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CONNE US
Totally ConformableRevolutionizing sand management with shape
memory polymer foam
Brazils Big OilPre-salt: The worlds next big opportunity
The Booming BakkenUnlocking the secrets of the giant shale
play
2011 | Volume 2 | Number 1
The Baker Hughes Magazine
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In the inaugural issue of Connexus, Chad Deaton, our CEO,
discussed the new Baker Hughes. The last few years have been an
exciting time of change for Baker Hughes and today, we are
executing on our expanded business capabilities to better serve
customers across every phase of their operations.
The geomarket organization we established in 2009 is delivering
stronger market understanding, a coordinated products and service
offering, and closer relationships with our customers. For example,
the stories on Pages 11-15 describe how our Brazil team is building
strong ties with customers. We work closely with Petrobras and
other companies in Brazil to understand their challenges and to
develop the technologies needed to unlock reserves locked in
offshore Brazils complex reservoirs. We will open a region
technology center in Rio de Janeiro later this year to build even
stronger technology relationships with our customers.
The reservoir competencies weve added to our product portfolio
are now embedded in the business. We are identifying opportunities
across the asset life cycle to help our clients maximize the full
value of their prospects and elds. You will nd an example of this
integration of our portfolio in the story on Page 50 that describes
how the collaboration between the reservoir team and our Southeast
Asia geomarket is helping clients better understand fractured
basement reservoirs. Also, we were recently awarded a contract by
PETRONAS Carigali to revitalize the mature elds in the D-18
production area offshore Malaysia. This project will bring together
the full breadth of Baker Hughes reservoir capabilities and
products and services to partner with PETRONAS Carigali for a full
eld redevelopment.
The integration of BJ Services has been faster and smoother than
we anticipated. The merger
BEYOND TRANSFORMATIONPresident and Chief Operating Ofcer Martin
Craighead
-
was a perfect t. In North America, we are offering a coordinated
suite of technologies, including drilling, completion, pressure
pumping, and production products and services designed to lower
operating costs and maximize production. This is particularly true
in the shale plays where the right solution is critical to economic
development. The story on the Bakken shale (Page 20) details how we
are solving customer challenges in this prolic play.
Pressure pumping also is an important addition to our
international portfolio. On Page 4 you can learn more about how we
have integrated our drilling, completion, stimulation and
production expertise to provide Petrobras and other companies in
Brazil innovative solutions to their deepwater challenges.
Of course, technology innovation is the foundation of Baker
Hughes business, and we are in the midst of one of the most
exciting technology development eras in our history. We now have an
enterprise technology strategy that is market centered, business
oriented and research enabled. We have developed a clearer
commercial framework for technology-led business innovation.
We have charted a course to increase the velocity of technology
through our system and to focus on commercial results. As a
consequence, we are concentrating on the most critical technology
developments in our ideation pipeline, and we have improved our
speed to market in many cases by a factor of three. The result
is innovative technology advancementstruly disruptive step changes
to some of our customers biggest challenges. On Page 16 you will nd
an in-depth article on one of those technologies. The GeoFORM sand
management system is an outgrowth of our fundamental science
initiative and represents an entirely new approach to sand control
that will lower risk factors and improve productivity from
unconsolidated reservoirs.
As we accelerate the execution phase of building the new Baker
Hughes, it is important to acknowledge that this level of change
comes with a certain amount of stress. I have to commend our global
workforce for the hard work and perseverance to see us through this
time of ux. Our people were asked to take on new roles, often in
new places, and often with a great deal of ambiguity. It may sound
clichd, but its truethe greatest asset for any organization is not
its monetary capital, but rather its people, and the teams all
across Baker Hughes have pulled together to ensure that our
customers needs have remained our singular focus.
To fully leverage the strength of our organization to better
serve customers, its been necessary to redesign how we work. We now
have an operating system in place to reduce the complexity of our
business and drive standardization across operations and product
lines. The key to an effective global operating system lies in its
ability to capture optimization and
pollinate the organization with learning. We are already seeing
its impact at every level of our business. For example, there are
processes and procedures in place today designed to guide our
global quality and reliability program; to assess market needs; to
recruit and develop talent; and to manage our portfolioall
important business drivers that add value for our customers.
Going forward, we will measure our success. Ultimately, the goal
is to make accountability the core of our culture. I am a rm
believer that you get what you measure and we have a process in
place to measure ourselves as our customers and our investors
measure us. We track operational key performance indicators at a
global level to give us visibility to trends in our business and at
the local level to get a more granular view of our operations. No
function gets a passwe also have standard key performance
indicators for our global teams like products and technology and
supply chain.
In closing, I am excited about our substantial progress toward
executing on our strategies to build a customer-focused operation
and a stronger portfolio. Of course, none of this would be possible
without the support of you, our customers. We sincerely appreciate
the opportunity to work with you to solve your reservoir, drilling
and production challenges.
| 1www.bakerhughes.com
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Advancing Technology FrontiersBaker Hughes is constructing a new
$30- million research and technology center in Rio de Janeiro to
support the industrys economic development of pre-salt reservoirs
offshore Brazil.
Intellectual RelationshipsAnticipating growth in Brazil, Baker
Hughes put a strategy in place to grow business and foster
long-lasting customer relationships.
Reshaping Sand ControlA totally conformable sand screen
engineered from shape memory polymer foam has the industry
rethinking sand management.
Unlocking the BakkenAdvances in drilling and completion
technology are lowering operating costs and enhancing production
performance for operators in the Bakken shale.
Industry InsightJames J. Volker, chairman, president and CEO of
Whiting Petroleum, shares insight into producing some of the top
oil shale plays in the U.S. and the technologies needed for the
future.
Real-time Solutions in RussiaNew technologies applied on wells
drilled in northwest Siberias Yamal Peninsula are helping operators
reach new levels of productivity.
Clean, Efcient FracturingAn innovative hydraulic fracturing
technology dramatically cuts water and chemical requirements to
safely and efciently stimulate gas production from shale formations
in environmentally conscious New York.
Faces of InnovationMeet Bennett Richard, the newest Baker Hughes
Lifetime Achievement Award winner, who enjoys developing people as
much as technologies.
Ghanas First OilAs a key player in the Jubilee project, Baker
Hughes is determined to make this African countrys rst oil pay off
for the people.
The Complete PackageThe OptiPortTM completion system combines
coiled tubing with sliding sleeves to take multistage fracturing to
new levels.
Contents 2011 | Volume 2 | Number 1
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On the Cover Rio de Janeiro occupies one of the most spectacular
settings of any metropolis in the world.
Big OilWith Brazils pre-salt reservoirs poised to be the worlds
next big opportunity, Baker Hughes is focused on establishing a
deepwater center of excellence in Brazil to deliver customized
answers to the toughest of challenges.
2 |
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5016
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60
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Whats in Your Basement?From constructing detailed geomechanical
and reservoir volumetric models to record-setting drilling and
evaluation performance, Baker Hughes is delivering results in Asia
Pacics fractured basement reservoirs.
Geothermal Hot SpotWith the Baker Hughes Center of Excellence
for geothermal and high-temperature research and development in
Celle, Germany, the company is well positioned to support the
growing demand for geothermal power in continental Europe.
Good NeighborsA grant from Baker Hughes is helping enterprising
Kazakhstani youth make a positive contribution to their
community.
Latest TechnologyBaker Hughes develops and delivers new
technologies to solve customer challenges.
A Look BackR.C. Bakers contributions to the petroleum industry
helped launch todays Baker Hughes.
is published by Baker Hughes global marketing. Please direct all
correspondence regarding this publication to
[email protected].
www.bakerhughes.com
2011 Baker Hughes Incorporated. All rights reserved. 32310 No
part of this publication may be reproduced without the prior
written permission of Baker Hughes.
Editorial TeamKathy Shirley, corporate communications
managerCherlynn C.A. Glover, publications editorTae Kim, graphic
artistStephanie Weiss, writer
Printed on recycled paper
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BIGOILA glass-paneled cable car destined for the peak of Sugar
Loaf is the perfect venue for a million tourists a year to enjoy
the sights and sounds of Rio de Janeiro: the white sands of
Copacabana beach, samba in the streets and the Cristo Redentor
statue, one of the new Seven Wonders of the World.
Far beyond the outstretched arms of the art deco statue lie even
greater wonders: huge nds that, by industry estimates, hold between
50 and 100 billion barrels of oil. Its enough to transform Brazil
into one of the worlds top ve crude oil producers.
Brazils Pre-salt: The Worlds Next Big Opportunity
4 |
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Petrobras, the Brazilian state oil company, announced plans to
invest $224 billion from 2010 to 2014 to help Brazil become a major
energy exporter by tapping the vast reserves buried some 7 km (4
miles) beneath the ocean in what is known as pre-salt
reservoirs.
In 2007, while drilling in more than 2.1 km (1.3 miles) of water
in the Tupi prospect of the Santos basin, Petrobras made a huge
discovery in the pre-salt. Almost instantly, the company knew two
things: It had found a supergiant oil eld, and producing it was
going to require technologies yet unknown to the industry. (The
Tupi prospect was renamed Lula in December 2010 in honor of
outgoing Brazilian President Luiz Incio Lulada Silva.)
The pre-salt reservoir lies in water depths up to 3 km (1.8
miles) and beneath a vast layer of salt, which, in certain areas,
can be as much as 2 km (1.2 miles) thick. Above the salt canopy lie
1 to 2 km (.62 to 1.2
miles) of rock sediments, and below it lies the
actual oil-laden pre-salt bounty, 5 to
7 km (3.1 to 4.3 miles) below the
oceans surface (see Fig. 1).
The challenges run deepThe Brazilian pre-salt discoveries open a
new frontier in exploration and development not only for Petrobras,
but for the many international oil companies moving into these
waters. However, exploring, drilling and producing the reservoirs
present operators with incredible challenges related to the
complexities of the carbonate reservoir rocks, the ow assurance
issues due to the nature of the oil and production conditions, the
separation and disposal of the CO2 in the produced gas, and the
handling of the produced water. Add to that ultradeep water and the
remoteness of the elds themselvessome 250 to 350 km (155 to 217
miles) from landand the challenge of producing these elds grows
exponentially.
From microbial limestone deposits in ultradeep watersome
containing very hard and abrasive dispersed silica or nodules
similar to quartzto a variety of creeping salts, Brazils deep water
is a geological puzzle.
| 5www.bakerhughes.com
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Depending on the area and depth you are working in, you face
completely different reservoir lithologies, says Luiz Costa,
completion engineering manager for Baker Hughes in Brazil.
Sometimes, those big differences can occur within one single
well.
Abdias Alcantara, marketing and business development manager for
Baker Hughes drill bit systems, agrees. The pre-salt environment
consists of reservoirs that are complex heterogeneous carbonates.
The deposition is not like a typical sequence of rock with one
smooth layer upon another, he explains. You might be drilling
through intercalated shales, then drill a few meters in
another direction and
discover something different. These zones are very unpredictable
and
some of the toughest weve ever drilled.
Baker Hughes has recently deployed two differentiating wireline
technologiesthe MaxCOR system and the FLEX tool as part of the
RockView system, both developed in collaboration with Petrobrasto
help characterize these reservoirs so more effective drilling and
production programs can be designed. The RockView system combines
geochemical data to compute detailed lithology and mineralogy
descriptions of the formation. It collects geochemical data that is
used to determine the mineral
properties, amount and distribution of total organic content in
a reservoir.
The MaxCOR system is a rotary sidewall coring technology that
enables the recovery of more than three times more core volume and
up to 60 cores, when compared to standard rotary coring tools. The
MaxCOR system can drill and retrieve multiple 1-in. diameter core
samples greater than 2 in. in length in minutes, greatly reducing
rig time dedicated to coring operations. The higher core volumes
provide better results when analyzing mechanical properties,
relative permeability, compressibility, capillary pressure,
electrical parameters and geomechanical properties.
In these ultradeep waters, where rig spread-rates can easily
reach $1 million a day, it is imperative to push the technology
envelope. Marcos Freesz, pre-salt project manager in Brazil, says
that Baker Hughes has implemented a strong downhole monitoring
philosophy to improve drilling performance and drilling rates in
both the salt layers and the pre-salt formations.
In the salt, we are mainly using the CoPilot real-time drilling
optimization service and AutoTrak rotary steerable system to push
the rate of penetration (ROP) to technical limits, Freesz says.
Weve seen a 159-percent increase in average penetration rates from
when we rst started drilling two years ago.
Using its TruTrak motor closed-loop system, Hughes Christensen
Quantec
Fig. 1
6 |
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PDC bits and the CoPilot service in the pre-salt carbonate
section, Baker Hughes has increased ROP more than 300 percent,
Freesz adds. Besides improved penetration rates, the process is
focused on maintaining bit cutting structure for as long as
possible, thus eliminating bit runs, which equates to customers
spending less on rig time, as well as a reduction in associated
HS&E risk.
Baker Hughes has drilled four pre-salt wells with this system
approach. From the rst well until now, this solution has reduced
vibration levelsthe biggest challenge to drilling performancealmost
100 percent, Freesz says. We have tested 12-in. and 8-in. Quantec
PDC bit designs with the most impact-resistant cutters, and
although performances cannot be totally replicated yet, were seeing
a consistent optimization improvement through a very important and
steep learning curve.
In the reservoirs above the salt canopy (post-salt) in the
Campos and Espirito Santos basins, quite a different geological
objective is being successfully achieved with horizontal well
drilling using the AziTrak azimuthal deep resistivity system
coupled with full Reservoir Navigation Services (RNS) in real time,
adds Jeremy Jez Lofts, director of strategic business development
for Baker Hughes in Latin America.
In a continuing effort to better understand the complexities of
drilling these formations, Baker Hughes is working with CENPES, the
research arm of Petrobras, and with the
Universidade Federal do Rio de Janeiro to establish the worlds
most highly sophisticated drilling laboratory simulator that will
help develop and test technologies to further bolster drilling
capabilities.
Deepwater center of excellenceBaker Hughes entered the Brazilian
market in 1973 when Hughes Tool Company acquired a roller cone bit
manufacturing facility in Salvador, the capital of Bahia state.
Since the very start, the company established itself as the major
drill bit supplier in the Brazilian oil industry.
For the past three years, Baker Hughes has been the leading
directional drilling provider for Petrobras, while its articial
lift product line now holds the leading market share in electrical
submersible pumping (ESP) systems in Brazil. The drilling uids
product line in Brazil also has the lions share of all the activity
planned by Petrobras for the next ve years through a major contract
to provide technical services, drilling uid chemicals, brine
ltration equipment and environmental services (including solids
control and waste management services and equipment).
With the huge growth and opportunity of both the Brazilian
deepwater pre-salt and post-salt formations, and with some of the
most advanced deepwater technologies available, Baker Hughes is
focusing on ensuring success for operators here by becoming a
deepwater center of excellence that designs and delivers customized
answers to the
toughest of challenges, Lofts says.
One example is Shells BC-10 project in the Campos basin, which
encompasses three separate eldsOstra, Abalone and Argonauta, says
Ignacio Martinez, technical support manager for articial lift and
ow assurance. Each eld presented different
01> A 500-km (310-mile) long, 15 to 20-km (9 to 12-mile) deep
seismic section into the upper crust of the earth shows the
sedimentary succession from near surface post-salt oceanic
sediments deposited after the Atlantic ocean opened, including salt
evaporite layers, basin sag sediments (including pre-salt
reservoirs), to synrift and prerift sediments and the uppermost
crust.
02> A silica nodule and associated siliceous laminations such
as these found within the pre-salt carbonate reservoir sequence
tend to pose unpredictable drilling obstacles and ones that must be
constantly monitored to ensure that drill bit life and ROP are
maintained.
Log
grap
hic
cour
tesy
of I
ON
-GXT
01
02
| 7www.bakerhughes.com
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challenges that resulted in a collaborative approach to boost
liquids ve miles along the seabed and, then, approximately 1524 m
(5,000 ft) up to the FPSO. Baker Hughes installed its Centrilift XP
enhanced run-life ESP system in six vertical subsea boosting
stations on the seaoor. The systems are designed to boost the FPSOs
maximum capacity of 100,000 barrels of uid per day.
ESP design considerations at BC-10 included temperature cycling,
rapid gas decompression, high-horsepower lift requirements and
high-uid volumes. To overcome these challenges, Baker Hughes
employed newly developed technology to handle the uid volumes with
the required high differential pressurethe Centrilift XP
high-horsepower motor for enhanced reliability and a redesigned
seal to withstand rapid gas decompression and high-thrust forces
from the pump.
Critical to the solution was planning the ESP system as an
integral component to the entire hardware conguration. This differs
from the approaches where the ESP system is considered as a
separate item instead of being preplanned as part of the nal
conguration, Martinez explains. This project presented unique
challenges and demanded innovative approaches to meet Shells needs.
Although we have a demonstrated track record in subsea
applications, the complexity of this subsea infrastructure and
associated procedures for BC-10 called upon many of our combined
resources.
A complete technology portfolioBaker Hughes provides a full line
of capabilities related to reservoir characterization, drilling,
intelligent well completions, cementing and stimulation techniques
offshore Brazil.
New solutions will be needed, however, to meet Petrobras
requirements for the future, including:
A better understanding of reservoir heterogeneity in the complex
microbial carbonate environments
Faster, safer drilling and better quality wells in very
challenging ultradeepwater environments
More intelligent production and completions technology that uses
materials and equipment almost tailor-made for the characteristics
of the developments
Improved reservoir hydrocarbon stimulation techniques
Well integrity in unstable thick salt layers
Baker Hughes has been the leader and pioneer in intelligent well
systems and multilateral installations in deepwater Brazil. More
than 70 percent of Brazilian offshore
01
Phot
o co
urte
sy o
f St
fers
on F
aria
, Pet
robr
as
01> The FPSO Cidade de So Vicente in the Lula eld in the
Santos basin
02> Baker Hughes stimulation vessels, the Blue Angel (left)
and the Blue Shark, docked in Rio de Janeiro
03> Service Supervisor Tom Lister aboard the West Polaris
deepwater rig outtted with the new generation BJ SeahawkTM
cementing unit
8 |
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wells are equipped with Baker Hughes well monitoring systems,
Costa says. We are nalizing the completion of the rst pre-salt well
with an intelligent well system installed to monitor and control a
deep, dual-zone, gas-injector well in the Lula eld, in the Santos
basin.
In sand control, Baker Hughes is introducing in Brazil the rst
Pay Zone Management system in the world. This system allows
horizontal openhole gravel packing in offshore wells and injection
of chemicals at several points along the screen. The rst
installation will use chemicals only, but there is an option to
connect ber optics, hydraulics and electronics, Costa adds.
Outside the Gulf of Mexico, Brazil is the only other place in
the Western Hemisphere where Baker Hughes has stimulation vessels.
The joining of the pressure pumping product line with the rest of
the Baker Hughes service lines certainly increases our
overall volume of business in the country and our platform for
growth, says Edgar Pelez, Baker Hughes vice president, business
development and marketing, Latin America. Baker Hughes has the
majority of the stimulation vessel market in Brazil.
Baker Hughes has three stimulation vessels under an exclusive
contract to Petrobrasthe Blue Shark, the Blue Angel and the Blue
Marlinall based in Maca, 200 km (125 miles) north of Rio de
Janeiro. In Brazil, pressure-pumping operations perform between
1,200 and 1,300 jobs a year, including cementing, stimulation,
coiled tubing services, wellbore cleanup, casing running,
completion tools, ltration uids and chemical services, says Luis
Duque, engineering and marketing manager for pressure pumping in
Brazil.
Most of the wells are highly deviated or horizontal with
production sections as long as 2000 m (6,561 ft), Duque explains.
The
biggest challenge while stimulating these wells is to perform an
effective treatment to cover the entire production section. So far,
the technologies weve used to achieve this goal are self-diverting
acid, gelled acids and fracturing assisted by a sand jetting tool,
among others.
Regarding cementing, the biggest challenges are the deepwater
locations, wells around 6200 m (20,341 ft) total depth, the thick
salt layer to pass through, and bottomhole temperatures up to 250F
(121C). We have introduced some new technologies in cementing, such
as our BJ Set for Life family of cement systems, which were
developed to attend to the wide variety of scenarios found in elds
like these, such as loss-circulation zones and reservoirs with high
CO2 and H2S contents. Weve also recently introduced and
successfully tested the concentric coiled tubing BJ Sand-Vac well
vacuuming system for hydrate removal in owlines.
With the huge growth opportunity of both the Brazilian deepwater
pre-salt and post-salt formations, and with some of the most
advanced deepwater technologies available, Baker Hughes is focusing
on ensuring success for operators here by establishing a deepwater
center of excellence that designs and delivers customized answers
to the toughest of challenges. Jeremy Lofts Director of strategic
business development for Baker Hughes in Latin America
02 03
| 9www.bakerhughes.com
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Building for the futureContinuing to deliver technologies to
help understand and produce these complex reservoirs is critical to
maintaining a competitive edge in this new frontier, says Saul
Plavnik, drilling and evaluation operations director for Baker
Hughes in Brazil. But the true advantage lies in planning now for
technologies that will be needed as this market moves beyond its
infancy.
Baker Hughes and Petrobras have a long history of joint
technology development, Plavnik says. Over the next four years, we
jointly plan to spend more than $40 million on technology
collaboration projects that include, among others, 3D vertical
seismic proling to enhance surface seismic data; the understanding
of geomechanics-while-drilling; hydraulic, electrical and optical
completion automation; and the inuence of Baker Hughes inow control
devices and well geometries in microbialite reservoirs.
Together, we are already building a vision for the future.
Team Brazil Marks Two Drilling Milestones in 2010Late in 2010,
Baker Hughes Brazil celebrated the milestone of drilling 2 million
ft (609 600 m)most of it in water depths greater than 1,000 ft (305
m). In a second record, the Baker Hughes Brazil geomarket passed 1
million ft (304 800 m) of drilling with the Baker Hughes AutoTrak
rotary steerable drilling system.
This is a very proud moment for all involved in this fantastic
achievement. AutoTrak is an automated, closed-loop drilling system
designed exactly for these complex deepwater offshore environments,
where it is routinely being deployed with great success, says
Wilson Lopes, sales director for the Brazil geomarket.
This milestone and performance position us very well, as a
preferred partner, for the expected growth in the emerging
ultradeepwater pre-salt plays, adds Jeremy Lofts, director of
strategic business development for Baker Hughes in Latin
America.
The Brazil drilling systems business has grown from just two
operations with Petrobras to 22 operations in only three years, and
it has diversied to drilling for other oil companies, as well. This
entails a lot of hard work and achievement by the entire team, says
Mauricio Figueiredo, Baker Hughes vice president of Brazil. We are
very proud.
Baker Hughes Completes First Directional 2D Well in Salt In
March, Baker Hughes drilled the rst directional 2D well kicking off
in salt in the ultradeep Tupi cluster area of the Santos basin
offshore Brazil. Based on our track record of experience, processes
and performance, we were very honored to be the directional
provider for this important well, Figueiredo states. This signicant
milestone marks the move to better understand the optimum well type
needed to produce this vast hydrocarbon play offshore Brazil, as
well as to satisfy tieback logistics.
The 2D well trajectory was executed exactly as planned, and the
rate of penetration achieved was comparable to vertical sections,
adds Johan Badstber, technical director, Brazil. The 14-in. section
was kicked off within the salt (3.9 inclination) and the angle was
built up to 23.4 inclination with 2/100 ft dogleg severity, and
then kept at tangent until TD. AutoTrak G3TM, OnTrak and CoPilot
technologies were run with a PDC bit, and the CoPilot on-site and
remote drilling optimization service (provided from the clients
ofces in Santos) proved key to the success. The well construction
general manager for the Santos customer states, Now, directional
wells into the salt dont seem a monster. The performance obtained
after drilling 1850 m (6,069 ft) was 14.3 m/h average penetration
rate in a 14-in. section, outpacing peer performance of 12.5 m/h in
a nearby vertical section. These types of jobs are consolidating
Baker Hughes in a top position relative to evaporate drilling,
Badstber adds.
> Drilling 2 million ft was cause for celebration in Maca,
Brazil, where Baker Hughes has a major operations base and a drill
bit manufacturing facility.
10 |
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The future of this industry will demand technology. We are
looking each day to a more challenging environment. The easy oil is
gone. Without the proper technology, we wont produce.
Carlos Tadeu da Costa Fraga Executive manager, Petrobras
Research and Development Center
Rio Research and Technology Center
Advancing Technology Frontiers
The supergiant pre-salt discoveries offshore Brazil bring new
technological challenges and demand for additional infrastructure
investments. To help meet these challenges, Baker Hughes is
involved in a dozen collaboration projects with Petrobras and is
constructing a regional technology center to support the industrys
quest for technology necessary to economically develop pre-salt
reservoirs in ultradeep water offshore Brazil.
Under a cooperative agreement signed in 2009, Petrobras and
Baker Hughes will invest $16.4 and $29 million, respectively, to
jointly develop and apply new technologies to help address some of
the challenges in pre-salt exploration and production.
Baker Hughes is investing approximately $30 million to build its
Rio de Janeiro Research and Technology Center (RRTC). The center is
under construction within
| 11www.bakerhughes.com
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the area known as Science Park on Ilha da Cidade Universitaria
(University Island), an articial island that serves as home to one
of the largest universities in Brazil and several research
centers.
Ilha da Cidade Universitaria, formerly known as Ilha do Fundo,
is also home to CENPES, the Petrobras research and development
center that employs approximately 2,000 people. Last year,
Petrobras celebrated the opening of a $700-million expansion to the
CENPES facilitiesalready one of the largest in the oil and gas
industrydoubling the size to 305 000 m2 (3.3 million ft2).
The capacity for technology innovation in Brazil has been
increased dramatically with this expansion, says Carlos Tadeu da
Costa Fraga, executive manager, Petrobras Research and Development
Center.
Brazilian universities and R&D institutions have also been
investing in the expansion of their capabilities. We believe that
we have in Brazil some of the best test facilities in the world,
and Petrobras plans
to attract the most important suppliers to join these
institutions to develop a new generation of technology needed to
produce the pre-salt reservoirs.
We look to all of these institutions as an extension of our
facility, in the same way we would like to have Baker Hughes see us
as an extension of their R&D facility, he continues. Theirs has
to be seen not as a different facility but as part of the whole
effort to increase the capacity of Brazil to fulll the gap in our
upstream activities. Baker Hughes has been one of the companies to
show the most aggressive contribution toward our strategy, and we
recognize the companys true commitment.
Petrobras wants us to help them solve problems, says Dan Georgi,
vice president of regional technology centers for Baker Hughes.
They have a stated objective to use the best technologies
available. In 2014, when they plan to start a lot of their major
developments, they want to have available new technology that will
help them recover and produce more
oil at a lower cost. They are looking at us and the other
service companies and universities to advance the frontier.
The Baker Hughes RRTC will facilitate collaboration between
Baker Hughes and Petrobras, as well as the many international oil
companies working offshore Brazil, and four universities:
Universidade Federal do Rio de Janeiro (UFRJ), Universidade
Estadual de Campinas (Unicamp), Pontifcia Universidade Catlica do
Rio de Janeiro (PUC/RJ) and Universidade Estadual do Norte
Fluminense/Laboratory of Engineering and Petroleum Exploration
(UENF/Lenep).
Baker Hughes is involved in several ongoing research projects
with these universities, including an evaporate drilling project
with PUC and reservoir engineering studies for production
optimization with intelligent wells with Unicamp. In addition,
Baker Hughes is working with CENPES and UFRJ to establish a
world-class drilling laboratory simulator.
> The Rio drilling lab will house the worlds largest
high-pressure drilling simulator, approximately twice as powerful
as the simulator at the drill bit systems product center in The
Woodlands, Texas, shown here.
12 |
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This drilling lab will house the worlds largest high-pressure
simulator, capable of drilling 24-in. diameter rock cores with a
14-in. bit. These cores will be pressurized to simulate downhole
conditions up to 20,000 psiemulating an approximate depth of 42,000
vertical ft (12 801 m) when utilizing a standard 9.5 ppg
water-based mud, explains Paul Lutes, manager for testing services
at the Baker Hughes drill bit systems product center in The
Woodlands, Texas.
The bit will be rotated either through a conventional rotary
table arrangement or via downhole motor/turbine, which will be fed
up to 500 gallons per minute at maximum pressure, or up to 1,000
gallons per minute at 6,000 psi.
While this rig will not physically be much larger than the
simulator we have in The Woodlands, it will be approximately twice
as powerful, Lutes adds. Power is what allows you to test at higher
pressures and greater speeds. That is why it will unquestionably be
the worlds largest high-pressure simulator.
A facility of this size will recreate the downhole conditions
encountered in the pre-salt sections offshore Brazil. In order to
optimize drilling parameters, it is necessary to simulate as much
of the bottomhole assembly as possible. Therefore, the potential to
add a drilling mud motor has been planned into this system.
Capabilities to test with increased mud and rock temperatures,
and to handle highly porous rock and control pore pressure are also
under evaluation.
Initially, the Baker Hughes Rio de Janeiro Research and
Technology Center will focus on:
Wellbore construction optimization, especially for deepwater and
pre-salt carbonates
Salt and pre-salt geomechanics, including impact on borehole
stability and completion and production
Reservoir optimization, including application of intelligent
wells, flow assurance and multifunctional scale and asphaltene
inhibitors, and artificial lift technology
Reservoir description enhancement and reservoir optimization of
microbial carbonates
The centers primary objective is to provide cost-effective
solutions to Petrobras, Georgi says. We plan to do this by driving
deepwater pre-salt reservoir cost reduction for wellbore
construction, and reservoir productivity and recovery-factor
optimization with advanced application engineering and geoscience;
rock, uids and materials testing; and support of eld tests.
The facility will house an analytical lab; laboratories for
cement evaluation; H2S and CO2 laboratories; a rock uids properties
and materials testing lab; a room for core analysis; a shop
suitable for testing logging-while-drilling, wireline and
intelligent wells tools; ofces and think pads for the approximately
90 employees who will work there when the center reaches its full
capacity.
With this center, we will be able to expedite what were
currently doing with our larger technology centerssuch as the drill
bit systems center in The Woodlands and the articial lift systems
facility in Claremore, Oklahomawhich are responsible for providing
technologies to the whole globe. This facility will be much more
focused on making sure we have the
right technologies in Brazil, Georgi says. If a product needs to
be customized in order to make it work better in the local market
or if we need to develop software for interpretation algorithms to
customize the project to the local market, we will be able to
understand what our clients problems are faster, then work with our
various groups outside of Brazil to shorten the development cycle
and to make the technology delivery more efcient.
Georgi also expects the whole of Baker Hughes to benet from the
Rio de Janeiro Research and Technology Center. We will be
interacting with the best and brightest minds in Brazilian
universities and will undoubtedly be able to attract some of them
to work for Baker Hughes in Brazil and throughout our organization,
not to mention new and enhanced technology that will ow from the
center to other parts of the globe, he adds.
Csar Muniz has been appointed director of the RRTC, scheduled
for completion by the end of 2011. Muniz brings 25 years of
experience in exploration, production and project management to the
position, having worked with Petrobras, Chevron and Repsol.
We are condent that we are going to deliver very creative
solutions with Baker Hughes, Tadeu says. Given the size of the
potential business, the demand for innovation of the deepwater
portfolio and the local content issue, why not establish a
long-term relationship with Baker Hughes in Brazil? This can become
a very important hub for its worldwide technological development
and, in turn, create what we have been calling a new generation of
technologies for oil and gas production in deep and ultradeep
water.
| 13www.bakerhughes.com
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There was a time when a service company provided little more
than muscles and tools. Thats no longer the case. Todays service
company is one that delivers solutions through collaboration and
partnerships.
INTELLECTUAL RELATIONSHIPSSmart planning for exploring the
future together
For Baker Hughes in Brazil, the shift began when the leadership
put a strategy in place to focus on anticipated growth. That
strategy included investing in the best technologies and bringing
in a network of technical experts that not only could grow the
business but forge long-lasting customer relationships.
We started with a major investment with our drilling and
evaluation business, and today, Baker Hughes holds more than 50
percent of the directional drilling market with Petrobras, says
Mauricio Figueiredo, Brazil vice president. In addition, weve
invested a lot in subsea completions, establishing an important
leadership position for our articial lift business in deepwater
environments. We now have more than 60 percent of that market
share. This represents a huge growth from four or ve years ago,
and it has a lot to do with having the right strategy in place and
pursuing the most promising opportunities in the market, not only
with Petrobras, but with other companies, as well. It also has to
do with knowing and understanding our customers better.
Because of the size of their portfolios, many major operators
are becoming technical partners with their suppliers through the
formation of intellectual relationships, says Edgar Pelez, vice
president of marketing for Baker Hughes in Latin America.
We, as service companies, are understanding better the business
of the operator and are able, with technology and operations, to
provide alternatives and
solutions to the end result. Instead of telling us what to do,
the operator is asking us, How do I solve this challenge? Then, we
offer a solution and the reason for it, rather than just providing
the mechanics of the job, Pelez adds.
I think that Petrobras sees Baker Hughes as a true partner. Weve
fostered customer relationships, and thats one of our main
strengths in Brazil. It is one where we are happy to say that upper
management of both companies calls each other by rst names, and
that is not necessarily something we can do with all our customers
around the world.
The other strength is the commitment of Baker Hughes to Brazil.
We have committed major investments in facilities,
> Baker Hughes hosted a three-day workshop in December 2010
for Petrobras at its Center for Technology Innovation in
Houston.
14 |
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in people and in the deployment of technology to support the
growth. This commitment fuels customer intimacy.
Carlos Tadeu da Costa Fraga, executive manager of CENPES,
Petrobras Research and Development Center, says that Petrobras has
a long-term commercial relationship with most service companies
because they have been doing business in Brazil for more than 30
years. But what is changing, Tadeu says, is that the national oil
companys growing and ever-challenging portfolio drives the need for
more expertise and knowledge.
The size of the potential business in Brazil is very attractive,
and most of the existing suppliers want to expand their commercial
activity in Brazil, and we welcome them, Tadeu says, but we want to
do that
followed by the establishment of a quite strong intellectual
relationship, as well.
In December 2010, Baker Hughes hosted a three-day workshop for
Petrobras at its Center for Technology Innovation in Houston so
executives from both companies could discuss long-range plans to
meet future challenges.
It was clear that Petrobras was not interested in seeing what
Baker Hughes has today, Pelez says. They were here to talk about
what they are going to need ve to 10 years from now that we dont
have today and what we would agree to develop so, when they need
it, it will be available.
The idea of looking that far aheadstarting to plan now for needs
ve
to 10 years down the roadis very important and a real
achievement for our company, Figueiredo says. Together, we have
been doing a lot of innovative things, but the vast majority has
been demand-driven. Sometimes you have to think of something so
innovative and so forward thinking that customers dont even realize
they might need it.
Taking into consideration the characteristics of Petrobras main
developments in Brazilcomplex reservoirs, ultradeepwater, deep
wells, pressure issuesTadeu outlines the following future
needs.
We will need to better characterize the internal properties of
those reservoirs so we can better understand and predict their
quality. We are developing and applying drilling technologies that
will allow us to drill faster, safer and quality-wise better in
those very challenging environments, as well as completions
technology that uses materials and equipment almost tailor-made for
the characteristics of our developments.
We are dealing with aggressive uids and different types of
reservoirs where intelligent completions are very, very important
for us. Because the salt may move over time, well integrity is very
important. We are looking for new approaches for bottomhole
assemblies, casing and cementing technologies and, in the
long-term, even to different drilling techniques such as laser
drilling.
Thirty years ago, the industry could never have imagined
intelligent completions, real-time monitoring or nanotechnology.
There is a lot of room for innovation in the drilling and
completion arenas, and we need to start thinking together more
aggressively about the new set of technologies we want to have
available for the pre-salt Phase II development. We are condent
that we are going to deliver very creative solutions with Baker
Hughes.
01> Workshop conversation between Carlos Tadeu da Costa
Fraga, executive manager of CENPES (upper right); Derek Mathieson,
president, products and technology for Baker Hughes (lower right);
Mauricio Figueiredo, vice president, Brazil for Baker Hughes (lower
left) and Matthew Kebodeaux, vice president of completions for
Baker Hughes.
01
| 15www.bakerhughes.com
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Reshaping Sand ControlShape Memory Polymer Foam Remembers
Original Size to Conform to Wellbore
> After Baker Hughes chemists proved the unique, scientic
properties of the shape memory polymer foam material, Bennett
Richard (left) and Mike Johnson helped take it from the lab table
to the rotary table.
16 |
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For as long as man has dug or drilled into the earth, whether
searching for drinking water or for heating oil, he has struggled
to keep his bounty free of sand. Today, sand migration continues to
plague drilling operations worldwide, causing reduced production
rates, damage to equipment, and separation and disposal issues. In
short, sand is an ever-present, costly obstacle to oil and gas
production.
Baker Hughes has been helping operators reduce the serious
economic and safety risks of sand production for decades through
deployment of sand management systemsincluding screens, inow
control devices and gravel packing. All have the same goal: to keep
sand from entering the well along
with the hydrocarbons without affecting production. But even
gravel packing, the most widely used and highly effective sand
control method, has its drawbacks.
In gravel packing, sand, or gravel as its called in the
industry, is pumped into the annular space between a screen and
either a perforated casing or an openhole formation, creating a
granular lter with very high permeability. However, sand production
may occur in an unconsolidated formation during the rst ow of
formation uid due to drag from the uid or gas turbulence, which
detaches sand grains and carries them into the wellbore. These nes
will then lodge in and plug the
gravel pack, increasing drawdown pressures and decreasing
production rates.
Now, after years of research, Baker Hughes has engineered a
totally conformable wellbore sand screen from shape memory polymer
foam that has the industry rethinking sand management: the GeoFORM
conformable sand management system using Morphic technology.
This advanced material can withstand temperatures up to 200F
(93C) and collapse pressures up to the base pipe rating while
allowing normal hydrocarbon uid production and preventing the
production of undesirable solids from the formation.
In a perfect world, hydrocarbons would ow unencumbered and sand
freefrom the reservoir into the wellbore like a river toward an
open sea.
How the GeoFORM conformable sand management system using Morphic
technology works
When the polymer tube is taken to a temperature above its glass
transition temperature, it goes from a glass or hard plastic state
to an elastic, rubber-like state. For the Baker Hughes 27/8-in.
totally conformable sand screen, the polymer tube is constructed
with an outside diameter of 7.2 in. The tube is taken to a
temperature above its glass transition temperature where it becomes
elastic. The tube is then compressed and constrained to a diameter
of 4.5 in. While holding this constraining force on the tube, it is
cooled below its glass transition temperature, which locks the
material at the new reduced diameter, essentially freezing the tube
into this new dimension. Once downhole, the material springs back
to its original 7.2-in. diameter.
| 17www.bakerhughes.com
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The possibility of performing multiple openhole completions with
sand control efciency close to that of frac and pack treatments but
with limited equipment and personnel is very appealing.
Giuseppe RipaSand control knowledge owner, Eni exploration and
production
Foam vs. metalHow do you convince a customer who has run metal
screens downhole for years to give something made of foam a
chance?
That was the big question that Baker Hughes scientists and
engineers faced as they developed a brand new technology never
before used in the oil eld.
When we rst started researching this, the properties of the
materials were a scientic novelty, says Mike Johnson, sand
management engineering manager for Baker Hughes. Usually, you bring
a technology into the oil and gas industry from another
industryfrom something thats already in use. In this instance the
science and technology were developed within Baker Hughes.
It denitely has some major advantages over what is currently
offered in the area of sand control. Compared to other products in
openhole applications, it provides a stress on the formation thats
unachievable with todays sand control technology to prevent sand
from moving initially.
Oddly enough, I thought this was going to be a difcult sell,
says Bennett Richard, director, research for the Baker Hughes
completions and production business
segment. But, every time our customers have toured our research
center and seen this product, theyve immediately grasped the
concept and seen the benets.
Richard explains how the technology works: Shape memory polymers
behave like a combination of springs and locks. The behavior of
these springs and locks is dependent upon what is called the glass
transition temperature. A polymer below a certain temperature is
locked in position and acts as a glass or hard plastic. If you take
it above this glass transition temperature, it starts to act as a
spring and becomes more elastic like rubber. For our 27/8-in.
screens, we construct a polymer tube with an outside diameter of
7.2 in. That tube is then taken to a temperature above its glass
transition temperature where it becomes elastic. The tube is then
compressed and constrained to a diameter of 4.5 in.
While holding this constraining force on the tube, it is cooled
back down below its glass transition temperature, which locks the
material at the new reduced diameter. The process essentially
freezes the tube into this new dimension. Once downhole, the
material sees its coded transition temperature again and remembers
that its supposed to be a bigger diameter and tries to spring back
to its original 7.2-in. diameter.
The material composition is formulated to achieve the desired
transition temperature slightly below the anticipated downhole
temperature at the depth at which the assembly will be used.
The totally conformable sand screens are currently manufactured
in two sizes27/8-in. for 6-in. to 7.2-in. openhole applications and
5-in. for 8-in. to 10-in. openhole applications. The screens come
in 30-ft joints made up of four 6-ft screen sections (tubes) and
can be run in any openhole application where metal expandable
screens, standalone screens and gravel packs would be used.
Conformance performanceShape memory polymers are being tested
for use in the auto industry on parts, such as bumpers, that repair
themselves when heated and in the medical industry for instruments,
such as expanding stints, which can be inserted into an artery as a
temporary shape and expand due to body heat.
There are many types of polymers commercially available:
polyethylene foam, silicone rubber foam, polyurethane foam and
other proprietary rubber foams, to name but a few. Most of these,
however, yield soft closed-cell foams that lack the strength to be
used downhole.
01
18 |
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Some materials, such as rigid polyurethane foam, are hard but
very brittle, Johnson says. In addition, conventional polyurethane
foams generally are made from polyethers or polyesters that lack
the thermal stability and the necessary chemical compatibility for
downhole applications.
The GeoFORM sand management system, created at the Baker Hughes
Center for Technology Innovation in Houston, is an advanced
open-cell foam material designed with two key attributes for
openhole application: reservoir interface management and
ltration.
Johnson explains, It is generally accepted that particulates
less than 44 micrometers can be produced from the well without
erosion damage to the tubing or surface equipment, so the GeoFORM
material matrix was designed to allow less than 3 percent total
particles to pass, with 85 percent of those particles being 44
micrometers or less.
An openhole completion ltration media permeability should be at
least 25 times the permeability of the productive reservoir to
avoid productivity restrictions. If the reservoir has a
permeability of one darcy, the GeoFORM sand management system would
require a permeability of 25 darcies to prevent productivity
impairment.
Because it is an entirely new material, the mechanical
properties, chemical stability, permeability, ltration
characteristics, erosion resistance, deployment characteristics and
mechanical tool design of the GeoFORM sand management system were
tested extensively before a eld trial on a cased-hole remediation
well in California in October 2010.
In order to fully understand the properties of the new material
and its potential application window in the downhole environment,
the material was aged in various inorganic and organic uids for
extended time periods and at varying temperatures up to 248F
(120C), Johnson says.
The totally conformable screen outperforms every screen that
Baker Hughes has ever tested for plugging or erosion resistancethe
two main problems with sand control completions, Richard says. Im
sure theres going to be a formation material that we nd at some
point that will plug it, but weve always been able to plug the
other screens weve tested over time, and we have never been able to
plug this material in laboratory tests.
The rst eld trial in an openhole sand control application was
successfully run in
December 2010 for Eni in the Barbara eld in the Adriatic Sea.
Giuseppe Ripa, sand control knowledge owner for Eni exploration and
production, says, The possibility of performing multiple openhole
completions with sand control efciency close to that of frac and
pack treatments but with limited equipment and personnel is very
appealing.
Moreover, there is the possibility to develop short (1 m)
unconsolidated silty layers where frac and pack is mandatory for
nes control and production efciency but the treatment is not
feasible, Ripa says. This aspect is very attractive in deepwater
developments where multiple sand bodies must be completed in one
horizontal or highly deviated well in order to be economical
through less rig time being consumed.
The GeoFORM screens are being manufactured at the Baker Hughes
Emmott Road facility in Houston at a rate of about 2,500 ft (762 m)
per month. Justin Vinson, project manager for the sand management
system, says, The product portfolio will be expanded in 2011 to
include more sizes, different temperature ranges and a
through-tubing remedial application.
01> Design Engineer Jose Pedreira calibrates the outside
diameter of the compacted GeoFORM screen before running it in the
well.
01> The rst eld trial in an openhole sand control
application, run in December 2010 for Eni in the Barbara eld in the
Adriatic Sea, receives a thumbs up from Eni personnel on the
rig.
02
| 19www.bakerhughes.com
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The story of the Bakken, an enormous hydrocarbon-bearing
formation in the northern U.S. and Canada, is so incredible that
some have suspected its an urban myth. Its even been addressed on
websites dealing with hoaxes. But those in the energy industry have
known for decades that it holds a vast amount of oilthey just didnt
understand until recently how to get much of it out of the
ground.
After 60 Years the
Oil was rst discovered in the Bakken formation in Williams
county, Mont., in 1951, but the giant accumulation remained a
mystery for almost 60 years. Only sporadic drilling occurred until
2008 when technology advancements nally unlocked the Bakken and
turned it into a bonade boom. Its no wonder oil companies kept
plugging away at the Bakken. The U.S Geological Survey estimates
that the play holds three to four billion barrels of recoverable
oilmaking it the largest oil nd in the contiguous U.S. Estimates
for the Canadian Bakken are approximately 68.7 million barrels of
oil.
> Just south of the boom town of Williston, N.D., is Theodore
Roosevelt National Park, a 30,000-acre wilderness where bison, elk,
wild horses and pronghorn sheep roam free.
20 |
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So, if everybody knows the oil is there, the rest should be
simple enough:
First, uncover the geology of the play
Second, drill horizontal wells into the productive zone
Third, complete and fracture the horizontal sections to maximize
production
But its far from easy. It takes a great deal of perseverance
and
technical know-how to recover the vast oil reserves in the
Bakken shaleand to recover it economically. Just as the Barnett
shale was the proving ground for unconventional gas resources, the
Bakken is the proving ground for unconventional oil plays, asserts
Charlie Jackson, director of marketing for Baker Hughes in the
U.S.
Companies like Houston-based Marathon Oil Corp. are staking big
claims in the Bakken. With an approximate 390,000-acre lease
position, the company has invested approximately $1.5 billion to
date in the Bakken and exited 2010 with about 15,000 BOPD net
production, relates Dave Roberts, executive vice president of world
upstream operations for Marathon. By 2013, the rm estimates its
production will top 22,000 BOPD.
Unraveling the BakkenIn one sense, the Bakken is no different
than any other oil and gas producing region. First,
operators must understand the geology to design effective
drilling, completion and production schemes. One fact that might
surprise those unfamiliar with the Bakken shale is that the primary
producing zone is not a shale at all.
The Upper Devonian-Lower Mississippian Bakken formation is a
thin but widespread unit within the central and deeper portions of
the Williston basin in Montana and North Dakota in the U.S., and
the Canadian provinces of Saskatchewan and Manitoba. The formation
is comprised of three members: the lower shale, the middle
sandstone and the upper shale. The organic-rich lower and upper
marine shales have yielded oil production, but primarily they serve
as the source rocks for the productive sandstone, which varies in
thickness, lithology and petrophysical properties across the basin.
The shales also source the productive Three Forks dolomite that
underlies the Bakken.
While these facts are well known, the art of producing the
Bakken lies in understanding its petrophysical subtleties. This
knowledge of the rock characteristics and how they react to both
natural micro and macro fractures, as well as to induced fractures,
is the key to unlocking the most effective fracturing and
completion strategies. The Bakken is unlike most shale plays where
the larger the vertical fractures the better the production. In the
Bakken, it is imperative to contain the fractures within the
formation to prevent unnecessary expenses for no gain in
production.
The Bakken is driven by economics. A well can initially produce
approximately 1,000 BOPD, but production drops off quickly. And
with average completion costs on the order of $6.1 million,
maximizing the effectiveness of each wells drilling, completion,
fracturing, and production strategy can make or break the play.
System
Mississippian
Devonian
Formation
Lodgepole
upper
middle
lower
Bakken
Three Forks
Units
| 21www.bakerhughes.com
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The depth of the Bakken shale varies, ranging from approximately
5,500 ft (1676 m) in Canada to 10,000 ft (3048 m) in North Dakota,
while the horizontal sections can be up to 10,000 ft (3048 m) long
to maximize reservoir contact. Drilling the vertical section is
more difcult than other U.S. shale plays. The hard, abrasive nature
of multiple layers, combined with pressure drops in older producing
zones and other issues, present technical challenges and, of
course, the overarching goal is to optimize drilling costs.
Its a balancing act between costs and delivering the best
quality wellbore, says Paul Bond, drilling systems marketing
director for Baker Hughes in the U.S. The abrasive layers in the
horizontal section are very hard on tools, so we deploy our
powerful 4-in. Navi-Drill X-treme series motors to maximize
penetration rates and to reduce the number of runs. The X-treme
motors precontoured stator design increases both mechanical and
hydraulic efciency for higher torque and more than 1,000 hp at the
bit.
Increasingly, operators are trying rotary steerable systems in
the vertical and curve sections to save time and to increase the
build rate in the curve. Baker Hughes is beginning to employ its
AutoTrak Express automated, rotary-steering drilling system for the
vertical and build section of the wellbore. It is designed to
maximize penetration rates while delivering a precise, straight,
smooth wellbore despite the abrasive zones.
Traditionally, geosteering and formation evaluation technologies
were not necessary to drill the horizontal section in the middle
Bakken, which is typically about 40 ft (12 m) thick. But these
techniques are becoming more prevalent as wells are placed closer
to the more geologically complex anks of the middle Bakken and in
the 10-ft (3-m) thick lower Bakken, Bond notes. As the easy wells
are drilled up, advanced technology is required to deliver the best
possible producing well. Again, its nding the balance between more
costly technologies to maximize production and overall well
economics. Recently, Baker Hughes has used some
of its formation evaluation and measurement-while-drilling (MWD)
tools and services very successfully. These include the CoPilot
system, which transmits real-time information from sensors mounted
on the bottomhole assembly (BHA) to the surface; AziTrak deep
azimuthal resistivity logging-while-drilling (LWD) tool; and OnTrak
integrated MWD and LWD service.
There is a lot of bending tendency in the Bakken, and with the
CoPilot system you can see how the BHA is being bent and modify
drilling behavior quickly, preventing wear and tear on your BHA,
according to Bond. The AziTrak tool provides the ability to steer
the well into the best producing formations through an accurate
picture of the wellbore with deep reading resistivity and borehole
gamma-ray imaging. The 360 deep-reading, close-to-the-bit sensors
detect bed boundaries so we can avoid nonproductive formations in
any direction around the wellbore, he says. The OnTrak service is
an array of integrated measurements, including full inclination and
azimuth close to the bit; deep-reading propagation resistivity;
> Baker Hughes directional tools were used during the
Precision 106 rigs drilling operations in the Sanish eld in
Mountrail county, N.D.
> The multiport system offers multiple fracture initiation
points at each stage. Currently, the multiport system can run up to
17 stages with ve entry points for a total of 85 sleeves per
completion.
22 |
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dual azimuthal gamma-ray sensors; vibration and stick-slip
monitoring; and bore and annular pressure in real time.
Optimizing the drilling process pays dividends. Marathon, for
example, has made impressive improvements in its drilling program.
Roberts says, In 2006, it took us an average of 50 days to drill a
Bakken well to a total measured depth of 20,000 ft (6096 m). Today
that same well takes less than 25 days. This improvement and other
technology advances are strengthening the economics of the Bakken
play. Marathons net development costs are in the $15 to $20 per
barrel range.
Completing a solution While drilling the best possible wellbore
at the best possible cost is critical to economically produce the
Bakken, everyone acknowledges that today it is all about the
completion. Brent Miller, operations manager of the Northern
Rockies asset group for Whiting Petroleum, says its a combination
of horizontal drilling and new completions technologies like Baker
Hughes FracPoint system, thats made the Bakken economic. These are
reservoirs that were passed up over the years. Theyre tighter rock.
There is not as much porosity and permeability so we have to go
horizontal. Then, we have to engage as much rock volume as we can
with FracPoint technology to improve our odds of having a protable
well.
Early on, operators employed the traditional plug-and-perf
method of completing and fracturing horizontal wells in the Bakken
shale. With this technique, composite plugs are deployed to isolate
each fracture stage and, then, a series of perforating clusters is
made through a cemented liner to access the formation in each
stage, according to Jose Iguaz, completion systems director for
Baker Hughes in the U.S. The drilling rig is moved off location and
replaced with frac equipment, e-line unit and, in most cases, a
coil unit on standby to perform emergency cleanups or milling of
preset plugs.
This system provides operators an industry-accepted, low-risk
way of stimulating their wellbores. But there are limitations. It
can take several days to perform multiple fracs and to set the
plugs, leaving costly frac equipment and crews idle much of the
time. Plus, this system requires the composite bridge plugs to be
drilled out before putting the well in production, he points
out.
More and more operators are recognizing that speeding up the
completion and fracturing process while controlling the fracture
regime is necessary to rein in costs while maximizing production.
That has led to increased use of single-trip, multistage fracturing
technology, which compartmentalizes the reservoir into multiple
200- to 400-ft mini reservoirs that are
fractured individually after the drilling rig moves off
location, notes Iguaz. This system can be run in openhole or
cased-hole applications and can be used for primary fracturing or
refracturing operations.
While looking for a solution that combined the
cost-effectiveness of a packer and sleeve system with the increased
number of initiation points of a plug-and-perf method, Whiting
Petroleum came to Baker Hughes. The result was the FracPoint EX
system.
The FracPoint system has seen tremendous growth in the Bakken as
more operators recognize the technical and economic value of single
trip multistage systems compared to plug and perf. The FracPoint
completion system uses packers to isolate intervals of the
horizontal section with frac sleeves between the packers, explains
Iguaz. The frac sleeves are opened by dropping balls between stages
of the fracture treatment program. As the ball reaches the sleeve,
it shifts the sleeve openexposing a new section of the lateral and
temporarily plugging the bottom of the sleeve. This provides
greater control of the fracture treatment and allows for fracture
treatments along the length of the horizontal wellbore.
Compared to plug and perf, the FracPoint system eliminates
perforating and liner cementing operations; saves time during
fracturing operations; reduces
uid usage during fracturing; and allows the well to be put on
production immediately, without the need for clean up and milling
operations. Initially, the one drawback to single-trip, multistage
systems like the FracPoint offering was a limit on the number of
frac stages, but that is no longer an issue. Constant technology
advances have pushed the number of stages higher and higher.
Earlier this year, Baker Hughes ran and fractured the rst
40-stage FracPoint EX-C system for Whiting Petroleum at the Smith
14 29XH well in the Bakken. This achievement marks the most number
of stages ever performed in a single lateral frac sleeve/packer
completion system. The FracPoint EX-C system extends capabilities
to 40 stages via 1/16-in. incremental changes in ball size to
achieve an increased number of ball seats. The patented design
provides additional mechanical support to the ball during pumping
operations.
Our ongoing collaborative relationship with Baker Hughes couples
Baker Hughes industry-leading tool expertise and experience with
Whitings Bakken completion expertise and is a key to Whitings
industry-leading position in Bakken fracture stimulation
effectiveness and efciency, notes Jim Brown, president and chief
operating ofcer for Whiting Petroleum.
| 23www.bakerhughes.com
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The next major innovation for the FracPoint system technology is
the multiport system. One perceived advantage of the plug-and-perf
method is the capability to create multiple fracture initiation
points at each stage. Now, the FracPoint system offers this same
advantage. It works like a conventional FracPoint system, but
provides up to ve entry points per stage. In February, Baker Hughes
installed the rst multiport system in a North Dakota Bakken well.
This technology has the potential to dramatically impact our
completion efciency in the shale plays in North America, Iguaz
says. Currently, the multiport system can run up to 17 stages with
ve entry points for a total of 85 sleeves per completion.
A revolutionary technology advancement is also in the works. The
FracPoint system with IN-tallic frac balls breaks new ground in
material science. Based on fundamental research in
nanotechnology,
Baker Hughes scientists have developed a light-weight,
high-strength material incorporating controlled electrolytic
metallic technology, which is based on an electrochemical reaction
controlled by varying nanoscale coatings within the composite grain
structure.
The frac balls made of this material are designed to react to a
specic wells uid and temperature regimes to literally disintegrate
in a prescribed timeframe. So whats the advantage of disintegrating
frac balls? At the conclusion of a traditional FracPoint
installation, ball sticking or differential pressure may keep a
ball on seat, requiring remedial actions such as milling and
delaying (full) production. The IN-tallic frac balls remove the
cost of possible remedial action.
Breaking into the BakkenOf course, completion technology is only
part of the storygetting the fracturing process just right is
imperative
to maximize production and to control well costs. In the Bakken,
the key to a successful frac job is eliminating excessive fracture
height growth to keep the fractures in the formation. Fracing out
of zone is a waste of money, says Kristian Cozyris, an engineer for
Baker Hughes. Getting the fracture geometry right is a function of
both the pumping rate and the uid type. Its not all about
horsepower in the Bakken. Typically, we pump 30 to 50 barrels of
uid per minute, and we use cross-linked gel-based uids.
But, typical is a relative term. Theres no such thing as
generalities in the Bakkenevery operator has a slightly different
philosophy on the best fracture methodology and the needs can vary
depending on where a well is drilled. There is still a great deal
we need to learn to determine the optimum approach. We have ongoing
research and development projects studying fracture growth in
the shales and additional science will be necessary as we better
understand the Bakken reservoir, Cozyris says.
Another serious challenge for fracturing operations is the
availability and quality of source water. Out of necessity,
operators are using more recycled water, but that can pose its own
set of problems, notes Brad Rieb, region technical manager for
Baker Hughes in Canada. Baker Hughes BJ Viking II PW system, which
uses produced brines combined with a high-performance polymer and
crosslinker, has been deployed successfully in the Canadian Bakken
where dry weather conditions and agriculture needs limit the volume
and availability of fresh and surface water.
Since its introduction in May 2008, the Viking II PW system has
been deployed in about 310 wells, or approximately 5,300 frac
stages. Weve saved 1.5 million barrels of fresh water from being
used in fracturing
> Baker Hughes fractures three wells side-by-side in the
Montana portion of the Bakken.
24 |
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operations, Rieb says. One customer estimated it saved 10 to 15
percent in total stimulation costs from reduced water purchases,
hauling, heating and uids disposal. The operator had a constant
source of produced water stored in several tanks. In addition to
the environmental benet of preserving the limited supply of fresh
water, other benets include reduced exhaust, dust, noise, and road
wear from trucking operations.
The Viking II PW system has not been widely used in the U.S.,
primarily because the Bakken producing formations are deeper,
hotter and more saline. The hotter bottomhole conditions impact the
uid. We currently have R&D projects under way to understand the
inuence of higher temperatures on the system. There is signicant
interest in this technology, so we are working hard to solve the
technical issues, Rieb explains.
Another serious challenge in the Bakken is mineral scale
formation on the tubulars, says Anthony Hooper, director of
marketing, pressure pumping, for Baker Hughes in the U.S. We have
seen Bakken wells with restrictions from severe scale buildup.
Barium sulfate, calcium sulfate, calcium carbonate scales and
sodium chloride precipitation are the most common problems in the
Bakken. Its extremely difcult to adequately recomplete 10,000-ft
(3048-m) laterals, so its imperative we get it right the rst time
to prevent
loss of the wellbore or an expensive and not very effective
remediation treatment.
To inhibit scale build up, Baker Hughes is employing its BJ
StimPlus services on an increasing number of frac jobs. This
service combines scale inhibiting chemicals with the stimulation
uids to address scale at its sourcethe rock face. This is our only
chance to get the chemicals directly into the reservoir, Hooper
says. Following the fracture stimulation, a post-treatment survey
monitors the reservoir and well assets for scale build up. We have
documented cases of uninterrupted well treatment lasting up to ve
years with no additional chemical intervention.
Lifting reserve recoveryBakken hydrocarbons are now technically
feasible to drill and recover, but production over time is yet
another challenge. Production rates decline rapidly and operators
are looking for ways to extend the productive life of every well
and to maximize ultimate reserve recovery.
Rod lift has been the traditional articial lift technique, but a
growing population of Canadian and U.S. wells is being produced
with electrical submersible pumping (ESP) systems and is proving
the value of this technology. According to Cal LaCoste, eld sales
manager for Baker Hughes in Canada, there are two primary
advantages
of ESP systems: ESPs can be set in the horizontal section of the
wellbore, which provides greater draw down for faster and higher
reserve recovery; and ESP systems can handle solids and gases
entrained in the production stream.
The key to successful deployment of ESP technology is picking
the right system for the right application. We have found that the
optimum solution is a low-horsepower/high-voltage system to keep
the motor temperature down. It is also very important to get the
pump size just rightit has to handle a wide operating range since
production rates drop off quickly in the Bakken. Another critical
element is chemical maintenance of the ESP systems to protect
against scale and corrosion, LaCoste explains.
Canada was the rst proving ground for ESP technology since the
wells are shallower with lower production volumes and a shallower
decline curve compared to the U.S. side of the play. However, U.S.
operators are testing the waters. Currently, more than 150
Centrilift SP ESP systems have been installed in Canada and the
U.S., and operators are realizing sizable benets.
In fact, the rst ESP system ever installed in a Bakken well in
Canada has run continuously for more than two and a half years. The
rod lift system originally in the well had to be worked over every
three to four months
due to a host of downhole problems. We convinced the operator to
give us a chance to improve the wells performance and to cut down
on the costs of frequent well interventions, LaCoste remembers. The
results were dramatic. Because the ESP system could be set in the
horizontal section of the well207 m (680 ft) deeper than the rod
pumpproduction initially increased by 76 BOPD and, over time,
stabilized at an increase of 20 barrels per day, a 50 percent
increase over the rod system. Plus, weve saved nearly $400,000 in
well intervention costs and another $500 per month in power costs
because the ESP system requires half the horsepower of the rod
system.
The technical challenges operators and service companies face in
their quest to unlock the promise of the Bakken shale have been
daunting, but the prize is worth it. Production from just the U.S.
sector of the play increased from 9.3 million BOE in 2004 to 70.9
million BOE in 2009. Production from the Bakken is expected to
reach 211.4 million BOE in 2020an average annual growth rate of 9.9
percent.
And the Bakken is just the rst chapter in this story. Marathons
Roberts sums it up. What we learn in the Bakken will be transferred
to other unconventional resource plays in North America and, then,
around the world. We are already seeing that trend. This is an
exciting journey for the industry.
| 25www.bakerhughes.com
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with James J. Volker, chairman, president and CEO, Whiting
Petroleum
wcW
James J. Volker and his senior management team, which he credits
with Denver-based Whiting Petroleums growth and success, share
insight into the challenges of producing some of the nations top
oil shale plays and the future technologies that will be vital to
meeting the needs of this market.
Interest is rising in natural gas shale basins globally. How can
the knowledge gained by mostly independent oil companies in the
U.S. be transferred to shale plays around the world?
First, it is very important, especially with regard to what we
call resource plays, to have access to subsurface information.
There is a great deal that we can do with old logs, in terms of
prequalifying these types of plays, when we combine log data with
pressure and production test information. Without that, youre at a
real disadvantage, so its very important to have access to that
type of information. Secondly, one of the things that distinguish
these resource plays from other types of plays is that they are
invariably large in scale, but they are marginal in their reservoir
quality compared to conventional reservoirs. The international oil
companies have historically been good at obtaining a large share of
the protability that is sometimes seen in a conventional reservoir
play. In order for independent U.S. companies to compete
internationally in the resource playswhere the economics are
typically in the 2:1 to 3:1 or 4:1 range, rather than 10:1its
important that the netbacks, in terms of the production sharing,
are high and are competitive with what they are in the U.S. We see
netbacks in the U.S. typically between 50 and 70 percent. You
rarely see that internationally,
Industry Insight
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so its going to be important for those countries that have
resource play opportunities to be realistic in their dealings with
U.S. companies to encourage them to come and make the large capital
investments necessary to get these big plays going. Royalties and
the whole scal regime need to be competitive with what were doing
here in the U.S.
Explain the differences in exploiting, producing and completing
shale oil and shale gas.
Because oil is a much thicker uid than gas, it is more difcult
for it to ow through the tiny pores within the shale. In the
completion or the fracturing phase, we aim to leave a much higher
fracture conductivitya much higher sand concentration, so to
speaknear the wellbore to maximize ow rates. You can ow more gas
than oil through a lower permeability sand pack. The other thing
thats true with oil reservoirs, whether youre in vertical wells or
horizontals, is you have to have tighter well spacing because youre
not going to drain as big an area. Thats why were drilling up to
six wells per 1,280-acre unit. Much of the multistage fracturing
designs have been transferable between gas and oil plays with
adjustments for the different rocks, well depths and well costs.
Both shale oil and gas plays should have repeatable results over a
large area.
How have drilling and completion methods changed in regard to
the Bakken shale over the last several years and what are your
expectations moving forward?
Whitings average time to drill a 20,000-ft (6096-m) well has
been reduced from 50 days to less than 20 days, and we currently
hold the record in the Bakken shale for drilling a 20,000-ft
(6096-m) well in 13.92 days from spud to total depth. All this is a
direct result of optimizing the drilling process through
improvements in downhole motor technologyespecially motors with
precontoured stator tubes that allow the entire lateral to be
drilled without changing the downhole assembly. High-pressure mud
motors that facilitate high rates of penetration are also
important. Another key driver for drilling efciency includes all
top-drive rigs. These rigs reduce connection time and reduce time
for reaming horizontal from three days to one day before running
liner. Also, our drilling-well-on-paper training keeps the rig crew
focused on a mission-critical bit-on-bottom strategy and accounts
for ve to seven days reduction in drill time.
On the completion side, Bakken shale completions have evolved
signicantly from three years ago. Horizontal drilling with
single-stage fracture stimulations was being used with good results
in Montanas
Elm Coulee eld, but with poor results in the North Dakota Bakken
play. We decided to try a Baker Hughes FracPoint multistage
fracture design with swell packers and frac sleeves, and the result
was our best well up to that date. This kicked off signicant
development in the Sanish eld, and weve been using multistage
fracturing ever since in the Bakken play. Along with Baker Hughes,
we pioneered the 24-stage frac system and have since run a 40-stage
system. With frac sleeves, we can do a completion in one day versus
ve or six days with plug and perf. Therefore, it is much more
efcient and much more cost effective. The more we can keep frac
costs per stage down in a long lateral, the more we are going to
accomplish commercial completions in poorer or thinner rock. Thus,
we can make the play work in not just the great areas like the
Sanish eld but also in some of the poorer rock quality areas we
want to drill.
In addition to using the multistage fracturing technology,
Whiting has adopted and improved upon the hybrid uid frac design
that uses slick water, linear gels and cross-linked gels in each
frac stage design. Whiting has moved quickly from less than
10-stage completion designs to 30-stage designs. This has resulted
in some of our best wells to date, and we have plans to use even
more stages in the future. The challenge for Whiting is to continue
to push for lower per stage frac costs and optimum stimulation
designs to produce higher estimated ultimate recovery [EUR].
Efcient use of fracturing equipment is important in reducing costs.
Our individual well fracturing operations are now normally done
within 24 hours.
Unconventional resources are a relatively new market with
limited long-term exposure. As the industry moves further into the
life cycle of unconventional resources, what technologies do you
see emerging to meet the needs of this market?
Because these are tight rock reservoirs with low permeability,
we think that the key elements will involve completing
multilaterals with more affordable multistage completions.
Therefore, a key factor will be having dependable assemblies that
can access as much rock volume as possible to increase the odds of
making a protable well.
Whiting Petroleum explores for crude oil, natural gas and
natural gas liquids. What percentage of each is your company
targeting from shale formations?
Approximately 80 percent of our exploration and development
budget is targeted
| 27www.bakerhughes.com
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at oil reservoirs, and almost 80 percent of this effort [64
percent of total] is directed at oil-rich shales. We have
concentrated on oil because it has the best prot margin.
Whiting Petroleum consistently has some of the largest initial
production rates in the Bakken shale. To what do you attribute this
success?
Whiting has leases covering some of the best Bakken and Three
Forks rock, uses multistage fracing and sees low damage to the
formation during drilling. Beyond that, I would say that its the
ability of our geoscience team to locate this better reservoir rock
that has enough porosity and permeability innately, so that when we
drill it horizontally, we get protable wells. Using the geoscience
that Mark Williams, our vice president of exploration, and his team
have applied has been the difference between our wells, which on
average have produced about 80,000 barrels in the rst six months of
production, to others who, on average, have had production of about
half of that.
The unconventional resource market in North America has been
revolutionized during the last decade with the
emergence of further plays in a seemingly endless cycle. In what
areas does Whiting Petroleum expect to emerge in the near future
and what are the corresponding challenges?
There are three primary areas: the various zones of the Bakken
hydrocarbon system in the Williston basin, the Niobrara zone in the
Denver Julesburg basin and the Bone Springs zone on the western
side of the Permian Basin. The challenges, of course, are how to
efciently drill and complete longer horizontal laterals. We think
that technologies such as the FracPoint multistage fracturing
system will be of assistance to us in these three areas because it
has increased the speed and effectiveness of multistage completion
systems to access greater rock volume.
Reserve estimates have changed dramatically over the past few
years. Why is it so difcult to estimate the amount of oil and gas
that lies within the U.S. shale plays?
Shale and other unconventional reservoirs have low reservoir
permeability but high permeability associated with natural and
induced fractures contained within the reservoir. Therefore,
wells
in these plays exhibit high initial rates of decline over the
rst one to three years as the fractures are produced.
Without contribution from the low-permeability matrix reservoir,
however, these wells would continue to decline rapidly. Because it
is often difcult in the early stages of production to determine the
degree of eventual contribution from the low-permeability matrix,
it is all the more important to treat and enhance the reservoir
with FracPoint-type technology. Contribution from the
low-permeability matrix can atten the rate of decline, improve
estimated ultimate recovery and make results more protable.
Of all the shale plays in which Whiting Petroleum is involved,
which is the most technically challenging and why?
Our big play is the Bakken shale play, but weve had challenges
within that play. The Sanish eld is some of the better rock in that
play but even in Sanish there have been some challenges related to
well spacing. We had to decide how many laterals to drill in the
middle Bakken within a 1,280-acre unit and how many to drill in the
Three Forks. Weve used some of Baker Hughes technology to help us
come up with the answers to those questions. Our studies now
indicate that we need to drill