Tandem Offloading System 

CONTRIBUTED BY TRELLEBORG 

Trelleborg has teamed up with leading oil and gas industry 

contractor Saipem to develop a new <strong>LNG</strong> tandem 

offloading system. 

Derived from existing and proven technologies, the latest 

development in cryogenic <strong>LNG</strong> floating hoses is set to 

become a key component in offloading systems for future 

offshore floating <strong>LNG</strong> (F<strong>LNG</strong>) projects. By enabling offshore 

transfer of <strong>LNG</strong> in tandem configuration, the cryogenic 

floating hose will pioneer a step change in the safety 

of this critical operation. is innovative system will also 

allow F<strong>LNG</strong> projects to be considered in harsher conditions, 

without excessive downtime due to offloading system 

availability, and with significantly reduced risk. 

Vincent Lagarrigue, marketing and project manager 

Trelleborg has teamed up with leading oil 

and gas industry contractor, Saipem, to 

develop a new <strong>LNG</strong> tandem offloading 

system. (Image courtesy of Trelleborg) 

within Trelleborg Industrial 

Solutions, commented: “e 

environmental conditions of 

the current F<strong>LNG</strong> locations 

are at present quite mild and 

only require the use of the 

most straightforward technology 

for the unloading of 

the <strong>LNG</strong>. But, with prospective 

new F<strong>LNG</strong> locations 

moving to sites where sea 

states, wind, and currents 

can be much more severe, 

this equipment isn’t enough 

and could result in plant 

shutdown. Tandem offloading 

solutions, which rely on the use of flexible 

hoses, are a viable alternative for the 

industry, which limit downtime and improve 

safety.” 

Tandem offloading, where vessels line up 

stern to bow, allows vessels to keep more 

distance between them, at 100 m (328 ) 

or more distance between F<strong>LNG</strong> and 

<strong>LNG</strong>C, and to cope with greater wave 

heights more easily. is highly limits the 

risk of collision between the two vessels 

and simplifies naval operations in approach, 

berthing, and residence. 

“As a key technical component of the 

tandem offloading solution, our cryogenic 

floating hose has been further enhanced to 

meet the parameters required for the new 

system,” Lagarrigue continued. “For example, 

the choice of a 50 cm (20 in.) inner diameter 

<strong>LNG</strong> hose was required as this 

enables operators to transfer <strong>LNG</strong> at least 

as fast as standard <strong>LNG</strong> loading arms on 

traditional jetties, for example, up to 12,000 

m 3 /h (423,776 3 /h).” 

e innovative <strong>LNG</strong> tandem offloading 

system from Trelleborg and Saipem uses 

three Cryoline <strong>LNG</strong> floating hoses, as well as 

a hose storage system, a connection head 

with a dedicated storage platform on the 

<strong>LNG</strong> terminal, and bow loading platform on 

the <strong>LNG</strong> carrier to provide a highly flexible, 

reliable, and durable alternative to traditional 

technologies such as marine loading arms. 

It is designed to operate in sea states with 

significant wave heights of up to 3.5 m (11.5 

) at connection and 4 m (13 ) during 

transfer and disconnection, even with non 

collinear wind or current directions. ese 

figures guarantee very good offloading availability 

in almost any location in the world. 

Trelleborg was responsible for the development 

of the 50 cm (20 in.) inner diameter 

cryogenic floating flexible hoses, while 

Saipem developed the offloading system 

and equipment to store and handle the 

hoses. Derived from existing and fieldproven 

technologies, Trelleborg’s new floating 

cryogenic hose is made up of several 

key components, including an inner cryogenic 

hose, an outer protective hose, an efficient 

insulation layer, and an integrated 

leak monitoring system. 

See <strong>LNG</strong> 



Steerable Drilling Liner Service Turns 

Trouble Zones into Pay Zones 

CONTRIBUTED BY BAKER HUGHES 

Operators are challenged with drilling more and more 

wells with stability issues. Depleted reservoirs bear 

the risk of heavy losses. Tar zones can result in torque increase 

(including potential twist-offs), and subsalt zones 

or other unstable formations may have already collapsed 

by the time the casing is run to secure the well. In a worstcase 

scenario the section may even be lost. All of these scenarios 

can result in substantial nonproductive time (NPT). 

Casing drilling was introduced to address most of 

these issues. State-of-the-art systems deploy wireline-retrievable 

pilot bottomhole assemblies with rotary steerable 

tools for directional control. However, casing drilling 

systems require modifications to the rig to allow the rotation 

of the casing, but using the casing as a drillstring 

and thus transmitting the drilling loads 

may induce additional wear and fatigue to 

the casing string. 

Service description 

e steerable drilling liner service combines 

a rotary steerable system with the liner to help overcome 

the challenges of drilling in zones with lower pressure 

and unstable shale and coal layers and in formations 

of varying flow and pressure regimes. Running the liner 

while drilling keeps the wellbore stable and eliminates 

the need to pull the drillstring to run casing. is can reduce 

risk and NPT and save the costs associated with 

contingency plans. Wellbore integrity is enhanced by 

drilling with the liner, leading to the smear effect, which 

reduces fluid loss and cuttings volume. 

Because the liner is isolated from the reamer shoe, the 

liner can be rotated at much lower rpm than the pilot and 

reamer bits. is design lessens the load on the liner, improving 

the fatigue life of the liner. 

To learn more visit Baker Hughes at booth 3731 during 

OTC 2013. n 

ARCTIC TECHNOLOGY 

CONFERENCE 

Save the Date: 

February 10-12, 2014 

George R. Brown Convention Center 

Houston, TX 

“The E&P industry event for arctic 

science and solutions” 

Call for papers deadline is June 13, 2013 

The SureTrak steerable drilling liner service 

makes it possible to drill in trouble 

zones while reducing the time and risk in 

drilling and completing a well. (Image 

courtesy of Baker Hughes) 

e Baker Hughes SureTrak steerable 

drilling liner service makes it possible to 

drill in trouble zones while reducing the 

time and risk in drilling and completing a 

well. e service drills, evaluates, and places 

a liner to total depth (TD) in a single run. 

Success in the North Sea 

e SureTrak service has been successfully 

deployed in offshore applications in the 

North Sea as well as onshore in the US and 

Saudi Arabia. In one case study, a North Sea 

operator wanted to isolate an unstable shale 

section that protruded into the reservoir. 

e well included multiple sidetracks that 

had been drilled to try and correct this 

same problem in the past. As a result, production 

had been limited due to “suboptimal 

placement of the wellbore close to 

gas-oil contact,” according to the case study. 

e operator directionally drilled 

through the formation using a 3-D rotary 

steerable system, an MWD/LWD service, 

and a real-time drilling optimization system. 

e steerable drilling liner service was 

then used to provide an openhole patch. 

e operation took less than three days, 

and the operator was able to reach optimized 

production levels in the area. 


35

PRODUCT NEWS 

Halliburton Introduces LockJar 

Multiconductor E-Line Jar, Enhancer 

Halliburton’s LockJar Multiconductor E-line Jar and enhancer 

can help avoid time-consuming and expensive stuck 

strings and fishing jobs in wireline logging operations. 

Available in 3.5-in. and 2.75-in. outside diameter, the 

hydraulic jar can be activated multiple times in multiple 

intervals to free a stuck tool string and preserve a logging 

run without costly delays. e hydraulic jar uses hydraulic 

time delay that overcomes the limitations of mechanical 

tools to maximize available force through surface pull. 

Unlike mechanical jars, the hydraulic jar can be triggered 

at any load above the preset lock, so greater maximum force 

is available for impact. is can allow full use of new wireline 

technology including high-strength cable and solid 

weak points and is critical in situations where stuck conditions 

are severe. 

All internal parts of the hydraulic jar are sealed and 

segregated from the wellbore, which can minimize wear 

on critical parts and increase tool reliability both as a data 

transmitter and power supply. 

e hydraulic jar can be run with an enhancer that increases 

the velocity of the hammer mass to yield a greater 

impact load while protecting the cable head by defusing 

any impact load moving upward. For more information 

visit Halliburton Booth 5225 or visit the company’s website 

at halliburton.com/wireline. 

Deepwater Pipeline Solutions 

Global demand for key energy sources continues to increase, 

and the search for hydrocarbons takes the industry 

into deeper and more difficult environments. Tata 

Steel’s products designed for hydrocarbon extraction and 

Thick-walled double-submerged arcwelded 

pipes in small diameters are able 

to withstand the extreme collapse pressures 

in ultra-deepwater environments. 

(Image courtesy of Tata Steel) 

distribution offshore strive to meet demanding 

offshore line pipe requirements. 

Tata Steel recently completed a US $150 

million (£100 million) project to provide 

pipe for the Discovery Producer Services 

LLC gas pipeline in Keathley Canyon in the 

deepwater Gulf of Mexico. Discovery is a 

60:40 joint venture between Williams Partners 

LP and DCP Midstream Partners LP. 

Tata Steel supplied Discovery’s Keathley 

Canyon ConnectorTM with 345 km (214 

miles) of 20-in.-diameter submerged arcwelded 

line pipe, weighing more than 

110,000 metric tonnes, which was manufactured 

at the company’s 42-in. pipe mill 

in Hartlepool, UK. e pipe was laid at 

water depths of up to 2,250 m (7,380 ) and 

is designed to meet the required specification 

for deepwater conditions. 

Tata Steel’s pipeline packages include 

double-submerged arc-welded line pipe 

manufactured at the mill in Hartlepool, 

which is equipped with the strongest edgecrimping 

and “O” press combination in the 

world. is enables the manufacture of 

thick-walled double-submerged arc-welded 

pipes in small diameters, which are able to 

withstand extreme collapse pressures in 

ultra-deep water. 

Tata Steel produces high-frequency induction 

(HFI) welded pipe for reel lay projects, 

which can allow for a shorter 

procurement schedule and superior ovality 

and wall thickness tolerance compared to 

that of seamless line pipe. is can lead to 

reduced costs at the design, welding, and 

installation stages. 

e company also manufactures and 

project manages pipe-in-pipe solutions for 

HP/HT pipelines, risers, spools, and bends. 

For more information, visit Tata Steel 

during OTC 2013 at booth 2173 or visit 

w w w . t a t a s t e e l e n e r g y . c o m / e n / 

news_and_events/events/Tata_Steel_at_ 

OTC_2013. 

Seal-Tite Highlights 

Expansion of Sealing 

Technologies 

Seal-Tite International is a US-based oil and 

gas technology company that provides leak 

repair services to the oil and gas industry. 

The company’s repair technology can be 


deployed in various applications, ranging from subsea 

connectors to wellhead leaks. 

As energy assets around the world mature, finding 

technological advances in well integrity to meet the 

ever-increasing demand for hydrocarbons is paramount. 

In recognition of this, the company has announced 

the expansion of its Engineered Sealing 

Solutions line with the asset-structured acquisition of 

Brinker Technology. 

By adding Brinker’s Platelet Barrier technology as 

well as other assets to its line of solutions for maintaining 

well integrity without the need for a rig 

workover, Seal-Tite is redefining current practices 

and assisting operators in meeting the growing demand 

and pressure for producing hydrocarbons. 

Each of the company’s products are in situ, pressureactivated 

sealing technologies field proven to significantly 

reduce the time and costs 

associated with locating and fixing leaks 

and getting wells back online, including 

wells in HP/HT environments up to 

22,000 psi and 343°C (650°F), respectively. 

The pressure-activated sealants are 

unique in that the pressure drop through 

the leak site causes them to polymerize 

to form a flexible bond across the leak 

site, while the remainder of the sealant in 

the system remains liquid. 

The time savings provided by the 

company’s products becomes clear when 

compared to standard methods of repairing 

(casing and tubing) leaks, which 

require some form of intensive intervention 

as well as a workover rig. This reduction 

in downtime adds significant 

value to the operator. Additionally, the 

low equipment footprint means the normal 

workflow is not disrupted. 

To learn more about Seal-Tite’s Engineered 

Sealing Solutions, visit sealtite.com 

or stop by booth 4046. 

Barge Master BV has installed Rexroth motion-compensation 

technology, which can neutralize waves and enhance 

the usefulness and safety of offshore cranes. 

(Image courtesy of Bosch Rexroth) 

the hull of the ship. By measuring the motions of the vessel 

and controlling the motion of the actuators, the cylinders’ 

movements can compensate for the waves. 

e remaining degrees of freedom – surge, sway, and 

yaw – are compensated by dynamic positioning of the 

vessel or traditional mooring systems. 

The launch of the Barge Master platform will allow for 

cranes weighing approximately 400 tons to operate in 

swells up to five times greater than allowed by current systems. 

“With Rexroth motion-compensation we have expanded 

the application window for the floating cranes – 

handling waves of up to 150 cm [59 in.],” van den Bos said. 

e Barge Master system is suitable for standard marine 

vessels and can reduce the manufacturing costs and 

operating expenses of offshore projects. 

For more information on the system contact 

drive-control@boschrexroth.com. n 

Motion-Compensation 

Platform for Stability in 

<strong>Offshore</strong> Crane Operations 

Barge Master launched the BM-001, the 

company’s first operational motion-compensation 

platform, in December 2012 to 

provide stability and safety to offshore 

crane operations. e moving platform 

uses a drive and control system from 

Bosch Rexroth to neutralize the roll, pitch, 

and heave caused by waves and can expand 

the uses for standard floating cranes. 

Crane stability has historically been a 

major challenge for offshore installation 

and decommissioning work because 

even small waves on the sea can produce 

major movements for the tip of the 

crane, which can endanger the crew. 

“Right now, standard floating cranes encounter 

difficulty with waves cresting at 30 

cm (12 in.). Safe crane operation can no 

longer be guaranteed,” Barge Master Director 

Jan-Paul van den Bos said. 

Working with Rexroth, Barge Master 

developed a solution to the problem, 

which includes all of the necessary drive 

and control components to compensate 

for movements in three degrees of freedom 

– heave, roll, and pitch. 

Special sensors deliver motion data to 

the system, which calculates how the 

platform must move to compensate for 

the action of the waves. Heave, roll, and 

pitch are compensated by three hydraulic 

cylinders that attach the crane to 


37

Investing in Brazil’s Economy, Local Workforce 

CONTRIBUTED BY SEMBCORP MARINE 

Sembcorp Marine continues to grow beyond Singapore 

with the construction of its first overseas integrated 

yard in Brazil, located in the municipality of 

Aracruz in Espirito Santo. Sembcorp Marine’s subsidiary 

Jurong Shipyard is undertaking the construction of Estaleiro 

Jurong Aracruz. 

The new yard is well positioned to serve the country’s 

thriving offshore oil and gas exploration and 

production sector with its close proximity to the rich 

oil and gas basin of Espirito Santo, one of Brazil’s 

giant presalt reservoirs. Planned facilities for Estaleiro 

Jurong Aracruz include a berthing quay, ancillary 

piping facilities, and steel fabrication workshops. 

Scheduled for completion by the end of 2014, the new 

yard will have the capabilities to undertake the construction 

of drillships, semisubmersible and jack-up 

rigs, platforms and supply 

vessels, FPSO integration 

and topside 

modules fabrication, in 

addition to the traditional 

services in rig and 

ship repairs, modification, 

and upgrade works. 

With the establishment 

of Estaleiro Jurong 

Aracruz, the company is 

well placed to partner 

with Brazil in its offshore 

fleet investment plan, 

which requires Brazilian 

local content for its exploration 

and production 

platform projects. Sembcorp 

Marine also can leverage Brazil’s 

strategic location near the oil and gas 

fields of the Atlantic, the Gulf of Mexico, 

and offshore West Africa, to capture 

emerging opportunities in these sectors. 

Nurturing talent for Estaleiro Jurong Aracruz 

Sembcorp Marine is investing in a series 

of scholarship and training programs to 

nurture the talents of the local Brazilian 

workforce at Estaleiro Jurong Aracruz. A 

key thrust of this workforce development 

drive is the Joint Educational Program. 

e program was developed in partnership 

with Brazil’s Instituto Federal do Espirito 

Santo (IFES) and Singapore’s Ngee 

Ann Polytechnic. 

The memorandum of understanding 

for the educational partnership was 

signed in April 2012 by the key stakeholders 

in the presence of the Governor 

of Espirito Santo, His Excellency Renato 

Casagrande. Under the joint initiative, 

Sembcorp Marine will be investing more 

than US $2 million over a period of five 

years to provide a valuable education 

through overseas training. 

A total of 23 promising IFES graduates 

from mechanical engineering were selected 

for the Joint Educational Program 

at Singapore’s Ngee Ann Polytechnic. 

Since arriving in Singapore in January, 

the participants have commenced a 

three-month technical English course to 

enhance their proficiency in the language 

and technical terms used in the 

maritime industry. This will be followed 

by a six-month specialized course where 

they will graduate with a diploma in Marine 

and <strong>Offshore</strong> Technology. The participants 

then will work at Jurong 

Shipyard for up to six months of on-thejob 

training before returning to Brazil to 

begin activities at Estaleiro Jurong 

Aracruz. 

Another key initiative under the Joint 

Educational Program is the “Train the 

Trainers” program, which aims to create a 

sustainable pipeline of marine and offshore 

engineering talents for Estaleiro Jurong 

Aracruz. As part of this initiative, lecturers 

from IFES will undergo a specialized 

course in Ngee Ann Polytechnic that will 

equip them with knowledge to develop a 

new marine and offshore technology 

course to further train the local talent pool 

in Espirito Santo. 

To learn more about Sembcorp Marine’s 

efforts in Brazil, visit the Singapore Pavilion 

at booth 9200. n 


INDUSTRY NEWS 

Petrobras’ Strategy for 

Deepwater Production 

Petrobras' executive manager for production engineering 

in exploration and production, Solange da Silva Guedes, 

spoke during the Global Deepwater Technology Development 

panel on Monday, May 6. Guedes highlighted the 

importance of integrating companies that operate in deepwater 

oil and gas fields with universities and suppliers for 

the development of offshore production technology. 

"e collaboration with universities from around the 

world, companies, and suppliers is something Petrobras 

is used to doing, and it has been very fruitful," said the 

executive, who discussed the opportunities for technological 

development that were created by the pre-salt discovery. 

"With technology, we have managed to produce 

300,000 barrels per day in the region aer only seven 

years aer its discovery."Among the pre-salt technological 

highlights, Guedes outlined the progress in 

the development of advanced solutions in 

reservoir characterization, well drilling and 

completion technologies, underwater 

equipment systems, the integrity of facilities, 

and CO 2 processing and treatment. 

Guedes said that Petrobras has partnered 

with other institutions to develop technologies 

with proven success, such as Procap, 

which made possible most of the solutions 

for the Campos Basin. "e first Procap was 

created to develop technologies for production 

in fields at water depths greater than 

400 meters," she said. "Today, the Procap 

Visão Futuro (Future Vision) seeks to anticipate 

the needs and to provide and improve 

the technologies." Procap is focused on 

technological solutions in oil and gas exploration 

and production and brings together 

more than 40 institutions from all over the 

world in the areas of logistics, reservoirs, 

sustainability, and well engineering. 

DeepStar, a joint project focused on the 

research and development of technologies 

for deepwater oil exploration and production, 

is the result of bringing together the 

world's most important energy companies. 

Joint projects such as DeepStar are very 

important for the company's technology 

development strategy because they accelerate 

the detection of solutions with reduced 

research and development costs, 

Guedes said. e company’s long-term 

technological strategy provides a strong 

cooperation between Petrobras and its 

main partners, contributing to technologies 

that ensure safe and efficient operations, 

she noted. 

Tesco Unveils Two 

Products at OTC 

Tesco Corp. (TESCO) unveiled two new 

products at OTC on Tuesday. 

TESCO’s newest top drive, HXI 150t, 

provides operators and end-users superior 

quality and run time. HXI 150t has a higher 

torque capacity than its competitors of 7315 

m/kg (24,000 /lbs) and a pull down capacity 

of 11340 kg (25,000 lbs), allowing operators 

the ability to reach total depth in 

extended reach horizontal wells. 

TESCO also introduced its Hydraulic 

Compact Casing Drive System (HCCDS), 

a compact, lightweight version of the company’s 

500-ton Casing Drive System. Replacing 

conventional power tongs, traveling 

elevators, and the stabbing board, the 

HCCDS allows circulation, rotation, and 

reciprocation of the casing to ensure it 

reaches casing point while improving cement 

bond and wellbore integrity. 

Aker Arctic Launches Oil Spill 

Recovery Icebreaker <strong>Project</strong> 

Aker Arctic Technology has introduced Aker ARC 100 

HD, the company’s heavy duty oblique icebreaker project 

for Arctic application. 

e ARC 100 HD includes new technical solutions for 

oil spill response, according to a news release. 

Formal launch coincides with the start of hull assembly 

work on the first vessel to be built to the ARC 100 concept 

for delivery to the Russian Ministry of Transport by early 

2014, Aker Arctic has reported. 

During OTC 2013, there will be an overview of the 

project’s objectives and the research behind it, an update 

on construction work at Kaliningrad’s OJSC Yantar 

and Helsinki’s Archtech yards, and insight into the 

concept’s maneuvering, ice management, and oil recovery 

capabilities. 

Rolls-Royce to Power 100th Drillship 

Following Latest Transocean Contract 

Rolls-Royce Plc has signed a contract to deliver drillship 

propulsion systems to Transocean. is latest contract 

will mark the 100th drillship to feature Rolls-Royce 

propulsion equipment. 

In recent months Rolls-Royce has secured orders to supply 

propulsion systems for seven new drillships totaling 

over US $100 million, including options, from a variety of 

customers including Transocean. ese ships will be built 

in the Samsung, Daewoo, and Hyundai shipyards in Korea. 

Rolls-Royce is the supplier of large thrusters to these specialist 

vessels, with a market share in excess of 70% globally. 

Drillships typically operate in the oil and gas fields off the 

coasts of Brazil, West Africa, and the Gulf of Mexico. 

See NEWS continued on page 44 


39

Using Robotics in Manufacturing 

Industry Equipment 

CONTRIBUTED BY ABB ROBOTICS 

The ABB Robotics business unit is highlighting products, 

systems, and technology designed to improve 

the quality and cost of manufactured products used in 

the oil and gas industry at booth 3917. ABB robots have 

been used in the facilities of a variety of oil and gas industry 

equipment manufacturers for applications including 

material removal, machine tending, welding, cutting, 

and assembly. Specific robotic functions range from the 

deburring of drill pipe and the packing of shape charge 

product used in well completion tools, to polishing ball 

valves and providing critical welds on blowout preventers. 

e precision and endurance of ABB robots help 

suppliers who manufacture products for both above- and 

below-ground and sea environments by reducing costs, 

Robots add speed and accuracy to manufacturing 

processes, and the oil industry 

is benefiting. (Images courtesy of ABB) 

improving product reliability, and meeting aggressive 

production demands. 

e primary ABB Robotics demo at OTC 2013 

is a machining cell featuring an ABB IRB 2600 

robot tending an Okuma Genos L200E-M lathe, 

using ABB Integrated Vision with a Cognex In- 

Sight 5100 Camera to locate the part for pickup. 

e simulation shows the speed and accuracy in 

which the robot moves a small pre-machined 

valve body in and out of the machining center. Enabled 

by ABB’s IRC5 Controller with QuickMove 

technology, the IRB 2600 completes the process 

up to 30% faster than comparable competitive 

robot models. e system also includes the new 

PC-based RobotStudio Machine Tending Power- 

Pac and the new controller-based RobotWare Machine 

Tending soware, providing significantly 

increased ease of programming and 

operation. 

“A prime feature of the Machine Tending 

PowerPac soware is the built-in support 

that allows robot programming to be 

done in a 3-D virtual environment on a 

PC, in or out of the office, without affecting 

production,” said Terry Crunk, machine 

tending specialist, ABB Robotics. “It 

makes the life of a programmer a lot less 

stressful, because a crash in the virtual 

world is a two-minute fix, while a crash in 

real time is going to be very costly and 

time consuming.” 

e list of the current applications in 

which ABB robots are used in oil and gas 

industry equipment manufacturing includes: 

• Welding, deburring, assembly, 

painting, inspection and machine 

tending of tubular and valve components; 

• ermal spraying and cladding; 

• Tool component hardfacing; 

• Traceability of parts through part 

marking; 

• Surface finishing; 

• Packing petroleum containers; and 

• Bag palletizing of bagged bulk 

powder product additives used in 

mineral and water exploration 

applications. n 

Robots can also lower costs and improve 

product reliability. 


INDUSTRY NEWS 


e propulsion systems are used to propel the vessels to 

and from drill sites and accurately maintain their positioning 

during drilling operations. eir high power and reliability 

is crucial in maintaining position and a drillship typically 

features six such thrusters. e thrusters are demountable, 

meaning they can which can be exchanged underwater, 

avoiding the downtime and expense of a visit to drydock. 

In addition to 100 drillships, Rolls-Royce has also delivered 

high-powered thrusters to 80 semi-submersible drilling rigs. 

Saipem Selects BMT for Riser 

Monitoring in Brazil’s Pre-Salt Fields 

Saipem has contracted BMT Scientific Marine Services 

(BMT), a subsidiary of BMT Group Ltd., to provide riser 

monitoring systems for two Free Standing Risers (FSHRs) 

and four Steel Lazy Wave Risers (SLWRs) 

for the Sapinhoá Norte and Cernambi Sul 

pre-salt fields offshore Brazil. 

ese systems will monitor the integrity 

of these risers by measuring strains, motions, 

attitude, and position of submerged portions 

of the riser strings. Each FSHR system will 

include BMT’s patent pending ROV-Serviceable 

Strain Sensor Assembly which allows 

users to service or replace individual 

sensors by ROV. BMT’s patented polypropylene 

welded attachment scheme for attaching 

strain sensors to submerged, insulated 

pipes will be employed on the SLWRs. 

BMT brings valuable experience to this 

project having supplied five Free Standing 

Riser Integrity Monitoring Systems since 

2007 covering a total of 12 riser towers, and 

two SCR monitoring Systems. e award 

complements BMT’s extensive order book 

that includes integrity monitoring systems 

for three riser towers in West Africa and two 

in Brazil as well as for eight SCR’s in Brazil. 

In addition, BMT has in various stages of delivery 

six Marine Integrity Monitoring Systems 

for Floating Production Units. 

BMT Group is exhibiting at OTC 2013 

in booth 2541-C in the EIC UK Pavilion. 

WorleyParsons To Host 

Technical Presentations 

A series of technical presentations will be 

hosted today, May 8, by WorleyParsons 

and its group companies, INTECSEA, 

Rosenberg, and DeltaAfrik at booth 1181. 

Topics will cover the companies’ engineering 

activities throughout the world. 

10 a.m. – Adjusting the Basis of Design: 

Why Engineers Need to ink, presented by 

Ken Arnold, 2013 recipient of OTC’s Distinguished 

Achievement Award for Individuals. 

Arnold, senior technical advisor for Worley- 

Parsons, has more than 40 years’ experience 

in engineering management and ownership. 

1 p.m. – Select: e Methodology that Adds 

Value in the Front-End for the Long-term. 

WorleyParsons Select is the specialist frontend 

division within WorleyParsons, focused on 

project viability assessment and development 

concept selection. Select supports decision 

making on critical front-end planning issues. 

3 p.m. – Asset Integrity Solutions: A Key Improve 

Differentiator by Mark McQueen, asset 

integrity solutions manager, INTECSEA. Experience 

in corrosion control and inspection 

methods of high-pressure transmission 

pipelines has enabled McQueen to assist 

many operators in meeting the ever-increasing 

demands of an evolving Integrity Management 

requirement through the implementation of new 

initiatives and adoption of continual process improvements. 

Produced Water Treatment 

Technology to be Launched 

Produced Water Absorbents Inc. (PWA) will launch its 

Osorb technology for the treatment of oil and gas wastewater 

streams during OTC 2013. 

Osorb is a regenerable media which removes up to 

99% of free, dispersed, emulsified, and soluble hydrocarbons 

and oilfield chemicals from water in both onshore 

and offshore applications, according to the company. e 

media, which resembles sand, has a high affinity for organic 

compounds and repels water. 

e technology can be applied in a vessel or canister 

Saipem riser monitoring in Brazil’s pre-salt fields 

(Image courtesy of BMT) See NEWS continued on page 44 


41

Majors’ Deepwater Push Is a Force for Change 


Numerous challenges are being driven by the push 

into deeper waters and more remote locations by the 

major operators, and the contractors are responding with 

innovative solutions. 

To a large extent contractors must respond this way 

since vessels need to be increasingly large to take care of 

the growing size, weight, and complexity of equipment 

such as subsea manifolds, spool pieces, seabed processing 

hardware, umbilicals, and power cables. ere also are 

more complex and sophisticated inspection, repair, and 

maintenance (IRM) and life-of-field requirements and 

the awareness that more suitable vessels will be needed 

for the growing likelihood of arctic developments. 

Challenges 

Shell, one of the biggest suppliers of business to the marine 

construction community, outlined the challenges it 

faces on numerous fronts in a recent presentation. According 

to Keith Smith, offshore installation manager for 

Shell International E&P, the company’s growing list of 

challenges on the technical front includes: 

• Mobilization and demobilization to and from 

remote areas; 

• Ultra-deepwater pipeline installation; 

• Ultra-deepwater subsea lowering capacities; 

• Seabed roughness conditions; 

• Metocean conditions such as wind, waves, and currents; 

• Installation of corrosion-resistant materials; 

• Welding and nondestructive evaluation of heavy 

wall pipe; 

• Seafloor equipment IRM; 

• Pipelay electrical trace heating; 

• Abandonment and decommissioning unknowns; and 

• Marine vessel assurance. 

Subsea 7’s Seven Oceans pipelay vessel worked for Shell 

offshore Brazil on its deepwater Parque das Conchas 

project. Shell said the industry still faces numerous challenges 

in the marine construction business as it pushes 

the boundaries with new projects in ultra-deepwater and 

harsh environments. (Image courtesy of Shell) 

Speaking at Quest <strong>Offshore</strong>’s MCE Deepwater 

Development (MCEDD) event in the 

Netherlands, Smith also highlighted other 

challenges including ice-class vessel capability, 

oil spill response in ice, winterization 

of vessels, environmental challenges 

(air/water discharge), remote area logistics, 

and technical integrity verification. 

Political and economic challenges such 

as local content requirements, project 

schedule pressures, and cost escalation also 

were flagged as significant issues. Unsurprisingly, 

commercial issues such as the 

availability of installation vessels, the competition 

for specialized installation equipment, 

the promotion of new (remote) 

technologies, and knowledge management/intellectual 

property were noted as 

challenges to be dealt with. 

Smith outlined what he described as the 

“deepwater funnel characteristics” of projects 

between now and 2017. In terms of 

water depth this is broken down as follows: 

• North Sea: up to 1,100 m (3,600 ); 

• Gulf of Mexico (GoM): 2,100 m to 

2,800 m (7,000 to 9,000 ); 

• Brazil: 1,800 m to 2,200 m (5,900 

to 7,200 ); 

• Nigeria: 1,000 m to 1,300 m (3,300 

to 4,300 ); and 

• Asia-Pacific: up to 1,000 m (3,300 ). 

General considerations varying by region 

included subsea pumping and compression, 

subsea heat exchangers, and the 

electrical heating of pipelines and flowlines. 

Ultra-deepwater considerations included 

shut-in tubing pressure of 13,000 psi to 15,000 

psi and wall thickness of 1.3 in. to 2 in. 

“Shell has numerous challenges in the 

marine construction business as we continue 

to push the boundaries. Some of our 

biggest challenges are in ultra-deepwater 

and the Arctic,” Smith said, adding that 

these have the potential “to drive changes in 

current marine construction equipment.” 

Added risks 

Among a number of company officials presenting 

at MCEDD was Jan-Pieter Klaver, 

CEO at Heerema Marine Contractors (and 

a former project engineer himself). He said 

the industry’s move into deeper waters, 

with rising contract values, came with 

added risks and technology challenges. 

In particular he raised the issue of materials. 

“We see the need for extreme material requirements, 

and the way to deal with this is 

to have rigorous testing programs,” he said. 

e sheer complexity of the new breed of 

projects is extremely challenging, Klaver 

added, highlighting the fact that the majority 


According to Shell, ultra-deepwater pipeline installation 

and subsea lowering capacities are just two of the 

challenges both it and its peers are facing offshore. 

(Image courtesy of Shell) 

of deepwater projects by the industry in the last 10 years have 

run over budget due to issues such as technical complexity, 

local politics, and experience. “Managing deepwater projects 

is like being a juggler with seven plates in the air,” he said. 

Klaver noted Heerema’s preparations for dealing with 

the market’s increasingly demanding requirements and 

the arrival later this year of its high-specification deepwater 

construction vessel Aegir, which will, 

among other things, have 2,000 metric tons 

of pipelay tensioner capability. 

Built at the Daewoo Shipbuilding and 

Marine Engineering (DSME) yard in South 

Korea, the 210-m- (689--) long, 46.2-m- 

(152--) wide vessel is now at the Huisman 

yard in Schiedam, Holland, where it will 

have a 4,000-metric-ton offshore mast 

crane and multilay pipelay system installed, 

tested, and commissioned. 

It is due to sail for the GoM for three 

weeks of testing in September before starting 

its first project in that area for 

Anadarko Petroleum. 

“e contracting community is able to 

respond to these developing ultra-deepwater 

demands and increasing project size. 

e challenge is to control costs, schedule, 

and quality,” Klaver said. 

Game-changers 

Ceona <strong>Offshore</strong>’s vice president of engineering, 

Vibor Paravic, told delegates that 

the company’s philosophy with its large 

newbuild construction vessel Ceona Amazon 

was essentially to overcome challenges 

such as logistics by essentially “taking the 

project with you.” 

In a “game-changers” session he outlined 

the newbuild’s planned role as a project execution 

vessel. e Amazon will be a state-ofthe-art 

multifunction dynamically positioned 

construction facility with large underdeck 

storage capacity for line pipe or umbilicals 

and a deck area of 4,600 sq m (49,514 sq ). 

is allows further storage of line pipe and 

standard flexible installation reels. 

e heavy-li vessel is being fitted with 

two 400-metric-ton heave-compensated 

masthead cranes and a single 30-metricton 

heave-compensated knuckleboom 

crane. e pipelay system, meanwhile, will 

consist of an inclined lay system with a top 

tension of 570 metric tons and a rigid 

pipeline firing line system. 

It will be able to lay rigid pipelines up to 

16 in. in diameter in up to 3,000 m (9,843 

) of water as well as flexible pipelines and 

umbilicals and install large subsea structures 

using one or both of its 400-metricton 

cranes in tandem li mode. 

It also will not need a spool base to support 

its operations, enabling it to operate in 

remote areas without logistical constraints; 

hence, its claimed ability to enable clients 

to “take their projects with them.” 

e Ceona Amazon will be 200 m (656 ) 

in length, having used a drill vessel hull, and 

will be able to carry up to 83 km (52 miles) of 

10-in. pipe or 40 km (25 miles) of 16-in. pipe. 

Client-driven solutions 

One of the major marine construction players, Subsea 7, 

highlighted the impetus for new vessels given by single 

clients. Dr. Stuart Smith, vice president of assets and 

technology, pointed out the same deepwater and remote 

trends affecting the industry. ere is a move toward 

larger vessels to deal with a larger subsea kit including 

not only manifolds and spool pieces but also the increasing 

weight and length of umbilicals and power cables. 

On top of this, vessels need to meet increased requirements 

and regulations for improved living and working conditions 

while also being able to deal with technical developments in 

varying pipeline and riser technologies such as higher pressures 

and temperatures and sour gas service. High performance 

pipe-in-pipe, lined pipe, and buoy-supported risers were 

just some of the technologies that were highlighted. “All the 

surface ships have to be capable of putting this lot in and connecting 

to all the different types of pipe,” he said. 

Last year Subsea 7 saw its Seven Borealis vessel come 

onto the market, which Smith described as representing 

a move into true engineering, procurement, installation, 

and construction project management. Another newbuild, 

the Seven Waves, is due for arrival in 2014 and was 

driven by just one client, Petrobras. 

Another new vessel, the Seven Viking, arrived earlier 

this year and is a life-of-field ship driven by another single 

client, in this case Statoil. 

“e industry is significantly expanding, and the contractors’ 

landscape continues to change as well. e introduction 

of new technologies will continue, and new vessels 

will continue to be introduced,” Smith concluded. n 

is article first appeared in the May issue of E&P. 

Heerema’s newbuild Aegir deepwater construction vessel 

will sail for the GoM in September for testing before 

starting work for Anadarko Petroleum. (Image courtesy 

of Heerema Marine Contractors) 


43

INDUSTRY NEWS 

NEWS continued from page 41 

or injected into the flow stream, then recovered and 

reused. Results are instantaneous and there is no significant 

loss of performance through its unique regenerable 

and reusable capabilities, the company said. It has 

demonstrated consistent capture ability in the presence 

of most oilfield chemicals, and can be used for cost-efficient 

and highly effective water treatment. 

During the past two years, the company has carried 

out a number of successful field trials in the US and recently 

ran its first international trial onshore in the Far 

East. e results demonstrated an average 96.2% reduction 

in oil in water from 85 ppm to 2.9 ppm. 

Before and after image of the instantaneous effect of 

Osorb on hydrocarbons (Image courtesy of PWA) 

Caterpillar to Feature 

Well Stimulation Pumps 

Caterpillar Global Petroleum is launching its Cat Well 

Stimulation Pumps for the well service market. Caterpillar 

is accepting orders for the Cat WS223, a 2250 bhp (1678 

bkW) triplex well stimulation pump, as well as the Cat 

WS255, a 2500 bhp (1864 bkW) quintuplex well stimulation 

pump. Caterpillar also will offer a variety of 8-in. and 

10-in. stroke fluid ends individually. A 2700hp triplex 

pump, available in late 2013, will be on display along with 

several fluid end models at the Caterpillar booth 3341. 

e Cat Well Stimulation Pumps feature fluid ends and 

power ends designed to an industry standard footprint. 

is will allow customers to easily fit the Cat 

pump into their existing trailer designs. In 

addition to the standard fluid end Cat will 

offer an Extreme Duty (XD) fluid end with 

superior durability for the harshest operating 

conditions. e fluid ends on both models 

have a valve-over-valve design to 

simplify valve, seat, and plunger installation. 

Gardline and OceanPact 

Announce Joint 

Venture Agreement to 

Expand Presence in Brazil 

Gardline Marine Sciences and OceanPact 

have established a joint venture and formation 

of a new company called Gardline Marine 

Sciences do Brasil S.A. e two 

companies will share their marine expertise 

and resources to pursue marine survey 

projects in Brazilian waters. 

Gardline Marine Sciences do Brasil S.A 

will focus on fully integrated survey packages 

including geophysical, hydrographic, environmental, 

oceanographic, and geotechnical 

surveys. e company will provide a wide 

range of integrated marine science services 

including 2-D seismic exploration, 2-D/3-D 

high-resolution data acquisition and interpretation, 

shallow gas hazard analysis, seabed 

mapping, shallow- to deepwater soil investigation, 

near shore and coastal surveys, water 

flow measurement, and water quality 

Expro Marks 40 years 

of Technology 

Expro is celebrating its 40th anniversary at 

OTC 2013 by showcasing its investment in 

new technology and innovation, according 

to a press release. 

Expro offers a wide range of products for 

well appraisal and testing. (Image courtesy 

of Expro) 


e company plans to launch the prototype HawkEye 

V downhole camera, the new HP/HT drillstem testing 

(DST) BigCat packer, and the Expro Annulus-operated 

Circulating and Test (ExACT) tool. 

e new HawkEye V downhole camera offers imaging 

capability and information to develop cost-effective remediation 

solutions for complex wellbore flow restrictions, obstacles, 

and reservoir management, Expro said in the release. 

HawkEye V features 149°C (300°F) capability, bi-directional 

side view rotation/scan (snapshot) in single degree increments, 

with enhanced quality picturing and soware. 

A range of Expro’s cameras, callipers, and logging tools 

also will be on show to assist in demonstrating the company’s 

global wireline intervention capabilities and its 

ability to offer BOP and riser inspection services. 

In addition, Expro will highlight its new DST BigCat 

packer, which provides a high strength, single-trip retrievable 

alternative to seal-bore packers in 

HP/HT well tests. e fully annulus-operated 

ExACT tool combines downhole shutin 

and circulating functionality. Rated at 

15K psi and temperatures of up to 232°C 

(450°F), ExACT features minimal, fast-cycling 

to position the ball and ports in the 

required position. 

Expro’s DST capabilities provide technology 

and specialist data services from reservoir to 

disposal to provide an integrated well test solutions 

package across the exploration and appraisal 

(E&A) phase of the well, the company 

said in the release. is includes tubing conveyed 

perforating, data acquisition, surface 

read-out through cableless telemetry, fluids 

sampling and analysis, compact well testing 

solutions, and enhanced flow measurement. 

For more information about Expro, visit 

booth 3933. 

Magma Global Gets Order 

for M-pipe Mud Boost Lines 

An offshore drilling contractor has placed an order for 

Magma Global’s m-pipe boost lines for deployment in Q4 

2013 on a deepwater drilling riser, the company announced 

in a press release. 

e deployment will be part of a qualification test to determine 

the suitability of m-pipe for use as riser auxiliary 

lines. According to Magma Global, the use of m-pipe for 

drilling riser auxiliary lines is expected to deliver benefits 

in terms of weight reduction and corrosion resistance. 

“We are delighted with this first application of m-pipe 

in a drilling riser configuration and believe m-pipe can 

deliver significant benefits for deepwater and HPHT 

drilling projects,” Magma Global's Commercial Director 

Steve Hatton said in the release. 

Magma will exhibit at booth 2641-L during OTC 2013. 

Sale of Gila Asset 

in Gulf of Mexico 

Petrobras has signed a sale and purchase agreement for 

the sale of the 20% stake the company holds in exploratory 

blocks KC 49, 50, 92, 93, 94, and 138 in the US 

Gulf of Mexico. ese blocks make up the asset known 

as Gila, and the operator is BP. 

Petrobras will receive US $110 million for the transaction 

and additional equity in an exploratory block adjacent 

the Tiber field, where Petrobras is already operating 

and has discovered reserved. 

is transaction is part of Petrobras' divestment program, 

outlined in the 2013-2017 Business & Management 

Plan, and is subject to third-party preferential 

rights and approval by the US Bureau of Ocean Energy 

Management. n 

JDR Marks Deployment 

of Subsea Umbilical 

Contract for CNOOC 

JDR reports it has deployed a range of dynamic 

subsea production umbilicals and 

ESP power cables for China National <strong>Offshore</strong> 

Oil Corp.’s (CNOOC) Liuhua 4-1 

field subsea tieback project. 

JDR designed and manufactured more 

than 42 km (26 miles) of ESP power 

cable, each incorporating nine power 

cores, delivered in three 14-km (9 miles) 

lengths. The order also included a 14-km 

(9 miles) main production control umbilical 

and a bridging manifold control umbilical, 

according to a news release. These 

umbilicals are operating in the South 

China Sea, at depths from 260 m (853 ft) 

to 300 m (984 ft). 

“We designed CNOOC’s umbilicals to 

maximize reliability, minimize project cost, 

and provide the customer with futureproofing 

options. For example, we produced 

the ESP power cables on our vertical 

lay-up machine (VLM) in Hartlepool,” Paul 

Gahm, JDR vice president of sales and 

marketing, said in the release. “is enables 

us to provide ultra-long length electric 

power cores, which significantly reduces 

the number of core splices required.” 

e main production umbilical is thermoplastic, 

designed for dynamic subsea environments, 

the release said. It incorporates 

a hydraulic control system to control subsea 

trees and deliver injection chemicals into the 

wellstream to reduce hydrate formation. 

Each ESP power cable includes three 3- 

phase power circuits, capable of serving 

three identical ESPs in this eight well field. 


45

SEAFLOOR continued from page 5 

REGULATIONS 


to open waters off their coasts to drilling, since the decision 

could give the economy a boost by creating jobs. 

e current five-year OCS leasing program for 2012 

to 2017 does not provide for lease sales in the Atlantic, 

despite the great potential that is out there, Luthi said. 

“It doesn’t look at new areas in the Atlantic, the Pacific, 

or even the eastern Gulf of Mexico. And it only provides 

for two sales off the coast of Alaska near the end 

of the five-year program.” 

e House-approved version of the five-year lease 

plan would have included 29 lease sales compared to 

the Obama administration’s 12 and would have opened 

the Atlantic to drilling, Luthi said. 

He pointed to a Huffington Post poll that showed 

58% of Americans favor offshore drilling. The same 

poll showed 50% of the respondents said they believe 

offshore technology was safe and that spills are 

rare accidents. A 2012 American Petroleum Institute 

poll indicated that 73% of voters would support increased 

offshore exploration, Luthi said. 

“e administration is not completely deaf to these 

kinds of numbers. ey are in the process of finalizing 

a programmatic environmental impact statement 

(EIS), which is one of the first steps you take in opening 

up a new area,” Luthi said. e EIS is for geological and 

Why the difference? 

“It’s market preference,” Crump said. “I don’t see 

any reason operators couldn’t be using sliding sleeves 

more.” 

Weatherford employs a mechanical counter that activates 

a sleeve aer a certain number of balls have passed 

through the mechanism. e mechanical counters enable 

sleeves to be activated with a single-sized ball. e 

company also is working on how those balls seat within 

the sleeve. Current designs can work with tolerances as 

close as one-sixteenth of an inch and still withstand up 

to 10,000 psi of pressure during the hydraulic fracturing 

process. 

Contractors may be seeking Tier I rigs, but they will 

soon be aer Tier 4 compliant engines as US Environmental 

Protection Agency emissions standards tighten 

for nonroad diesel engines over the next three years. Several 

Tier 4 engines were on display on the floor, including 

at the John Deere exhibit. A couple aisles away at the 

Caterpillar Inc. display, Brian DeCaires, senior application 

engineer, stood beneath a towering Caterpillar 

3512E, a 2,500-horsepower engine designed for hydraulic 

fracturing. 

Caterpillar now markets the fuel-efficient units as a 

turnkey package that incorporates factory-installed 

emissions equipment. e package, which includes large 

oxidation canisters on top of the engine, can be installed 

as a unit directly on the trailer. 

“Customers don’t have to mess with additional work 

to install the emissions equipment,” he said. 

Prosperity’s rising tide in the offshore sector is international. 

ere were more languages per square meter at 

Reliant Center than found in an aernoon’s stroll on the 

streets of New York. Multilingual delegates at OTC all 

communicated the same message, though: “Talk oil and 

gas nerdy to me.” n 

geophysical testing in the mid-Atlantic and south Atlantic 

and is due in 3Q 2013, although the date may be 

pushed to early February. 

“at is a first step. It’s a step that is necessary, but it 

could have mixed results,” Luthi said. “I fear without 

the realistic promise of a lease sale that the G&G [geological 

and geophysical] companies checking will not 

have a client which will buy the data.” 

While the move could be called progress, there 

are emerging threats to the industry. Among them 

is litigation. Luthi said that just about every part of 

the OCS is being impacted by litigation in different 

areas, including exploration planning and permitting, 

among others. But the biggest threat to shutting 

down offshore development is litigation 

involving seismic activities. His presentation included 

a short video by Oceana that aims to discourage 

the use of seismic airgun testing. The video 

highlights marine life with hopes that the Atlantic 

will not be opened for drilling. 

“at is the kind of PR we are up against in the offshore 

industry,” Luthi said. “<strong>Offshore</strong> seismic is the first 

step. We see the same types of attacks and concerns 

being raised about hydraulic fracturing. It is a campaign. 

It is something that we all need to be aware of. 

We all need to be able to find the facts and be able to 

tell our neighbors, tell our congressmen what the truth 

is and what the facts are.” n 

<strong>LNG</strong> continued from page 34 

e <strong>LNG</strong> tandem offloading system is currently undergoing 

a complete set of full-scale tests to ensure it 

qualifies for the EN1474-2 standard. Several reducedscale 

prototypes have been manufactured and tested 

since 2009 at ambient and cryogenic conditions in order 

to validate theories and demonstrate feasibilities. e design 

has already been validated by numerous characterization 

tests and qualification tests on 10 cm (4 in), 30 

cm (12 in.), and 50 cm (20 in.) internal diameter hoses. 

Since September 2012, an extensive qualification program 

has been underway for the 50 cm (20 in.) new <strong>LNG</strong> 

hose according to EN 1474-2 standard’s requirements including 

mechanical, thermal, and flow tests. More than 20 

tests will be performed, either destructive or non-destructive, 

at ambient and cryogenic temperature in order to 

qualify the technology under survey of Bureau Veritas. 

Several 50 cm (20 in.) prototypes will hence be tested in 

both static and dynamic conditions to demonstrate the 

suitability of a bonded flexible hose for <strong>LNG</strong> transfer applications. 

In particular, a fatigue test will be completed on 

full-scale prototypes to prove that Cryoline <strong>LNG</strong> hose 

withstands recurrent dynamic loads for long service life. 

e qualification of the 50 cm (20 in.) <strong>LNG</strong> hose is expected 

to be completed late in 2013. n 

STEELMAKER continued from page 14 

depth of the pipeline, coupled with severely undulating 

seabed, made it a challenging project. In all, about 194 

miles of line pipe was delivered in thicknesses ranging 

from 19.1 mm to 27 mm, dimensions the company says 

are “well beyond the production capabilities of most 

UOE mills.” 

e company is also working to meet the needs of expensive 

offshore assets. Such costs are huge, “so they can’t 

afford to be sitting idle. ere’s a lot of effort in this project 

to make sure we deliver in some very tight tolerances.” 

And the company can churn out high-quality pipe. For 

a 190-mile project in the Keathley canyon, for instance, 

the company can manufacture in excess of 9 miles of pipe 

per week. “It’s fairly quick,” Broughton said. 

Broughton said Tata Steel applies decades of experience 

to deliver strong, reliable, and innovative pipeline solutions 

for challenging and complex projects around the 

world. e company is working in other areas to bring its 

unique pipelines to undersea projects. 

“It’s not just the Gulf of Mexico. We’ve got farther 

south,” he said. “We do a lot of deepwater 

developments in the salt basins off the 

Brazilian coast.” n 

MOZAMBIQUE 


legal framework is needed for projects this 

size,” he added. 

Mozambique is more engaged on capacity 

building than on revenues from the 

<strong>LNG</strong> project. “ey are totally focused on 

capacity building for the country - more 

technical training, skills, and jobs. at is 

their biggest focus,” Peffer said. 

Anadarko faces quite a few challenges in 

developing the project in Mozambique. 

e EIA has taken more than two years to 

complete. Logistics is a big challenge. “If 

we don’t bring it, we won’t have it,” he 

noted. “ere are limited skilled workers 

available. You can find trained workers in 

the capital, Moputo. A few skilled workers 

are available in Pemba. In Palma, they are 

non-existent. 

“In the end, Mozambique is an attractive 

place to invest. It will be transformational 

for Mozambique,” Peffer concluded. n

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