connexus 2a. ed

CONNE US

Totally ConformableRevolutionizing sand management with shape memory polymer foam

Brazil’s Big OilPre-salt: The world’s 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 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 TRANSFORMATIONPresident 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.

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Advancing Technology FrontiersBaker Hughes is constructing a new $30- million research and technology center in Rio de Janeiro to support the industry’s 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 Siberia’s Yamal Peninsula are helping operators reach new levels of productivity.

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

Ghana’s First OilAs 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 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 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.

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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 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. 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 [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 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

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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 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 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 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

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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 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 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 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.

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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 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 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

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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 H2S 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

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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 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 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.

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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 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.

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“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; H2S 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 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, 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.

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

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

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Reshaping Sand ControlShape 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.

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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 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 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 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 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 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.

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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 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 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 well’s drilling, completion, fracturing, and production strategy can make or break the play.

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The depth of the Bakken shale varies, ranging from approximately 5,500 ft (1676 m) in Canada to 10,000 ft (3048 m) in North Dakota, while the horizontal sections can be up to 10,000 ft (3048 m) long to maximize reservoir contact. Drilling the vertical section is more 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.

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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. 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 BakkenOf 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.

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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 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 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 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

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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

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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.

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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

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01> Graph shows the well path of the long step-out in the first multilateral profile well in the Yurkharovskoe field.

02> From left, Vsevolod Kozlov, head of Novatek’s field geology department; Evgeny Tyurin, Baker Hughes senior geoscientist and RNS lead; and Margarita Ibragimova, Baker Hughes geoscience manager for Russia, in the BEACON center

> Ravan Ravanov, drilling systems sales

manager for Baker Hughes in Russia Caspian

01 02

center, via satellite, approximately 2414 km (1,500 miles) from the rig site on Siberia’s Yamal Peninsula. “Data transfer of this nature provided the basis for collective and collaborative decisions with NEU and Novatek for drilling best practices and optimized wellbore placement,” Ravanov explains. “Connecting the client’s experts to the operation is the key to informed operational decisions, and having instant access to previous well data and geological information allows even more informed evaluation of incoming data.”

During this first-ever RNS implementation in Russia on the first leg of the second multilateral well, Vsevolod Kozlov, head of Novatek’s field geology department, spent 48 hours in the BEACON center with Evgeny Tyurin, a Baker Hughes senior geoscientist and RNS lead. Together, they watched as all geological and drilling targets were set up and successfully met, resulting in a 65 percent improvement in reservoir rock exposure.

After some fine tuning of the RNS model in the office, the next horizontal section (600 m [1,968 ft]) was drilled in the payzone with no exit from the reservoir (Fig. 2). This was a step-out of 4452 m (14,606 ft) at a measured depth of 6045 m (19,832 ft). The smoothness of the wellbore path allowed the well to be drilled far longer than planned due to the reduction of torque and drag, which resulted in huge financial benefits in terms of additional gas production, Ravanov explains. This was also the longest extended reach well in Siberia to date.

“From log correlations, Novatek was projecting 8 to 10 m (26 to 32 ft) bottom reservoir thickness. But in reality, it pinched out to 2 m (6.5 ft), then even less. Thanks to clear images provided by RNS, it was decided to change the drilling program of payzone penetration,” Kozlov says.

“The initial well construction program reduced well penetration meterage significantly—to 5700 m (18,700 ft) total

Fig. 2

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Edge of the WorldThe Yurkharovskoe field is one of many being developed from the strategic oil and gas bearing Yamal Peninsula, a large parcel of land that juts out into the Kara Sea above the Arctic Circle. The peninsula consists mostly of permafrost ground and, in the language of its indigenous nomadic inhabitants, the Nenets, “Yamal” means “End of the World.”

Although the temperatures can reach -50°C (-58°F) in the winter, large-scale reindeer husbandry continues in its traditional form. By some estimates, there are 300,000 wild reindeer on the peninsula. In summer, when the topsoil defrosts, they graze in the north. When the winter turns brutal, they migrate south of the Arctic Circle to the central Siberian Plain.

The Nenets follow the migrating herds year round, sometimes for thousands of kilometers. The Nenets believe that, during a mythical past, the reindeer agreed to offer themselves as food and transport and, in return, the Nenets agreed to accompany them on their long journey and protect them from predators.

Though largely undeveloped, the Yamal Peninsula holds Russia’s largest natural gas reserves estimated at 55 trillion m3.

“A set of applied technologies, alongside new technologies such as the CoPilot real-time drilling optimization service and AutoTrak X-treme drilling system, have made it possible at the current stage to drill well No. 368 down to 6425 m (21,079 ft) with deviation from the wellhead to the top reservoir of 4600 m (15,091 ft).”

Sergey SolovievGeneral director,Investgeoservice

depth because of top drive limitation,” adds Sergey Soloviev, general director of Investgeoservice. “But, due to RNS helping us escape multiple doglegs in the profile and the AutoTrak steerable system making a smooth hole, total depth was at 6045 m (19,832 ft), doubling the section contacting the reservoir.”

“These wells highlighted the opportunity to drill extended reach wells from the existing surface infrastructure when the payzone is located, for instance, off the coast,” comments a Novatek expert. “Novatek had previously planned a very expensive island construction project that may no longer be required.”

Baker Hughes created additional value from the quality of the acquired real-time drilling LithoTrak™ data that was the same, if not better, than that of previous in-field wireline logs. The LWD logs proved sufficient for the end-of-well quantitative petrophysical report. This resulted in rig time savings and eliminated additional costs for wireline, Soloviev notes.

“A set of applied technologies, alongside new technologies such as the CoPilot™ real-time drilling optimization service and AutoTrak™ X-treme drilling system, have made it possible at the current stage to drill well No. 368 down to 6425 m (21,079 ft)

with deviation from the wellhead to the top reservoir of 4600 m (15,091 ft),” Soloviev adds.

“NEU, Novatek and Baker Hughes have worked together to improve upon the challenges faced in previous completions. New challenges may be avoided using a combination of two key factors—Baker Hughes technologies and global experience, and the local knowledge and technique experience of our customers,” says Timothy Adams, Baker Hughes vice president of marketing for Russia Caspian. “This project is a great example of what can be achieved by the careful application of the correct technologies in the appropriate applications and stands as a testament to the collaborative approach taken on this project, with the collective aim of improving performance.”

Iosif Levinzon, deputy chairman of Novatek’s management committee, and Dmitry Kuzovenkov, president of Russia Caspian for Baker Hughes, met recently in the Moscow BEACON Center to discuss future relationships, technology applications and strategy for development of the Novatek assets. As a result of this meeting, Mr. Levinzon has signed a protocol describing the future strategic relationship commitments of Novatek, NEU and Baker Hughes.


FracturingStimulation with Stewardship

with a fraction of the fluids

> VaporFrac services minimize the equipment required on location, reducing impact on the environment, including local roads.

34 |

01 02

The gas-bearing Marcellus shale underlies a large swath of the northeastern U.S., making it a hotbed of activity for energy extraction, environmental activism and governmental regulation. One of the most significant concerns for all of these groups is the continued availability of fresh water: Operators can’t economically produce gas from the shale without hydraulic fracturing, a technique that uses large volumes of water, and activists and regulators are both concerned that operators use too much water with too little regard for local communities.

To minimize the impact on fresh water supplies, some state and local regulators strictly limit energy extraction activities. In New York, for example, the state’s moratorium on hydraulic fracturing has all but eliminated oil and gas activity in its portion of the Marcellus shale.

In fact, the moratorium is not a complete freeze on hydraulic fracturing, as Baker Hughes Region Engineer Dan Kendrick learned in early 2010 from an operator, Gastem USA, who was curious about the BJ VaporFracTM services.

“They saw our SPE paper about using the technology in the Huron and Utica shales, and they were interested because it required very little fluid,” Kendrick recalls. “They had a lease at the northeastern edge of the Marcellus shale in New York, and the well required stimulation to make it an economical producer.”

VaporFrac stimulation services pump ultralightweight proppant slurry directly into a high-pressure nitrogen or carbon dioxide gas stream. The nondamaging technique creates a flow stream that is 94 to 96 percent

gas, significantly reducing freshwater requirements, chemical additives, post-frac cleanup time and water disposal costs. In addition, the efficient process minimizes equipment requirements, thereby limiting truck traffic on local and lease roads.

Stimulation performance compares favorably with other low-water stimulation techniques, as the proppant slurry lends mass to help create or extend a fracture, which can be challenging in nitrogen-only fracs, especially in naturally fractured formations, such as shale. In addition, the patented BJ LiteProp™ ultralightweight proppants are easier to transport into a fracture than conventional sand, improving the resulting effective (propped) fracture area and conductivity.

> Northeast Region Engineer David Wilson verifies the levels of the liquid LiteProp slurry in a tanker before pumping the first stage, then discusses job details with Sales Representative Bryan Wilson amid the nitrogen pumps.

As the media and regulators turn a watchful eye toward the energy extraction process, an innovative hydraulic fracturing technology takes center stage, dramatically cutting water and chemical requirements to safely and efficiently stimulate gas production from one of America’s most prolific shale formations.


A more effective fractureA conventional, optimized shale development starts with a long, horizontal well and a multistage hydraulic fracturing treatment using millions of gallons of fluid to connect the wellbore to as much of the shale’s natural fracture network as possible. But New York state environmental officials told Gastem engineers that under the moratorium, the only way they could use hydraulic fracturing was in a vertical well with just 80,000 gallons of fluid.

“It was not an ideal situation because, even for a VaporFrac treatment, the fluid volume was very low,” Kendrick says. “To make shale economical to produce, you want your fluid and proppant to connect with a lot of the formation rock. But, 80,000 gallons of fluid will only go so far.

“Still, theoretically, we knew that given a certain volume of fluid, our ultralightweight proppant technology should be able to create a larger,

more effective fracture area than anybody could make with a regular sand frac. Gastem thought the theory was sound, so we moved forward.”

The next steps were to create a provisional fracture design and to provide state regulators with chemical information about the fluid system that would be used to carry the proppant. After sending the OSHA-mandated material safety data sheets for the fluid system, the state asked for a few additional details—the exact chemical composition of each component.

“We knew that we had to spell out the fluid systems we were going to use,” Kendrick says. “I had no idea that state regulators would require as much detail as they did.”

A smaller footprintAlthough one of the benefits of VaporFrac services is its minimal chemical footprint, it does use a few additives, such as surfactants to improve proppant-carrying capacity. For

some additives, Baker Hughes had to contact its chemical suppliers for the detailed chemical information, “and, of course, their sense of urgency was not what ours was,” Kendrick says.

Andy Jordan, manager of technology support for Baker Hughes pressure pumping services, was involved with encouraging suppliers to provide the information. “The suppliers sent the information directly to the state—after they were convinced that the state had proper confidentiality systems in place,” Jordan says. “It took a long time, but we got it done.”

After the state received the final chemical information and approved the fracturing permit, the next challenge was logistics: Baker Hughes has no pressure pumping districts in New York. To avoid disrupting any one district’s stimulation schedule, the New York operation used a few pieces of equipment and operators from Gaylord, Mich., Dunbar, W.Va., and Jenkins, Ky.

01> Jenkins, Ky., District Safety Trainer Eric Adams oversees rig-up for the nitrogen pumps at the VaporFrac operation.

02> Gastem USA President Orville Cole (center) explains the VaporFrac procedures and environmental safeguards to residents whom he invited onsite to learn more about how Baker Hughes and Gastem worked together to minimize risks.

“The well came in strong, which proves our claims about efficient proppant transport. We know we hit the fracture network, which is what we needed to do. And we saved a lot of water, which is great from an environmental standpoint.”

Dan KendrickRegion engineer, Baker Hughes

01

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In late October 2010, the equipment and personnel converged on a hilltop near Maryland, N.Y., where Gastem had laid hemlock matting to protect and stabilize the wellsite from erosion and truck damage. Gastem had also developed a water-monitoring program to test area water wells for impacts from drilling and other operations. And while Baker Hughes crew members rigged up their equipment, Gastem USA President Orville Cole met with neighbors at the edge of the wellsite.

“It’s important to talk to people, to show them all that we do to minimize risks,” Cole notes. “We did some townhall meetings to explain the processes, but when I can bring people right up to the location and show them that we have thought about the things that concern them, they feel better about the operation. You can’t always please everyone, but education is always worth the effort.”

Gastem started the outreach in 2008. “The experience with the industry in this area is very limited. People voice their appreciation, but there are a number of other voices in this region who are not only opposed to hydro-fracturing but to any intrusion from industry,” Cole explains. “This makes community relations, education and industry innovation so very important. I believe the industry needs to show continuous improvement in establishing baseline environmental conditions prior to drilling in a new area, and to be prepared to restore drilling sites and pipeline right-of-ways to blend with the areas where we work.”

Successful operationAs Cole, a handful of neighbors and two representatives of the New York State Department of Environmental Conservation watched, Baker Hughes began the fracture stimulation treatment with a crescendo of pump trucks. In the end, the operation treated two zones more than 2,000 ft (609 m)

deep in the Marcellus shale, using 40,000 lb of LiteProp ultralightweight proppant, 7 MMcf of nitrogen and less than 20,000 gallons of water.

In December, Gastem reported the results exceeded expectations—initial production of 200 Mcf/D and sustained production of 150 Mcf/D after four weeks of extended flow.

For Kendrick, the operation was successful but not an ideal reflection of the technology’s potential to demonstrate environmental stewardship in the Marcellus shale. “The well came in strong, which proves our claims about efficient proppant transport,” he says. “We know we hit the fracture network, which is what we needed to do. And we saved a lot of water, which is great from an environmental standpoint.”

“But it’s one vertical well,” he adds. “We could be so much more efficient if we could do a horizontal with 10 stages, instead of 10 individual vertical

wells: We’d move equipment and people once instead of 10 times, drive on local roads once instead of 10 times, bother the neighbors once instead of 10 times. You get the idea.”

In fact, efficient field development, well placement and enhanced recovery techniques are key elements for minimizing risks in the oil field.

“VaporFrac services and our BJ SmartCare™ fluid systems definitely reduce our water and chemical impacts,” says Dan Daulton, director of environmental conformity and marketing for Baker Hughes. “But we could reduce waste and overall health, safety and environmental impacts even more with an integrated approach. That’s where the industry is moving—efficient field development so we have fewer wells and less surface impact, and if we do a better job of understanding the reservoir and planning up front, we should get better ultimate recovery, too.”

“We did some townhall meetings to explain the processes, but when I can bring people right up to the location and show them that we have thought about the things that concern them, they feel better about the operation.”

Orville ColePresident,

Gastem USA02


Bennett Richard’s idea of an open-door policy means more than just open communication and feedback between a manager and his or her employees. It literally means opening doors for people.

Faces of INNOVATION

BENNETT

38 |

His inspiration goes back almost 35 years to when someone opened the door of a south Louisiana Travelodge motel lounge—and a new career—for him.

“In 1976, Baker Oil Tools created a new division called Baker Sand Control to specialize in sand control technology and service,” Richard relates. “Baker started the division with gravel pack tools but had aspirations of becoming a full-service sand control provider by adding pumping services, gravel pack screens and tubing-conveyed perforating.

“Larry Kennedy, vice president of operations for the new division, went to Mobil Oil, which was a very big purchaser of sand control services in the Gulf of Mexico at the time, and said, ‘We know that BJ Services does all of your pumping services, but if we go into the pumping services business, can we get a portion of it?’ Mobil told him, ‘Absolutely not! They have an engineer that does all of our work, and we’re not changing.’”

Kennedy complained to his sales manager, Charles Richard, about Mobil’s refusal to work with Baker because “they’ve got this kid who’s doing all their work, and they’re really high on him.”

That “kid” was Bennett Richard, Charles’ younger brother. (Ironically, it was Charles who, in 1974, had opened the door for Bennett to work at BJ Services.)

Richard had joined BJ Services as a field engineer specializing in sand control after working three years at the Louisiana State University (LSU) Medical School in Shreveport as a research scientist.

“After 2½ years in field operations, BJ offered me a sales position in the regional office in New Orleans,” Richard recalls. “I was on my way to New Orleans for the interview, and I was going to stay with my brother over the

weekend. Under the pretense of picking up a package to take to him, I had to meet his boss at a Travelodge along I-10 in Lafayette.”

The man with the nonexistent package turned out to be Kennedy, and he was there to recruit Richard for a job with the new startup pumping product line. “I told him I wasn’t interested. I told him that I really liked working for BJ. He asked me, ‘What will it take?’ and I told him again, ‘It won’t take anything. I’m just not interested.’

“You’d just have to know Larry Kennedy. He was the most charismatic individual I’d ever met. I mean, you’d follow that guy straight into hell knowing what would be there.”

Before leaving the I-10 Travelodge, Richard had accepted the job. He and the four others who were recruited to help start Baker Sand Control Pumping Services were given free rein to design pumping equipment and complementary fluids and to run a business that soon had 80 percent of the market share. “We really challenged the competition by taking sand control to another level,” he recalls.

“Baker Sand Control was a very young and progressive company for that particular time period. The culture was just totally different in that organization,” Richard says. “Empowerment was at the very foundation of the company’s culture and taking risks was an everyday occurrence. It was an exhilarating experience that I will never forget.

“A person shouldn’t have to go through his or her work life without ever having experienced that feeling, and I tell that to my team all the time.”

An inventor at heartRichard (pronounced REE-shard) was born in Carencro, Louisiana, near Lafayette. His devout Catholic mother was insistent upon his attending a private boys’ school run by

the Christian Brothers organization. “All my friends went to grammar and high school in Carencro where we were raised,” he says. “None of them went on to college, but there was no doubt by the time I was in the sixth or seventh grade that I was going to college. That’s what Christian Brothers does—it prepares you for college—no ‘ifs,’ ‘ands’ or ‘buts’ about it.”

After graduating from high school, Richard enrolled in the University of Louisiana with thoughts of becoming a dentist. Having earned a degree in biology with a minor in chemistry, he went to work at the LSU Medical School. “One thing about my upbringing was adopting good work ethics. I think it’s part of the Cajun culture,” he says. “I worked very, very hard at the medical school, and my boss noticed. They actually gave me responsibility for the sophomore pharmacology lab, even though the appointment required a master’s degree, and I only had a bachelor’s degree.”

Richard conducted research in the lab for a couple of years before realizing his future there was not very promising. “I was having a lot of fun doing what I was doing, but I realized that I had more to contribute than that,” he says.

On the advice of his brother, Richard went to work in the oil field and soon found it to be a proving ground for his passions—applied research and technology.

During his 34 years at Baker Hughes, Richard has been listed as inventor on 40 granted U.S. patents, with 12 more pending. His contributions to industry-changing technologies in the areas of sand control and production optimization have added more than $1.2 billion in revenue to the company and helped earn him the 2010 Baker Hughes Lifetime Achievement Award.

Richard led the development of technologies, including the hydrolyzer, a device that made


gravel pack gels filterable and beneficially impacted production optimization; the gravel infuser, a device that meters gravel concentration in water and pumps a uniform and nondamaging sand/water system; PERFFLOW™ drill-in fluid to prevent formation damage and to provide formation stability for successful hole cleaning and gravel packing procedures; the industry-leading EXCLUDER™ premium mesh sand screen; and, most recently, the GeoFORM™ sand management system using Morphic™ technology (See related article on Page 16).

Of all the technology advancements he’s helped develop, Richard considers the gravel infuser, the EXCLUDER sand screen and the new GeoFORM sand management system among the most significant.

“The gravel infuser was a device that could actually meter any concentration of gravel in water that we wanted and it would be consistent over the period of time that we were pumping,” he explains. “I was reporting to Mike Johnson (now senior engineering manager for Baker Hughes) at the time, and

we built an acrylic gravel pack simulator to allow our customers to see gravel transport and packing efficiency firsthand. It was the best salesman Baker Oil Tools ever had. We would bring in a customer in the morning and another one in the afternoon to witness the simulations. We got two brand new water pack customers almost every day! Mike and I are awfully proud of having improved reservoir performance by turning the industry from gel packs to water packs.”

As for the EXCLUDER premium sand screen, Richard says, “I just woke up one morning and said, ‘You know, wire wrap screen is 50 years old. There’s got to be a better way.’” The result was EXCLUDER—still the standard for gravel pack premium screens.

However, in recent years, he’s found something better. “I kept telling product line management that we had a technology that would be a step change in sand management, but it was difficult to imagine replacing the industry-leading EXCLUDER. Finally, the test data and

benefits were so overwhelming that a new sand management solution was born—the GeoFORM sand management system.”

This new technology—based on advanced shape memory polymer science—is unlike anything else Richard or anyone in the industry has seen, he contends.

“I think it has a lot of potential applications: shape memory polymer packers, shape memory polymer screens, shape memory polymer cementing equipment. I think it could actually one day replace some cement jobs,” he says.

“I think my next big adventure—and I’m not as quick as I once was in figuring out how to solve a problem—is a one-trip well,” he says. “We need to be able to drill and case, at least temporarily, at the same time, as well as do some type of temporary cementing while drilling. If we could do all that, we could drill a well in one-tenth the time.

“When you’ve got a rig that’s $700,000 or $800,000 a day, and you knock off 30 days,

��“I’ve been surrounded by talented people my whole career, but it takes more than talent and luck to be successful. Management support is key. I’ve been extremely fortunate in that regard. Let me tell you something, I’ve come up with some pretty wacky ideas over the years, and I don’t know if it was my track record or if management just didn’t understand how wacky they were, but management’s always supported me.”

��“There’s the old saying that you can fail as long as you learn something from it. I’m all for learning, but I don’t really care if you learn from failure. The thing that I don’t want you to do is stop and brood over it. Just move on, learn something new. You’re only human. Only God doesn’t make mistakes.”

�� “I never start anything with only one application in mind. When I work on a new technology, I go into it thinking, ‘It’s got to be commercially viable and fit several applications. It’s going to fit a screen. It’s going to fit a packer, cementing equipment, downhole pump.’ So, if I miss one, I say, ‘Well, I still have four or five other applications that it will address!’ I may even find others from experimental results along the way that are better opportunities. I think detailed plans with a single application in mind are pretty risky. That’s not innovation.”

��“David Curry [a Baker Hughes Fellow] sent me an e-mail from London last November and said he needed to talk to me. I wrote him back and said that I was fishing and to call me at home Thursday morning. He calls me on Thursday, which was Thanksgiving Day, and he says, ‘I really hate to ruin your holiday.’ I said, ‘David, you have my undivided attention. You can bother me on holidays, but don’t bother me while I’m fishing.’”

��

40 |

that’s a lot of money. This is not Star Wars stuff. I think this could be big, and I have a concept in mind that I think is doable.”

A developer of peopleAs director of completion and production product engineering, Richard leads the Technology Innovation Group, a team of approximately 80 scientists and engineers that he helped put together. It’s one of three groups at Baker Hughes in which Richard played a major role in creating.

He cosponsored the Endeavor Young Professional networking group, whose goal was to create a social fabric within the technology organization to share common interests and ideas.

Richard was a cofounder, along with Volker Krueger, director of strategic technology development for Baker Hughes, of the Baker Hughes Materials Committee that introduced the concept of peer cells through active participation of experts in specific technology functional areas crossing all Baker Hughes product lines.

“Volker and I can’t take all of the credit as it was one of my team leaders, Kevin Holmes, who convinced us that there was a better way of transferring knowledge across the organization—youth and empowerment, what a combination!” he exclaims.

With the Technology Innovation Group, Richard developed and implemented a plan for creating a permanent research function for completions and production technology.

“Prior to Bennett’s involvement, the group consisted of, at most, five individuals working on disparate projects that would ultimately prove to be inefficient in the uptake as solutions offered via the Baker Hughes portfolio,” says Rustom Mody, vice president, completions and production technology, for Baker Hughes. “Under his new organization, there are approximately 80 people covering new technologies and application sciences spanning shaped memory polymers, high-pressure/high-temperature/high-load sealing mechanisms, new fracturing systems and an emerging nanotechnology partnership with Rice

University, to name just a few.”

“The role I’ve had in creating these groups is the most rewarding aspect of my career,” Richard says without hesitation.

“I’ve always enjoyed getting my hands around a beaker, a flask or a tool,” he continues. “Invention is easy. I can literally invent something every day, but inventing something that is game changing or commercially viable is the tough part. I think constantly. I think in the shower. I think driving home. I think in my sleep.”

Richard’s ability to identify talented people and place them in environments where they can develop their technical and leadership skills has opened a lot of doors for many high-potential Baker Hughes employees.

“I cherish watching people fulfill their potential,” he says. “That is what has been so gratifying to me, and I think if I had to leave a legacy, it would be just that—that I provided a work environment that allowed people to fulfill their potential.”

��“My wife Kim and my girls never complained about it, but I’ve been a Baker Hughes workaholic from day one. I remember when I was in Lafayette, I often got up at 11 at night or two in the morning. Kim would say, ‘Where are you going?’ and I’d say, ‘That piece of equipment I’m working on … I just figured out why it didn’t work yesterday.’ I just couldn’t wait until 8:00 in the morning, so I’d get up in the middle of the night and go try to fix it. I guess if I had to do it all over, I would have spent a little more time with the family.”

��“When the [Lifetime Achievement] award was announced, I got a congratulatory note that said, ‘You’ve made some significant contributions over your career…’ ‘Look, I’m not done yet. I’ve still got a couple more ideas in my hip pocket that I haven’t even told you about, yet. And when I get to working on those two, I’ll put two more in my hip pocket.’ I really don’t want to leave until Baker Hughes is the undisputed technological leader in our industry, and I think we’re close, very close.”

��“I’ve told a lot of young people over my career that every company has a different culture. Find one that really aligns well with yours. You have to be happy at what you’re doing and with the people you’re working with to be successful. The second thing is challenge yourself. I tell my group all the time, ‘You’re the best of the best, but you’re not as good as you can get.’”

��“I’ve got a lot of stuff left in

the vault.”thtthththhee

> Richard points out his favorite fishing spot to

7-year-old grandson Alex.


The West African nation of the Republic of Ghana is one of the world’s top produc-ers of gold, but historically Ghana has not enjoyed the benefits of oil, or “black gold,” the way some other African nations have. In late 2010, that changed.

Jubilation!Baker Hughes’ role in Jubilee project creates jobs in Ghana

In an historic moment and a turning point for this proud, stable nation, Ghana brought on stream its first oil production from a vast offshore deepwater field named Jubilee. Ghana chose this joyful name to commemorate the 50th anniversary of winning its national independence in 1957. Jubilee was discovered in 2007.

Baker Hughes, as a key player in the Jubilee project, is determined to make this first oil pay off for the people of Ghana.

Flowing Ghana’s first oilOn Nov. 28, 2010, Jubilee field production came on line. By January 2011, production to the FPSO vessel had climbed to approximately 50,000 BOPD, and on Jan. 5, the crew achieved the first lifting (offloading onto tankers) of Jubilee crude oil—a 650,000 barrel cargo.

Ultimately, there will be nine producers, six water injectors and two gas injectors for Phase 1. The subsea infrastructure installed for Phase 1 can accommodate 15 more wells for future infill drilling, as required. By the end of January 2011, four producers and two water injectors were active. One well per month will be added as completions continue this year. The wells farthest from the FPSO are 14 km (8.7 miles) away and are connected through a daisy-chained cluster manifold subsea network.

Jubilee has attracted major interest from global investors because of the oil’s quality and the field’s proximity to European and U.S. markets. Oil production is expected to deliver a significant economic bonus to Ghana.

Kosmos Energy of Dallas, Texas, discovered the Jubilee field in June 2007, and, by the end of that year, had brought Baker Hughes into the project. Kosmos, a 23.491-percent equity partner in the Jubilee Ph

otos

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Tullo

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il

> The Eirik Raude semisubmersible rig operating in the Jubilee field

42 |

unit project, was drilling the second appraisal well, Mahogany 2 and hired Baker Hughes to bring in the downhole well-test completion equipment and frac pack services for well testing. The well test was completed in April 2008.

Reggie Boggs, senior project manager for Baker Hughes, describes local conditions at the beginning of the project. “There was near zero oil infrastructure in Ghana, and essentially zero for deepwater work,” he says. “We went from the first deepwater well test ever done there to the first deepwater well completion ever in Ghana.”

Partnering with Tullow OilBaker Hughes’ involvement in the Jubilee project increased dramatically when the company was awarded its first major contract from Tullow Oil, the Jubilee field unit operator, on behalf of Ghana National Petroleum Corporation (GNPC) and partners. In February 2008, Tullow invited Baker Hughes to tender completion services for the entire Jubilee Phase 1 development, and Tullow Ghana Ltd. awarded Baker Hughes the work in September 2008.

Baker Hughes designs the completions, specifies and delivers all downhole equipment, manages the inventory, makes up and tests the equipment, and installs it in the wells. Downhole equipment

includes tubing-conveyed perforating (TCP) equipment, premium sand screens, frac pack equipment, packers, safety valves, gauges and flow assurance equipment.

Originally, all the wells were designed to be single zone, but the Baker Hughes Jubilee team redesigned the completions as dual zone to allow the wells to produce from longer sand intervals. This increases production potential and also lengthens the lifespan of the wells.

A Tullow Oil spokesperson commenting on the contract award said that Baker Hughes already had a proven track record in providing downhole equipment and an integrated service offering of perforating, sand control equipment, completion equipment and pumping services. Tullow also recognized that Baker Hughes had a team with deepwater West Africa experience and a reputation for maintaining a high quality assurance/quality control (QA/QC) level before shipping offshore equipment and for meeting all delivery times.

For the Jubilee production phase, Baker Hughes also won the contract to fully manage the holistic production chemical process, including supplying chemicals, managing inventory,

By the Numbers24.7 million

Population of Ghana

1957 Year Ghana became the first sub-Saharan country in colonial Africa to gain its independence

2007 Year Kosmos Energy discovered the Jubilee field

700 million barrels

Estimated oil reserves in the Jubilee field

539 km (335 miles) Length of coastline

60 km (37 miles) Distance from Jubilee field to the coast

885 m (2,904 ft) Mount Afadjato, Ghana’s highest point

8° 00 N, 2° 00 W Ghana’s latitudinal and longitudinal coordinates, making it geographically closer to the center of the world than any other country

16th 2011 FIFA (Fédération Internationale de Football Association) world ranking, highest among African countries

> The Kwame Nkrumah FPSO vessel in the Jubilee field


optimizing chemical usage and ensuring quality control. The chemical laboratory on the FPSO is staffed by Baker Hughes technicians and chemists.

The main chemicals being used in this early phase of production include methanol for subsea hydrate mitigation to prevent flowline blockage, triethylene glycol to control the dewpoint of the produced gas and to prevent pipeline corrosion or plugging, low volumes of corrosion inhibitor to protect the subsea infrastructure and topside pipework, small volumes of oxygen scavenger to prevent corrosion, biocide to prevent high hydrogen sulfide levels caused by sulfate-reducing bacteria and boiler-treating chemicals.

By January 2011, four production wells were in service with a full capacity of 50,000 BOPD, and this is anticipated to grow by

mid-year to 120,000 BOPD as the remaining five producers are completed and brought on line. At peak production, Baker Hughes will be chemically treating 120,000 BOPD and 40,000 barrels of water per day from the nine subsea production wells.

Creating jobs in GhanaBaker Hughes already had a presence in Ghana with an administrative and sales office in Accra that supports all projects and product lines, but after joining the Jubilee project, the company was able to hire even more Ghanaians, making substantial contributions to the local economy. The fast-track startup of the offshore project meant that Baker Hughes had to create an onshore base in less than one year to support operations. Takoradi, an industrial and commercial coastal port with a population of more than 360,000, was selected as the location for the operations base.

In keeping with its aggressive plan to hire and train a local workforce, the company now employs 56 Ghanaian nationals at its operations base, along with 74 expatriates that include employees from several other African nations. The workforce consists of skilled, technical and some labor workers.

The well-equipped Takoradi complex hosts Baker Hughes business operations teams, a BEACON™ center providing real-time remote support and communication to the FPSO, three workshops, a laboratory and an explosives bunker. The bunker is used to store downhole TCP charges until they are required at the wellsite.

Crews work seven days a week to assemble and ready completion equipment for mobilization offshore to prepare the Jubilee wells for production, water injection and gas injection. The integrated laboratory

01> Quality Specialist Isaac Nyarko works on a chemical injection mandrel at the new Baker Hughes complex in Takoradi.

02> Finance employees Dale Akambase (left) and Michael Adjei outside the Baker Hughes office in Accra.

“We knew Baker Hughes would supply quality products, so the work on local content and employment is a very important differentiator to us. We aim to be producing for 20 years plus, so we need service partners with that similar vision and a will to invest upfront.” Stuart Wheaton Ghana development manager, Tullow Oil

01

02

44 |

has testing capabilities for cement, fluids and chemicals. Other work performed at the complex includes up to 10,000 psi pressure testing, repair and maintenance of electronics equipment, and logistics operations that handle more than 600 shipments annually. There is ample room for expansion and job creation at Takoradi as the project grows.

Tullow Oil also maintains a significant office next door, which enhances communication between the companies. Tullow representatives have expressed satisfaction with the onshore support Baker Hughes is providing, not just from the base in Takoradi but also from its London and Houston offices.

A few miles from the Takoradi operations base, Baker Hughes has a team in place at a 1,700 m2 (18,298 ft2) dockside chemicals and storage facility 30 m (100 ft) from the water’s edge, with easy access to and from the ships. The team includes six Ghanaian nationals: the base manager, two QA/QC managers who oversee the work of the on-site laboratory, an accounts manager and two offshore chemists in training.

Stuart Wheaton, Ghana development manager for Tullow Oil, stresses the importance to Tullow of local hiring by Baker Hughes. “Tullow Ghana has been very satisfied with Baker Hughes’ efforts on the Jubilee Phase 1 project, in particular the commitments made to set up in Ghana to support the project, engage the local community and train national staff. We knew Baker Hughes would supply quality products, so the work on local content and employment is a very important differentiator to us. We aim to be producing for 20 years plus, so we need service partners with that similar vision and a will to invest upfront.”

According to Dai Jones, president and general manager of Tullow Ghana, more than 80 percent of Tullow’s employees are Ghanaian, and the company expects this to rise to 90 percent by 2013.

Training for the futureBaker Hughes provides both on-the-job training at Takoradi and on the FPSO, and also sends many team members out of the country for extended periods of instruction. “We’re committed to hiring and training the workforce of Ghana to be the future talent of the Ghana oil industry, and the government of Ghana agrees with this philosophy,” says James McDougall, managing director of Baker Hughes Ghana.

“The most important asset of the country is not oil: The most important asset of the country is the people of Ghana,” states Dr. Joe Oteng Adjei, Ghana’s minister for energy.

Committing to health and safetyThe Baker Hughes commitment to local hiring and training would not mean much without an equally strong commitment to high health, safety and environment standards in all aspects of the project. The Ghana team motto is, “No one gets hurt.” With this in mind, the team implemented a comprehensive set of initiatives involving safety in driving, the workshop and offshore. The record speaks for itself: In 2010, the entire Baker Hughes Ghana team had zero lost-time incidents, zero driving incidents and zero environmental incidents, even with a major increase of people working on the project.

On the health front, in Sub-Sahara Africa, malaria remains a significant health risk, especially for the expatriate workforce, which has no immunity. The Awareness, Bite Prevention, Chemoprophylaxis and Diagnosis (ABCD) method of managing

malaria was recently extended to ensure that all Baker Hughes team members and their families were included. This educational and prevention program receives close cooperation and support from Dr. Ernest Nagali, medical adviser for Tullow Oil. In 2010, only one expatriate malaria case was reported on the team, compared to nine cases in 2009.

Celebrating with a nationJust over two weeks after the first oil flowed in Ghana, the event was celebrated on Dec. 15, 2010—both on the offshore FPSO and onshore in Takoradi. Attended by guest of honor John Evans Atta Mills, president of Ghana, two former presidents of Ghana and numerous other dignitaries, the lavish ceremony was broadcast live on Ghana TV and globally via the Tullow Oil website. As part of the offshore ceremony, President Mills traveled by helicopter to the FPSO Kwame Nkrumah, where he turned on the inlet valve to symbolize the first oil production.

The Jubilee project is just beginning. Production will continue for some time from the wells currently in operation, and more wells will be drilled as the project matures.

And in 2010, Tullow discovered and began to appraise two additional offshore Ghana fields, the Enyenra (formally Owo) and Tweneboa fields, which have an estimated combined gross resource upside of 1.4 billion BOE. The potential of this new deepwater province in West Africa seems vast, indeed.

“We expect to remain active in this region for the foreseeable future,” McDougall says. “Undoubtedly, our commitment to hire from the local workforce is key to our continued involvement.”


“Falling into the Right Arms” by Michael Osei-Kesse As green as I was, energized with a perpetual quest to contribute to Ghana and the engineering profession, I fell into the right arms: Baker Hughes. I graduated from Kwame Nkrumah University of Science and Technology in Ghana with a bachelor’s degree in mechanical engineering and joined the Baker Hughes family in August 2009 as a completions field engineer trainee for cased-hole completions.

Working for Baker Hughes is a great learning experience because everyone is willing to share knowledge. I have had a series of well-tailored training programs to fully equip me toward the fast-driven technological oil industry. There are vast volumes of valuable information available in various modes for learning. I am enrolled in an Engineering Development Program that assigns me to SMART goals under the supervision of competent mentors and managers.

I assist with shop floor activities that encompass assembling and disassembling of equipment for the Jubilee field project. It is a great opportunity for me to learn across the board and

to learn about the tools. I enjoy the excitement of working to meet deadlines, enhancing my teamwork capabilities and troubleshooting, and a host of oil industry experience has started creeping in. Working on this project has helped complement theory with hands-on experience. I have been highly motivated by the challenges posed. I have also learned a great deal from the Baker Hughes penchant for heath, safety and environment. As much as Baker Hughes provides opportunity, help and guidance to its valued employees, learning and development is enormously dependent on the individual.

The oil industry is a big boom for Ghana. Signals of the reserves show a promising future. The proceeds will boost the economy and help provide more good schools and health facilities, dwindle poverty, create employment and provide a plethora of immense benefits from the black gold. Good measures must be adopted to help escalate Ghana from a developing country to a developed one. Baker Hughes has shown a good lead in exhibiting complete compliance in its operations in Ghana. Baker Hughes has also shown concern for the impoverished communities by providing for the poor and physically challenged in Ghana.

Personally, Ghana’s oil industry is a good platform to learn a lot and contribute to Ghana and Baker Hughes,

and to leave a good legacy for our future generations.

In December 2010, I passed my local board review and was promoted to field engineer II after meeting the requirements of that position. I share the success with my managers, supervisors, mentors and colleagues who gave their unstinting support in making this dream translate to reality. I am looking forward to more challenging opportunities in the future.

Bringing Overseas Training Back to Ghana Petroleum engineer Terry Cobbson recently completed a seven-week assignment within the Africa operations support drilling applications engineering group in Aberdeen, Scotland. A graduate of the Kwame Nkrumah University of Science and Technology in his native Ghana, Terry joined Baker Hughes in 2009. He is being trained for a drilling engineering role for Ghana and the Sub-Sahara Africa geomarket.

Achieving well-planning certification helped accelerate Terry’s development and enhance his drilling engineering capabilities. This was achieved by working alongside and collaborating with members of the drilling applications engineering support group and through ongoing support and input from his mentor, Drilling Applications Engineer Pedro Garcia.

While in Aberdeen, Terry was exposed to a range of engineering tasks that helped him develop a wider appreciation of the engineering needs of his own geomarket, as well as the others in Africa. He received training in the Baker Hughes quality management system, advantage engineering, and wellbore positioning and surveying.

Terry’s training continued in Gabon where he became part of the Gabon applications engineering team. There, he worked on various projects under the supervision of drilling engineers Elizabeth Perez and Sanna Zainoune.

“My on-the-job training was very beneficial, and the opportunity I had to work with highly experienced engineers really enlightened me,” Terry says. “My training has significantly equipped me to yield improved output at my home base in Ghana.”

Terry was among the first group of trainees promoted to field engineer II in Ghana, and he currently provides well planning services to clients in Ghana and Gabon. He is now looking at developing the engineering side of his developmental matrix.

Focus on Young Ghanaian Engineers

46 |

To maximize production from long, horizontal wells, many operators want to isolate the pay zone in as many segments as possible. A new technology extends the limits, changes the environmental equation and creates a layer of flexibility to optimize multistage fracture stimulation.

MAKE IT THE COMBOCoiled tubing opens sliding sleeves to optimize multistage fracturing

The ability to accurately place long, horizontal wellbores changed the way the industry approaches field development and enabled economic production from previously ignored low-permeability formations, such as the Viking and Amaranth sandstones and the Bakken shale in Saskatchewan, Canada.

It also opened the door to new technologies that maximize production by optimizing the fracture stimulations across the length of the typically heterogeneous producing formations.

“What is the optimal number of fracs and at what spacing? That’s the million-dollar question,” says David Wind, a Baker Hughes technical sales representative in Calgary, where he specializes in pressure pumping services. “We see a reluctance to run detailed openhole characterization of the horizontal trajectory prior to fracturing. If the well is expected to produce 200 barrels a day, time is not spent obtaining the appropriate logging data throughout the openhole section to decide where to put the fracs.”

More segments, more oilInstead, operators try to ensure full wellbore coverage by breaking the horizontal length into segments and stimulating each segment separately. This practice triggered the development of increasingly efficient technologies designed to simplify multistage stimulation operations and the number of potential treatment stages (See ).

“We anticipated the desire for more and more stages,” Wind recalls. “The ball-drop systems started with eight stages, then 12, then 18…Every time the technology allowed


increases in frac staging, the customers wanted more.”

As customer demand in the field was recognized, design experts at the Baker Hughes Coiled Tubing Research and Engineering Centre in Calgary began working to develop multistage tools and technology that can grow with the demand.

“The sand-jetting tool we developed for our BJ OptiFrac™ SJ services was reliable and convenient, but it can be expensive and time-consuming due to the cost and availability of incremental fracturing fluid,” says Brad Rieb, director, technology, Canada region. “But the ball-drop completion systems have disadvantages, too, such as a limit on how many stages you can place in a well, a restricted inside diameter of the borehole, and the complications that can arise if we screen out the treatment. So, the next step was to combine the best aspects of both technologies—and that’s where the OptiPort™ system came in.”

OptiPort technology combines sliding sleeves like those in the ball-drop completion systems, but it opens the sleeves with a coiled tubing (CT) tool rather than sequentially sized balls. This enables a virtually unlimited number of stages and leaves the CT in the well for an annular frac, permitting a quick cleanout if required after a screenout.

Saving time and waterThe concept was an immediate hit with customers. “We wanted a system where we could frac with the coil in the hole for optimizing frac conductivity and for efficient screenout recovery,” says Rob Hari, vice president of operations for Triaxon Oil Corp. in Calgary. “We used ball-drop systems before, with up to 16 stages, and if you had an early screenout during the frac, you lost a lot of time, added cost and, potentially, lost some of the stages. So, then, you would be cautious with your design, which compromises productivity, instead of optimizing the frac conductivity. Now, we can do 18 or 20 stages, and we don’t compromise on the frac design, as we aren’t worried about losing time and cost due to screenouts.”

For Christie Hillis, a completion engineer at Penn West Exploration in Calgary, the concern was water conservation. “We had been using abrasive jetting and annular fracs,” Hillis recalls. “I liked the idea of this new system because we could still do our annular fracs, but it was going to reduce our water volumes, which was a stakeholder-relations issue.”

After a number of operations, Hillis estimated that the new system uses approximately 40 percent less water and saves 20 to 30 percent on operation time. In fact, customer acceptance created a new

problem: how to keep up with the demand, which hit just as BJ Services was being integrated into Baker Hughes.

“The timing couldn’t have been better,” Rieb says. “At BJ Services, we had hydraulic fracturing and coiled tubing expertise. Baker Hughes brought downhole completion tool engineering and manufacturing and is a leading completions company, from high-end completions in the Gulf of Mexico to openhole multistage completions like the FracPoint™ system. Baker Hughes is also strong in service tools. So, it was an ideal combination.”

> Stimulation treatments with the OptiPort completion system are similar to other coiled tubing-assisted fracturing treatments but typically use less water and treat more stages in a day.

“We used ball-drop systems before, with up to 16 stages, and if you had an early screenout during the frac, you lost a lot of time, added cost and, potentially, lost some of the stages. So, then, you would be cautious with your design, which compromises productivity, instead of optimizing the frac conductivity. Now, we can do 18 or 20 stages, and we don’t compromise on the frac design, as we aren’t worried about losing time and cost due to screenouts.”

Rob HariVice president of operations for Triaxon Oil Corp.

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More flexibility for customersKent Meyer, OptiPort system product line manager in Calgary, says manufacturing is ramping up, and the challenge going forward will be to expand the system’s reach. “We have 1,800 stages in the ground between the 4½- and 5½-in. tools,” he says. “Now, we’re looking at new formations and trying to figure out how far can we push the envelope.”

Meyer notes that the technology does have some operational limitations, which future developments may extend. “But most likely, it will never be the end-all, be-all: You’ll still need ball-drop systems and plugs. But the OptiPort system adds flexibility. That means we can work with customers to choose the best tools for the formation in the envelope where we know it works, rather than trying to sell a system because it’s the only option we have.”

> The Baker Hughes FracPointTM system

Multistage Options Create Flexibility for CompletionsPlug-and-perf technology: Perforating guns and composite bridge plugs are run into the well between stimulation stages to isolate prior stages.

Ball-drop sleeve systems (the Baker Hughes FracPoint™ system): Sliding sleeves are run with the casing, isolated with packers, typically openhole. Sleeves are opened by dropping a ball at the end of each fracture stimulation treatment.

Annular fracturing services (BJ OptiFrac™ SJ services): Conventional casing is run and cemented. A sand-jetting tool on coiled tubing (CT) creates perforations in the casing, and the frac is pumped down the casing/CT annulus (typically called an “annular frac”). At the end of each fracturing stage, a highly concentrated proppant slug is pumped to create a sand plug that isolates the stage, and the process repeats. After all stages, the CT is used to remove the sand from the wellbore.

BJ LitePlug™ services: Similar to BJ OptiFrac SJ services, except the slugs of sand include a proppant additive that improves stability and reliability for sand plugs in horizontal wells.

OptiPort™ system: Sliding sleeves are run with the casing and can be cemented in place or isolated with packers. A CT tool opens the sleeves, and annular fracs ensue.


British mountaineer George Leigh Mallory, who disap-peared during a 1924 expedition to Mount Everest, is famously quoted as having replied to the question “Why do you want to climb Mount Everest?” with the retort: “Because it’s there.”The same answer might be given by operators looking for oil in basement reservoirs because producing oil from the world’s hardest rock comes with a mountain of chal-lenges in drilling, logging and modeling.

01> Adriaan Bal, regional geoscience adviser for Baker Hughes in Asia Pacific, leads a group from Petronas on a field trip to Pulau Pinang, Malaysia, to measure fracture density along a psuedo-borehole.

02> This 20-m (66-ft) gap between two fractured-granite basement blocks on Pulau Lima, Malaysia, is the result of selective weathering of a fault-weakened zone. Such zones are characterized by a dense network of shear fracturing that results in significantly increased porosity and permeability relative to the adjacent foot and hanging wall blocks.

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Oil and gas reserves within these basement reservoirs are held in place through an extensive network of connected fractures. Gavin Lindsay, drilling and evaluation marketing director for Baker Hughes in Asia Pacific, says, “Once you’ve connected all the fractures to allow the oil to flow,

you can get wells that are really quite prolific and economic. The challenge is estimating reserves in place and the sustainability of production.”

Many Asian countries, from Japan to Malaysia and Indonesia, are discovering additional reserves in basement plays, Lindsay says, but Vietnam is the best-known basement producer in the region. Offshore Vietnam’s Cuu Long basin comprises 95 percent of the country’s hydrocarbon production, with 85 percent of this value coming from the fractured granite basement. Cuu Long’s Bach Ho (White Tiger) field, alone, is a giant four-billion-barrel field with hundreds of producing wells.

Basement reservoirs are typically fractured metamorphic or igneous rock, unconformably

overlain by a sedimentary sequence. Usually, the fractured basement reservoir has been uplifted by tectonic forces. The fractured basement is, then, charged with hydrocarbons from a conventional, usually downdip, kitchen. Although it has been known for decades that the oil migrates into

fractured basement, historically it has not been considered as an economic reservoir.

Perhaps one of the most challenging aspects of producing basement reservoirs is predicting where the hydraulically conductive natural fractures are located. And, depending upon how weathered the granite is, drilling progress tends to be slow and abrasive. Moreover, basement rocks are very difficult to characterize with logging tools that were designed to “look” at sedimentary reservoirs.

However, with today’s advanced technologies, more and more operators—particularly those working in Southeast Asia where significant reserves have been discovered in basement reservoirs—are willing to gamble on these complicated, yet potentially rich, plays.

Knowing where to drillFor conventional reservoir plays, depositional environment is the primary lens through which the reservoir is characterized. This mindset, however, changes when dealing with basement reservoirs where almost all the porosity for hydrocarbon storage and permeability is in the fractures.

“We, therefore, change our primary lens and focus on the mechanisms that created the fractures,” says See Hong Ong, Baker Hughes Reservoir Development Services (RDS) regional technical adviser in Asia Pacific. “We need to understand the fractures. When did they form? How did they form? And where are the fracture sweet spots?”

Understanding the stress state of the basement rock and predicting where the natural, hydraulically conductive fractures are in order to orient the placement of the well is key to producing from the basement.

“This understanding is grounded in structural geology and geomechanics, and it allows us to rank potential prospects and optimally drill the best well,” Ong contends.

“The best well is not always oriented perpendicularly to the most fractures. When given knowledge of the present-day tectonic-stress state, the distribution of natural fractures and the properties of those fractures, it is possible to select the best direction to drill a well to maximize productive

contact with the reservoir. However, knowledge of stress or fracture patterns from image logs or other evidence, by itself, can lead to radically different predictions and suboptimal drilling orientation.”

A discrete fracture network model that incorporates all information, including seismic and field data, is a convenient way of describing the distribution of fractures within the reservoir. Once prescribed with the fracture hydrological properties and calibrated with drillstem tests or production data, the discrete fracture network is scaled up to a full simulation model for history matching and reservoir performance forecasting.

In addition to the discrete fracture network model, it is advantageous to develop a 3D

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geomechanical model, according to Ong. Many of the initial open and hydraulically conductive fractures actually close during production due to the reduction of pore pressure, causing a rapid decline in production rates. Direct analysis of the connection among individual stress-sensitive fractures achieved by coupling the different models with feedback loops allows predictions of the best locations and drainage areas for planned wells. This coupled simulation, performed either iteratively or fully, is an important contribution to predicting field production rates and ultimate recovery, as well as efficient field management.

“These complex models and interpretations are based on critical evaluation and integration of many different datasets,” Ong adds.

Though difficult to obtain, core data provides critical information about fracture morphology and mineral fill that may have a significant impact on the conceptual fracture model. “From detailed core descriptions, we are able to confirm the nature of fracture genesis and development,” says David Castillo, global director and vice president of reservoir geomechanics for Baker Hughes

RDS. “For example, secondary mineralization may prop open selected fracture sets with orientations suboptimal to that expected from the current-day stress regime.

“These observations are most effectively derived from observing the actual rocks in the field or core. Furthermore, core allows direct measurement of geomechanical properties.”

Mudlogs, drilling reports, core information, conventional logs, borehole images and full waveform acoustic data are all used to build the advanced geomechanical model to quantify the magnitude and direction of the stresses and to identify those fractures that are critically stressed and, therefore, more prone to productivity.

Drilling the basementGerald Heisig, applications engineering manager for Baker Hughes in Southeast Asia, describes the challenges associated with drilling the basement rocks: “Granite can be very hard and abrasive, slowing the drilling progress and elevating tool wear and tear. High weight-on-bit is necessary to achieve acceptable rates of penetration. All of this results in short bit and motor life, with runs that rarely exceed 40 drilling hours. Moreover, tools suffer from outer diameter wear, which can be very expensive to repair. As a result, the best drilling strategy is to use downhole motors and to keep surface rotary speed as low as possible.”

Today, operators drill wells at higher inclinations to achieve the longest sections possible and to penetrate as many optimally aligned fractures as they can. For these wells, it is best to use directional drilling with steerable motor systems, Heisig says.

“It is very difficult to keep the motor orientation steady in these very long wells,” he adds. “This is where expertise in drilling motors, drill bits and drilling systems makes a difference. Having drilled more than 100 wells in the fractured basements of southeast Asia over the last 10 years, Baker Hughes has a wealth of experience in drilling such challenging wells and continually develops and improves fractured basement drilling systems.”

In 2008, Baker Hughes was the first company to introduce rotary steerable system technology in the Cuu Long basin. Heisig’s drilling system of choice for the basement? The Baker Hughes AutoTrak eXpress™ rotary steerable system, downhole Ultra X-treme™ motors with special high-load axial bearings with a tungsten-carbide insert roller cone bit, with the StarTrak™ high-definition advanced LWD imaging system and CoPilot™ real-time drilling optimization service modules.

“With the CoPilot service, drilling is optimized using downhole measurements that can accurately measure downhole weight-on-bit, torque and bending in the bottomhole assembly, plus several forms of vibrations, giving an accurate picture of the downhole drilling environment so that the life of the downhole equipment can be extended,” Heisig says.

In addition, drilling is faster with this technology. “It’s possible to drill farther with a drilling assembly without tripping out of hole. Yes, rotary steerable system technology is more expensive than conventional steering systems, but if we can save the client a few days of rig time, it’s money well spent,” Heisig explains.

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Characterizing the reservoir“Of all reservoirs, the basements are the most important to evaluate early in the field lifecycle to minimize the costs of drilling unnecessary wells,” says Adriaan Bal, regional geoscience adviser for Baker Hughes in Asia Pacific. “It is, therefore, essential to acquire important fracture characterization data early to optimize future well locations and paths, to predict field production rates and recovery, and to deplete the field economically.”

One of the most important Baker Hughes technologies in the fractured basement is the new second-generation UltrasonicXplorer™ borehole acoustic imager. “This imaging instrument is sensitive to open, potentially productive, fractures,“ Bal says. “The tool also operates very well in highly deviated and horizontal wells since it’s less sensitive to the need for tool centralization when compared to older generation tools.”

The StarTrak system, if required, allows for a rapid fracture evaluation in real time. Baker Hughes was the first company to acquire high-definition resistivity images while drilling over a granite section. “Both the StarTrak tool and the UltrasonicXplorer tool provide full 360° coverage, which is important since this complete dataset provides more certainty for geomechanics studies,” Bal adds.

Of equal importance, he says, the full waveform acoustic data from the XMAC F1™ acoustic service provides fundamental information. “For example, rock strength parameters and Stoneley permeability both help evaluate and identify

potentially productive fractures,” Bal adds. “Furthermore, the cross-dipole can now be used to image fractures up to 60 ft (18 m) from the borehole wall.”

Building relationshipsBaker Hughes has a complete understanding of what it takes to make a basement play economic and is building lasting client relationships through sharing of experiences and open discussions of new methods and technologies required to enhance basement exploitation.

“We can give clients the entire package, from constructing detailed geomechanical and reservoir volumetric models to record-setting drilling and evaluation performance,” Lindsay says. “All this results in a well that is placed in the right location to maximize production, a good understanding of how much hydrocarbons will be produced, well construction costs kept to a minimum, and stimulation and remediation for the life of the field.”

Baker Hughes continues to be at the forefront of research and development as well, he adds. “For example, a new shear-wave reflection imaging technique to ‘see’ open fractures within a radial extent of about 60 ft (18 m) is being investigated. And, with a full suite of innovative chemical products and research into stimulation of fractures, the future is very promising.

“The basement might be unrelenting, but those of us working it do not see it as an unassailable obstacle,” Lindsay says, “but rather a mountain that is possible to climb.”

Using an innovative shear-wave reflection imaging technique provided by the Baker Hughes XMAC™ F1 acoustic service, fractures can be “seen” around the borehole within a radial extent of about 60 ft (18 m)—a much larger volume than is typically investigated. Moreover, open fractures tend to produce stronger reflections. This technique uses a dipole acoustic tool to generate shear waves that radiate away from the borehole and reflect from optimally aligned impeding open fractures. The resulting reflections are imaged to allow determination of the fracture length, strike and dip.

PICTURE PERFECTSeeing fractures 60 ft from the borehole

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> Quartz veins show mineralized natural hydraulic fractures created by internal fluid pressure during the last stages of granite emplacement.


Humans discovered thousands of years ago that the earth stored energy in the form of heat beneath its surface.

Native Americans and other early cultures used natural hot spring waters, often rich in minerals, for bathing and as a healing source. In the early 1800s, a Frenchman invented a way to use steam to separate boric acid from volcanic mud; and, in 1892, enterprising citizens in Boise, Idaho, figured out how to pipe water from hot springs into town to heat buildings—creating the world’s first district heating system. Ph

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> The Alps provide a stunning backdrop for a Hekla Energy geothermal project in Bavaria, near the town of Mauerstetten, Germany.

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Today, there is more interest than ever in geothermal power. A 2010 report by the Geothermal Energy Association called “Geothermal Energy: International Market Update” states that both the number of countries producing geothermal power and the total worldwide geothermal power capacity under development appear to be increasing significantly.

The report found that between 2005 and 2010, Germany was the fastest growing geothermal power producer in the world with a whopping 2,774 percent increase in installed megawatt capacity.

Increased awareness of “clean” energy to reduce CO2 emissions, concern over continued world oil production and rising

costs of energy exports are all helping to expand Germany’s renewable energy market. But perhaps the biggest driver powering the growth is the country’s Renewable Energy Sources Act—a very ambitious plan to replace 30 percent of the total electricity consumption in Germany with renewable energy by 2030. By 2050, the goal is 60 percent.

Germany announced its new energy goals at the end of the last millennium and today is one of the leading industrial nations in the renewable energy sources sector, according to the country’s Federal Ministry for the Environment, Nature Conservation and Nuclear Safety.

Helping fuel this trend toward climate-friendly energy are government incentives in the form of grants to industries and universities to research and develop enhanced geothermal technologies, and 20-year fixed feed-in tariffs to power plant operators that give priority to electricity that comes from renewable energy sources, such as geothermal—making higher risk and higher cost projects more feasible.

This increase in geothermal drilling and production has made geothermal the fastest growing business for Baker Hughes in continental Europe. Plus, 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 products and services, as well as the government’s ambitious target.

Getting into hot waterGeothermal energy is used to heat homes and to produce electricity. Getting the naturally occurring hot underground water or steam from the subsurface requires drilling a well and pumping it to surface where geothermal power plants generate electricity for commercial and residential use by using the hot water or steam to drive their turbines. The used water or steam is then reinjected into the geothermal reservoir through a second well so the process can begin again.

There are two basic categories of geothermal power: flash, a simple-to-produce heat source found in shallow, low-temperature reservoirs; and hot dry rock (also called enhanced geothermal systems), which is found in much deeper reservoirs and is more difficult to produce but, because of its high temperature, is essential for electricity production.

Flash energy occurs at temperatures of 149°C (300°F) or less and is produced if naturally occurring water and rock porosity are sufficient to carry heat to the surface. These low-temperature resources are typically used in direct-use applications such as district heating where the heat is put into a large pipeline and distributed directly to houses or businesses.


Geothermal energy hot enough to produce electricity often comes from crystalline rock usually more than 4000 m (13,123 ft) below the earth’s surface. The low permeability of the hard rock is enhanced by pumping high-pressure cold water down an injection well into the rock. Water moves through fractures, capturing the heat of the rock until it is forced out of the production well as superheated water, which is converted into electricity. Some of the fractures are natural, while others have to be created through fracturing processes commonly used in the oil and gas industry. Once cooled, the water is injected back into the ground to heat up again before going through the same cycle.

Making geothermal affordableThere are two major obstacles in geothermal recovery: overcoming the technical challenges of drilling and completing wells in extreme-temperature reservoirs and pure economics.

Drilling costs common in the hydrocarbon industry are not affordable for the geothermal industry. It takes 10 to 15 years before a geothermal project becomes profitable and the investment is recouped. “The bottom line is that hot water doesn’t sell for $75 a barrel,” says Thomas Mueller, technical sales manager for Baker Hughes in continental Europe.

Nonetheless, because of the government subsidies that guarantee long-term payouts for geothermal energy, many companies with little drilling experience are entering the geothermal arena. Their lack of both capital and experience poses a unique set of challenges for Baker Hughes.

“There’s certainly a learning curve involved,” says Tim Erdmann, sales manager for geothermal in Germany, Austria and Switzerland. “Baker Hughes provides the geothermal industry with some of the best off-the-shelf technologies available today, but it’s our job to work

with these clients and help make their wells more economical and more reliable by providing better reservoir analysis, faster drilling with our advanced drilling technologies and more reliable pumping systems.”

“Baker Hughes has the capability to deliver quality wellsite equipment and product knowledge, but we should be involved in some cases way up front, perhaps a year or two in advance, to make sure we understand the environment in which we’re working,” says Joachim Oppelt, Baker Hughes director of external programs, technology portfolio management. “This is where our Reservoir Development Services (RDS) group comes in. Geomechanics can look at the crack structure of a reservoir and tell a client exactly where the two wells need to be placed. And placing a well correctly into the reservoir is the key to success.”

“Because we are able to use standard technology to produce

these wells, new technologies such as the latest Hughes Christensen Quantec™ PDC bits, VertiTrak™ nonrotary drilling system, TruTrak™ automated drilling service and AutoTrak™ rotary steerable system are just making their way into the geothermal industry,” Erdmann explains. “And, because the client’s first perception is that all this new technology is too costly, it’s our job to educate them on the benefits of these advanced technologies.”

“Combining the AutoTrak system with Quantec PCD bits saves the client money by saving drilling days, and morever, they end up with better hole quality, which allows the operator to run casing easier and to get better resolution and, therefore, better results from wireline logs,” Mueller explains. “There is a growing interest in all this technology, especially from potential clients who are going to drill 4000-m to 6000-m (13,123-ft to 19,685-ft) wells. This is when they will really start to see the

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benefits. Deeper wells create higher costs. This is the perfect opportunity for us to really show the client the benefits of this advanced technology that makes drilling these projects more economical.”

Another product advancement just being introduced to geothermal clients is the Hughes Christensen GaugePro XPR™ expandable reamer technology. “As the casing scheme is dictated by the geology, many clients have now realized that increasing the last diameter of hole, by underreaming the reservoir, is the key to maximize return on investment,” Mueller says. “A large diameter in the reservoir means a higher flow rate and, at the end of the day, the electrical power is dependent on both the temperature of the hot water and on the flow rate—how much you can pump out of the well.”

The one “must have” technology in the geothermal market is a pumping system to lift the hot

water or steam to surface and guarantee a flow rate sufficient to produce electricity.

“Every time a pumping system fails or stops, it’s an emergency,” Oppelt says. “There is either no electricity being generated or a district heating system is not kept warm. The geothermal client is depending on the long-term, reliable operation of a high-volume, high-temperature pump.

“The efficiency of the ESP [electrical submersible pumping] system is crucial to the success of the geothermal project. If our system works 2 to 3 percent more efficiently over a period of 10 years, that’s a tremendous amount of value to the operator.”

“Baker Hughes owns 80 percent of the geothermal pumping system market in continental Europe,” says Aad Castricum, manager of technical support for artificial lift systems. “Due to our references and the high reliability of our

equipment, customers are selecting Baker Hughes’ ESP systems whether or not we were involved in the drilling.”

Baker Hughes has the industry’s highest horsepower ESP system, the Centrilift XP™ Xtreme Performance series, which consists of the new 880 motor—the first ESP motor capable of 2800 hp and production flow rates of 4,500 gal/min (0.28 m3/s).

“We have installed the new 880 motor in a major geothermal project in Unterhaching in southern Germany to achieve high flow rates in combination with the high-lifting requirements of the well, increasing the overall system efficiency significantly,” Castricum adds. The district heating network, the largest newly built network in Germany since the 1980s, is 28 km (92 ft) long and provides heat for private homes, the town hall, schools, swimming baths and commercial sites.

Managing projectsBaker Hughes has 40 years of background working in geothermal projects around the globe, says David “Nic” Nickels, director of global geothermal markets. “This experience is augmented with a large array of products and services, and with the recent acquisition of pressure pumping and stimulation service capabilities, which provides the ideal solution for fracturing formations for the hot dry rock projects, Baker Hughes Integrated Operations can do everything from well planning to drilling to managing the project for the client,” Nickels says.

“We do have the full project management capabilities,” Erdmann adds. “If you come with the specs and ask us to deliver the project from A to Z, Baker Hughes can do that. I would consider this the most important feature we offer today.”

> In Iceland, one of the world’s most active geothermal regions, Baker Hughes provides drilling and evaluation services and drill bits to all of Iceland Drilling Company’s drilling operations.

A half century ago, with hundreds of drilling rigs dotting the German countryside, George Christensen saw an opportunity and opened a subsidiary in Germany to manufacture diamond drill bits and coring bits for the mining and oilfield industries. Christensen, along with a friend and former football teammate, Frank Christensen, had founded the Christensen Diamond Products Company in Salt Lake City, Utah, in 1944.

Celle Technology Center

The Christensen Diamond Products manufacturing plant opened in Celle, Germany, in 1957. The facility built diamond core heads and drill bits and later expanded to make downhole tools. In 1977, the Celle engineering and manufacturing team introduced the Navi-Drill™ line of downhole drilling motors.

After a series of mergers and acquisitions that began in the late 1970s, the facility became part of Baker Hughes in 1990 with the acquisition of Eastman Christensen. Other innovations developed in Celle include the industry’s first steerable motor system and the AutoTrak™ rotary steerable closed-loop system.

The Celle Technology Center (CTC), as it’s called today, was expanded in 2009 to support joint technology developments, including geothermal, with operators and local universities. Since its grand reopening, the CTC is also home to the Baker Hughes Center of Excellence for geothermal and high-temperature research and development.

HOT SPOT FOR GEOTHERMAL RESEARCH

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In 2009, Baker Hughes and the Niedersachsen (Lower Saxony) state government jointly launched a multimillion euro, five-year cooperative university research project aimed at improving the technology for generating geothermal energy from very deep (4000 m to 6000 m) [13,123 ft to 19,685 ft] geological formations. With guidance from Baker Hughes scientists in Celle, Lower Saxony’s technical universities will combine their acknowledged strengths in geosciences, material sciences, drilling technology and technical systems in order to generate leading-edge research results for Baker Hughes to integrate into the development of sustainable and marketable products and services.

The Lower Saxony state government is also providing financial support for Baker Hughes’ research and development of high-temperature electronics for use in drilling

and evaluation, as well as completion and production applications. In addition, Germany’s federal government has awarded Baker Hughes a cofunded project to develop cost-efficient drilling technologies for geothermal wells.

Baker Hughes is conducting a second project supported by the German government to improve the performance of electrical submersible pumping (ESP) systems, with a special focus on reliability. Integral to this research is the Celle high-temperature test loop, designed to specifically test new high-horsepower, high-volume ESP system technology for the geothermal environment.

“The new test loop will continue to grow the center’s reputation in the fields of high temperature and geothermal systems,” says Trey Clark, former director of technical support for Baker Hughes in continental Europe.

The test loop will include a control room, storage and maintenance area, loading unit, contained pressure vessel, and 20 kv transformers and variable speed drives. Maximum electrical power can reach 3,500 kVA and the temperature rating is up to 190°C (375°F). Completion of the test loop is anticipated in the second quarter of 2011.

The center is also developing new wellbore construction and drilling technologies, specific to the geothermal market. “In addition to our existing portfolio of geothermal products and services, we see the advancement of our ESP and drilling technologies as game-changing to the industry, allowing new wells to be drilled more economically, and energy production to be maximized over the life of the well,” Clark says.

01> Martin Paland tests Navi-Drill motor rotors at the CTC.

02> Expanded in 2009, the CTC houses a geothermal and high-temperature R&D center.

03> Bernd Grote assembles electronics into tools at the CTC.

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KAZAKHSTANI VOCATIONAL PROGRAM

Musabekova Guljahan studies economics in Astana, the capital city of Kazakhstan, but she has always been interested in finding applications for alternative energy sources. “I am aware of a great need for renewable energy in Kazakhstan,” she says. “I also know that there are very few companies on the national market that use solar-powered technologies, so I thought that production of solar panels would be a very good business idea that would become competitive on the market and contribute to the environmental sustainability in Kazakhstan.”

Another student, Filistovich Mihail, plans to open his own printing company. “I have already developed a business plan, which will give me more chances to get credit from a bank for business development. Meanwhile, I am working in the industry as an employee and trying to learn all the details of managing a printing company.”

The Know About Business (KAB) program, supported by grants from Baker Hughes and Chevron, as well as funding from both the U.S. and Kazakhstan governments, has helped thousands of Kazakhstani youth like Filistovich and Musabekova discover their passions, think creatively and use their enterprising ideas to make a positive contribution to their community.

The International Labor Organization (ILO) created the KAB program as a global course to increase employment opportunities for youth

through vocational education systems. Today, the program that teaches business practices and entrepreneurial skills is offered in more than 20 countries in Central Asia, Africa and Latin America.

The ILO brought the course to Kazakhstan about eight years ago. Recognizing the importance of entrepreneurship education in support of the long-term goal of a diversified Kazakhstan economy, the Ministry of Education and Science made a short version of the course mandatory in certain specialized vocational institutions. The ILO trained and certified approximately 30 teachers and eventually qualified them as key facilitators (certified teachers of teachers), but the program lacked resources and sponsors to expand.

According to the ILO, by the end of 2008, approximately 10 primary vocational schools in Kazakhstan were teaching the KAB course and about 3,000 students had been reached.

That’s when Baker Hughes and Chevron stepped in and stepped up the program.

Seeing a need to invest in the development of the Kazakhstani workforce and to modernize the vocational education system, Baker Hughes and Chevron independently engaged the United States Agency on International Development (USAID) in late 2009 and agreed to provide grants to support improvement of the vocational education system.

Baker Hughes Grant Kick-Starts

Good Neighbors

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USAID assigned the program to the Kazakhstan Small Business Development Project (KSBD), which is jointly funded by USAID and the government of Kazakhstan. Recognizing the program’s success in other parts of the world, Baker Hughes and Chevron agreed to allocate their grants for the KAB program.

A report by the KSBD last year indicated that, due to cooperation from the Ministry of Education and Science and local education departments, “The KAB program was able to achieve results far beyond the original targets.”

Between April 2009 and June 2010, the nationwide program trained 642 new teachers and provided preparation in entrepreneurship to almost 115,000 Kazakhstani students in 517 vocational schools.

“Baker Hughes has been active in the Kazakhstani oil and gas industry since 1992 and shares in the country’s desire to prepare its local work force through investment in the formal education system,” said Jochem Scherpenisse, Kazakhstan country director for Baker Hughes. “The KAB program was the perfect platform for launching a bold new educational program to help develop a competitive, diversified and innovation-driven economy in the 21st century. The grants provided by the Baker Hughes Foundation and Chevron were the spark needed to ignite the program.”

Through interactive and participatory teaching methods—experimental ground for most Kazakh teachers—the course helps students develop entrepreneurial skills and practical business knowledge. It immerses them in real life learning experiences where they take risks, manage the results and learn from their project outcomes.

The KSBD report said that teachers describe the participatory approach as a groundbreaking methodology that has changed their

attitudes about teaching and provided them with a range of new opportunities to build students’ knowledge and experience.

“In the world of new technologies that students are exposed to, there is no space for the old lecturing system,” one teacher said. “Participatory methodology is exactly what we need to captivate students’ attention and motivate them for learning.”

Seventy percent of teachers reported that they have changed their approach to teaching in other classes as a result of the KAB program. In addition, the majority of teachers indicated that the program has contributed to their professional development, increased their professional competence and improved their overall knowledge in such subjects as economics, marketing and accounting.

“This program is beneficial to Kazakh communities on so many levels,” said Jennifer Cutaia, director, government relations, for Baker Hughes. “It prepares students to become more effective members of the workforce by teaching them how to set goals, develop a business plan and manage their finances. It’s a motivational means of providing them with information about the opportunities, challenges, procedures and attitudes needed for entrepreneurship. And, it serves as a professional development tool for teachers in the vocational education system. It’s definitely a win-win program for everyone involved.”

> Baker Hughes personnel visited a vocational school in Astana, Kazakhstan, to see how the Know About Business course was being implemented. Representing Baker Hughes were Atle Loge, vice president, drilling and evaluation, Russia Caspian; Zukhra Abdrakhmanova, manager, business development, Kazakhstan; and Jennifer Cutaia, director, government relations.


Blue Tarpon Deepwater Stimulation VesselThe Baker Hughes Blue Tarpon deepwater stimulation vessel is designed and engineered to meet the extreme challenges of large multiwell deepwater projects.

At 300 ft (91.6 m) in length, the vessel can carry 2.75 million lbs of proppant and 10,200 bbl of fluid—enough to perform multiple well completions without returning to dock to resupply.

Pumping high-rate and high-volume frac pack treatments adds more demand on equipment and systems. Baker Hughes has reduced that risk by installing backup systems on all key elements of the stimulation plant, thereby delivering the highest level of reliability and reducing operational risks.

“The three blenders on the vessel are designed to communicate with one another, and in the event that there is an issue with one of them, the computer can switch the job to another blender to continue the progress of a job—a critical issue when you are in the middle of a programmed pumping treatment or stage,” says Rick Jeffrey, global fluid pumping services manager for Baker Hughes.

The stimulation plant, built inside an enclosed structure, is completely protected from the environment, further improving equipment reliability and reducing the effects of corrosion.

All pumping equipment is operated from the control room via electronic controls, providing the highest level of safety for the personnel onboard. All critical equipment is monitored via live video feed from 16 independent locations, giving the crew visual access to all operations.

The vessel features a touch-screen control room with fully automated ratio controls for the addition of proppant and chemical additives, as well as for remote valve actuation, providing increased flexibility when performing multiple applications.

The Blue Tarpon, the ninth in the Baker Hughes offshore fleet, is capable of delivering 24,000 hhp through six SC-2000 triplex pumps and four SC-3000 quintuplex pumps. It will join the almost identical Blue Dolphin, launched in December 2009, in the Gulf of Mexico.

Other Blue Tarpon features include � Remote satellite transmission of data and video with dual backup systems

� WellLink RT™ WITSML-compliant service to transfer, host and visualize well data in real time

� Accommodations for up to 44 personnel, allowing for nonstop operations on large-scale multizone projects

� Laboratory that provides real-time QA/QC on fluids and chemicals � Maximum working pressure of 15,000 psi � 80-BPM continuous-mix frac fluid rate � 20-BPM continuous-mix acid system � 80-BPM fluid filtration capability

SC-XP™ Extreme Performance Gravel and Frac Packing SystemThe Baker Hughes SC-XP™ extreme performance system provides “on-demand” performance in extreme environments through a single-platform system that is easily converted for frac packs or openhole gravel packs. The system delivers faster conveyance rates and higher production rates than existing sand control systems, while maintaining the capability for simple retrieval.

The SC-XP system’s single-platform system facilitates inventory management and prompt customer attention because of a large variety of sand-face completion applications, such as cased-hole gravel packing, high-performance frac packing, openhole gravel packing, deepwater, horizontal and high pressure/high temperature.

“This system isn’t called an extreme performance system simply because of its ability to treat larger pay zones at once,” says Anderson Amaral, sand control tools product line manager for Baker Hughes. “The SC-XP system can handle extremely high-horsepower jobs that pump high volumes of proppant without damaging the tools or the casing.

“At the same time, the system is flexible enough to allow long horizontal, openhole gravel packing without disturbing the filter cake. It is also compatible with extreme reservoir conditions, handling high-differential pressure operations in high-temperature environments.”

LATEST TECHNOLOGY from Baker Hughes

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The SC-XP system can withstand temperature ratings of 400°F (204°C), treating pressures of 15,000 psi (103.421 MPa) and a proppant volume of 1.5 million lbs at a rate of 60 bpm, while still preserving the casing integrity while opening and enlarging flow paths for the oil through the most challenging formations and reservoirs.

The SC-XP system delivers operational reliability by supporting elevated set-down loads for higher pumping rate treatments and heave compensation. In addition, the system uses an ISO 14310 V0-rated packer that, if needed, can be retrieved without cutting or milling.

BAKER-SQUEEZ™ Lost Circulation SolutionThe BAKER-SQUEEZ™ product, the new and innovative solution tomoderate to severe lost circulation, is proven to be effective and easy to use, even in the most stringent regulatory environments.

“The BAKER-SQUEEZ™ solution is designed for use inenvironmentally sensitive areas such as the Gulf of Mexico and theNorth Sea,” says Gary McGuffey, product line manager for specialtyfluids products. “It has passed all toxicology tests for use in the Gulfand has received a ‘Green’ rating for use in the Norwegian NorthSea—the best rating awarded by Norwegian regulatory agencies.”

Applied as a pill, the product works by rapidly dewatering, resulting in a solid plug of lost circulation material in wellbore fractures and rock defects. (A pill is a small quantity [less than 200 bbl] of a special blend of drilling fluid to accomplish a specific task that the regular drilling fluid cannot perform, such as to plug a thief zone.)

“Since the BAKER-SQUEEZ offering mixes readily with most any basefluid, it eliminates the need to mix pills in anticipation of losses,”

McGuffey explains. “The pill can be made up on the spot andpumped downhole and spotted to cure losses, quickly eliminatingnonproductive time and getting the rig back to the job of drilling.It has been field tested on numerous jobs in the Gulf of Mexico andU.S. Land, proving effective time and time again.

“The plug formed by the BAKER-SQUEEZ treatment developscompressive strength and is effective in sealing all types of fractures,highly permeable formations and vugular spaces,” McGuffey adds.“It can be easily blended using most rig equipment and appliedusing water, oil or synthetic-based fluids. And, it’s temperature stableup to 400°F (204°C) and pH tolerant.”

When blended in any fluid, filtrate expressed from the slurry intothe formation will bond with any clay or gumbo shale to form arigid bridge inside the fracture and fracture tip. A BAKER-SQUEEZtreatment can also be pumped through the drillstring and throughmost downhole tools. Pumped or squeezed ahead of cement, theproduct aids in getting cement to the surface through reducing or eliminating channeling by filling all cracks, microfractures and rock defects.

“Many of the competitive products are two-part systems or they require additives such as thinners or defoamers to perform. The BAKER-SQUEEZ solution only requires the base fluid and the one-sack product to cure losses. Barite is added to achieve the desired weight for the pill,” adds Joseph Szabo, commercial coordinator for Baker Hughes drilling fluids. “Some products also require specialized equipment for mixing and spotting, but BAKER-SQUEEZ treatment requires no special equipment, only what is available on the rig, making it convenient for the rig hands and the product of choice when severe losses occur.”

> The Blue Tarpon, the ninth in the Baker Hughes offshore fleet, is capable of delivering 24,000 hhp through six SC-2000 triplex pumps and four SC-3000 quintuplex pumps.

> The SC-XP system can handle jobs with extremely high horse power pumps, allowing high volumes of proppant to be pumped without damaging tools or casing.


A Look Back

Like so many turn-of-the-century entrepreneurs, Reuben Carlton “R.C.” Baker’s story is one of rags to riches.

Baker arrived in Los Angeles on April 4, 1895, with only 95 cents in his pocket but a head full of dreams of finding his fortune in the newly discovered oil fields of southern California.

Just weeks earlier, the 22-year-old had left his home in northern California bound for Alaska to prospect for gold. To earn train fare, he worked in a quarry and slept in a barn. In just two weeks, he had earned $24, but when he returned to the barn one night after work, his clothes had been stolen. Hearing talk going around about an oil discovery in southern California, Baker decided to take his $24 and strike out for Los Angeles to search for gold—black gold.

Finding work wasn’t hard in those days. Baker took a number of jobs in the oil field, including one as a tool dresser for a contract driller named Irving Carl. When Carl couldn’t pay Baker’s wages, Carl made him his partner.

R.C. BakerIf the (casing) shoe fits… build a business on it

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With the company making a profit, the two men decided to divide their assets, and in 1898, only three years after arriving in the oil patch, Baker was in business for himself doing contract drilling.

In 1899, Baker contracted to drill a well in Coalinga, Calif., a booming oil town north of Los Angeles. Drilling was steady in the newly discovered Kern River oil fields, so Baker decided to settle in Coalinga.

Hard rock layers in the area made setting casing difficult, so Baker developed an offset bit for cable tool drilling that enabled him to drill a hole larger than the casing. He received his first U.S. patent on the invention in 1903. But, it was his second invention—the Baker casing shoe—patented in 1907, that improved the driving of cable tool casing by guiding it into the hole and led to the founding of a small company that would eventually become Baker Oil Tools and Baker Hughes Incorporated.

With no manufacturing facilities of his own, Baker licensed independent machine shops to fabricate the casing shoes on a royalty basis and to market them nationwide. In 1912, Baker patented the Baker cement retainer, which was designed to pack off between the casing and tubing when pumping cement through tubing. The invention made cementing more efficient and effective. The next year, Baker organized his own corporation—the Baker Casing Shoe Company—and in 1918, he bought a machine shop in Coalinga that had two lathes, a drill press, a power saw, a shaper and one pipe-threading machine.

The 3,400-ft2 (315 m2) plant manufactured Baker casing shoes, drilling and fishing tools, and various oilwell machinery and supplies. It was

the first in a long line of Baker manufacturing plants and research centers wherever oil and gas is produced. Baker opened branch offices where there was a demand for oilfield tools, and in 1927, a branch office and warehouse opened in Houston to accommodate sales in fields throughout Texas and Louisiana.

In 1928, Baker Casing Shoe Company was renamed Baker Oil Tools to reflect a growing line of oilfield products, including a complete line of guiding, floating and cementing equipment. Despite troubled economic conditions during the 1930s, Baker Oil Tools continued to grow its business alongside oil companies that had become dependent on “service” companies. But it was after World War II that business boomed and technology advanced.

Between 1948 and 1959, 50 new branch offices opened in 16 states. In addition, the Los Angeles headquarters moved into a new $1.25 million facility in Orange County, Calif., in 1952.

In 1957, at the age of 85, Baker retired as president of Baker Oil Tools. He died a few weeks later after a brief illness. Baker had 150 U.S. patents and laid the groundwork for a company that would eventually move its headquarters to Houston in 1986 and merge with Hughes Tool Company to become Baker Hughes the following year.

It was his second invention—the Baker casing shoe—patented in 1907, that improved the driving of cable tool casing by guiding it into the hole and led to the founding of a small company.

with Hughes Tool Company to become Baker Hughes the following year.

www.bakerhughes.com

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