Connexus 2a. ed.

CONNE US
Totally Conformable
Revolutionizing sand
management with shape
memory polymer foam
Brazil’s Big Oil
Pre-salt: The world’s next
big opportunity
The Booming Bakken
Unlocking the secrets of
the giant shale play
2011 | Volume 2 | Number 1
The Baker Hughes Magazine

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 Brazil’s 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 we’ve 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 fields. You will find 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 fields
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 field redevelopment.
The integration of BJ Services has been faster
and smoother than we anticipated. The merger
BEYOND TRANSFORMATION
President and Chief Operating Officer Martin Craighead

was a perfect fit. 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 prolific 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
advancements—truly disruptive step
changes to some of our customers’ biggest
challenges. On Page 16 you will find 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 flux. Our people were asked to take on
new roles, often in new places, and often
with a great deal of ambiguity. It may sound
clichéd, but it’s true—the 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,
it’s 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 portfolio—all 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 firm 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 pass—we
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

Advancing Technology Frontiers
Baker Hughes is constructing a new $30-
million research and technology center in
Rio de Janeiro to support the industry’s
economic development of pre-salt
reservoirs offshore Brazil.
Intellectual Relationships
Anticipating growth in Brazil, Baker
Hughes put a strategy in place to grow
business and foster long-lasting customer
relationships.
Reshaping Sand Control
A totally conformable sand screen
engineered from shape memory polymer
foam has the industry rethinking
sand management.
Unlocking the Bakken
Advances in drilling and completion
technology are lowering operating costs
and enhancing production performance
for operators in the Bakken shale.
Industry Insight
James 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 Russia
New technologies applied on wells
drilled in northwest Siberia’s Yamal
Peninsula are helping operators
reach new levels of productivity.
Clean, Efficient Fracturing
An innovative hydraulic fracturing
technology dramatically cuts water
and chemical requirements to
safely and efficiently stimulate gas
production from shale formations in
environmentally conscious New York.
Faces of Innovation
Meet Bennett Richard, the
newest Baker Hughes Lifetime
Achievement Award winner,
who enjoys developing people
as much as technologies.
Ghana’s First Oil
As a key player in the Jubilee
project, Baker Hughes is determined
to make this African country’s first
oil pay off for the people.
The Complete Package
The OptiPortTM
completion system
combines coiled tubing with sliding
sleeves to take multistage fracturing
to new levels.
Contents 2011 | Volume 2 | Number 1
11 30
34
38
47
42
04
14
16
20
26
On the Cover
Rio de Janeiro occupies
one of the most
spectacular settings of any
metropolis in the world.
Big Oil
With Brazil’s pre-salt reservoirs poised
to be the world’s 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 |

50
16
20
50
54
54
60
62
64
What’s 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
Paciﬁc’s fractured basement reservoirs.
Geothermal Hot Spot
With 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 Neighbors
A grant from Baker Hughes is helping
enterprising Kazakhstani youth make a
positive contribution to their community.
Latest Technology
Baker Hughes develops and delivers new
technologies to solve customer challenges.
A Look Back
R.C. Baker’s contributions to the petroleum
industry helped launch today’s Baker Hughes.
is published by Baker Hughes
global marketing. Please direct all
correspondence regarding this publication to
connexus@bakerhughes.com.
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 Team
Kathy Shirley, corporate communications manager
Cherlynn “C.A.” Glover, publications editor
Tae Kim, graphic artist
Stephanie Weiss, writer
Printed on recycled paper

BIGOIL
A 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 ﬁnds that, by industry
estimates, hold between 50 and
100 billion barrels of oil. It’s enough
to transform Brazil into one of the
world’s top ﬁve crude oil producers.
Brazil’s Pre-salt: The World’s Next Big Opportunity
4 |

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 field,
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 Inácio
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
ocean’s surface
(see Fig. 1).
The challenges run deep
The 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 flow 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 fields themselves—some 250
to 350 km (155 to 217 miles) from
land—and the challenge of producing
these fields grows exponentially.
From microbial limestone deposits in
ultradeep water—some containing
very hard and abrasive dispersed
silica or nodules similar to quartz—to
a variety of creeping salts, Brazil’s
deep water is a geological puzzle.

“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 we’ve ever drilled.”
Baker Hughes has recently deployed two
differentiating wireline technologies—
the MaxCOR™ system and the FLEX™
tool as part of the RockView™ system,
both developed in collaboration with
Petrobras—to 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 1½-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. “We’ve
seen a 159-percent increase in average
penetration rates from when we ﬁrst started
drilling two years ago.”
Using its TruTrak™ motor closed-loop
system, Hughes Christensen Quantec™
Fig. 1
6 |

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 first
well until now, this solution has reduced
vibration levels—the biggest challenge to
drilling performance—almost 100 percent,”
Freesz says. “We have tested 12¼-in. and
8½-in. Quantec PDC bit designs with the
most impact-resistant cutters, and although
performances cannot be totally replicated
yet, we’re 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 world’s most highly
sophisticated drilling laboratory simulator
that will help develop and test technologies
to further bolster drilling capabilities.
Deepwater center of excellence
Baker 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 artificial
lift product line now holds the leading
market share in electrical submersible
pumping (ESP) systems in Brazil. The drilling
fluids product line in Brazil also has the
lion’s share of all the activity planned by
Petrobras for the next five years through
a major contract to provide technical
services, drilling fluid chemicals, brine
filtration 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 Shell’s BC-10 project in
the Campos basin, which encompasses
three separate fields—Ostra, Abalone and
Argonauta,” says Ignacio Martinez, technical
support manager for artificial lift and flow
assurance. “Each field 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.
LoggraphiccourtesyofION-GXT
01
02

challenges that resulted in a collaborative
approach to boost liquids five 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 seafloor. The systems are
designed to boost the FPSO’s maximum
capacity of 100,000 barrels of fluid per day.
ESP design considerations at BC-10
included temperature cycling, rapid gas
decompression, high-horsepower lift
requirements and high-fluid volumes. To
overcome these challenges, Baker Hughes
employed newly developed technology to
handle the fluid volumes with the required
high differential pressure—the 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 configuration. “This
differs from the approaches where the ESP
system is considered as a separate item
instead of being preplanned as part of the
final configuration,” Martinez explains.
“This project presented unique challenges
and demanded innovative approaches
to meet Shell’s 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 portfolio
Baker 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
PhotocourtesyofStéfersonFaria,Petrobras
01> The FPSO Cidade de São Vicente in the
Lula field 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 outfitted
with the new generation BJ SeahawkTM
cementing unit
8 |

wells are equipped with Baker Hughes well
monitoring systems,” Costa says. “We are
finalizing the completion of the first pre-salt
well with an intelligent well system installed
to monitor and control a deep, dual-zone,
gas-injector well in the Lula field, in the
Santos basin.”
In sand control, Baker Hughes is introducing
in Brazil the first 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 first
installation will use chemicals only, but
there is an option to connect fiber 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
Peláez, 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 Petrobras—
the Blue Shark™, the Blue Angel™ and
the Blue Marlin™—all based in Macaé,
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, filtration fluids
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 we’ve 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 250°F
(121°C). 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 fields
like these, such as loss-circulation zones
and reservoirs with high CO2
and H2
S
contents. We’ve also recently introduced
and successfully tested the concentric coiled
tubing BJ Sand-Vac™ well vacuuming
system for hydrate removal in flowlines.”
“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

Building for the future
“Continuing 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 profiling to enhance surface
seismic data; the understanding of
geomechanics-while-drilling; hydraulic,
electrical and optical completion
automation; and the influence of Baker
Hughes’ inflow 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 2010
Late 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 diversified 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 first 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 significant 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 Badstöber, technical director,
Brazil. “The 14¾-in. section was kicked off within the salt (3.9º inclination) and the angle
was built up to 23.4º inclination with 2º/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 client’s offices
in Santos) proved key to the success.” The well construction general manager for the
Santos customer states, “Now, directional wells into the salt don’t seem a monster.” The
performance obtained after drilling 1850 m (6,069 ft) was 14.3 m/h average penetration rate
in a 14¾-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,” Badstöber adds.
> Drilling 2 million ft was cause for celebration in Macaé, Brazil, where Baker Hughes has a
major operations base and a drill bit manufacturing facility.
10 |

“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 won’t 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 industry’s 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

the area known as Science Park on Ilha da
Cidade Universitaria (University Island), an
artiﬁcial 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 Fundão, 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 facilities—already one of the
largest in the oil and gas industry—doubling
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 fulﬁll 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 company’s 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), Pontifícia Universidade
Católica 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 world’s 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 |

“This drilling lab will house the world’s
largest high-pressure simulator, capable
of drilling 24-in. diameter rock cores
with a 14¾-in. bit. These cores will
be pressurized to simulate downhole
conditions up to 20,000 psi—emulating
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 world’s
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 center’s 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, fluids and materials
testing; and support of field tests.”
The facility will house an analytical lab;
laboratories for cement evaluation;
H2
S and CO2
laboratories; a rock fluids
properties and materials testing lab; a
room for core analysis; a shop suitable
for testing logging-while-drilling, wireline
and intelligent wells tools; offices 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 we’re currently doing with
our larger technology centers—such as the
drill bit systems center in The Woodlands
and the artificial lift systems facility
in Claremore, Oklahoma—which 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 efficient.”
Georgi also expects the whole of Baker
Hughes to benefit 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 flow from the
center to other parts of the globe,” he adds.
César 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 confident 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.”

There was a time when a service company provided little more than muscles and
tools. That’s no longer the case. Today’s service company is one that delivers solutions
through collaboration and partnerships.
INTELLECTUAL RELATIONSHIPS
Smart 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, we’ve
invested a lot in subsea completions,
establishing an important leadership
position for our artificial lift business in
deepwater environments. We now have
more than 60 percent of that market
share. This represents a huge growth from
four or five 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 Peláez, 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,” Peláez adds.
“I think that Petrobras sees Baker
Hughes as a true partner. We’ve fostered
customer relationships, and that’s 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 first 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 |

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 company’s 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,” Peláez says. “They were here to talk
about what they are going to need five to
10 years from now that we don’t have today
and what we would agree to develop so,
when they need it, it will be available.”
“The idea of looking that far ahead—
starting to plan now for needs five
to 10 years down the road—is 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 don’t
even realize they might need it.”
Taking into consideration the characteristics
of Petrobras’ main developments in Brazil—
complex reservoirs, ultradeepwater, deep
wells, pressure issues—Tadeu 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 fluids
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
confident 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

Reshaping Sand Control
Shape Memory Polymer Foam ‘Remembers’ Original Size to
Conform to Wellbore
> After Baker Hughes
chemists proved
the unique, scientiﬁc
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 |

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 systems—
including screens, inflow 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
it’s 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 filter with
very high permeability. However, sand
production may occur in an unconsolidated
formation during the first flow of formation
fluid due to drag from the fluid or gas
turbulence, which detaches sand grains
and carries them into the wellbore. These
“fines” 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 200°F (93°C) and
collapse pressures up to the base pipe rating
while allowing normal hydrocarbon fluid
production and preventing the production of
undesirable solids from the formation.
In a perfect world, hydrocarbons
would flow unencumbered—
and sand free—from 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.

“The possibility of performing multiple
openhole completions with sand control
efficiency close to that of ‘frac and pack’
treatments but with limited equipment
and personnel is very appealing.”
Giuseppe Ripa
Sand control knowledge owner,
Eni exploration and production
Foam vs. metal
How 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 field.
“When we first started researching
this, the properties of the materials
were a scientific novelty,” says Mike
Johnson, sand management engineering
manager for Baker Hughes. “Usually, you
bring a technology into the oil and gas
industry from another industry—from
something that’s already in use. In this
instance the science and technology
were developed within Baker Hughes.
“It definitely 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 that’s unachievable with
today’s sand control technology to prevent
sand from moving initially.”
“Oddly enough, I thought this was going
to be a difficult 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, they’ve immediately grasped
the concept and seen the benefits.”
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 it’s
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 sizes—27/8-
in. for 6-in. to 7.2-in. openhole applications
and 5½-in. for 8½-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 performance
Shape 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 |

“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 filtration.
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 filtration 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, filtration characteristics,
erosion resistance, deployment
characteristics and mechanical tool design
of the GeoFORM sand management system
were tested extensively before a field
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 fluids for extended time periods
and at varying temperatures up to
248°F (120°C),” Johnson says.
“The totally conformable screen outperforms
every screen that Baker Hughes has ever
tested for plugging or erosion resistance—
the two main problems with sand control
completions,” Richard says. “I’m sure there’s
going to be a formation material that we
find at some point that will plug it, but
we’ve always been able to plug the other
screens we’ve tested over time, and we have
never been able to plug this material in
laboratory tests.”
The first field trial in an openhole sand
control application was successfully run in
December 2010 for Eni in the Barbara field
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 efficiency 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 fines control
and production efficiency 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 first field trial in an
openhole sand control
application, run in December
2010 for Eni in the Barbara
field in the Adriatic Sea,
receives a “thumbs up” from
Eni personnel on the rig.
02

The story of the Bakken, an enormous hydrocarbon-
bearing formation in the northern U.S. and Canada, is
so incredible that some have suspected it’s an urban
myth. It’s 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
oil—they just didn’t understand until recently how
to get much of it out of the ground.
After 60 Years the
Oil was first 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 finally unlocked
the Bakken and turned it into a bonafide
boom. It’s 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 oil—making it the largest oil
find 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 |

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 it’s far from easy. It takes a
great deal of perseverance and
technical know-how to recover
the vast oil reserves in the
Bakken shale—and 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
ﬁrm estimates its production
will top 22,000 BOPD.
Unraveling the Bakken
In 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 well’s
drilling, completion, fracturing,
and production strategy can
make or break the play.
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Bakken
Three Forks
Units

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 difficult 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.
“It’s 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 4¾-in. Navi-Drill
X-treme™ series motors to
maximize penetration rates
and to reduce the number of
runs.” The X-treme motor’s
precontoured stator design
increases both mechanical
and hydraulic efficiency 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
flanks 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,
it’s finding 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 rig’s drilling operations in
the Sanish field 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 five entry
points for a total of 85 sleeves
per completion.
22 |

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. Marathon’s 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 it’s a combination of
horizontal drilling and new
completions technologies like
Baker Hughes’ FracPoint™
system, that’s made the Bakken
economic. “These are reservoirs
that were passed up over the
years. They’re 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 profitable 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
open—exposing 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
fluid 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 first
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 Whiting’s
Bakken completion expertise
and is a key to Whiting’s
industry-leading position in
Bakken fracture stimulation
effectiveness and efficiency,”
notes Jim Brown, president
and chief operating officer for
Whiting Petroleum.

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 five entry points per stage.
In February, Baker Hughes
installed the first multiport
system in a North Dakota
Bakken well. “This technology
has the potential to dramatically
impact our completion
efficiency in the shale plays in
North America,” Iguaz says.
Currently, the multiport system
can run up to 17 stages with
five 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 specific well’s fluid and
temperature regimes to literally
disintegrate in a prescribed
timeframe. So what’s 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 Bakken
Of course, completion
technology is only part of the
story—getting 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 fluid type.
“It’s not all about horsepower in
the Bakken. Typically, we pump
30 to 50 barrels of fluid per
minute, and we use cross-linked
gel-based fluids.”
But, “typical” is a relative
term. There’s no such thing as
generalities in the Bakken—
every 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. “We’ve 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 |

operations,” Rieb says. One
customer estimated it saved 10
to 15 percent in total stimulation
costs from reduced water
purchases, hauling, heating and
fluids disposal. The operator had
a constant source of produced
water stored in several tanks. In
addition to the environmental
benefit of preserving the
limited supply of fresh water,
other benefits 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 fluid. “We currently
have R&D projects under way
to understand the influence
of higher temperatures on the
system. There is significant
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. It’s extremely difficult
to adequately recomplete
10,000-ft (3048-m) laterals,
so it’s imperative we get it
right the first 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 fluids to address
scale at its source—the 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 five
years with no additional
chemical intervention.”
Lifting reserve recovery
Bakken 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
artificial 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, field 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 right—it 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 first 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 benefits.
In fact, the first 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 well’s 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
well—207 m (680 ft) deeper
than the rod pump—production
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, we’ve 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 2020—an average annual
growth rate of 9.9 percent.
And the Bakken is just the
first chapter in this story.
Marathon’s 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.”

with James J. Volker,
chairman, president and CEO,
Whiting Petroleum
w
c
W
James J. Volker and his
senior management team,
which he credits with
Denver-based Whiting
Petroleum’s growth and
success, share insight into
the challenges of producing
some of the nation’s 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, you’re at a real
disadvantage, so it’s 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
proﬁtability that is sometimes
seen in a conventional reservoir
play. In order for independent
U.S. companies to compete
internationally in the resource
plays—where the economics
are typically in the 2:1 to
3:1 or 4:1 range, rather than
10:1—it’s 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
26 |

so it’s 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 fiscal regime need
to be competitive with what
we’re 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
fluid than gas, it is more difficult
for it to flow through the tiny
pores within the shale. In the
completion or the fracturing
phase, we aim to leave a much
higher fracture conductivity—a
much higher sand concentration,
so to speak—near the wellbore
to maximize flow rates. You can
flow more gas than oil through
a lower permeability sand pack.
The other thing that’s true with
oil reservoirs, whether you’re
in vertical wells or horizontals,
is you have to have tighter
well spacing because you’re
not going to drain as big an
area. That’s why we’re 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?
Whiting’s 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 technology—especially
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 efficiency 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 five to seven
days reduction in drill time.
On the completion side,
Bakken shale completions have
evolved significantly from three
years ago. Horizontal drilling
with single-stage fracture
stimulations was being used
with good results in Montana’s
Elm Coulee field, 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
significant development in the
Sanish field, and we’ve 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 five or six days
with plug and perf. Therefore, it
is much more efficient 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 field 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 fluid
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]. Efficient 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
profitable 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

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 profit 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 it’s 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 profitable 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 first 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 efficiently
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
difficult 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 first 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
difficult 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 flatten the rate of decline,
improve estimated ultimate
recovery and make results
more profitable.
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 we’ve had challenges
within that play. The Sanish field
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. We’ve
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
separate wellbores in the Sanish
field—typically four wellbores
in the Bakken and another three
in the underlying Three Forks to
most efficiently drain both of
those reservoirs.
As we embark into some areas
within our Lewis and Clark
play and subsets of that play
away from the Sanish field,
we get into some thinner rock
that doesn’t have as much
Bakken pay. It’s tighter rock.
It’s also harder rock. One of
the challenges that we’ve
encountered there is much
higher frac pressures. We’ve had
to modify our frac designs to
frac the rock at higher pressures.
The fractures don’t open as
wide. We can’t put as much
sand into the fractures in the
harder rock areas. In the thinner
rocks, it’s even more important
to keep our costs down. Using
frac sleeves to help us keep our
per-stage frac costs down, we
can develop areas where the
Bakken rock is thinner, and not
as good a rock, and still make
very productive wells.
This year, Baker
Hughes ran a 40-stage
completion in the
Williston basin for
Whiting Petroleum—
the largest number
of stages ever run
using a ball/sleeve
method for isolation.
Explain how multistage
completions enhance
reservoir performance.
28 |

Prior to the Baker Hughes
FracPoint technology, it was
difficult to create multiple
fractures over a large interval,
thus, some parts of the lateral
were left unstimulated.
Multistage completions are very
effective, especially in longer
laterals, because the lateral is
stimulated one small section at
a time, effectively stimulating
the entire lateral. Baker Hughes
has been a pioneer in multistage
fracing and continues to
work closely with Whiting to
develop new technology in
multistage tools and design.
Forty stages was a real high
point. Baker Hughes is working
to enhance the industry’s
ability to stimulate our shale oil
wells even more effectively.
Recovery rates in
most shale plays
range from 15 to 25
percent with current
“best technologies.”
What next-generation
technologies are
needed to increase
these recovery rates?
Contacting the reservoir is a
recurring theme here. Any new
technologies that will allow
us to effectively contact more
rock will help us increase our
profitability and our overall
efficiency, whether that’s more
fracture stages through 40-stage
or 50-stage FracPoint systems
or tighter well density. If we
can touch more rock, we’re
going to get better results.
The Sanish field has some of
the very best rock seen in the
middle Bakken, but as we move
out into other areas, we may
not be as blessed with such a
high-quality reservoir. Therefore,
it will be more important to
efficiently touch more reservoir
rock in order to make our drilling
program a success. Anything
we can do to understand the
reservoir better through log
interpretation, core analysis
or reservoir modeling, the
better we can adapt to it—
mechanically or chemically or
just through sheer force to help
us achieve better results.
The very first well that we drilled
that was economically successful
in Sanish was called the Perry
State 11-25H well. In that well,
we drilled 21,000 ft (6401 m)
in three separate laterals. Our
original idea was that the more
rock that you access, the better
your opportunity to increase
your recovery. The problem
we encountered was that you
could really only do multistage
completions in a single lateral.
We are now moving to design
multistage completions in
multilateral wellbores. That,
as we see it, is one of the next
evolutionary steps in trying
to develop these reservoirs.
For now, we have elected
to drill single laterals until
some lower cost multilateral
devices are developed.
What is the fracturing
method of choice in
shale reservoirs?
Whiting’s choice is definitely
FracPoint completions in long
laterals. We’ve used various
methods and we’ve definitely
watched operators use a wide
range of methods, but for us, for
our efficiency, for our level of
activity, FracPoint technology is
our chosen route.
Some of your
competitors prefer
the plug and perf
methodology, and
they believe that
gives them better
productivity. What is
your view on that?
We disagree. We have
benchmarks. We know what
we expect, and we know what
we are getting. We’ve spoken
about spud to total depth,
but in the overall picture, the
most important measure is
spud to sales because spud
is when you start investing
money, and sales are when
you start earning a return on
your investment. By using
multistage sleeve technology,
we can complete a frac in 24
hours versus six days, so, once
again, that decreases our spud
to sales time, which is the
ultimate measure of how well
you invest your money. We’ve
done quite a bit of plug and
perf work just to make sure that
we’re right—that sleeves are
just as good. We have not seen
better results in comparable
rock with plug and perf.
You can certainly say that we
would not be at this production
level or have the same number
of wells producing if we were
having to complete with the
plug and perf method.
> Front row (left to right), Brent Miller, operations manager, Northern Rockies
Asset Group, Whiting Petroleum; Monte Madsen, senior operations engineer,
Northern Rockies, Whiting Petroleum; and Adam Anderson, vice president,
U.S. Land Operations, Baker Hughes; back row (left to right), Doug Walton,
vice president, U.S. Drilling, Whiting Petroleum; John Paneitz, senior
operations engineer, Northern Rockies, Whiting Petroleum; and George
Gentry, account manager, Baker Hughes.

It is never easy to reconstruct the events from millions of years ago
that led to the formation of valuable deposits of oil and gas now
trapped thousands of meters below the ground. Sometimes the
challenge of unlocking these hydrocarbons demands the application
of cutting-edge technologies such as the advanced logging-while-
drilling (LWD) tools that Baker Hughes recently introduced in Russia.
01> New technologies
applied on wells
drilled on northwest
Siberia’s Yamal
Peninsula are helping
operators reach new
levels of productivity
4500 m (2.8 miles)
under the sea.
01
The right technologies in the right applications
Conventional drilling and formation evaluation techniques being used on long horizontal wells in the
Yurkharovskoe ﬁeld in northwest Siberia were not meeting Novatek’s (Russia’s largest independent natural
gas producer) objective, which was to improve planned well rate and construction performance. Baker
Hughes, in partnership with drilling contractor Nova Energeticheskie Uslugi LLC (NEU), wholly owned division
of CJSC Investgeoservice, delivered a solution.
“Sedimentary reservoirs are not always laid down in a neat and tidy manner by Mother Nature. There
are many types of reservoirs, and some are thinly laminated, often requiring horizontal wells to be drilled
through the sweetest spot to maximize the wells’ drainage area,” explains Ravan Ravanov, drilling systems
sales manager for Baker Hughes in Russia Caspian. “Often, there are faults and up-thrusts, pinch-outs and
30 |

other events that challenge even the most
experienced geologists to predict with any
degree of certainty where the well path must
be placed for maximum gas production. This
is where downhole real-time measurement
technology lends a hand.”
Baker Hughes began providing directional
drilling services and basic LWD services
in this field in August 2009 and has since
drilled wells with continuously improved
rates of penetration (ROP). To improve
drilling performance, Baker Hughes proposed
the use of its Navi-Drill™ Ultra™ series
high-powered downhole drilling motors,
including the Ultra R™, Ultra XL™,
Ultra-Xtreme™ and Xtreme™ motors,
in combination with drill bits specially
designed for this particular reservoir to
complement the motor characteristics and
to provide optimized drilling economics. As a
result, drilling performance on the first four
conventional wells increased dramatically,
according to Ravanov.
Fig. 1 highlights the performance on the
third well based on an aggressive updated
drilling plan where days on bottom were
further reduced by approximately 42 percent.
Encouraged by the productivity increases,
Baker Hughes worked with NEU to propose
a plan for the next well—a 4400-m
(14,435-ft) dual lateral—that included
the application of more sophisticated
technologies for well construction.
Baker Hughes used the AutoTrak™ rotary
steerable drilling system, paired with
OnTrak™ and LithoTrak™ advanced LWD
tools, to acquire the data on the horizontal
sections of the well. The customer also
added Baker Hughes bits to improve
reliability, ROP and steerability. The
post-well petrophysical evaluation of the
first multilateral leg by a Baker Hughes
geoscience team indicated that the payzone
exposure along the wellbore was only 33
percent reservoir quality sand: the remaining
390 m (1,279 ft) was nonreservoir quality
rock. “It became clear that the anticipated
quality and thickness of the reservoir was
not reached, and so a new plan for the next
well was needed,” Ravanov says.
Working closely with the NEU specialists
and Novatek geologists, the Baker Hughes
geoscience and drilling teams suggested the
implementation of Baker Hughes Reservoir
Navigation Services™ (RNS™). This
sophisticated system combines the AutoTrak
system with a range of LWD sensors that
measure, then transmit to surface, real-time
data about the rock being drilled. This data
enables petrophysicists and geologists to
build a detailed lithological model around
the wellbore as it is being drilled. The
distance to and spatial position of reservoir
boundaries are determined, which then
allows real-time optimization of wellbore
trajectory through commands being sent
to the steerable system to steer up, down,
left or right, and thus stay within the most
productive reservoir zone.
Field data was sent to the Moscow Baker
Hughes BEACON™ real-time operations
Fig. 1

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days
Time vs. Depth
meters

Connexus 2a. ed.

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