Tài liệu THE OFFICIAL 2013 OFFSHORE TECHNOLOGY CONFERENCE NEWSPAPER pdf
Bạn đang xem bản rút gọn của tài liệu. Xem và tải ngay bản đầy đủ của tài liệu tại đây (4.88 MB, 48 trang )
n With more than 40 major upstream projects slated through the end of
the decade, BP is relying on technology and a talented workforce to meet
future energy demands.
B
P plans to help meet the world’s growing energy de-
mand by pumping as much as 80% of its capex into
upstream operations.
Technology will be at the heart of meeting the demand,
which is expected to jump 36% by 2030, creating a need
for 16MMb/d more oil than is needed today, according
to Lamar McKay, BP’s upstream chief executive.
Speaking during the sold-out “Unlocking the Future:
BP’s Global Upstream” topical breakfast Monday at OTC
2013, McKay said BP plans to drill as many as 25 new ex-
ploration wells per year as the company continues to ac-
quire and interpret seismic data.
“By testing at least 10 new material conventional and
unconventional opportunities every decade, we want to
be able to add at least two more new signicant produc-
ing areas over the next 10 years, each with multibillion
barrel potential,” McKay said. “Worldwide, we have ac-
cessed acreage covering
more than 150,000 sq miles
since 2010. at’s an area
roughly the size of Califor-
nia and twice as much as we
acquired in the previous
nine years.”
Areas holding promise
include Brazil, Canada,
Trinidad & Tobago,
Uruguay, Australia, and the
US, among others. However,
BP is focused heavily on Angola, Azerbaijan, the Gulf of
Mexico (GoM), and the North Sea, areas that combined
are expected to generate half of the company’s operating
income by 2020, McKay said.
Admittedly an upstream-biased business, BP has slated
BY VELDA ADDISON
T
he operator-funded DeepStar global technology
initiative has been the upstream industry’s most
successful collaboration in tackling the challenges of
the deep.
But according to a panel of leading experts from
oil companies and contractors, the need for plenty
more collaboration and standardization as the off-
shore industry pushes into the world’s ultra-deep wa-
ters is crucial if it is to achieve its aims of both
accessing new reserves and also maximizing produc-
tion from its existing assets.
Speaking at an OTC 2013 DeepStar panel session
on Monday, Occo Roelofsen, director of the global
oil and gas practice at McKinsey & Co., highlighted
the offshore industry’s success in pushing its average
water depth 100 m (328 ) deeper every year over the
past 10 years. “We predict that over the coming 10
years the industry will also see its deepwater liquids
production grow by 7% over that period.”
The need, therefore, for collaboration initiatives
such as DeepStar is vital for its success, he contin-
ued. If the Gulf of Mexico was being operated by
one single company, it would dramatically speed up
the process of bringing fields onstream, developing
standardized technical solutions, and maximizing
the value of its assets. This theoretical single opera-
tor, Roelofsen said, would have around US $50 bil-
lion of projects today in action but would have the
potential to turn those projects into assets with a net
present value of up to $110 billion mainly through
optimization.
It also would have the ability to reduce capex and
opex by an estimated $46 billion over the next
decade, he added.
Although this single company is, of course, just
theoretical, Roelofsen’s point is that further industry
collaboration could go a long way toward achieving
some of the gains that the single entity company
OTC2013
w
ww.OTC.com TUESDAY, MAY 7, 2013
|
THE OFFICIAL 2013 OFFSHORE TECHNOLOGY CONFERENCE NEWSPAPER
|
DAY 2
OFFSHORE TECHNOLOGY CONFERENCE
|
HOUSTON, TEXAS
SM
n Diversication through offshore exploration and foreign ventures
helps achieve growth.
P
etrovietnam has gone from being an E&P company
in Vietnam to a vertically integrated energy company
in Vietnam that is involved in oil and gas production, re-
ning and petrochemicals, international E&P, power
generation, and oileld services. e company has been
expanding its operations internationally to increase its
reserve position.
Petrovietnam has gone from being an E&P company
in Vietnam to a vertically integrated energy company in
Vietnam that is involved in oil and gas production, re-
ning and petrochemicals, international E&P, power
generation, and oileld services.
e company has been expand-
ing its operations internation-
ally to increase its reserve
position.
“We have been producing oil
and gas mostly on the continen-
tal shelf. We are exploring off-
shore. We have not found much
onshore,” Dr. Do Van Hau, pres-
ident and CEO of Petrovietnam,
Dr. Do Van Hau
COLLABORATION
IS KEY TO
DEEPWATER
ADVANCES
n
Joint industry projects can
lead to increased technology
capable of maximizing production.
See continued on page 46
See continued on page 21 See continued on page 3
BY SCOTT WEEDEN
Lamar McKay
BY MARK THOMAS
SCHEDULE
OF EVENTS
OTC2013
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
4 p.m. to 6 p.m. WISE Networking Event:
Women in the Industry Sharing Experiences
7 p.m. to 11 p.m. OTC Night at the Ballpark at Minute Maid Park
continued from page 1
PEGGY WILLIAMS
JO ANN DAVY
RHONDA DUEY
MARK THOMAS
S
COTT WEEDEN
J
ENNIFER PRESLEY
RICHARD MASON
VELDA ADDISON
MARY HOGAN
ANTHONY DARBY
CRIS DEWITT
STEVE HAMLEN
BEVAN MORRISON
DANIEL QUARM
A
RTHUR STODDART
ALEXA SANDERS
JAMES GRANT
PHOTOS BY GARY BARCHFELD
PHOTOGRAPHY
JO LYNNE POOL
ERIC ROTH
RUSSELL LAAS
KEVIN F. HIGGINS
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
would achieve. “Deepwater and oil and gas has been all about
technology. Technology is a very important component, but I
would say an important next step is in the economics and col-
laboration to nd more value.”
Another speaker, Steve urston, Chevron’s vice president of
deepwater exploration and projects, said, “e fact is that what
is normal today was considered ‘impossible’ 10 years ago. And
what is ‘impossible’ today will be normal in 10 years from now.
So in terms of technology, we need it all, from top to bottom.”
He highlighted dual-gradient drilling technology as being a clear
example of a DeepStar technology that went from an initial re-
search project in 1996 to full deployment in 2013. e technique
essentially eliminates water depth constraints for deepwater wells
by replacing the mud in the riser with sea water density uids.
Projects such as this are the lifeblood of DeepStar, which re-
mains the industry’s most well-known collaboration, having
been in existence for more than 20 years and having successfully
identied and executed hundreds of R&D projects so far. It has
invested more than $100 million in these projects and 325 tech-
nical reports.
e focus of its current Phase 11 work program is on deepwa-
ter developments in water depths of up to 3,048 m (10,000 ),
involving more than 30 separate projects, but its goals are aimed
at developing new enabling technologies for economic produc-
tion in depths of up to 3,658 m (12,000 ).
According to Greg Kusinki, Chevron’s DeepStar director, the
joint industry project is already under way with the process of
deciding what will be tackled in Phase 12. e member company
operators will start discussing potential projects in June before
voting on which ones to select in September or October. Phase
12 will kick off officially in January 2014.
e current member operators of DeepStar are Anadarko Pe-
troleum, BP, Chevron, ConocoPhillips, Maersk Oil, Marathon
Oil, Nexen Petroleum, Petrobras, Statoil, Total, and Woodside
Energy, but it also has more than 60 contributing member com-
panies for Phase 11.
“Generally, DeepStar will continue with the successful need-
driven process with strategic overarching top-down direction,”
Kusinki said. “e needs will be both near-term to ve years, and
longer term to 10 years.”
He said that the management committee will be encouraging
bigger impact projects that are conducted in a more collabora-
tive manner, particularly with larger contributors. “DeepStar
expects to continue interaction with regulators to ensure Deep-
Star-developed technologies can be readily accepted for deploy-
ment and use.” n
Panelists in the DeepStar plenary session yesterday at OTC focused on key issues such as standardization and collaboration and
how the industry can improve its economic performance on major deepwater projects. Panelists included moderator Greg Kusinski
of Chevron (speaking at the podium), Kevin Kennelly of BP, Ram Shenoy of ConocoPhillips, John Gremp of FMC Technologies,
Solange Guedes of Petrobras, Steve Thurston of Chevron, Alain Goulois of Total, and Occo Roelofsen of McKinsey & Co.
(Photo by Gary Barchfeld Photography)
4 TUESDAY | MAY 7, 2013 | OTC SHOW DAILY
O
TC 2013’s Spotlight Award winners include companies
and technologies that are helping to move the offshore
industry forward. In Monday’s show daily, the rst of the 15
award winners were reviewed. ey included ABB for its
Onboard DC Grid power distribution, automation, and elec-
tric propulsion system and Baker Hughes for the Fastrak
LWD uid analysis sampling and testing service. Dow Oil
and Gas, PIH, Trelleborg Offshore, and Bayou Wasco Insu-
lation also won for the Neptune Advanced Subsea Flow As-
surance Insulation System. FMC Technologies won for its
Condition and Performance Monitoring (CPM) soware
service, and FMC teamed up with Sulzer Pumps Ltd. to take
home an award for the High-Speed Helico-Axial Multiphase
Subsea Boosting System. Finally, GE Oil & Gas le with two
awards, for its RamTel Plus and ROV Subsea Display Panel,
and another for the Deepwater BOP Blind Shear Ram.
Riserless drilling technology addresses deepwater hazards
Reelwell has received an award for the Reelwell Riserless
Drilling Method (RDM) technology. e company de-
scribed its RDM technology as a new solution for drilling
E&P wells, enabling the drilling of well sections with
challenging pressure conditions and
drilling to targets beyond conventional
reach. Reelwell developed the new method
with support from Petrobras, RWE, Shell,
Total, and the Research Council of Norway.
e RDM technology involves a dual-
drillstring or closed-loop ow circulation
system, top-drive adapter, dual-oat valve,
and ow-control unit. It differs from con-
ventional drilling in the circulation ow
path of the drilling uid, with the dual-
drillstring acting as a riser. During conven-
tional drilling, the drilling uid returns to
surface via the wellbore annulus, whereas
in the new riserless drilling technique, the
uid returns to surface via the inner pipe
of the dual drillstring. RDM is based on
pumping the drilling uid into the dual
drillstring annulus through the top-drive
adapter and down to the dual-oat valve at
the top of the conventional bottomhole as-
sembly. From the dual-oat valve, cuttings
are transported back to surface inside the
inner string, ensuring that the hole remains
clean at all times, the company said.
According to Reelwell, the system im-
proves offshore drilling safety because of its
ability to perform managed-pressure and
under-balanced drilling operations without
pressurized equipment on surface. More-
over, the design eliminates the potential
hazards from drilling with a riser in ultra-
deep water.
For more information about RDM-R,
visit Reelwell at booth 5241.
Drilling riser transport system
reduces cost and risk
SBM Offshore has received an award for its
Drilling Riser Trip Saver technology. e
rail-mounted transport apparatus relocates
a suspended drilling riser with a drilling
riser tensioner system and surface BOP in
place. e technology can be used while
drilling multiple subsea wells consecu-
BY HART ENERGY STAFF
In Reelwell’s Riserless Drilling Method,
omitting the riser is possible using a dual-
drillstring to transport cutting to surface.
(Image courtesy of Reelwell)
5OTC SHOW DAILY | MAY 7, 2013 | TUESDAY
tively, reducing risk while also saving time by avoiding
the removal of the suspended drilling riser from the well
bay of the vessel. In addition to substantial time savings,
safety risk is reduced by minimizing dropped object haz-
ard concerns during simultaneous drilling and produc-
tion operations while live wells are in production.
A oating, offshore drilling, and/or production plat-
form is equipped with a rail-mounted transport system
that can be positioned at a plurality of selected positions
over the well bay. Using the transport system, the drilling
riser is lied just clear of a rst subsea wellhead and po-
sitioned over an adjacent, second subsea
wellhead using guidelines to restrain the
disconnected bottom end of the riser dur-
ing transfer. e system allows for the
drilling riser to be parked on an existing
subsea wellhead while the rig is skidded
and positioned over another well slot in
order to deploy the production riser, run
the completion string, and install the sur-
face production tree.
According to SBM, the technology was
introduced for the rst time in April 2012
in a client bid request for a dry-tree ten-
sion-leg wellhead platform (TLWP) appli-
cation in West Africa in 800-m (2,625-)
water depth. is method of handling and
transferring a high-pressure drilling riser
from one well to another on a dry-tree
TLWP had previously not been developed.
For more information about the Drilling
Riser Trip Saver, visit SBM Offshore at
booth 4141.
Mobile robotic system solves manual cutback challenges
ShawCor has received an award for its Mobile Robotic
Cutback System. The company’s Bredero Shaw divi-
sion designed the end-machining technology for in-
sulated pipe. Offshore pipe often is insulated with
specialized polymers to meet demanding thermal per-
formance criteria. When the individual lengths of
pipe are welded together, insulation must be removed
in a controlled way to allow welding. This removal is
called a “cutback.” Some of the manual processes used
to form the cutback in the past include wire brushing,
grinding, and scraping. The most significant disad-
vantages of these methods are safety risks of exposure
to high-speed cutting devices, excessive noise, high
labor costs, inconsistent cutback profiles, and the
generation of large amounts of nonrecyclable waste.
The Robotic Cutback System addresses all of these is-
sues. The system has been integrated into two spe-
cially designed shipping containers, allowing it to be
transported and erected quickly without the need for
S
ee continued on page 22
The Drilling Riser Trip Saver method and
apparatus can be used to consecutively
drill multiple subsea wells.
(Image courtesy of SBM Offshore)
The Mobile Robotic Cutback System can pro-
duce higher quality cutbacks with an ex-
panded ability to deliver new geometries
allowing pipeline engineers to optimize the
design of the joint protection system and
deliver a uniform coating over the field joint.
(Image courtesy of ShawCor)
6 TUESDAY | MAY 7, 2013 | OTC SHOW DAILY
P
etrobras is the operator of the vast majority of the coun-
try’s offshore mega projects. e company has a total
of 25 new production units due to start up between 2013
and 2017, with another 13 due by 2020. is growing eet
of 38 new offshore production facilities includes 13 new
units between 2013 and 2017 that have yet to be contracted.
is build-or-lease program for FPSOs mainly destined
for ultra-deepwater projects has been the engine room
driving the global oating production systems sector.
Since the year 2000, says analyst Ineld Systems, the trend
for oating platform installations beyond water depths of
500 m (1,640 ) and greater has been primarily driven by
Brazil, which since that year has consistently held a 35%
market share of Capex at this water depth level.
In terms of spending by Petrobras alone, the company
recently had its business plan approved for 2013 to 2017
and will invest a total of US $236.7 billion, with the E&P
sector taking up 62% ($147.5 billion) of the total. Of the
total, 73% will be allocated to production development,
16% to exploration, and 11% to infrastructure, according
to Petrobras. e goal is to hit a production target for oil
and natural gas liquids (NGL) of 2.5 MMb/d in 2016,
raising this to 2.75 MMb/d in 2017 and 4.2
MMb/d by 2020.
From 2013 to 2015, a total of 11 new pro-
duction units are expected to come on-
stream, representing a capacity increase of
1.45 MMb/d for Petrobras.
Much of the emphasis is focused on the
pre-salt reserves in the Santos and Campos
Basins. Petrobras conrmed earlier this
year that oil production from its operated
elds in those basins hit 300,000 b/d of oil,
just seven years aer oil was rst found in
the pre-salt layers.
But it is also pushing on with its efforts
to improve the overall production curve for
its existing oil and gas elds, with initiatives
such as its Campos Basin Operational Effi-
ciency Improvement Program, designed to
increase the reliability of meeting its pro-
duction targets by improving operational
efficiency levels and the integrity of pro-
duction systems in the Campos Basin.
Solange Guedes, E&P executive manager
for production engineering at Petrobras,
highlighted in a plenary session at OTC
yesterday the operator’s efforts to revitalize
its aging elds. ese include the deepwa-
ter Marlim eld offshore Brazil, which
started producing in 1991 but has in recent
years seen its production levels fall from a
peak of more than 600,000 b/d to its cur-
rent level of around 200,000 b/d.
“is required a novel approach to in-
crease the oil recovery rate and extend its life,
which led to the testing of an oil/water sepa-
ration system, which began operations in
April,” she said. is is the world’s rst sys-
tem for deepwater subsea separation of
heavy oil and water, with the water reinjected
back into the reservoir to boost production.
e subsea separation module is designed to
separate heavy oil, gas, sand, and water at a
depth of 900 m (2,950 ) of water.
e Brazilian Pavilion is located at booth
1117, organized by the IBP (Brazilian Pe-
troleum, Gas & Biofuels Institute). n
BY MARK THOMAS
ARCTIC
TECHNOLOGY
CONFERENCE
George R. Brown
Convention Center
Houston, TX
T
hose who have spent Sunday aernoons cheering on
the Houston Texans at Reliant Stadium would
scarcely have recognized it Sunday night. Festooned in
an underwater theme that included giant jellysh, the
stadium was transformed into a subsea paradise for the
OTC 2013 Awards Banquet.
Aer opening remarks from OTC Chairman Steve Balint
and Houston Mayor Anise Parker, Chuck Richards, dinner
chairman, introduced the annual beneciary of the banquet,
the Offshore Energy Center (OEC). Several companies in-
cluding Chevron, Oceaneering, Shell, and Total helped spon-
sor the award, along with Baker Hughes, BP Reliant Park and
Houston Convention and Visitors’ Bureau, the Society of Pe-
troleum Engineers (SPE), Technip, and Transocean.
“We look for charitable organizations that make a dif-
ference in the lives of people or address important envi-
ronmental issues. We also want to support a worthy
organization that’s connected to the offshore industry and
to the communities where we operate,” Richards said.
Executive Advisory Board Chairman Steve Newman con-
tinued the introductions, noting that the center is notable for
its Ocean Star museum, a converted oil platform in Galve-
ston that has been turned into a center that
teaches the public about the offshore industry.
Aer the OEC recognition the awards
presentation began. Kenneth E. Arnold, a
senior technical advisor for Worley Par-
sons, won a distinguished achievement
award for individuals based on his work to
establish oileld facilities engineering as a
recognized technical engineering specialty.
“I never thought this would happen,”
Arnold told the audience. “e people who
won this award before me were my men-
tors. I guess I must be old enough now.”
Total took home honors in the distin-
guished achievement award for companies,
organizations, or institutions for its pio-
neering Pazor project. e project is no-
table for using the world’s largest FPSO
vessel along with a very complex subsea
network. e eld is 150 km (94 miles) off-
shore Angola and produces 220,000 b/d.
Heritage awards are bestowed each year
based on continuous distinguished service
in exploration, drilling, production, and
R&D. is year two recipients – James
Brill, professor emeritus at the University
of Tulsa, and E. Dendy Sloan of the Col-
orado School of Mines – were honored.
Brill has helped to pioneer the understand-
ing of multiphase ow, authoring more than
200 technical papers and research reports on
the topic. He said his interest was piqued in
the early 1960s when he took a graduate
course on articial li taught by Kermit
Brown that he said became the rst multi-
phase course in the world. “He worked our
fannies off, and I loved it,” Brill said. “By the
end of the semester, we submitted a paper to
the SPE annual fall meeting in Denver
based on our homework assignments, and
it was soon published in the ‘Journal of Pe-
troleum Technology.’ Kermit Brown had a
BY RHONDA DUEY
See continued on page 10
Steve Balint (left) presents Kenneth E.
Arnold with the Distinguished Achieve-
ment Award.
(Photos by Gary Barchfeld Photography)
D
ay 1 of OTC was one to remember. From the thousands
of attendees representing countries across the globe, to
the more than 2,700 exhibitors presenting their state-of-the-
art technology, to a special guest visit, OTC was bustling both
in person and on social media. Check out some of the pop-
ular conversations taking place on the OTC platforms.
Twitter: e hashtag #OTCHOUSTON is wildly popular
on Twitter. At one point, it was even “trending” on Twitter,
meaning it was one of the most shared, used, and talked
about topics on the site. Follow the hashtag to see what ex-
hibitors are showcasing at their booths, takeaways from
technical sessions, and more. Join us on Twitter and connect
with other OTC attendees. www.Twitter.com/OTCHouston
Facebook: Our online community loves photos. is
proved especially true when we shared photos from the an-
nual OTC dinner, attendees in action, and the Crown Prince
of Norway’s tour of the exhibit oor. Post your OTC photos
on our wall for everyone to enjoy. www.Facebook.com/
OTCevents
YouTube: Miss a session? Want insights from OTC board
members? Want video coverage? Each day, we post Daily
Highlights video segments produced on-site by OTC-TV.
ey are the guys with the blue shirts walking
around OTC. If you see them, smile because
you’re on OTC-TV. www.YouTube.com/
eOTCvideos
LinkedIn: OTC attendees are taking the
conversation from Reliant Park online, by
connecting, networking and sharing on the
business networking site, LinkedIn. Join
the official group or one of the more spe-
cic subgroups to connect with like minds.
Search “Offshore Technology Conference
(OTC)” in the groups search eld. n
BY ANTHONY D. DARBY
massive impact on my life.”
Brill went to Tulsa in 1966 as a young
assistant professor. During his tenure at
the university he went on to develop re-
search projects in fluid flow and paraffin
deposition.
Sloan has published 230 papers and ve
books on methane hydrates, developing
modeling and simulation tools that are now
routinely used for the design and operation
of offshore production systems. He
founded the International Conference on
Gas Hydrates in 1993, a conference that is
still going strong 20 years later.
“We all realize that this heritage award is
not given to one person but to a group
composed of the past and present family of
students who have done much of the inno-
vation and all of the laboratory effort that
has culminated in our results,” Sloan said.
“Students are the principle product of our
laboratories.” n
continued from page 8
James Brill (top right) and E. Dendy
Sloan (bottom right) receive their
Heritage awards from Steve Balint.
S
ize and agility are two highly prized physical attrib-
utes in sports. In project management, especially
with the megaprojects of today, the two together can be
both help and hindrance. Operators and contractors
working in the highly volatile environment of offshore
development are moving to an agile approach for faster
response to changing circumstances.
Chris Ross, senior consultant for CRA Marakon,
kicked off the rst of Monday’s OTC 2013 technical ses-
sions, “Agile Strategies in Offshore Development,” as
moderator. He nimbly navigated the discussion that fea-
tured operator and service provider organizations that
have had success in implementing agile project manage-
ment strategies.
“e reality is, as the saying goes, ‘when man plans,
God laughs,’” Ross said. Agility in project management,
he added, requires rethinking the conventional approach.
The session featured audience interaction via live
electronic polling. One poll showed that 95% consider
agility in offshore development projects to
be more important today than it was five
years ago.
Featured panelists included Dick West-
ney, founder and director, Westney Con-
sulting Group; Stuart Wheaton, group
development and operations manager, Tul-
low Oil; Sandeep Khurana, manager of de-
velopment, major projects group, Noble
Energy; Dennys Moreira de Campos,
Brazil IPM operations manager, Schlum-
berger; and Erik Namtvedt, president,
FloaTEC.
e panel addressed key questions such
as types of projects that are particularly
suited to an agile approach, to what extent
agility requires a departure from the con-
ventional practice, and how an agile ap-
proach increases or decreases project risk.
Dening value
In dening the value of agile project man-
agement, Westney said that agility is a
“matter of perspective,” with several key
steps in the establishment of the process.
Aligning behaviors and accountability with
value from project start to nish is key, he
added.
In addition, a clear purpose and a respect
for the culture and values of the team are
equally important. Perhaps most critical,
Westney said, is effective performance
management and the establishment of “de-
cision rules.” e technically complex proj-
ects, he continued, requires the partnering
of conventional best practices and com-
plete exibility for success.
One approach
Classic project execution, Stuart Wheaton
offered, involves many basic steps like cost
management, scheduling, and production
ramp up. Project management in other
countries, such as in Ghana where Tullow’s
Jubilee project has experienced great suc-
cess, raises additional concerns, including
sensitivity to environmental issues and
project transparency. Wheaton said that in-
country involvement by and with the host
country at all levels is critical.
For example, he said, Tullow’s social per-
formance activities included the develop-
ment of the Takoradi Polytechnic Facility
for training of the local workforce and the
Malaria Burden Project. In Ghana, 30% of
working time is lost due to malaria, accord-
ing to Wheaton.
Another way in which Tullow has found
its success is through the use of integrated
BY JENNIFER PRESLEY
12 TUESDAY | MAY 7, 2013 | OTC SHOW DAILY
continued on next page
13OTC SHOW DAILY | MAY 7, 2013 | TUESDAY
project management teams that bring both
the primary company employees and con-
tractors together “under one roof.”
Wheaton encouraged the use of early
team building as a way of enforcing core
team values. When creating teams, it is
vital to create a project culture and
process that is both technically sound and
streamlined.
In closing, Wheaton offered that agility
in project management is necessary and
that it is also a state of mind. Any project
can do it, he said, the key is getting aligned
early and being exible enough to handle
the project “unknown unknowns.” n
NETL RESEARCH
PRESENTATION
Dr. Barbara Kutchko, ultra-
deepwater complementary
program research lead at
the US Department of En-
ergy's National Energy Tech-
nology Laboratory, will
present the results of recent
research and development
in the application and in-
tegrity of foamed cements.
The presentation, "Improv-
ing the Science Base for
Wellbore Integrity: Foamed
Cements," will take place at
the Department of Energy
exhibit in booth 4056 at
noon today, May 7, and on
Wednesday, May 8. The
presentation is open to all
interested OTC attendees.
continued from previous page
Monday's technical session on agile proj-
ect management included panelists (left
to right): Erik Namtvedt, FloaTEC; Den-
nys Moreira de Campos, Schlumberger;
Sandeep Khurana, Noble Energy; Stuart
Wheaton, Tullow Oil; Dick Westney, West-
ney Consulting Group; and moderator
Chris Ross, CRA Marakon.
(Photo by Gary Barchfeld Photography)
14 TUESDAY | MAY 7, 2013 | OTC SHOW DAILY
A
t OTC 2013 Baker Hughes is presenting two technolo-
gies to meet the challenges of deepwater completions:
one for the sandface and one for the upper completion.
Baker Hughes’ multizone single-trip (MST) comple-
tion system delivers frac-packing or gravel-packing treat-
ments to multiple zones in a single downhole trip, which
can improve project economics by reducing completion
time and cost. The system has a proven track record in
wells in India and Indonesia, where it
helped reduce the costs of sand control
operations by 40% to 60% while allowing
for a large production casing inside diam-
eter for improved production rates and
maintaining well integrity throughout the
operation. However, use in the Gulf of
Mexico has posed unique challenges that
have required careful planning.
Recently, Baker Hughes worked closely
with Petrobras to complete its Cascade 5
well, located in 2,484 m (8,149 ) of water.
e MST was used to conduct frac-pack
completions through 10⅛-in. casing in this
high-pressure Lower Tertiary formation.
e well had a bottomhole pressure ex-
ceeding 19,000 psi and was successfully
stimulated at a pumping rate of 32 bbl/min
with an average of 260,000 lbm of proppant
per zone. Petrobras did not incur any lost-
time incidents or nonproductive time
(NPT) related to the deployment and op-
eration of the MST and achieved additional
deepwater rsts in the process. e well’s
total depth was 8,103 m (26,586 ), making
it one of the deepest frac-packed wells on
record and the deepest application of the
MST system.
For many operators, being able to treat
two or more zones in one trip has resulted
in a cost savings of 45% or more compared
to treating the multiple zones in individual
trips. With the MST system operators can
selectively produce zones, access marginal
zones, and treat and produce longer zones
more economically. e MST system pro-
vides exibility while maximizing hydro-
carbon recovery by enabling selective or
commingled production. e one-trip
process and predeployment preparation
can save time, reduce risk and NPT, and
maximize safety.
Baker Hughes also has developed a new
tubing-retrievable subsurface safety valve
for ultra-deepwater, deepwater, and
HP/HT applications.
REACH subsurface safety valves can be
set as deep as 6,096 m (20,000 ) and can
ensure fail-safe closed operation using re-
liable eld-proven heavy-sprung closure
technology. e new valve offers a single
CONTRIBUTED BY BAKER HUGHES
See
continued on page 28
The MST completion system delivers frac-
turing and gravel-packing treatments,
which can reduce completion time and
cost. (Image courtesy of Baker Hughes)
audi Aramco has announced the opening of three
research centers in the US with Houston named one
of the cities to house a new facility focused on upstream
research. Houston joins two other US-based centers in
Cambridge, Mass., and Detroit designed to extend the
energy giant’s global R&D network.
The Houston Research Center, expected to be op-
erational later this year, will consist of teams spanning
upstream subsurface domains. Saudi Aramco cur-
rently is hiring experts from around the world to
work in this center, which has a state-of-the-art lab-
oratory to develop technology to advance the discov-
ery and recovery of oil and gas.
In opening these research centers, the company looks
to further strengthen its collaboration with others and to
provide solutions to challenges in the upstream and
downstream sectors of the industry. ese
specialized centers of excellence will ad-
dress far-reaching challenges.
The three centers join a worldwide
network of research centers established
by Saudi Aramco to leverage scientific
expertise and further complement the
work done by the its Exploration and Pe-
troleum Engineering Center’s Advanced
Research Center (EXPEC ARC) and Re-
search and Development Center
(R&DC), both of which are located in
Dhahran, Saudi Arabia. These R&D cen-
ters are devoted to original research
from the upstream E&P sector to down-
stream refining. The work supports
Saudi Aramco’s strategic aims to increase
oil and gas reserves, improve recovery
rates, and develop improved refining
processes.
The Houston Research Center, located
in the city’s “energy corridor” west of
downtown along Interstate 10, was
strategically placed in a major hub for oil
and gas R&D. The facility is near energy-
related companies, chemical and oilfield
fluids manufacturers, and service com-
panies, as well as R&D labs and top pe-
troleum engineering universities.
The Cambridge Research Center was
strategically located in a standalone cen-
ter adjacent to the Massachusetts Insti-
tute of Technology (MIT) to support
computational reservoir modeling, nan-
otechnology, and advanced gas mem-
brane systems.
e Detroit Research Center, sited in
southeastern Michigan in the city of Novi,
was strategically located to take advantage
of collaboration with leading research or-
ganizations for joint research on fuel effi-
ciency and engine development.
Saudi Aramco R&D representatives
say much of their research happens in
partnerships with premier universities
and technology providers as well as in-
dependent researchers and developers
across the globe.
e three US-based centers will employ
experienced professionals with advanced
degrees in petroleum engineering, geol-
ogy, chemistry, materials science, or
other related fields. The company also
has research centers in Thuwal, Saudi
Arabia; Delft, the Netherlands; Paris;
and Beijing; and a technology center in
Aberdeen, Scotland.
Learn more about the company’s re-
search centers by visiting aramcoser-
vices.com. n
CONTRIBUTED BY SAUDI ARAMCO
16 TUESDAY | MAY 7, 2013 | OTC SHOW DAILY
An artist’s rendition of
the Houston Research
Center located in the
city’s “energy corridor”
with more than 4,181
sq m (45,000 sq ft) of
office and laboratory
space. The new facility
will focus on upstream
research to advance
the discovery and re-
covery of oil and gas.
(Image courtesy of
Saudi Aramco)
T
here are few more high-prole issues in the offshore
oil and gas sector today than that of well integrity.
While parts of the world such as the Far East are still
allowing certain amounts of self-regulation, offshore re-
gions such as the Gulf of Mexico (GoM) and the North
Sea are seeing increasingly strict well management re-
quirements from organizations such as the US Bureau of
Ocean Energy Management (BOEM) and Norway’s Pe-
troleum Safety Authority (PSA) – to name just two.
A study of wells on the Norwegian Continental Shelf by
the PSA, for example, found that every h well analyzed
had well integrity weaknesses. In addition, a 2011 Society
of Petroleum Engineers paper (“Well Integrity Analysis in
Gulf of Mexico Wells Using Passive Ultrasonic Leak De-
tection Methods,” ISBN 978-1-55563-342-4) found that
45% of GoM wells had sustained casing pressure.
ese regulatory requirements are in-
creasing the onus on operators to establish
structural integrity and contingencies at
the planning stage, recomplete existing
producing wells to comply with new legis-
lation, ensure that well integrity is not
compromised by trouble zones and stuck
casing, and reinstate well integrity quickly
when damage does occur.
Furthermore, operators and drilling con-
tractors today have to not only guarantee
the safe and reliable containment of well
uids throughout the life of the well, but
they must also work within an environment
of increased pressures to maximize produc-
tion while at the same time managing costs.
To date, however, well integrity has been
viewed primarily as a reactive process where
problems are dealt with and xed only aer
they have happened and where unplanned
events simply cannot be planned for.
It is against this backdrop that Ab-
erdeen, Scotland-based Meta has a clear
message to take to operators and drilling
contractors – that well integrity can be
planned for and that preexisting technol-
ogy limitations relating to well integrity
can be overcome.
Underpinning Meta’s vision is a technol-
ogy called Metalmorphology, which uses
the established metal working principle of
autofrettage to create durable and perma-
nent metal-to-metal and gas-tight connec-
tions that provide isolation integrity over
the lifetime of the well. Metalmorphology
and Meta’s selection of morphable products
deliver or reinstate original well integrity
and come with no reductions in inside di-
ameters or reliance on elastomeric seals.
Metalmorphology is central to a number
of products that are helping redene well in-
tegrity. e Meta Liner Tieback, for example,
uses the morphing technology to connect
the liner to a tieback string of casing, result-
ing in a V0, metal-to-metal, gas-tight, and
load-bearing connection that is qualied to
the highest industry standards. e Liner
Tieback solution can play a crucial role in
planning for well integrity contingencies as
well as enabling existing wells to be recom-
pleted to meet evolving legislation without
the need to change completion parameters.
e Meta Internal Clad System uses
Metalmorphology to shape metal for total
isolation and for the installation of clad
through clads. e system seeks to bring an
end to limitations as to where and when op-
erators can isolate zones and can prevent the
need for complete well workovers with the
accompanying lost production and expenses.
In this way, operators can better plan their
drilling and production strategies, develop the formations
they want to maximize production, and provide an alterna-
tive to the long-held belief of producing from the “bottom
up” of the well.
Other Meta solutions include the Meta Casing Recon-
nect, which adopts Metalmorphology to deploy itself
over existing casings, thereby allowing operators to rein-
state well integrity and focus on their original well plans;
and the Meta Isolation Barrier, which provides a perma-
nent barrier to annular or zonal ow within the well.
For too long well integrity has been dened by a reactive
approach, and the limitations of current well planning and
intervention technologies where unplanned events lead to
rising costs, lost production, and deviations to original drilling
and well production programs. ese new morphable solu-
tions instead allow for building in contingencies, reducing
risk, and protecting and enhancing future production.
To learn more, visit metadownhole.com. n
CONTRIBUTED BY META DOWNHOLE
17OTC SHOW DAILY | MAY 7, 2013 | TUESDAY
Meta’s metal-to-metal, load-bearing, life-of-well “mor-
phable” technology can optimize downhole isolation for
well integrity applications.
(Image courtesy of Meta Downhole)
W
hen NASA rst envisioned the Neutral Buoyancy
Laboratory (NBL), it was designed to simulate
complex space operations. Here, procedures and time-
lines could be tested in a safe, controlled underwater en-
vironment before operations were executed in the
unpredictable environment of space.
Today, an expanded partnership between Raytheon and
NASA leverages this same technology and environment to
elevate subsea testing for the oil and gas industry. e NBL’s
capabilities for test control and monitoring and underwater
operations can be used to develop, test, and troubleshoot
procedures for new subsea tools, technologies, equipment,
and methodologies prior to deepwater deployments – all
within a highly realistic underwater environment.
“is is a unique resource for the oil and gas industry,”
Tracy Cox, director of applied strategies for Raytheon
Professional Services, said. “We provide hands-on testing
and state-of-the-art simulations that help operators be-
come safer and more efficient.”
Raytheon experience with high-stakes “failure is not
an option” organizations includes NASA, the US military,
and the Federal Aviation Administration.
“is partnership provides state-of-the-art, fully instru-
mented subsea testing environments to deliver signicant
cost benets by reducing risks through preevent validation
and verication in a controlled, consistent subsea simula-
tion,” Tom Ellis, Raytheon’s NASA program manager, said.
Testing for assured success
Benets to the oil and gas industry of this underwater test-
ing environment include reduced risk of off-
shore and subsea operations; accelerated
schedules for critical projects; lower costs
within a realistic testing environment; earlier
troubleshooting and renement of technol-
ogy; and optimized productivity of resources
in a centralized Houston-area location.
e operational excellence and safety
culture of NASA’s NBL is applied to a range
of technologies and operational method-
ologies, including simulation of high-risk
interventions, repair and inspection
methodologies, and integration of ROVs,
AUVs, and ADSs with custom test tools.
Test support capabilities at the NBL in-
clude integrated engineering and manufac-
turing support for prototyping, poolside
power and air, full range surface and sub-
surface video capability, control room
oversight, wireless information technology
access, and dive operators experienced in
SCUBA and surface-supplied dive systems.
e Wet SIT advantage
e Wet system integration test (SIT) and
timeline development offered at the facility
helps emerging technology become more ef-
cient and productive. Simulations and Wet
SITs in the NBL’s controlled environment can
reduce operators’ costs, enhance realism, and
provide earlier opportunities for technology
renement and enhancement.
From previous efforts, NASA and
Raytheon understood that computer simu-
lations can be too idealistic. For example, in
early design revisions, buoyancy control
challenges were underestimated, and at-
tached tool behavior was inaccurate. A Wet
SIT increases simulation and training reli-
ability by using an underwater environment
with full use of control systems, including
thrust, buoyancy, added mass, attached tool
behavior, and overall system response.
Prior to offshore implementation, proce-
dures and designs can be modied during
NBL Wet SIT simulations, saving time and
effort in the more expensive, less forgiving
offshore environment. Unlike other testing
facilities available to offshore operators, the
NBL has all the capabilities needed for suc-
cess integrated into one facility.
is intermediate testing step lowers risk
and increases reliability while enhancing proj-
ect execution, management, and safety,
thereby ensuring overall operational readiness
prior to a move to a deepwater environment.
To learn more about the underwater
testing facility visit train4space.com or
rps.com or visit Raytheon during OTC
2013 at booth 12214. n
CONTRIBUTED BY RAYTHEON
18 TUESDAY | MAY 7, 2013 | OTC SHOW DAILY
An underwater chain repair is completed at the NBL.
(Image courtesy of Raytheon)
A
ustralia’s planned and potential LNG developments
have made it a world leader in this activity sector, but
rising costs have seen one of the country’s major players
– Woodside – recently scrap its plans for an onshore liq-
uefaction solution and go back to the drawing board.
Woodside decided in April that plans for its Browse
LNG project at James Price Point near Broome, Western
Australia, did not achieve the appropriate commercial
return levels. e project partners are now considering
other development concepts, including a oating LNG
(FLNG) solution.
e company has since entered into an agreement with
Shell that sets out the key principles that would apply if
the Browse reserves were developed using Shell’s FLNG
technology. “e agreement provides a framework that
would enable the Browse joint venture to progress FLNG
as a development concept,” Woodside said in a statement.
Woodside CEO Peter Coleman said FLNG had the po-
tential to commercialize the Browse resources in the ear-
liest timeframe, as well as strengthen the Australian
operator’s relationship with Shell – something that could
be highly benecial in the offshore Australian gas sector
given both companies’ assets in the arena.
“is agreement enables Woodside, as operator of the
Browse LNG development, to strengthen our develop-
ment and operational capabilities through the potential
use of Shell’s ‘design one build many’ FLNG technology,”
Coleman said. “It also provides the opportunity for West-
ern Australia to become an industrial, operational, and
technology center for excellence for FLNG worldwide.”
Woodside said it “will immediately engage with the joint
venture participants regarding the agreement, the extent of
work on alternative development concepts, and the obliga-
tions under the Browse retention leases. e selection of any
development concept requires approval by
the Browse joint venture participants.”
Rising costs
e Browse LNG rethink was prompted by
a technical and commercial evaluation of
the proposed James Price Point onshore fa-
cility, which according to Woodside showed
the concept did not “meet the company’s
commercial requirements for a positive nal
investment decision.”
e company added, “A tender evalua-
tion has recently been completed for all up-
stream and downstream scopes of work,
which showed that the development would
not deliver the required commercial re-
turns to support a positive nal investment
decision by Woodside.
“Woodside will immediately engage with
the Browse joint venture to recommend eval-
uation of other development concepts to
commercialize the Browse resources, which
could include FLNG technologies, a pipeline
to existing LNG facilities in the Pilbara, or a
smaller onshore option at the proposed
Browse LNG precinct near James Price Point.”
Woodside’s latest move puts the FLNG
option in pole position and underlines the
progress the solution has made in recent
years, the most high-prole example being
Shell’s Prelude development.
Regarding the current state of the
Browse project, Coleman said, “The cost
escalation on Browse has been consistent
with other projects in Australia. Unfortu-
nately, the cost escalation has been such
that the total costs for Browse have re-
sulted in the current development not
being commercial. The decision is a com-
mercial one.”
On the search for a new development so-
lution, he continued, “We’ve been monitor-
ing different development options as we’ve
been progressing our reference case. Over
the past two to three years there have been
a number of factors which have changed in
the LNG industry, such as costs and tech-
nology for example.
“One of the alternatives is FLNG tech-
nology, and that is something we will rec-
ommend the joint venture consider as we
move forward. ere are other possibilities,
which we have looked at previously. ose
other options could include a pipeline to
existing facilities in the Pilbara and a
smaller onshore option around James Price
Point. It is too early to say if any of those
are commercial.”
Browse holds reserves of 15.5 Tcf
(439.1 Bcu m) of dry gas and 417 MMbbl
of condensate. n
BY STEVE HAMLEN
Woodside has signed an agreement with Shell that
could see an FLNG solution similar to Shell’s planned
Prelude facility used on the companies’ Browse LNG
project offshore Western Australia.
(Image courtesy of Shell)
21OTC SHOW DAILY | MAY 7, 2013 | TUESDAY
T
o disassemble topsides of offshore platforms, workers
used to have to manually disassemble the structure into
transportable individual parts on the high seas – work that
is both time-consuming and hazardous. In the future a new
vessel from the Allseas Group will li the platforms from
their steel “jacket” and transport them onto land, which
could make disassembly safer and more cost-effective.
A prerequisite for that simplied process is a topside
liing system (TLS). e TLS can li 48,000 tons, which
is equivalent to 80 fully loaded Airbus A380s. As engi-
neering partner to the Allseas Group, Bosch Rexroth de-
veloped and engineered the drive and control system
solution and the major components for the TLS. For
Allseas Group owner Edward Heerema, the engineering
is the heart of the project. “We had to lay
the foundation for all of the ship’s func-
tions here. at’s why nothing could be
forgotten: All technical requirements had
to be precisely met, and all possible scenar-
ios had to be run through.”
To make that happen, Allseas brought
Bosch Rexroth on board as a long-term
partner. Rexroth possesses experience in
designing and realizing drive and control
solutions for offshore installations and
maritime applications. An international
team comprised of industry specialists and
technology experts developed a TLS drive
and control system, based on the principles provided by
Allseas. “No comparable system has ever been created be-
fore, making this an exciting task, even for our experi-
enced engineers,” Ron van den Oetelaar, Bosch Rextoth
project manager, said.
In complex cosimulations Rexroth reviewed the design
and dimensioning of major components with a focus on
adhering to high safety standards. e company-owned
soware takes both mechanical strengths and specic hy-
draulic characteristics into consideration. In addition to
engineering products and services, Rexroth also supplies
the 5-MW central hydraulic power unit as well as nu-
merous key components and subassemblies for the TLS.
e new vessel, Pieter Schelte, is being built in a South
Korean shipyard and is set to begin disassembling the
rst offshore platforms in early 2014. n
CONTRIBUTED BY BOSCH REXROTH
The Pieter Schelte vessel will be able to lift and trans-
port topsides of offshore platforms with a weight of up
to 48,000 tons in one piece.
(Image courtesy of Bosch Rexroth)
said at the OTC 2013 topical breakfast May
6 on “Energy Challenges and Opportuni-
ties in Vietnam and Beyond.”
“Currently, there are 90 petroleum con-
tracts with our partners in Vietnam. Oil
production is now at 320,000 b/d at this
point,” he said. Natural gas production is
now at 1 Bcf/d, and the company plans to
increase production to 1.5 Bcf/d in the next
four to ve years.
Diversifying internationally
“We have been going overseas since the early
2000s,” he continued. “We are now working
in 15 countries with 20 projects in Russia,
Central Asia, Southeast Asia, South Amer-
ica, and North Africa. Of the projects we are
implementing overseas, three are under pro-
duction, and our share is 36,000 b/d. We
started production two years ago. By 2015
overseas production will be 50,000 b/d.”
Five other projects are under development
internationally. One project in Algeria should
begin production in 2014 with peak produc-
tion of 40,000 b/d. Two other projects in Rus-
sia are slated to start production in 2014 and
2015. e company also is in a project in
Venezuela that is producing very heavy oil.
Petrovietnam is expanding by diversify-
ing with overseas ventures. e company
has a project in Peru, where it bought a 50%
interest in Block 67. First oil is expected in
November 2013 with maximum produc-
tion of 60,000 b/d, Dr. Khanh Van Do, pres-
ident and CEO of Petrovietnam
Exploration Production Co., said.
Offshore Myanmar, the company is the
operator of one block with an 85% interest.
e company is seeking other partners to
c
ontinued from page 1
See
continued on page 46
22 TUESDAY | MAY 7, 2013 | OTC SHOW DAILY
concrete foundations. The new system is faster and
safer, the company said, and can produce higher quality
cutbacks with an expanded ability to deliver new geome-
tries. is allows pipeline engineers to optimize the de-
sign of the joint protection system and deliver a uniform
coating over the eld joint, which can ensure a consistent
U value over the entire pipe length, the company said.
Subsea hot tap technology saves production uptime
Statoil ASA has received an award for its Remotely
Welded Retrot Subsea Hot Tap Tee technology. In August
2012 the company carried out the rst hot tap installation
in connection with preparations for its Åsgard subsea gas
compression development in 265-m (869-) water depth
in the Norwegian North Sea.
e remotely operated hot tap operation consists of a
robot welding a T-piece onto the pipe while gas is owing
through it. Once complete, a remote-controlled drilling
machine drills holes in the producing pipeline, with no ef-
fect on pressure and production. e company cited hot
tap technology as a technological breakthrough for devel-
oping marginal elds and also for extending the lifetime of
mature assets. Further, the ability to connect anywhere on
the pipeline without stopping production can yield consid-
erable exibility and signicant savings, the company said.
Statoil started working to develop remotely operated
hot tap technology for offshore pipelines in 1999. Ac-
cording to the company, these operations had previously
been performed on Tampen Link on the Statord eld
in the North Sea and on the Ormen Lange eld in the
Norwegian Sea, but the critical T-piece already had been
installed on the pipeline in advance.
For more information about the technology, visit Sta-
toil at booth 430.
Automated rigs increase completions efficiencies
Superior Energy Services has received an award for its
Complete Automated Technology System (CATS), an on-
shore and offshore completion services rig that uses re-
motely operated or preprogrammed robotics to control
various completion components, including a snubbing unit,
BOP/well control stack, pumps, circulation tanks, top drive,
closing systems, and pipe-handling systems,
as part of a single unit.
According to the company, the system
is leading the industry into automated well
completion services with a focus on long-
lateral applications. The use of remotely
operated or preprogrammed robotic com-
ponents allows for safer, more precise op-
erations as well as data collection of
operations, bringing the industry closer to
a manufactured well design that delivers
consistent repeat performance of comple-
tion designs, the company said. The rig re-
quires minimal crew sizes and features
integrated software systems that replace
educated guesses with analytical data for
enhanced decision-making to increase ef-
ficiency at the wellhead.
For more information about the CATS
technology, visit Superior at booth 5833.
Flexible offshore solution turns
associated gas into fuel
Wärtsilä Corp. has received an award for the
Wärtsilä GasReformer, which uses steam re-
forming technology to convert associated
gas recovered in offshore oil production to
a quality that can be used as fuel in the
company’s range of gas-fueled engines.
e technology is based on a known cat-
alytic process from the petrochemical in-
dustry and reneries, where hydrogen is
produced from various hydrocarbon feeds.
e GasReformer exploits the same cat-
alytic process, but it operates under differ-
ent conditions. e technology can
improve the methane number of any fuel
gas up to 100±5 by converting the heavier
hydrocarbons to synthesis gas and nally to
methane. Traditionally such gases would be
ared and otherwise wasted.
According to the Global Gas Flaring Re-
duction Partnership, approximately 150
The Remotely Welded Retrofit Subsea Hot Tap Tee tech-
nology’s ability to connect anywhere on the pipeline
without disruption to production can yield significant
cost savings. (Image courtesy of Statoil ASA)
A step toward automating well completion
services, CATS rigs use remotely operated
or preprogrammed robotics to control
completion components as part of one
unit. (Image courtesy of Superior Energy
Services)
continued from page 5
The Continuous Motion Rig is fully robotized and capable
of running jointed drillpipe and casing continuously.
(Image courtesy of WeST Drilling Products)
23OTC SHOW DAILY | MAY 7, 2013 | TUESDAY
Bcu m (5.3 Tcf) of gas are ared or ventedvery year, caus-
ing some 400 million tons of CO2 in annual emissions.
at is equivalent to 30% of the EU’s gas consumption.
Using an 8-MW GasReformer combined with a dual-fuel
engine, operators can reduce the need for bunkered fuel
oil by about 20 tons per day, according to Wärtsilä.
For more information about the Wärtsilä GasReformer
technology, visit Wärtsilä at booth 1325.
A safer approach to cutting
drillpipe and casing
Welltec has received an award for its Well
Cutter technology. e tool enables
drillpipe, liner, tubing, and casing recovery
operations without the need for explosives
by using a rotating head to remove pipe in-
crementally, preventing the creation of
shavings. A “polishing” trip with drillpipe
also may be eliminated as a result of the
smooth, bevel surface produced from its
cut. Conveyed on electric line for accurate
depth control, the tool incorporates a fail-
safe mechanism that prevents it from get-
ting stuck in the event of power failure. By
eliminating the use of explosives that can
pose operational risks, especially when si-
multaneous operations are being con-
ducted, the HSE impact is signicantly
improved. e transfer of explosives also
can cause logistical requirements and sig-
nicant operational delays, which makes
the tool an attractive alternative for pipe
recovery operations, the company said.
For more information about the Well
Cutter, visit Welltec at booth 1453.
Robotic rig technology provides continuous drilling
WeST Drilling Products AS has received an award for its
Continuous Motion Rig (CMR) technology, the world’s
rst fully robotized rig developed to eliminate safety risk
for personnel and address downhole problems associated
with differential sticking and pressure uctuations.
During the last 20 years the drilling industry has un-
dertaken extensive mechanization and automation of
tasks on the drill oor that traditionally have been man-
ual. Amid efforts to increase the efficiency and safety of
drilling operations through automation, day rates for as-
sociated rig rental and services have increased signi-
cantly. Alternatively, the CMR technology provides
continuous drilling movement of up to 3,600 m/hr
(11,810 /hr) compared to a standard 600 m/hr to 900
m/hr (1,970 /hr to 2,950 /hr), allowing for full circula-
tion and the facilitation of managed pressure and under-
balanced drilling at maximum tripping speed. According
to WeST, the rig is capable of reducing overall drilling
time up to 50% and overall drilling cost up to 40%.
For more information about the CMR technology, visit
WeST Drilling Products at booth 5241. nBy turning waste gas into fuel, the Wärtsilä
GasReformer system significantly lowers
operating costs, particularly for oil plat-
forms and FPSO vessels that demand high
levels of power, while enhancing environ-
mental sustainability.
(Image courtesy of Wärtsilä Corp.)
The Welltec Well Cutter eliminates the
need for explosives in drillpipe and casing
recovery operations.
(Image courtesy of Welltec)
P
lans for a potential LNG terminal onshore East Africa’s
Tanzania are emerging aer a milestone drillstem test
on an ultra-deepwater gas discovery produced better than
expected results.
e UK’s BG Group conrmed in a press release it had
completed the successful drillstem test in Block 1, with ini-
tial results from the Mzia-2 well showing better than ex-
pected properties in the deeper Cretaceous reservoir. e
test on Mzia-2, the rst done on a Cretaceous discovery in
deep water off Tanzania, owed at a maximum rate of 57
MMcf/d of natural gas, constrained by testing equipment.
Mzia-2 is 4 km (2 miles) from the original Mzia-1 dis-
covery and sits in around 1,620 m (5,315 ) of water ap-
proximately 45 km (28 miles) off the coast of southern
Tanzania. It is approximately 22 km (14 miles) to the north
of the Jodari-1 discovery well, also in Block 1, where a suc-
cessful drillstem test was completed in March 2013 on the
shallower Tertiary reservoir.
BG’s minority partner in the Mzia eld, Ophir Energy,
has revealed in a separate press release that it has now up-
graded its mean reserve estimates for the nd by 22% from
3.5 Tcf of recoverable gas to 4.5 Tcf.
BG Group Chief Executive Chris Finlayson said in BG’s
release: “e successful Mzia-2 drillstem test follows com-
pletion of a multi-well appraisal program earlier this year
on the nearby Jodari eld. Results from the current cam-
paign demonstrate the excellent quality of our interests off-
shore Tanzania, where our resources are helping support
plans for a multi-train LNG export project.
“While we continue exploration and appraisal offshore,
BG Group and others are jointly studying suitable sites
for a potential onshore LNG terminal and anticipate pro-
viding proposed locations to the Tanzania government
in the next few months.”
Ophir added in its release that the Mzia-2 appraisal well
drilled in February 2013 had conrmed an estimated 62
m (203 ) of net gas pay in Cretaceous reservoirs, estab-
lishing pressure communication between the Mzia-2 and
Mzia-1 gas columns, and determining a vertical gas col-
umn of at least 200 m (656 ) for the eld.
e Mzia DST was designed to be the rst test of Creta-
ceous age reservoirs in the Tanzanian deepwater play, it
said. Ophir had previously estimated that a threshold ow
test rate of 10-20 MMcf/d would be required to conrm
the commerciality of future production wells from this
asset. “On test, the Mzia-2 DST ow rate was at the very
upper limit of the expected range. e 60-hour main ow
period owed at the maximum equipment limited rate of
57 MMcf/d with a low drawdown (<600psi). Successful
completion of the Mzia-2 appraisal program has validated
the resource potential of the eld and conrmed that ex-
cellent development well productivity may be expected,” it
stated in the release.
Ophir went on to say in the release that the
DST results suggest that the reservoir pa-
rameters that had previously been used to
calculate recoverable volumes in the Creta-
ceous reservoirs were conservative, and that
although further appraisal drilling will likely
be required to determine the total recover-
able resource of the eld, it now estimates
that mean recoverable resources from Mzia
have increased to 4.5 Tcf.
Ophir CEO Nick Cooper said in that
company’s release: “e recent Jodari ow
test demonstrated the excellent reservoir
deliverability potential of the younger Ter-
tiary reservoirs in Tanzania. is Mzia ow
test is a landmark result as the rst time
that the older, Cretaceous reservoir has
been ow tested in Tanzania. By owing at
an equipment-constrained 57 MMcf/d the
Mzia eld has signicantly exceeded our
expectations.
“e Mzia-2 DST result has increased es-
timated recoverable resources from the eld
to an estimated 4.5 Tcf. is ow test result
will boost expected production rates and im-
prove development economics for this asset.
With this better than expected reservoir per-
formance in the Cretaceous, the Ophir-BG
JV will reassess the potential of both the ear-
lier Papa-1 discovery and the remaining
prospects of similar Cretaceous age. is is
another important step forward in Tanzania’s
rst LNG development project and illus-
trates the potential for further considerable
upside in our acreage in Tanzania.”
e drillship Deepsea Metro-1 has now
relocated to Block 4 to drill exploration well
Ngisi-1, adjacent to the existing Pweza and
Chewa discoveries. According to Ophir,
Ngisi-1 is designed with two deviated well
paths to test separate compartments of the
Ngisi prospect and the deeper Chewa dis-
covery. It estimates Ngisi-1 could increase
the mean in-place resource of the Chewa-
Pweza-Ngisi hub to 5.8 Tcf in place (4.1 Tcf
mean recoverable) and “will provide critical
scale for gas aggregation and development
from Block 4,” according to its release.
BG and Ophir will use data from the cur-
rent exploration and appraisal campaign and
a recently completed 3-D seismic survey to
help identify new targets for a third explo-
ration program beginning later this year.
Prior to Mzia-2, BG’s acreage offshore
Tanzania had produced seven consecutive
natural gas discoveries, two successful ap-
praisal wells, and a successful test on Jodari
e UK company is operator with a 60%
interest in Blocks 1, 3, and 4, with Ophir
holding 40%. n
BY MARK THOMAS
24 TUESDAY | MAY 7, 2013 | OTC SHOW DAILY
A
s well trajectories become more complex and costly,
there is an increasing need to drill less wells to pro-
duce more hydrocarbons. However, with increasing ge-
ological complexity of drilling targets, there has been an
unwelcome rise in the amount of nonproductive time
(NPT) associated with unexpected geological and geo-
mechanical events. In today’s environment, especially in
deep water, achieving drilling success requires addressing
difficult well construction challenges with minimum
NPT, while at the same time remaining focused on the
ultimate goal of meeting the geological objectives.
Exploration drilling campaigns usually target potential
hydrocarbon reservoirs with wells placed through surface
seismic imaging. Acoustic velocities used for the depth
conversion – derived from seismic data – are
inexact for the purpose, and drilling target
depths based on such conversions will have
intrinsic errors. ese uncertainties not only
introduce exploration risk related to the in-
tegrity of the reservoir trap and its potential
hydrocarbon volumes but also manifest
themselves as drilling risk, both in the loca-
tion of targets or hazards and in the estima-
tion of pore pressure ahead of the bit.
Until recently, exploration and develop-
ment drilling followed a fundamentally se-
quential approach that started with a
geological depth model based on an inter-
preted seismic volume. e model then made
corrections to the depth prole along the 1-
D well trajectory based on logging measure-
ments made either while drilling or soon aer
by wireline. A new seismic guided drilling
(SGD) methodology has now been developed
by Schlumberger that takes an integrated and
fully 3-D approach, combining iterative sur-
face seismic depth imaging and anisotropic
velocity modeling workows constrained by
data from the well being drilled. is is used
to produce new calibrated 3-D models ahead
of the bit to aid drilling decisions.
e SGD methodology uses newly ac-
quired borehole logging data to iteratively
improve the accuracy of the 3-D seismic
model around the well trajectory. As new
well log data become available – particu-
larly seismic checkshot velocities from
LWD or wireline – the local anisotropic
earth velocity model is updated, and
prestack depth migration (PSDM) is rap-
idly reapplied to the surface seismic data.
is helps to reduce uncertainty about the
geology ahead of the bit. Pore pressure re-
nement is possible up to 457 m (1,500 )
ahead of the drill bit. Improved knowledge
of the location of reservoir targets and geo-
hazards such as faults support proactive
decisions regarding well placement and is-
sues such as casing planning.
e SGD methodology is enabled by
technological advances in real-time LWD
measurements coupled with large in-
creases in cost-effective compute power.
e method requires iterative PSDM of a
surface seismic data volume typically 5 km
by 5 km (3 miles by 3 miles) centered on
the well location. Until recently, processing
of such a dataset would require several
weeks, but it can now be performed within
a time relevant for a drilling schedule. To
facilitate this multidisciplinary approach,
fully integrated soware platforms are re-
quired that can be used by skilled teams of
experts able to convert new calibrated log-
ging data into the information needed to
support rapid well construction decisions in real time.
e SGD methodology has been applied in several
deepwater exploration and development basins around
the world to iteratively update geological models based
on increasingly accurate knowledge of the acoustic ve-
locity of formations ahead of the bit. In its 2011 to 2012
report the Directorate General of Hydrocarbons, a body
of the Indian government, noted that applying the SGD
approach in the country had resulted in enhanced sub-
surface denition and improved well placement, coupled
with considerable cost and time savings.
To learn more about how the SGD methodology can
help achieve the increasingly difficult goals of both
drilling wells safely and successfully to total depth while
also meeting the geological needs for the wells and the
asset, visit Schlumberger at booth 4441. n
CONTRIBUTED BY SCHLUMBERGER
25OTC SHOW DAILY | MAY 7, 2013 | TUESDAY
SGD updated the pore pressure model ahead of the bit
while drilling. The model was confirmed by formation
pressures taken after drilling. (Image courtesy of
Schlumberger, and data courtesy of Oil and Natural
Gas Corp. Ltd.)
