Connexus 2

CONNE US

Totally ConformableRevolutionizing sand management with shape memory polymer foam

Brazils Big OilPre-salt: The worlds next big opportunity

The Booming BakkenUnlocking the secrets of the giant shale play

2011 | Volume 2 | Number 1

The Baker Hughes Magazine

In the inaugural issue of Connexus, Chad Deaton, our CEO, discussed the new Baker Hughes. The last few years have been an exciting time of change for Baker Hughes and today, we are executing on our expanded business capabilities to better serve customers across every phase of their operations.

The geomarket organization we established in 2009 is delivering stronger market understanding, a coordinated products and service offering, and closer relationships with our customers. For example, the stories on Pages 11-15 describe how our Brazil team is building strong ties with customers. We work closely with Petrobras and other companies in Brazil to understand their challenges and to develop the technologies needed to unlock reserves locked in offshore Brazils complex reservoirs. We will open a region technology center in Rio de Janeiro later this year to build even stronger technology relationships with our customers.

The reservoir competencies weve added to our product portfolio are now embedded in the business. We are identifying opportunities across the asset life cycle to help our clients maximize the full value of their prospects and elds. You will nd an example of this integration of our portfolio in the story on Page 50 that describes how the collaboration between the reservoir team and our Southeast Asia geomarket is helping clients better understand fractured basement reservoirs. Also, we were recently awarded a contract by PETRONAS Carigali to revitalize the mature elds in the D-18 production area offshore Malaysia. This project will bring together the full breadth of Baker Hughes reservoir capabilities and products and services to partner with PETRONAS Carigali for a full eld redevelopment.

The integration of BJ Services has been faster and smoother than we anticipated. The merger

BEYOND TRANSFORMATIONPresident and Chief Operating Ofcer Martin Craighead

was a perfect t. In North America, we are offering a coordinated suite of technologies, including drilling, completion, pressure pumping, and production products and services designed to lower operating costs and maximize production. This is particularly true in the shale plays where the right solution is critical to economic development. The story on the Bakken shale (Page 20) details how we are solving customer challenges in this prolic play.

Pressure pumping also is an important addition to our international portfolio. On Page 4 you can learn more about how we have integrated our drilling, completion, stimulation and production expertise to provide Petrobras and other companies in Brazil innovative solutions to their deepwater challenges.

Of course, technology innovation is the foundation of Baker Hughes business, and we are in the midst of one of the most exciting technology development eras in our history. We now have an enterprise technology strategy that is market centered, business oriented and research enabled. We have developed a clearer commercial framework for technology-led business innovation.

We have charted a course to increase the velocity of technology through our system and to focus on commercial results. As a consequence, we are concentrating on the most critical technology developments in our ideation pipeline, and we have improved our

speed to market in many cases by a factor of three. The result is innovative technology advancementstruly disruptive step changes to some of our customers biggest challenges. On Page 16 you will nd an in-depth article on one of those technologies. The GeoFORM sand management system is an outgrowth of our fundamental science initiative and represents an entirely new approach to sand control that will lower risk factors and improve productivity from unconsolidated reservoirs.

As we accelerate the execution phase of building the new Baker Hughes, it is important to acknowledge that this level of change comes with a certain amount of stress. I have to commend our global workforce for the hard work and perseverance to see us through this time of ux. Our people were asked to take on new roles, often in new places, and often with a great deal of ambiguity. It may sound clichd, but its truethe greatest asset for any organization is not its monetary capital, but rather its people, and the teams all across Baker Hughes have pulled together to ensure that our customers needs have remained our singular focus.

To fully leverage the strength of our organization to better serve customers, its been necessary to redesign how we work. We now have an operating system in place to reduce the complexity of our business and drive standardization across operations and product lines. The key to an effective global operating system lies in its ability to capture optimization and

pollinate the organization with learning. We are already seeing its impact at every level of our business. For example, there are processes and procedures in place today designed to guide our global quality and reliability program; to assess market needs; to recruit and develop talent; and to manage our portfolioall important business drivers that add value for our customers.

Going forward, we will measure our success. Ultimately, the goal is to make accountability the core of our culture. I am a rm believer that you get what you measure and we have a process in place to measure ourselves as our customers and our investors measure us. We track operational key performance indicators at a global level to give us visibility to trends in our business and at the local level to get a more granular view of our operations. No function gets a passwe also have standard key performance indicators for our global teams like products and technology and supply chain.

In closing, I am excited about our substantial progress toward executing on our strategies to build a customer-focused operation and a stronger portfolio. Of course, none of this would be possible without the support of you, our customers. We sincerely appreciate the opportunity to work with you to solve your reservoir, drilling and production challenges.

| 1www.bakerhughes.com

Advancing Technology FrontiersBaker Hughes is constructing a new $30- million research and technology center in Rio de Janeiro to support the industrys economic development of pre-salt reservoirs offshore Brazil.

Intellectual RelationshipsAnticipating growth in Brazil, Baker Hughes put a strategy in place to grow business and foster long-lasting customer relationships.

Reshaping Sand ControlA totally conformable sand screen engineered from shape memory polymer foam has the industry rethinking sand management.

Unlocking the BakkenAdvances in drilling and completion technology are lowering operating costs and enhancing production performance for operators in the Bakken shale.

Industry InsightJames J. Volker, chairman, president and CEO of Whiting Petroleum, shares insight into producing some of the top oil shale plays in the U.S. and the technologies needed for the future.

Real-time Solutions in RussiaNew technologies applied on wells drilled in northwest Siberias Yamal Peninsula are helping operators reach new levels of productivity.

Clean, Efcient FracturingAn innovative hydraulic fracturing technology dramatically cuts water and chemical requirements to safely and efciently stimulate gas production from shale formations in environmentally conscious New York.

Faces of InnovationMeet Bennett Richard, the newest Baker Hughes Lifetime Achievement Award winner, who enjoys developing people as much as technologies.

Ghanas First OilAs a key player in the Jubilee project, Baker Hughes is determined to make this African countrys rst oil pay off for the people.

The Complete PackageThe OptiPortTM completion system combines coiled tubing with sliding sleeves to take multistage fracturing to new levels.

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On the Cover Rio de Janeiro occupies one of the most spectacular settings of any metropolis in the world.

Big OilWith Brazils pre-salt reservoirs poised to be the worlds next big opportunity, Baker Hughes is focused on establishing a deepwater center of excellence in Brazil to deliver customized answers to the toughest of challenges.

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Whats in Your Basement?From constructing detailed geomechanical and reservoir volumetric models to record-setting drilling and evaluation performance, Baker Hughes is delivering results in Asia Pacics fractured basement reservoirs.

Geothermal Hot SpotWith the Baker Hughes Center of Excellence for geothermal and high-temperature research and development in Celle, Germany, the company is well positioned to support the growing demand for geothermal power in continental Europe.

Good NeighborsA grant from Baker Hughes is helping enterprising Kazakhstani youth make a positive contribution to their community.

Latest TechnologyBaker Hughes develops and delivers new technologies to solve customer challenges.

A Look BackR.C. Bakers contributions to the petroleum industry helped launch todays Baker Hughes.

is published by Baker Hughes global marketing. Please direct all correspondence regarding this publication to [email protected].

www.bakerhughes.com

2011 Baker Hughes Incorporated. All rights reserved. 32310 No part of this publication may be reproduced without the prior written permission of Baker Hughes.

Editorial TeamKathy Shirley, corporate communications managerCherlynn C.A. Glover, publications editorTae Kim, graphic artistStephanie Weiss, writer

Printed on recycled paper

BIGOILA glass-paneled cable car destined for the peak of Sugar Loaf is the perfect venue for a million tourists a year to enjoy the sights and sounds of Rio de Janeiro: the white sands of Copacabana beach, samba in the streets and the Cristo Redentor statue, one of the new Seven Wonders of the World.

Far beyond the outstretched arms of the art deco statue lie even greater wonders: huge nds that, by industry estimates, hold between 50 and 100 billion barrels of oil. Its enough to transform Brazil into one of the worlds top ve crude oil producers.

Brazils Pre-salt: The Worlds Next Big Opportunity

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Petrobras, the Brazilian state oil company, announced plans to invest $224 billion from 2010 to 2014 to help Brazil become a major energy exporter by tapping the vast reserves buried some 7 km (4 miles) beneath the ocean in what is known as pre-salt reservoirs.

In 2007, while drilling in more than 2.1 km (1.3 miles) of water in the Tupi prospect of the Santos basin, Petrobras made a huge discovery in the pre-salt. Almost instantly, the company knew two things: It had found a supergiant oil eld, and producing it was

going to require technologies yet unknown to the industry. (The Tupi prospect was renamed Lula in December 2010 in honor of outgoing Brazilian President Luiz Incio Lulada Silva.)

The pre-salt reservoir lies in water depths up to 3 km (1.8 miles) and beneath a vast layer of salt, which, in certain areas, can be as much as 2 km (1.2 miles) thick. Above the salt canopy lie 1 to 2 km (.62 to 1.2

miles) of rock sediments, and below it lies the

actual oil-laden pre-salt bounty, 5 to

7 km (3.1 to 4.3 miles) below the

oceans surface (see Fig. 1).

The challenges run deepThe Brazilian pre-salt discoveries open a new frontier in exploration and development not only for Petrobras, but for the many international oil companies moving into these waters. However, exploring, drilling and producing the reservoirs present operators with incredible challenges related to the complexities of the carbonate reservoir rocks, the ow assurance issues due to the nature of the oil and production conditions, the separation and disposal of the CO2 in the produced gas, and the handling of the produced water. Add to that ultradeep water and the remoteness of the elds themselvessome 250 to 350 km (155 to 217 miles) from landand the challenge of producing these elds grows exponentially.

From microbial limestone deposits in ultradeep watersome containing very hard and abrasive dispersed silica or nodules similar to quartzto a variety of creeping salts, Brazils deep water is a geological puzzle.


Depending on the area and depth you are working in, you face completely different reservoir lithologies, says Luiz Costa, completion engineering manager for Baker Hughes in Brazil. Sometimes, those big differences can occur within one single well.

Abdias Alcantara, marketing and business development manager for Baker Hughes drill bit systems, agrees. The pre-salt environment consists of reservoirs that are complex heterogeneous carbonates. The deposition is not like a typical sequence of rock with one smooth layer upon another, he explains. You might be drilling through intercalated shales, then drill a few meters in

another direction and

discover something different. These zones are very unpredictable and

some of the toughest weve ever drilled.

Baker Hughes has recently deployed two differentiating wireline technologiesthe MaxCOR system and the FLEX tool as part of the RockView system, both developed in collaboration with Petrobrasto help characterize these reservoirs so more effective drilling and production programs can be designed. The RockView system combines geochemical data to compute detailed lithology and mineralogy descriptions of the formation. It collects geochemical data that is used to determine the mineral

properties, amount and distribution of total organic content in a reservoir.

The MaxCOR system is a rotary sidewall coring technology that enables the recovery of more than three times more core volume and up to 60 cores, when compared to standard rotary coring tools. The MaxCOR system can drill and retrieve multiple 1-in. diameter core samples greater than 2 in. in length in minutes, greatly reducing rig time dedicated to coring operations. The higher core volumes provide better results when analyzing mechanical properties, relative permeability, compressibility, capillary pressure, electrical parameters and geomechanical properties.

In these ultradeep waters, where rig spread-rates can easily reach $1 million a day, it is imperative to push the technology envelope. Marcos Freesz, pre-salt project manager in Brazil, says that Baker Hughes has implemented a strong downhole monitoring philosophy to improve drilling performance and drilling rates in both the salt layers and the pre-salt formations.

In the salt, we are mainly using the CoPilot real-time drilling optimization service and AutoTrak rotary steerable system to push the rate of penetration (ROP) to technical limits, Freesz says. Weve seen a 159-percent increase in average penetration rates from when we rst started drilling two years ago.

Using its TruTrak motor closed-loop system, Hughes Christensen Quantec

Fig. 1

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PDC bits and the CoPilot service in the pre-salt carbonate section, Baker Hughes has increased ROP more than 300 percent, Freesz adds. Besides improved penetration rates, the process is focused on maintaining bit cutting structure for as long as possible, thus eliminating bit runs, which equates to customers spending less on rig time, as well as a reduction in associated HS&E risk.

Baker Hughes has drilled four pre-salt wells with this system approach. From the rst well until now, this solution has reduced vibration levelsthe biggest challenge to drilling performancealmost 100 percent, Freesz says. We have tested 12-in. and 8-in. Quantec PDC bit designs with the most impact-resistant cutters, and although performances cannot be totally replicated yet, were seeing a consistent optimization improvement through a very important and steep learning curve.

In the reservoirs above the salt canopy (post-salt) in the Campos and Espirito Santos basins, quite a different geological objective is being successfully achieved with horizontal well drilling using the AziTrak azimuthal deep resistivity system coupled with full Reservoir Navigation Services (RNS) in real time, adds Jeremy Jez Lofts, director of strategic business development for Baker Hughes in Latin America.

In a continuing effort to better understand the complexities of drilling these formations, Baker Hughes is working with CENPES, the research arm of Petrobras, and with the

Universidade Federal do Rio de Janeiro to establish the worlds most highly sophisticated drilling laboratory simulator that will help develop and test technologies to further bolster drilling capabilities.

Deepwater center of excellenceBaker Hughes entered the Brazilian market in 1973 when Hughes Tool Company acquired a roller cone bit manufacturing facility in Salvador, the capital of Bahia state. Since the very start, the company established itself as the major drill bit supplier in the Brazilian oil industry.

For the past three years, Baker Hughes has been the leading directional drilling provider for Petrobras, while its articial lift product line now holds the leading market share in electrical submersible pumping (ESP) systems in Brazil. The drilling uids product line in Brazil also has the lions share of all the activity planned by Petrobras for the next ve years through a major contract to provide technical services, drilling uid chemicals, brine ltration equipment and environmental services (including solids control and waste management services and equipment).

With the huge growth and opportunity of both the Brazilian deepwater pre-salt and post-salt formations, and with some of the most advanced deepwater technologies available, Baker Hughes is focusing on ensuring success for operators here by becoming a deepwater center of excellence that designs and delivers customized answers to the

toughest of challenges, Lofts says.

One example is Shells BC-10 project in the Campos basin, which encompasses three separate eldsOstra, Abalone and Argonauta, says Ignacio Martinez, technical support manager for articial lift and ow assurance. Each eld presented different

01> A 500-km (310-mile) long, 15 to 20-km (9 to 12-mile) deep seismic section into the upper crust of the earth shows the sedimentary succession from near surface post-salt oceanic sediments deposited after the Atlantic ocean opened, including salt evaporite layers, basin sag sediments (including pre-salt reservoirs), to synrift and prerift sediments and the uppermost crust.

02> A silica nodule and associated siliceous laminations such as these found within the pre-salt carbonate reservoir sequence tend to pose unpredictable drilling obstacles and ones that must be constantly monitored to ensure that drill bit life and ROP are maintained.

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challenges that resulted in a collaborative approach to boost liquids ve miles along the seabed and, then, approximately 1524 m (5,000 ft) up to the FPSO. Baker Hughes installed its Centrilift XP enhanced run-life ESP system in six vertical subsea boosting stations on the seaoor. The systems are designed to boost the FPSOs maximum capacity of 100,000 barrels of uid per day.

ESP design considerations at BC-10 included temperature cycling, rapid gas decompression, high-horsepower lift requirements and high-uid volumes. To overcome these challenges, Baker Hughes employed newly developed technology to handle the uid volumes with the required high differential pressurethe Centrilift XP high-horsepower motor for enhanced reliability and a redesigned seal to withstand rapid gas decompression and high-thrust forces from the pump.

Critical to the solution was planning the ESP system as an integral component to the entire hardware conguration. This differs from the approaches where the ESP system is considered as a separate item instead of being preplanned as part of the nal conguration, Martinez explains. This project presented unique challenges and demanded innovative approaches to meet Shells needs. Although we have a demonstrated track record in subsea applications, the complexity of this subsea infrastructure and associated procedures for BC-10 called upon many of our combined resources.

A complete technology portfolioBaker Hughes provides a full line of capabilities related to reservoir characterization, drilling, intelligent well completions, cementing and stimulation techniques offshore Brazil.

New solutions will be needed, however, to meet Petrobras requirements for the future, including:

A better understanding of reservoir heterogeneity in the complex microbial carbonate environments

Faster, safer drilling and better quality wells in very challenging ultradeepwater environments

More intelligent production and completions technology that uses materials and equipment almost tailor-made for the characteristics of the developments

Improved reservoir hydrocarbon stimulation techniques

Well integrity in unstable thick salt layers

Baker Hughes has been the leader and pioneer in intelligent well systems and multilateral installations in deepwater Brazil. More than 70 percent of Brazilian offshore

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01> The FPSO Cidade de So Vicente in the Lula eld in the Santos basin

02> Baker Hughes stimulation vessels, the Blue Angel (left) and the Blue Shark, docked in Rio de Janeiro

03> Service Supervisor Tom Lister aboard the West Polaris deepwater rig outtted with the new generation BJ SeahawkTM cementing unit

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wells are equipped with Baker Hughes well monitoring systems, Costa says. We are nalizing the completion of the rst pre-salt well with an intelligent well system installed to monitor and control a deep, dual-zone, gas-injector well in the Lula eld, in the Santos basin.

In sand control, Baker Hughes is introducing in Brazil the rst Pay Zone Management system in the world. This system allows horizontal openhole gravel packing in offshore wells and injection of chemicals at several points along the screen. The rst installation will use chemicals only, but there is an option to connect ber optics, hydraulics and electronics, Costa adds.

Outside the Gulf of Mexico, Brazil is the only other place in the Western Hemisphere where Baker Hughes has stimulation vessels. The joining of the pressure pumping product line with the rest of the Baker Hughes service lines certainly increases our

overall volume of business in the country and our platform for growth, says Edgar Pelez, Baker Hughes vice president, business development and marketing, Latin America. Baker Hughes has the majority of the stimulation vessel market in Brazil.

Baker Hughes has three stimulation vessels under an exclusive contract to Petrobrasthe Blue Shark, the Blue Angel and the Blue Marlinall based in Maca, 200 km (125 miles) north of Rio de Janeiro. In Brazil, pressure-pumping operations perform between 1,200 and 1,300 jobs a year, including cementing, stimulation, coiled tubing services, wellbore cleanup, casing running, completion tools, ltration uids and chemical services, says Luis Duque, engineering and marketing manager for pressure pumping in Brazil.

Most of the wells are highly deviated or horizontal with production sections as long as 2000 m (6,561 ft), Duque explains. The

biggest challenge while stimulating these wells is to perform an effective treatment to cover the entire production section. So far, the technologies weve used to achieve this goal are self-diverting acid, gelled acids and fracturing assisted by a sand jetting tool, among others.

Regarding cementing, the biggest challenges are the deepwater locations, wells around 6200 m (20,341 ft) total depth, the thick salt layer to pass through, and bottomhole temperatures up to 250F (121C). We have introduced some new technologies in cementing, such as our BJ Set for Life family of cement systems, which were developed to attend to the wide variety of scenarios found in elds like these, such as loss-circulation zones and reservoirs with high CO2 and H2S contents. Weve also recently introduced and successfully tested the concentric coiled tubing BJ Sand-Vac well vacuuming system for hydrate removal in owlines.

With the huge growth opportunity of both the Brazilian deepwater pre-salt and post-salt formations, and with some of the most advanced deepwater technologies available, Baker Hughes is focusing on ensuring success for operators here by establishing a deepwater center of excellence that designs and delivers customized answers to the toughest of challenges. Jeremy Lofts Director of strategic business development for Baker Hughes in Latin America

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Building for the futureContinuing to deliver technologies to help understand and produce these complex reservoirs is critical to maintaining a competitive edge in this new frontier, says Saul Plavnik, drilling and evaluation operations director for Baker Hughes in Brazil. But the true advantage lies in planning now for technologies that will be needed as this market moves beyond its infancy.

Baker Hughes and Petrobras have a long history of joint technology development, Plavnik says. Over the next four years, we jointly plan to spend more than $40 million on technology collaboration projects that include, among others, 3D vertical seismic proling to enhance surface seismic data; the understanding of geomechanics-while-drilling; hydraulic, electrical and optical completion automation; and the inuence of Baker Hughes inow control devices and well geometries in microbialite reservoirs.

Together, we are already building a vision for the future.

Team Brazil Marks Two Drilling Milestones in 2010Late in 2010, Baker Hughes Brazil celebrated the milestone of drilling 2 million ft (609 600 m)most of it in water depths greater than 1,000 ft (305 m). In a second record, the Baker Hughes Brazil geomarket passed 1 million ft (304 800 m) of drilling with the Baker Hughes AutoTrak rotary steerable drilling system.

This is a very proud moment for all involved in this fantastic achievement. AutoTrak is an automated, closed-loop drilling system designed exactly for these complex deepwater offshore environments, where it is routinely being deployed with great success, says Wilson Lopes, sales director for the Brazil geomarket.

This milestone and performance position us very well, as a preferred partner, for the expected growth in the emerging ultradeepwater pre-salt plays, adds Jeremy Lofts, director of strategic business development for Baker Hughes in Latin America.

The Brazil drilling systems business has grown from just two operations with Petrobras to 22 operations in only three years, and it has diversied to drilling for other oil companies, as well. This entails a lot of hard work and achievement by the entire team, says Mauricio Figueiredo, Baker Hughes vice president of Brazil. We are very proud.

Baker Hughes Completes First Directional 2D Well in Salt In March, Baker Hughes drilled the rst directional 2D well kicking off in salt in the ultradeep Tupi cluster area of the Santos basin offshore Brazil. Based on our track record of experience, processes and performance, we were very honored to be the directional provider for this important well, Figueiredo states. This signicant milestone marks the move to better understand the optimum well type needed to produce this vast hydrocarbon play offshore Brazil, as well as to satisfy tieback logistics.

The 2D well trajectory was executed exactly as planned, and the rate of penetration achieved was comparable to vertical sections, adds Johan Badstber, technical director, Brazil. The 14-in. section was kicked off within the salt (3.9 inclination) and the angle was built up to 23.4 inclination with 2/100 ft dogleg severity, and then kept at tangent until TD. AutoTrak G3TM, OnTrak and CoPilot technologies were run with a PDC bit, and the CoPilot on-site and remote drilling optimization service (provided from the clients ofces in Santos) proved key to the success. The well construction general manager for the Santos customer states, Now, directional wells into the salt dont seem a monster. The performance obtained after drilling 1850 m (6,069 ft) was 14.3 m/h average penetration rate in a 14-in. section, outpacing peer performance of 12.5 m/h in a nearby vertical section. These types of jobs are consolidating Baker Hughes in a top position relative to evaporate drilling, Badstber adds.

> Drilling 2 million ft was cause for celebration in Maca, Brazil, where Baker Hughes has a major operations base and a drill bit manufacturing facility.

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The future of this industry will demand technology. We are looking each day to a more challenging environment. The easy oil is gone. Without the proper technology, we wont produce.

Carlos Tadeu da Costa Fraga Executive manager, Petrobras Research and Development Center

Rio Research and Technology Center

Advancing Technology Frontiers

The supergiant pre-salt discoveries offshore Brazil bring new technological challenges and demand for additional infrastructure investments. To help meet these challenges, Baker Hughes is involved in a dozen collaboration projects with Petrobras and is constructing a regional technology center to support the industrys quest for technology necessary to economically develop pre-salt reservoirs in ultradeep water offshore Brazil.

Under a cooperative agreement signed in 2009, Petrobras and Baker Hughes will invest $16.4 and $29 million, respectively, to jointly develop and apply new technologies to help address some of the challenges in pre-salt exploration and production.

Baker Hughes is investing approximately $30 million to build its Rio de Janeiro Research and Technology Center (RRTC). The center is under construction within


the area known as Science Park on Ilha da Cidade Universitaria (University Island), an articial island that serves as home to one of the largest universities in Brazil and several research centers.

Ilha da Cidade Universitaria, formerly known as Ilha do Fundo, is also home to CENPES, the Petrobras research and development center that employs approximately 2,000 people. Last year, Petrobras celebrated the opening of a $700-million expansion to the CENPES facilitiesalready one of the largest in the oil and gas industrydoubling the size to 305 000 m2 (3.3 million ft2).

The capacity for technology innovation in Brazil has been increased dramatically with this expansion, says Carlos Tadeu da Costa Fraga, executive manager, Petrobras Research and Development Center.

Brazilian universities and R&D institutions have also been investing in the expansion of their capabilities. We believe that we have in Brazil some of the best test facilities in the world, and Petrobras plans

to attract the most important suppliers to join these institutions to develop a new generation of technology needed to produce the pre-salt reservoirs.

We look to all of these institutions as an extension of our facility, in the same way we would like to have Baker Hughes see us as an extension of their R&D facility, he continues. Theirs has to be seen not as a different facility but as part of the whole effort to increase the capacity of Brazil to fulll the gap in our upstream activities. Baker Hughes has been one of the companies to show the most aggressive contribution toward our strategy, and we recognize the companys true commitment.

Petrobras wants us to help them solve problems, says Dan Georgi, vice president of regional technology centers for Baker Hughes. They have a stated objective to use the best technologies available. In 2014, when they plan to start a lot of their major developments, they want to have available new technology that will help them recover and produce more

oil at a lower cost. They are looking at us and the other service companies and universities to advance the frontier.

The Baker Hughes RRTC will facilitate collaboration between Baker Hughes and Petrobras, as well as the many international oil companies working offshore Brazil, and four universities: Universidade Federal do Rio de Janeiro (UFRJ), Universidade Estadual de Campinas (Unicamp), Pontifcia Universidade Catlica do Rio de Janeiro (PUC/RJ) and Universidade Estadual do Norte Fluminense/Laboratory of Engineering and Petroleum Exploration (UENF/Lenep).

Baker Hughes is involved in several ongoing research projects with these universities, including an evaporate drilling project with PUC and reservoir engineering studies for production optimization with intelligent wells with Unicamp. In addition, Baker Hughes is working with CENPES and UFRJ to establish a world-class drilling laboratory simulator.

> The Rio drilling lab will house the worlds largest high-pressure drilling simulator, approximately twice as powerful as the simulator at the drill bit systems product center in The Woodlands, Texas, shown here.

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This drilling lab will house the worlds largest high-pressure simulator, capable of drilling 24-in. diameter rock cores with a 14-in. bit. These cores will be pressurized to simulate downhole conditions up to 20,000 psiemulating an approximate depth of 42,000 vertical ft (12 801 m) when utilizing a standard 9.5 ppg water-based mud, explains Paul Lutes, manager for testing services at the Baker Hughes drill bit systems product center in The Woodlands, Texas.

The bit will be rotated either through a conventional rotary table arrangement or via downhole motor/turbine, which will be fed up to 500 gallons per minute at maximum pressure, or up to 1,000 gallons per minute at 6,000 psi.

While this rig will not physically be much larger than the simulator we have in The Woodlands, it will be approximately twice as powerful, Lutes adds. Power is what allows you to test at higher pressures and greater speeds. That is why it will unquestionably be the worlds largest high-pressure simulator.

A facility of this size will recreate the downhole conditions encountered in the pre-salt sections offshore Brazil. In order to optimize drilling parameters, it is necessary to simulate as much of the bottomhole assembly as possible. Therefore, the potential to add a drilling mud motor has been planned into this system.

Capabilities to test with increased mud and rock temperatures, and to handle highly porous rock and control pore pressure are also under evaluation.

Initially, the Baker Hughes Rio de Janeiro Research and Technology Center will focus on:

Wellbore construction optimization, especially for deepwater and pre-salt carbonates

Salt and pre-salt geomechanics, including impact on borehole stability and completion and production

Reservoir optimization, including application of intelligent wells, flow assurance and multifunctional scale and asphaltene inhibitors, and artificial lift technology

Reservoir description enhancement and reservoir optimization of microbial carbonates

The centers primary objective is to provide cost-effective solutions to Petrobras, Georgi says. We plan to do this by driving deepwater pre-salt reservoir cost reduction for wellbore construction, and reservoir productivity and recovery-factor optimization with advanced application engineering and geoscience; rock, uids and materials testing; and support of eld tests.

The facility will house an analytical lab; laboratories for cement evaluation; H2S and CO2 laboratories; a rock uids properties and materials testing lab; a room for core analysis; a shop suitable for testing logging-while-drilling, wireline and intelligent wells tools; ofces and think pads for the approximately 90 employees who will work there when the center reaches its full capacity.

With this center, we will be able to expedite what were currently doing with our larger technology centerssuch as the drill bit systems center in The Woodlands and the articial lift systems facility in Claremore, Oklahomawhich are responsible for providing technologies to the whole globe. This facility will be much more focused on making sure we have the

right technologies in Brazil, Georgi says. If a product needs to be customized in order to make it work better in the local market or if we need to develop software for interpretation algorithms to customize the project to the local market, we will be able to understand what our clients problems are faster, then work with our various groups outside of Brazil to shorten the development cycle and to make the technology delivery more efcient.

Georgi also expects the whole of Baker Hughes to benet from the Rio de Janeiro Research and Technology Center. We will be interacting with the best and brightest minds in Brazilian universities and will undoubtedly be able to attract some of them to work for Baker Hughes in Brazil and throughout our organization, not to mention new and enhanced technology that will ow from the center to other parts of the globe, he adds.

Csar Muniz has been appointed director of the RRTC, scheduled for completion by the end of 2011. Muniz brings 25 years of experience in exploration, production and project management to the position, having worked with Petrobras, Chevron and Repsol.

We are condent that we are going to deliver very creative solutions with Baker Hughes, Tadeu says. Given the size of the potential business, the demand for innovation of the deepwater portfolio and the local content issue, why not establish a long-term relationship with Baker Hughes in Brazil? This can become a very important hub for its worldwide technological development and, in turn, create what we have been calling a new generation of technologies for oil and gas production in deep and ultradeep water.


There was a time when a service company provided little more than muscles and tools. Thats no longer the case. Todays service company is one that delivers solutions through collaboration and partnerships.

INTELLECTUAL RELATIONSHIPSSmart planning for exploring the future together

For Baker Hughes in Brazil, the shift began when the leadership put a strategy in place to focus on anticipated growth. That strategy included investing in the best technologies and bringing in a network of technical experts that not only could grow the business but forge long-lasting customer relationships.

We started with a major investment with our drilling and evaluation business, and today, Baker Hughes holds more than 50 percent of the directional drilling market with Petrobras, says Mauricio Figueiredo, Brazil vice president. In addition, weve invested a lot in subsea completions, establishing an important leadership position for our articial lift business in deepwater environments. We now have more than 60 percent of that market

share. This represents a huge growth from four or ve years ago, and it has a lot to do with having the right strategy in place and pursuing the most promising opportunities in the market, not only with Petrobras, but with other companies, as well. It also has to do with knowing and understanding our customers better.

Because of the size of their portfolios, many major operators are becoming technical partners with their suppliers through the formation of intellectual relationships, says Edgar Pelez, vice president of marketing for Baker Hughes in Latin America.

We, as service companies, are understanding better the business of the operator and are able, with technology and operations, to provide alternatives and

solutions to the end result. Instead of telling us what to do, the operator is asking us, How do I solve this challenge? Then, we offer a solution and the reason for it, rather than just providing the mechanics of the job, Pelez adds.

I think that Petrobras sees Baker Hughes as a true partner. Weve fostered customer relationships, and thats one of our main strengths in Brazil. It is one where we are happy to say that upper management of both companies calls each other by rst names, and that is not necessarily something we can do with all our customers around the world.

The other strength is the commitment of Baker Hughes to Brazil. We have committed major investments in facilities,

> Baker Hughes hosted a three-day workshop in December 2010 for Petrobras at its Center for Technology Innovation in Houston.

14 |

in people and in the deployment of technology to support the growth. This commitment fuels customer intimacy.

Carlos Tadeu da Costa Fraga, executive manager of CENPES, Petrobras Research and Development Center, says that Petrobras has a long-term commercial relationship with most service companies because they have been doing business in Brazil for more than 30 years. But what is changing, Tadeu says, is that the national oil companys growing and ever-challenging portfolio drives the need for more expertise and knowledge.

The size of the potential business in Brazil is very attractive, and most of the existing suppliers want to expand their commercial activity in Brazil, and we welcome them, Tadeu says, but we want to do that

followed by the establishment of a quite strong intellectual relationship, as well.

In December 2010, Baker Hughes hosted a three-day workshop for Petrobras at its Center for Technology Innovation in Houston so executives from both companies could discuss long-range plans to meet future challenges.

It was clear that Petrobras was not interested in seeing what Baker Hughes has today, Pelez says. They were here to talk about what they are going to need ve to 10 years from now that we dont have today and what we would agree to develop so, when they need it, it will be available.

The idea of looking that far aheadstarting to plan now for needs ve

to 10 years down the roadis very important and a real achievement for our company, Figueiredo says. Together, we have been doing a lot of innovative things, but the vast majority has been demand-driven. Sometimes you have to think of something so innovative and so forward thinking that customers dont even realize they might need it.

Taking into consideration the characteristics of Petrobras main developments in Brazilcomplex reservoirs, ultradeepwater, deep wells, pressure issuesTadeu outlines the following future needs.

We will need to better characterize the internal properties of those reservoirs so we can better understand and predict their quality. We are developing and applying drilling technologies that will allow us to drill faster, safer and quality-wise better in those very challenging environments, as well as completions technology that uses materials and equipment almost tailor-made for the characteristics of our developments.

We are dealing with aggressive uids and different types of reservoirs where intelligent completions are very, very important for us. Because the salt may move over time, well integrity is very important. We are looking for new approaches for bottomhole assemblies, casing and cementing technologies and, in the long-term, even to different drilling techniques such as laser drilling.

Thirty years ago, the industry could never have imagined intelligent completions, real-time monitoring or nanotechnology. There is a lot of room for innovation in the drilling and completion arenas, and we need to start thinking together more aggressively about the new set of technologies we want to have available for the pre-salt Phase II development. We are condent that we are going to deliver very creative solutions with Baker Hughes.

01> Workshop conversation between Carlos Tadeu da Costa Fraga, executive manager of CENPES (upper right); Derek Mathieson, president, products and technology for Baker Hughes (lower right); Mauricio Figueiredo, vice president, Brazil for Baker Hughes (lower left) and Matthew Kebodeaux, vice president of completions for Baker Hughes.

01


Reshaping Sand ControlShape Memory Polymer Foam Remembers Original Size to Conform to Wellbore

> After Baker Hughes chemists proved the unique, scientic properties of the shape memory polymer foam material, Bennett Richard (left) and Mike Johnson helped take it from the lab table to the rotary table.

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For as long as man has dug or drilled into the earth, whether searching for drinking water or for heating oil, he has struggled to keep his bounty free of sand. Today, sand migration continues to plague drilling operations worldwide, causing reduced production rates, damage to equipment, and separation and disposal issues. In short, sand is an ever-present, costly obstacle to oil and gas production.

Baker Hughes has been helping operators reduce the serious economic and safety risks of sand production for decades through deployment of sand management systemsincluding screens, inow control devices and gravel packing. All have the same goal: to keep sand from entering the well along

with the hydrocarbons without affecting production. But even gravel packing, the most widely used and highly effective sand control method, has its drawbacks.

In gravel packing, sand, or gravel as its called in the industry, is pumped into the annular space between a screen and either a perforated casing or an openhole formation, creating a granular lter with very high permeability. However, sand production may occur in an unconsolidated formation during the rst ow of formation uid due to drag from the uid or gas turbulence, which detaches sand grains and carries them into the wellbore. These nes will then lodge in and plug the

gravel pack, increasing drawdown pressures and decreasing production rates.

Now, after years of research, Baker Hughes has engineered a totally conformable wellbore sand screen from shape memory polymer foam that has the industry rethinking sand management: the GeoFORM conformable sand management system using Morphic technology.

This advanced material can withstand temperatures up to 200F (93C) and collapse pressures up to the base pipe rating while allowing normal hydrocarbon uid production and preventing the production of undesirable solids from the formation.

In a perfect world, hydrocarbons would ow unencumbered and sand freefrom the reservoir into the wellbore like a river toward an open sea.

How the GeoFORM conformable sand management system using Morphic technology works

When the polymer tube is taken to a temperature above its glass transition temperature, it goes from a glass or hard plastic state to an elastic, rubber-like state. For the Baker Hughes 27/8-in. totally conformable sand screen, the polymer tube is constructed with an outside diameter of 7.2 in. The tube is taken to a temperature above its glass transition temperature where it becomes elastic. The tube is then compressed and constrained to a diameter of 4.5 in. While holding this constraining force on the tube, it is cooled below its glass transition temperature, which locks the material at the new reduced diameter, essentially freezing the tube into this new dimension. Once downhole, the material springs back to its original 7.2-in. diameter.


The possibility of performing multiple openhole completions with sand control efciency close to that of frac and pack treatments but with limited equipment and personnel is very appealing.

Giuseppe RipaSand control knowledge owner, Eni exploration and production

Foam vs. metalHow do you convince a customer who has run metal screens downhole for years to give something made of foam a chance?

That was the big question that Baker Hughes scientists and engineers faced as they developed a brand new technology never before used in the oil eld.

When we rst started researching this, the properties of the materials were a scientic novelty, says Mike Johnson, sand management engineering manager for Baker Hughes. Usually, you bring a technology into the oil and gas industry from another industryfrom something thats already in use. In this instance the science and technology were developed within Baker Hughes.

It denitely has some major advantages over what is currently offered in the area of sand control. Compared to other products in openhole applications, it provides a stress on the formation thats unachievable with todays sand control technology to prevent sand from moving initially.

Oddly enough, I thought this was going to be a difcult sell, says Bennett Richard, director, research for the Baker Hughes completions and production business

segment. But, every time our customers have toured our research center and seen this product, theyve immediately grasped the concept and seen the benets.

Richard explains how the technology works: Shape memory polymers behave like a combination of springs and locks. The behavior of these springs and locks is dependent upon what is called the glass transition temperature. A polymer below a certain temperature is locked in position and acts as a glass or hard plastic. If you take it above this glass transition temperature, it starts to act as a spring and becomes more elastic like rubber. For our 27/8-in. screens, we construct a polymer tube with an outside diameter of 7.2 in. That tube is then taken to a temperature above its glass transition temperature where it becomes elastic. The tube is then compressed and constrained to a diameter of 4.5 in.

While holding this constraining force on the tube, it is cooled back down below its glass transition temperature, which locks the material at the new reduced diameter. The process essentially freezes the tube into this new dimension. Once downhole, the material sees its coded transition temperature again and remembers that its supposed to be a bigger diameter and tries to spring back to its original 7.2-in. diameter.

The material composition is formulated to achieve the desired transition temperature slightly below the anticipated downhole temperature at the depth at which the assembly will be used.

The totally conformable sand screens are currently manufactured in two sizes27/8-in. for 6-in. to 7.2-in. openhole applications and 5-in. for 8-in. to 10-in. openhole applications. The screens come in 30-ft joints made up of four 6-ft screen sections (tubes) and can be run in any openhole application where metal expandable screens, standalone screens and gravel packs would be used.

Conformance performanceShape memory polymers are being tested for use in the auto industry on parts, such as bumpers, that repair themselves when heated and in the medical industry for instruments, such as expanding stints, which can be inserted into an artery as a temporary shape and expand due to body heat.

There are many types of polymers commercially available: polyethylene foam, silicone rubber foam, polyurethane foam and other proprietary rubber foams, to name but a few. Most of these, however, yield soft closed-cell foams that lack the strength to be used downhole.

01

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Some materials, such as rigid polyurethane foam, are hard but very brittle, Johnson says. In addition, conventional polyurethane foams generally are made from polyethers or polyesters that lack the thermal stability and the necessary chemical compatibility for downhole applications.

The GeoFORM sand management system, created at the Baker Hughes Center for Technology Innovation in Houston, is an advanced open-cell foam material designed with two key attributes for openhole application: reservoir interface management and ltration.

Johnson explains, It is generally accepted that particulates less than 44 micrometers can be produced from the well without erosion damage to the tubing or surface equipment, so the GeoFORM material matrix was designed to allow less than 3 percent total particles to pass, with 85 percent of those particles being 44 micrometers or less.

An openhole completion ltration media permeability should be at least 25 times the permeability of the productive reservoir to avoid productivity restrictions. If the reservoir has a permeability of one darcy, the GeoFORM sand management system would require a permeability of 25 darcies to prevent productivity impairment.

Because it is an entirely new material, the mechanical properties, chemical stability, permeability, ltration characteristics, erosion resistance, deployment characteristics and mechanical tool design of the GeoFORM sand management system were tested extensively before a eld trial on a cased-hole remediation well in California in October 2010.

In order to fully understand the properties of the new material and its potential application window in the downhole environment, the material was aged in various inorganic and organic uids for extended time periods and at varying temperatures up to 248F (120C), Johnson says.

The totally conformable screen outperforms every screen that Baker Hughes has ever tested for plugging or erosion resistancethe two main problems with sand control completions, Richard says. Im sure theres going to be a formation material that we nd at some point that will plug it, but weve always been able to plug the other screens weve tested over time, and we have never been able to plug this material in laboratory tests.

The rst eld trial in an openhole sand control application was successfully run in

December 2010 for Eni in the Barbara eld in the Adriatic Sea. Giuseppe Ripa, sand control knowledge owner for Eni exploration and production, says, The possibility of performing multiple openhole completions with sand control efciency close to that of frac and pack treatments but with limited equipment and personnel is very appealing.

Moreover, there is the possibility to develop short (1 m) unconsolidated silty layers where frac and pack is mandatory for nes control and production efciency but the treatment is not feasible, Ripa says. This aspect is very attractive in deepwater developments where multiple sand bodies must be completed in one horizontal or highly deviated well in order to be economical through less rig time being consumed.

The GeoFORM screens are being manufactured at the Baker Hughes Emmott Road facility in Houston at a rate of about 2,500 ft (762 m) per month. Justin Vinson, project manager for the sand management system, says, The product portfolio will be expanded in 2011 to include more sizes, different temperature ranges and a through-tubing remedial application.

01> Design Engineer Jose Pedreira calibrates the outside diameter of the compacted GeoFORM screen before running it in the well.

01> The rst eld trial in an openhole sand control application, run in December 2010 for Eni in the Barbara eld in the Adriatic Sea, receives a thumbs up from Eni personnel on the rig.

02


The story of the Bakken, an enormous hydrocarbon-bearing formation in the northern U.S. and Canada, is so incredible that some have suspected its an urban myth. Its even been addressed on websites dealing with hoaxes. But those in the energy industry have known for decades that it holds a vast amount of oilthey just didnt understand until recently how to get much of it out of the ground.

After 60 Years the

Oil was rst discovered in the Bakken formation in Williams county, Mont., in 1951, but the giant accumulation remained a mystery for almost 60 years. Only sporadic drilling occurred until 2008 when technology advancements nally unlocked the Bakken and turned it into a bonade boom. Its no wonder oil companies kept plugging away at the Bakken. The U.S Geological Survey estimates that the play holds three to four billion barrels of recoverable oilmaking it the largest oil nd in the contiguous U.S. Estimates for the Canadian Bakken are approximately 68.7 million barrels of oil.

> Just south of the boom town of Williston, N.D., is Theodore Roosevelt National Park, a 30,000-acre wilderness where bison, elk, wild horses and pronghorn sheep roam free.

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So, if everybody knows the oil is there, the rest should be simple enough:

First, uncover the geology of the play

Second, drill horizontal wells into the productive zone

Third, complete and fracture the horizontal sections to maximize production

But its far from easy. It takes a great deal of perseverance and

technical know-how to recover the vast oil reserves in the Bakken shaleand to recover it economically. Just as the Barnett shale was the proving ground for unconventional gas resources, the Bakken is the proving ground for unconventional oil plays, asserts Charlie Jackson, director of marketing for Baker Hughes in the U.S.

Companies like Houston-based Marathon Oil Corp. are staking big claims in the Bakken. With an approximate 390,000-acre lease position, the company has invested approximately $1.5 billion to date in the Bakken and exited 2010 with about 15,000 BOPD net production, relates Dave Roberts, executive vice president of world upstream operations for Marathon. By 2013, the rm estimates its production will top 22,000 BOPD.

Unraveling the BakkenIn one sense, the Bakken is no different than any other oil and gas producing region. First,

operators must understand the geology to design effective drilling, completion and production schemes. One fact that might surprise those unfamiliar with the Bakken shale is that the primary producing zone is not a shale at all.

The Upper Devonian-Lower Mississippian Bakken formation is a thin but widespread unit within the central and deeper portions of the Williston basin in Montana and North Dakota in the U.S., and the Canadian provinces of Saskatchewan and Manitoba. The formation is comprised of three members: the lower shale, the middle sandstone and the upper shale. The organic-rich lower and upper marine shales have yielded oil production, but primarily they serve as the source rocks for the productive sandstone, which varies in thickness, lithology and petrophysical properties across the basin. The shales also source the productive Three Forks dolomite that underlies the Bakken.

While these facts are well known, the art of producing the Bakken lies in understanding its petrophysical subtleties. This knowledge of the rock characteristics and how they react to both natural micro and macro fractures, as well as to induced fractures, is the key to unlocking the most effective fracturing and completion strategies. The Bakken is unlike most shale plays where the larger the vertical fractures the better the production. In the Bakken, it is imperative to contain the fractures within the formation to prevent unnecessary expenses for no gain in production.

The Bakken is driven by economics. A well can initially produce approximately 1,000 BOPD, but production drops off quickly. And with average completion costs on the order of $6.1 million, maximizing the effectiveness of each wells drilling, completion, fracturing, and production strategy can make or break the play.

System

Mississippian

Devonian

Formation

Lodgepole

upper

middle

lower

Bakken

Three Forks

Units


The depth of the Bakken shale varies, ranging from approximately 5,500 ft (1676 m) in Canada to 10,000 ft (3048 m) in North Dakota, while the horizontal sections can be up to 10,000 ft (3048 m) long to maximize reservoir contact. Drilling the vertical section is more difcult than other U.S. shale plays. The hard, abrasive nature of multiple layers, combined with pressure drops in older producing zones and other issues, present technical challenges and, of course, the overarching goal is to optimize drilling costs.

Its a balancing act between costs and delivering the best quality wellbore, says Paul Bond, drilling systems marketing director for Baker Hughes in the U.S. The abrasive layers in the horizontal section are very hard on tools, so we deploy our powerful 4-in. Navi-Drill X-treme series motors to maximize penetration rates and to reduce the number of runs. The X-treme motors precontoured stator design increases both mechanical and hydraulic efciency for higher torque and more than 1,000 hp at the bit.

Increasingly, operators are trying rotary steerable systems in the vertical and curve sections to save time and to increase the build rate in the curve. Baker Hughes is beginning to employ its AutoTrak Express automated, rotary-steering drilling system for the vertical and build section of the wellbore. It is designed to maximize penetration rates while delivering a precise, straight, smooth wellbore despite the abrasive zones.

Traditionally, geosteering and formation evaluation technologies were not necessary to drill the horizontal section in the middle Bakken, which is typically about 40 ft (12 m) thick. But these techniques are becoming more prevalent as wells are placed closer to the more geologically complex anks of the middle Bakken and in the 10-ft (3-m) thick lower Bakken, Bond notes. As the easy wells are drilled up, advanced technology is required to deliver the best possible producing well. Again, its nding the balance between more costly technologies to maximize production and overall well economics. Recently, Baker Hughes has used some

of its formation evaluation and measurement-while-drilling (MWD) tools and services very successfully. These include the CoPilot system, which transmits real-time information from sensors mounted on the bottomhole assembly (BHA) to the surface; AziTrak deep azimuthal resistivity logging-while-drilling (LWD) tool; and OnTrak integrated MWD and LWD service.

There is a lot of bending tendency in the Bakken, and with the CoPilot system you can see how the BHA is being bent and modify drilling behavior quickly, preventing wear and tear on your BHA, according to Bond. The AziTrak tool provides the ability to steer the well into the best producing formations through an accurate picture of the wellbore with deep reading resistivity and borehole gamma-ray imaging. The 360 deep-reading, close-to-the-bit sensors detect bed boundaries so we can avoid nonproductive formations in any direction around the wellbore, he says. The OnTrak service is an array of integrated measurements, including full inclination and azimuth close to the bit; deep-reading propagation resistivity;

> Baker Hughes directional tools were used during the Precision 106 rigs drilling operations in the Sanish eld in Mountrail county, N.D.

> The multiport system offers multiple fracture initiation points at each stage. Currently, the multiport system can run up to 17 stages with ve entry points for a total of 85 sleeves per completion.

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dual azimuthal gamma-ray sensors; vibration and stick-slip monitoring; and bore and annular pressure in real time.

Optimizing the drilling process pays dividends. Marathon, for example, has made impressive improvements in its drilling program. Roberts says, In 2006, it took us an average of 50 days to drill a Bakken well to a total measured depth of 20,000 ft (6096 m). Today that same well takes less than 25 days. This improvement and other technology advances are strengthening the economics of the Bakken play. Marathons net development costs are in the $15 to $20 per barrel range.

Completing a solution While drilling the best possible wellbore at the best possible cost is critical to economically produce the Bakken, everyone acknowledges that today it is all about the completion. Brent Miller, operations manager of the Northern Rockies asset group for Whiting Petroleum, says its a combination of horizontal drilling and new completions technologies like Baker Hughes FracPoint system, thats made the Bakken economic. These are reservoirs that were passed up over the years. Theyre tighter rock. There is not as much porosity and permeability so we have to go horizontal. Then, we have to engage as much rock volume as we can with FracPoint technology to improve our odds of having a protable well.

Early on, operators employed the traditional plug-and-perf method of completing and fracturing horizontal wells in the Bakken shale. With this technique, composite plugs are deployed to isolate each fracture stage and, then, a series of perforating clusters is made through a cemented liner to access the formation in each stage, according to Jose Iguaz, completion systems director for Baker Hughes in the U.S. The drilling rig is moved off location and replaced with frac equipment, e-line unit and, in most cases, a coil unit on standby to perform emergency cleanups or milling of preset plugs.

This system provides operators an industry-accepted, low-risk way of stimulating their wellbores. But there are limitations. It can take several days to perform multiple fracs and to set the plugs, leaving costly frac equipment and crews idle much of the time. Plus, this system requires the composite bridge plugs to be drilled out before putting the well in production, he points out.

More and more operators are recognizing that speeding up the completion and fracturing process while controlling the fracture regime is necessary to rein in costs while maximizing production. That has led to increased use of single-trip, multistage fracturing technology, which compartmentalizes the reservoir into multiple 200- to 400-ft mini reservoirs that are

fractured individually after the drilling rig moves off location, notes Iguaz. This system can be run in openhole or cased-hole applications and can be used for primary fracturing or refracturing operations.

While looking for a solution that combined the cost-effectiveness of a packer and sleeve system with the increased number of initiation points of a plug-and-perf method, Whiting Petroleum came to Baker Hughes. The result was the FracPoint EX system.

The FracPoint system has seen tremendous growth in the Bakken as more operators recognize the technical and economic value of single trip multistage systems compared to plug and perf. The FracPoint completion system uses packers to isolate intervals of the horizontal section with frac sleeves between the packers, explains Iguaz. The frac sleeves are opened by dropping balls between stages of the fracture treatment program. As the ball reaches the sleeve, it shifts the sleeve openexposing a new section of the lateral and temporarily plugging the bottom of the sleeve. This provides greater control of the fracture treatment and allows for fracture treatments along the length of the horizontal wellbore.

Compared to plug and perf, the FracPoint system eliminates perforating and liner cementing operations; saves time during fracturing operations; reduces

uid usage during fracturing; and allows the well to be put on production immediately, without the need for clean up and milling operations. Initially, the one drawback to single-trip, multistage systems like the FracPoint offering was a limit on the number of frac stages, but that is no longer an issue. Constant technology advances have pushed the number of stages higher and higher.

Earlier this year, Baker Hughes ran and fractured the rst 40-stage FracPoint EX-C system for Whiting Petroleum at the Smith 14 29XH well in the Bakken. This achievement marks the most number of stages ever performed in a single lateral frac sleeve/packer completion system. The FracPoint EX-C system extends capabilities to 40 stages via 1/16-in. incremental changes in ball size to achieve an increased number of ball seats. The patented design provides additional mechanical support to the ball during pumping operations.

Our ongoing collaborative relationship with Baker Hughes couples Baker Hughes industry-leading tool expertise and experience with Whitings Bakken completion expertise and is a key to Whitings industry-leading position in Bakken fracture stimulation effectiveness and efciency, notes Jim Brown, president and chief operating ofcer for Whiting Petroleum.


The next major innovation for the FracPoint system technology is the multiport system. One perceived advantage of the plug-and-perf method is the capability to create multiple fracture initiation points at each stage. Now, the FracPoint system offers this same advantage. It works like a conventional FracPoint system, but provides up to ve entry points per stage. In February, Baker Hughes installed the rst multiport system in a North Dakota Bakken well. This technology has the potential to dramatically impact our completion efciency in the shale plays in North America, Iguaz says. Currently, the multiport system can run up to 17 stages with ve entry points for a total of 85 sleeves per completion.

A revolutionary technology advancement is also in the works. The FracPoint system with IN-tallic frac balls breaks new ground in material science. Based on fundamental research in nanotechnology,

Baker Hughes scientists have developed a light-weight, high-strength material incorporating controlled electrolytic metallic technology, which is based on an electrochemical reaction controlled by varying nanoscale coatings within the composite grain structure.

The frac balls made of this material are designed to react to a specic wells uid and temperature regimes to literally disintegrate in a prescribed timeframe. So whats the advantage of disintegrating frac balls? At the conclusion of a traditional FracPoint installation, ball sticking or differential pressure may keep a ball on seat, requiring remedial actions such as milling and delaying (full) production. The IN-tallic frac balls remove the cost of possible remedial action.

Breaking into the BakkenOf course, completion technology is only part of the storygetting the fracturing process just right is imperative

to maximize production and to control well costs. In the Bakken, the key to a successful frac job is eliminating excessive fracture height growth to keep the fractures in the formation. Fracing out of zone is a waste of money, says Kristian Cozyris, an engineer for Baker Hughes. Getting the fracture geometry right is a function of both the pumping rate and the uid type. Its not all about horsepower in the Bakken. Typically, we pump 30 to 50 barrels of uid per minute, and we use cross-linked gel-based uids.

But, typical is a relative term. Theres no such thing as generalities in the Bakkenevery operator has a slightly different philosophy on the best fracture methodology and the needs can vary depending on where a well is drilled. There is still a great deal we need to learn to determine the optimum approach. We have ongoing research and development projects studying fracture growth in

the shales and additional science will be necessary as we better understand the Bakken reservoir, Cozyris says.

Another serious challenge for fracturing operations is the availability and quality of source water. Out of necessity, operators are using more recycled water, but that can pose its own set of problems, notes Brad Rieb, region technical manager for Baker Hughes in Canada. Baker Hughes BJ Viking II PW system, which uses produced brines combined with a high-performance polymer and crosslinker, has been deployed successfully in the Canadian Bakken where dry weather conditions and agriculture needs limit the volume and availability of fresh and surface water.

Since its introduction in May 2008, the Viking II PW system has been deployed in about 310 wells, or approximately 5,300 frac stages. Weve saved 1.5 million barrels of fresh water from being used in fracturing

> Baker Hughes fractures three wells side-by-side in the Montana portion of the Bakken.

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operations, Rieb says. One customer estimated it saved 10 to 15 percent in total stimulation costs from reduced water purchases, hauling, heating and uids disposal. The operator had a constant source of produced water stored in several tanks. In addition to the environmental benet of preserving the limited supply of fresh water, other benets include reduced exhaust, dust, noise, and road wear from trucking operations.

The Viking II PW system has not been widely used in the U.S., primarily because the Bakken producing formations are deeper, hotter and more saline. The hotter bottomhole conditions impact the uid. We currently have R&D projects under way to understand the inuence of higher temperatures on the system. There is signicant interest in this technology, so we are working hard to solve the technical issues, Rieb explains.

Another serious challenge in the Bakken is mineral scale formation on the tubulars, says Anthony Hooper, director of marketing, pressure pumping, for Baker Hughes in the U.S. We have seen Bakken wells with restrictions from severe scale buildup. Barium sulfate, calcium sulfate, calcium carbonate scales and sodium chloride precipitation are the most common problems in the Bakken. Its extremely difcult to adequately recomplete 10,000-ft (3048-m) laterals, so its imperative we get it right the rst time to prevent

loss of the wellbore or an expensive and not very effective remediation treatment.

To inhibit scale build up, Baker Hughes is employing its BJ StimPlus services on an increasing number of frac jobs. This service combines scale inhibiting chemicals with the stimulation uids to address scale at its sourcethe rock face. This is our only chance to get the chemicals directly into the reservoir, Hooper says. Following the fracture stimulation, a post-treatment survey monitors the reservoir and well assets for scale build up. We have documented cases of uninterrupted well treatment lasting up to ve years with no additional chemical intervention.

Lifting reserve recoveryBakken hydrocarbons are now technically feasible to drill and recover, but production over time is yet another challenge. Production rates decline rapidly and operators are looking for ways to extend the productive life of every well and to maximize ultimate reserve recovery.

Rod lift has been the traditional articial lift technique, but a growing population of Canadian and U.S. wells is being produced with electrical submersible pumping (ESP) systems and is proving the value of this technology. According to Cal LaCoste, eld sales manager for Baker Hughes in Canada, there are two primary advantages

of ESP systems: ESPs can be set in the horizontal section of the wellbore, which provides greater draw down for faster and higher reserve recovery; and ESP systems can handle solids and gases entrained in the production stream.

The key to successful deployment of ESP technology is picking the right system for the right application. We have found that the optimum solution is a low-horsepower/high-voltage system to keep the motor temperature down. It is also very important to get the pump size just rightit has to handle a wide operating range since production rates drop off quickly in the Bakken. Another critical element is chemical maintenance of the ESP systems to protect against scale and corrosion, LaCoste explains.

Canada was the rst proving ground for ESP technology since the wells are shallower with lower production volumes and a shallower decline curve compared to the U.S. side of the play. However, U.S. operators are testing the waters. Currently, more than 150 Centrilift SP ESP systems have been installed in Canada and the U.S., and operators are realizing sizable benets.

In fact, the rst ESP system ever installed in a Bakken well in Canada has run continuously for more than two and a half years. The rod lift system originally in the well had to be worked over every three to four months

due to a host of downhole problems. We convinced the operator to give us a chance to improve the wells performance and to cut down on the costs of frequent well interventions, LaCoste remembers. The results were dramatic. Because the ESP system could be set in the horizontal section of the well207 m (680 ft) deeper than the rod pumpproduction initially increased by 76 BOPD and, over time, stabilized at an increase of 20 barrels per day, a 50 percent increase over the rod system. Plus, weve saved nearly $400,000 in well intervention costs and another $500 per month in power costs because the ESP system requires half the horsepower of the rod system.

The technical challenges operators and service companies face in their quest to unlock the promise of the Bakken shale have been daunting, but the prize is worth it. Production from just the U.S. sector of the play increased from 9.3 million BOE in 2004 to 70.9 million BOE in 2009. Production from the Bakken is expected to reach 211.4 million BOE in 2020an average annual growth rate of 9.9 percent.

And the Bakken is just the rst chapter in this story. Marathons Roberts sums it up. What we learn in the Bakken will be transferred to other unconventional resource plays in North America and, then, around the world. We are already seeing that trend. This is an exciting journey for the industry.


with James J. Volker, chairman, president and CEO, Whiting Petroleum

wcW

James J. Volker and his senior management team, which he credits with Denver-based Whiting Petroleums growth and success, share insight into the challenges of producing some of the nations top oil shale plays and the future technologies that will be vital to meeting the needs of this market.

Interest is rising in natural gas shale basins globally. How can the knowledge gained by mostly independent oil companies in the U.S. be transferred to shale plays around the world?

First, it is very important, especially with regard to what we call resource plays, to have access to subsurface information. There is a great deal that we can do with old logs, in terms of prequalifying these types of plays, when we combine log data with pressure and production test information. Without that, youre at a real disadvantage, so its very important to have access to that type of information. Secondly, one of the things that distinguish these resource plays from other types of plays is that they are invariably large in scale, but they are marginal in their reservoir quality compared to conventional reservoirs. The international oil companies have historically been good at obtaining a large share of the protability that is sometimes seen in a conventional reservoir play. In order for independent U.S. companies to compete internationally in the resource playswhere the economics are typically in the 2:1 to 3:1 or 4:1 range, rather than 10:1its important that the netbacks, in terms of the production sharing, are high and are competitive with what they are in the U.S. We see netbacks in the U.S. typically between 50 and 70 percent. You rarely see that internationally,

Industry Insight

26 |

so its going to be important for those countries that have resource play opportunities to be realistic in their dealings with U.S. companies to encourage them to come and make the large capital investments necessary to get these big plays going. Royalties and the whole scal regime need to be competitive with what were doing here in the U.S.

Explain the differences in exploiting, producing and completing shale oil and shale gas.

Because oil is a much thicker uid than gas, it is more difcult for it to ow through the tiny pores within the shale. In the completion or the fracturing phase, we aim to leave a much higher fracture conductivitya much higher sand concentration, so to speaknear the wellbore to maximize ow rates. You can ow more gas than oil through a lower permeability sand pack. The other thing thats true with oil reservoirs, whether youre in vertical wells or horizontals, is you have to have tighter well spacing because youre not going to drain as big an area. Thats why were drilling up to six wells per 1,280-acre unit. Much of the multistage fracturing designs have been transferable between gas and oil plays with adjustments for the different rocks, well depths and well costs. Both shale oil and gas plays should have repeatable results over a large area.

How have drilling and completion methods changed in regard to the Bakken shale over the last several years and what are your expectations moving forward?

Whitings average time to drill a 20,000-ft (6096-m) well has been reduced from 50 days to less than 20 days, and we currently hold the record in the Bakken shale for drilling a 20,000-ft (6096-m) well in 13.92 days from spud to total depth. All this is a direct result of optimizing the drilling process through improvements in downhole motor technologyespecially motors with precontoured stator tubes that allow the entire lateral to be drilled without changing the downhole assembly. High-pressure mud motors that facilitate high rates of penetration are also important. Another key driver for drilling efciency includes all top-drive rigs. These rigs reduce connection time and reduce time for reaming horizontal from three days to one day before running liner. Also, our drilling-well-on-paper training keeps the rig crew focused on a mission-critical bit-on-bottom strategy and accounts for ve to seven days reduction in drill time.

On the completion side, Bakken shale completions have evolved signicantly from three years ago. Horizontal drilling with single-stage fracture stimulations was being used with good results in Montanas

Elm Coulee eld, but with poor results in the North Dakota Bakken play. We decided to try a Baker Hughes FracPoint multistage fracture design with swell packers and frac sleeves, and the result was our best well up to that date. This kicked off signicant development in the Sanish eld, and weve been using multistage fracturing ever since in the Bakken play. Along with Baker Hughes, we pioneered the 24-stage frac system and have since run a 40-stage system. With frac sleeves, we can do a completion in one day versus ve or six days with plug and perf. Therefore, it is much more efcient and much more cost effective. The more we can keep frac costs per stage down in a long lateral, the more we are going to accomplish commercial completions in poorer or thinner rock. Thus, we can make the play work in not just the great areas like the Sanish eld but also in some of the poorer rock quality areas we want to drill.

In addition to using the multistage fracturing technology, Whiting has adopted and improved upon the hybrid uid frac design that uses slick water, linear gels and cross-linked gels in each frac stage design. Whiting has moved quickly from less than 10-stage completion designs to 30-stage designs. This has resulted in some of our best wells to date, and we have plans to use even more stages in the future. The challenge for Whiting is to continue to push for lower per stage frac costs and optimum stimulation

designs to produce higher estimated ultimate recovery [EUR]. Efcient use of fracturing equipment is important in reducing costs. Our individual well fracturing operations are now normally done within 24 hours.

Unconventional resources are a relatively new market with limited long-term exposure. As the industry moves further into the life cycle of unconventional resources, what technologies do you see emerging to meet the needs of this market?

Because these are tight rock reservoirs with low permeability, we think that the key elements will involve completing multilaterals with more affordable multistage completions. Therefore, a key factor will be having dependable assemblies that can access as much rock volume as possible to increase the odds of making a protable well.

Whiting Petroleum explores for crude oil, natural gas and natural gas liquids. What percentage of each is your company targeting from shale formations?

Approximately 80 percent of our exploration and development budget is targeted


at oil reservoirs, and almost 80 percent of this effort [64 percent of total] is directed at oil-rich shales. We have concentrated on oil because it has the best prot margin.

Whiting Petroleum consistently has some of the largest initial production rates in the Bakken shale. To what do you attribute this success?

Whiting has leases covering some of the best Bakken and Three Forks rock, uses multistage fracing and sees low damage to the formation during drilling. Beyond that, I would say that its the ability of our geoscience team to locate this better reservoir rock that has enough porosity and permeability innately, so that when we drill it horizontally, we get protable wells. Using the geoscience that Mark Williams, our vice president of exploration, and his team have applied has been the difference between our wells, which on average have produced about 80,000 barrels in the rst six months of production, to others who, on average, have had production of about half of that.

The unconventional resource market in North America has been revolutionized during the last decade with the

emergence of further plays in a seemingly endless cycle. In what areas does Whiting Petroleum expect to emerge in the near future and what are the corresponding challenges?

There are three primary areas: the various zones of the Bakken hydrocarbon system in the Williston basin, the Niobrara zone in the Denver Julesburg basin and the Bone Springs zone on the western side of the Permian Basin. The challenges, of course, are how to efciently drill and complete longer horizontal laterals. We think that technologies such as the FracPoint multistage fracturing system will be of assistance to us in these three areas because it has increased the speed and effectiveness of multistage completion systems to access greater rock volume.

Reserve estimates have changed dramatically over the past few years. Why is it so difcult to estimate the amount of oil and gas that lies within the U.S. shale plays?

Shale and other unconventional reservoirs have low reservoir permeability but high permeability associated with natural and induced fractures contained within the reservoir. Therefore, wells

in these plays exhibit high initial rates of decline over the rst one to three years as the fractures are produced.

Without contribution from the low-permeability matrix reservoir, however, these wells would continue to decline rapidly. Because it is often difcult in the early stages of production to determine the degree of eventual contribution from the low-permeability matrix, it is all the more important to treat and enhance the reservoir with FracPoint-type technology. Contribution from the low-permeability matrix can atten the rate of decline, improve estimated ultimate recovery and make results more protable.

Of all the shale plays in which Whiting Petroleum is involved, which is the most technically challenging and why?

Our big play is the Bakken shale play, but weve had challenges within that play. The Sanish eld is some of the better rock in that play but even in Sanish there have been some challenges related to well spacing. We had to decide how many laterals to drill in the middle Bakken within a 1,280-acre unit and how many to drill in the Three Forks. Weve used some of Baker Hughes technology to help us come up with the answers to those questions. Our studies now indicate that we need to drill

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