Connexus 3

CONNE US2011 | Volume 2 | Number 2

The Baker Hughes Magazine

Understanding StressLearning the natureof shale reservoirs is keyto ultimate recovery

A Technical EvolutionFracPoint completionsystem is a result of customerdemand for new technology

Creating New MaterialInnovative chemistryleads to groundbreakingnanostructured material

In this issue of Connexusas well as upcoming issuesyou will find articles on projects with a scope much larger than the traditional oilfield service model. We are living through an inflection point in the market and, increasingly, customers are requiring service companies to provide not only products and services for well construction, completion and production, but also project management, logistics and other activities. This is the world of integrated operations, or IO, as we call it in Baker Hughes.

A growing number of the projects we compete for today are being driven towards an integrated service model that allows our customers to simplify contractual and operating practices while improving efficiencies and mitigating technical and commercial risks. This trend started as national oil companies matured and began working directly with oilfield service companies to provide more holistic solutions, but now integrated operations is embraced by independents and even the worlds largest integrated oil companies.

At the highest level we are focusing on two tracks of integrated operations: multiservice integrated packages, which include project management and turnkey services; and field management projects that encompass reservoir studies, field development plans, procurement, project construction and some production management support. We are establishing centers of excellence where we can build bench strength and grow in a structured, deliberate way along these two tracks in the IO space.

> Martin Craighead

President and chief

operating officer

< Darrell Howard

President,

integrated operations

Integrated operations is the fastest growing segment in our industry. The reopening of the Iraq exploration and production market was an inflection point for this business. Today, a significant amount of the IO activity is centered in the Middle East, but other emerging markets include Russia, Asia, Africa and Latin America. For instance, Mexico is embracing the field management model to redevelop mature fields. Even U.S. unconventional shale projects are moving to a full-service model where oilfield service companies are contracted to manage multiwell developments. Its a global phenomenon across all of our market sectors and a trend that looks set to continue.

With this explosive growth comes challenges for oilfield service companies like Baker Hughes. This can be a high-reward business, but IO business models typically require a longer-term view to return on investment and a wider perspective on the understanding and management of risk. This evolution from a predominantly transactional product and services project scope is changing our perspective on implications for growth over the next few years. It has organizational, portfolio, process and talent implications.

It is important to recognize that not all IO projects are a good fit for us. The service sector cant just look at IO projects through the lens of market sharewe must clearly understand which IO projects give us the best chance to meet our customers objectives, where we believe we can add some critical advantage, and where we can identify suitable profit margins to deliver sustainable value to our shareholders. Projects that foster long-term working

relationships with our customers and that lock in volume for our more traditional businesses are the most attractive.

Many of the portfolio decisions weve made in recent years were driven, in part, by our need to enhance our capabilities to make IO a more convenient business. The acquisition of several expert reservoir companies that today make up the Baker Hughes reservoir development services group was vital to compete for field management IO projects. And the acquisition of BJ Services was important to round out our well construction capabilities. Additionally, our reorganization to a geomarket structure is positioning us extremely well in the IO space. Our business segments and geomarkets are working together to leverage the depth of our product lines to build differential solutions for the IO business. We have the strongest downhole portfolio in the industry and we are organized to take full advantage of our strengths.

The year 2011 has been one of step change for us in terms of business growth for IO and the foundations laid this year promise continued growth into 2012 and beyond. Just a few examples include a recent well construction IO contract award by LUkOIL for the West Qurna field in Iraq. In Mexico, we were awarded a production incentivized contract by Pemex in Mexicos Burgos basin. This award was based on our successful execution of a Chicontepec basin field laboratory project for Pemex. Earlier this year, Petronas awarded us a reservoir study project for a major field redevelopment project for block D-18 offshore Malaysia. Our teams of geoscientists, along with our well construction and production experts,

could be busy for many years on this project, delivering both Petronas and Baker Hughes business drivers.

The exponential growth in the IO market is highlighting a critical shortage in the demand for skills in our sector. There are several important competencies needed for this business including petroleum and drilling engineering skills; wellsite supervisory personnel qualified to drill complex wells; commercialization specialists to understand the commercial requirements of a project to effectively align the risks and rewards; and project coordination and logistics specialists. These are all skills that are in equal demand on the operating side of the business and the industry is starting to recognize the need for more comprehensive recruiting and training programs in this areaparticularly in combination with the high technology side of the services business.

Finally, we have recently recruited a top-tier executive to lead our IO team. Darrell Howard joined Baker Hughes in August from VICO Indonesia, a BP-Eni joint venture. Prior to his appointment with VICO, Darrells long career with BP spanned various global assignments covering all aspects of the technical and commercial side of this business. With Darrells guidance we are building a clear charter to combine the best of operating practices and service technologies together, creating a differential value proposition in this space.

Integrated OperationsBalancing the Risks and RewaRds

| 1www.bakerhughes.com

Anything but ConventionalThe Baker Hughes FracPoint multistage fracturing system is one of the many innovative technological advances developed to support the needs of operators in shale plays. Because its modular system can be optimized according to customer specifications, it is a technical evolution in progress.

Understanding StressA recent Baker Hughes study in West Virginias Huron shale uncovers some surprising answers on how unconventional reservoirs reveal themselves and where operators should best place their wells to be profitable.

Clean and GreenThe Baker Hughes integrated operations group is managing the well construction and data collection operations of a CO2 storage project for the University of Wyomings Carbon Management Institute.

Starting from ScratchAs far as numbers go, OGX Oil & Gas is a small player in Brazil, directly employing fewer than 300 people. However, the company is making a big splash in the offshore exploration arena, and Baker Hughes is helping manage its operations.

Industry InsightOGX Oil & Gas executives Paulo Mendona and Reinaldo Belotti share insight into what sets the private sector company apart from the larger oil and gas companies operating in Brazil.

Thinking LeanNorways niche operators are rethinking integrated operations and relying on companies like Baker Hughes to provide innovative approaches to project management.

Drill PowerThe Baker Hughes AutoTrak rotary steerable drilling system transformed the practice of directional drilling when it was introduced. See whats next.

Contents 2011 | Volume 2 | Number 2

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On the Cover The unusual properties of cylindrical carbon molecules found within multiwalled carbon nanotubes are valuable for nanotechnology and other fields of materials science and technology.

08 One Colossal DiscoveryBaker Hughes materials scientists have discovered a groundbreaking nanostructured material technology that is lightweight, high strength and capable of disintegrating down hole. Baker Hughes has incorporated the technology into its IN-Tallic disintegrating frac balls used with the FracPoint multistage fracturing system.

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Faces of InnovationMeet Soma Chakraborty, a nanotechnology expert at the Baker Hughes Center for Technology Innovation. The girl who loathed chemistry in elementary school went on to synthesize multifunctional organometallic systems at the internationally acclaimed Indian Institute of Technology in Mumbai.

Good NeighborsFor the past 12 years, the Baker Hughes Express cycling team has been a part of the worlds biggest party on wheels, riding more than 150,000 collective miles and raising more than $840,000 to help find a cure for multiple sclerosis.

Latest TechnologyBaker Hughes develops and delivers new technologies to solve customer challenges in the areas of reservoir characterization, coring services and wellbore cleanup.

A Look BackIn 1914, William S. Barnickel developed a chemical process for separating water-in-oil emulsion. His TRETOLITE brand of fluids separation technologies is still an important product offering from Baker Hughes.

is published by Baker Hughes corporate communications. 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 Team kathy Shirley, corporate communications manager Cherlynn C.A. Williams, publications editor Tae kim, graphic artist Tiffany Fernandez, contributor Erica Bundick, contributor Monique Hitchings, contributor

Printed on recycled paper


Point TECHNOLOGy

Unconventional shale plays in the U.S. have been developed at a fever pitch in recent years due to the combination of horizontal drilling and multistage fracturing technologies. This activity has also spawned a frenzy in development of downhole technology to enable operators to produce wells more economically.

When it comes to unconventional shales, there has been an extremely rapid introduction of new products. The best way I can describe it is a technology rat race, says Jose Iguaz, U.S. Land business development manager for Baker Hughes completions. Its like nothing we have ever seen in the past for completion systems, where product life has typically been five, six, or maybe 10 years, and, now, we are seeing products becoming obsolete within two to three years.

The Baker Hughes FracPoint multistage fracturing system is one of the many

innovative technological advances developed to support the needs of operators in the shale plays. The system provides operators a way to economically complete horizontal wells in unconventional formations that require fracturing operations, while accelerating and increasing their net production, eliminating wireline and coiled-tubing operations, and reducing expensive pumping operations.

The FracPoint multistage fracturing system is a modular system that can be optimized according to customer specifications. Everything were doing with FracPoint technology is operator driven, says Jack Farmer, Baker Hughes product line manager of unconventional completions. The whole evolution of FracPoint technology has come about from U.S. customers asking for new developmentsfrom our first frac sleeve system that could do five stages to todays incredibly long laterals with 24 to 30 and up to 40 stages.

A completion system thats anything but conventional

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The FracPoint multistage fracturing system uses Baker Hughes openhole packers and specially designed ball-activated frac sleeves that isolate zones or intervals of a horizontal section and pinpoint fracture placements in the wellbore without cementing.

The system comprises five major components: the wellbore isolation valve; the pressure-activated frac sleeve or P-sleeve; either the FracPoint short-radius hydraulic-set openhole packer or the Baker Hughes REPacker (reactive element packer) system; the ball-activated frac sleeve; and the liner hanger packer incorporating a tieback receptacle. The tieback receptacle gives the operator the ability to tie back the casing to the surface if needed at a later date.

Aaron Burton, product line strategist for FracPoint technology, explains how the system works: Typically, the first stage of this system involves the P-sleeve, which

> The Baker Hughes FracPoint multistage fracturing system uses packers to isolate intervals of the horizontal section with frac sleeves between the packers. The frac sleeves are opened by dropping balls between stages of the fracture treatment program. As the ball reaches the sleeve, it shifts the sleeve openexposing a new section of the lateral and temporarily plugging the bottom of the sleeve. This provides greater control of the fracture treatment and allows for fracture treatments along the full length of the horizontal wellbore.


is opened by simply pressuring up to the predetermined activation pressure. Once the sleeve is opened, the first-stage fracture begins. After completing the first-stage fracture, a fluid flush is pumped, and the ball that corresponds to the second stage is dropped into the flush.

When the ball reaches the seat, pressure is applied to the ball to open the sleeve, and the second-stage fracture is performed. During the fluid flush between the second and third stages, the ball corresponding to the third-stage frac sleeve is dropped, and the process repeats itself until all stages have been completed.

Each time the sleeve is shifted open, a new section of the lateral is exposed and the previously fractured section is temporarily plugged by the ball sealing on the ball seat, Farmer adds. Each of the newly exposed sections is referred to as a stage, and each stage is isolated by openhole packers spaced out on either side of the sleeve. This provides greater control of the fracture treatment and allows fracture treatments along the entire length of the horizontal wellbore, increasing production.

Compared to the plug and perf method, FracPoint technology eliminates perforating and liner cementing operations. It saves time during fracturing operations, due to the fact that the ball-activated system allows a nonstop fracturing operation. Other benefits include reducing fluid usage during fracturing and allowing the well to be put on production immediately, without the need for clean up or milling operations.

Its easy to see that by eliminating multiple operations and speeding up the fracturing process with this one-trip system, operators are realizing considerable cost savings while gaining control of the fracturing process, Iguaz adds. The efficiency gained during the

fracturing process of the wellbore is critical as the total completion cost for a horizontal shale well ranges between 40 and 60 percent of the total well AFE [authorization for expenditures].

Introduced in 2006, the FracPoint openhole fracturing system has been continuously enhanced through various generations,

including the FracPoint EX-C frac sleeve system that earlier this year set a new record for the number of fracturing stages.

Record-setting performanceEven though every shale formation is different, there is a growing consensus in the industry that more stages equal more production; so, our clients are continually requesting increasing numbers of stages per well to shorten the frac spacing interval, improve fracture efficiency and increase their production on a per well basis, Farmer says.

The FracPoint EX-C system extends the high efficiency of ball-activated fracturing stages beyond what is available industrywide, Farmer continues. This was made possible by smaller incremental changes in ball sizes down to 0.875 in. In addition, the EX-C

technology uses patented ball seats that provide additional mechanical support to the ball during pumping operations.

In March, using the FracPoint EX-C system, Baker Hughes installed a record-setting 40-stage openhole completion system in North Americas Williston basin, which is known for extremely long laterals. This was the most stages ever performed in a single lateral frac sleeve/packer completion system.

The FracPoint system is currently used to complete an average of 19 stages per

well in the U.S.

A smarter frac ballWith all its advantages, the one-trip installation system has drawbacks. One is the potential loss in production if the balls and

ball seats hinder production. If the differential pressure between two

of the stages is great enough, the ball could remain sealed on the seat, and the

production from all stages below that ball would be lost, Burton says.

In these situations, removal of the balls and ball seats has conventionally been done by drilling them out of the wellbore before circulating the remains back to the surface, which can be a time-consuming and costly process. Another risk if the balls remain in the well is that they can pile up at a low point because the production rate is not great enough to bring them back to the surface, Burton continues. If this occurs, additional well debris could pile up on top, and a debris barrier would once again hinder production.

Realizing that operators valued the concept of a fully disintegrating ball material to guarantee an open flow path for each fractured zone without having to perform drill-out operations, Baker Hughes has developed a groundbreaking

The FracPoint

multistage fracturing system is one of the many

innovative technological advances developed to

support the needs of operators in the shale plays.

6 |

nanotechnology-enabled material that is being used to produce disintegrating frac balls. (See related article on Page 8.)

This interventionless technology uses a new class of engineered materials that is fully degradable. The high-strength, lightweight nanostructured material is composed of controlled electrolytic metallics technology and has been incorporated into the next-generation FracPoint completion system with IN-Tallic disintegrating frac balls.

The IN-Tallic disintegrating frac balls have been field tested in FracPoint system applications in the Bakken shale, as well as the Anadarko basin. The balls have also proven to be a value-added technology to plug and perf applications in the Northeast and other areas of the U.S., says Paul Madero, Baker Hughes engineering manager, completions, for U.S. Land. In many situations, operators are unable to secure rigs in a timely manner to allow for removal of composite plugs and, therefore, they have opted to produce the wells without removing the plugs. In these situations, the balls trapped between the plugs left in the well have caused restrictions in the wellbore that have resulted in lower initial production rates. By using the IN-Tallic disintegrating frac balls, the balls trapped in the wellbore disintegrate; therefore, eliminating the possibility of restricted production.

The IN-Tallic technology is currently in the commercial stage and is expected to be at full production by the last quarter of 2011.

> Constant technology advances have pushed the number of frac stages higher and higher. The FracPoint system is currently used to complete an average of 19 stages per well in the U.S.


Materials science breakthrough creates nanostructured material of immense proportions

NE Colossal DiscoveryThe future of global energy could greatly depend on economically exploiting shale reserves, estimated to be more than 6,500 trillion cubic feet. Judging by the activity in the U.S. alone, one would think that bringing it all online is as simple as punching a hole in the ground.

Not only is producing oil and gas from shale plays difficult, its expensive, and hydraulic fracturingnecessary to stimulate production from shale reservesis among the most costly expenditures.

Those costs include removal of flow-control devices, like setting balls or plugs that are used for sleeve actuation or stimulation diversion during fracturing. Milling or drilling out these components in order to recover the original size fluid pathway for production is a time-consuming and expensive operation that customers would prefer to avoid.

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Bennett Richard,

research and development director

at the Baker Hughes Center for Technology

Innovation, challenged Dr. Zhiyue (Zach) Xu and the advanced

composites group to do what seemed impossible: develop a lightweight,

high-strength Houdini-like material that must disintegrate down hole.

There was only one problem: the material didnt exist.

Rewriting the science booksOur newly formed team at Baker Hughes knew this was going to be a real challenge. In fact, it seemed as though we were being challenged to rewrite the materials science textbook, says Xu, senior materials scientist and team lead for the Baker Hughes advanced composites group.

All the conventional wisdom pointed to the fact that high-strength materials are

usually nondissolvable or, if they are dissolvable, the rate of dissolution is

so slow that its not suitable for an interventionless downhole tool,

Xu says. The automotive and aerospace industries

were already trying to develop a

high-

strength and corrosion-resistant material to avoid dissolution failure of the material. Basically, the required material defied physical engineering.

With the key material properties identified and with an application goal in mindsetting balls for the Baker Hughes FracPoint multistage fracturing systemXus team set out to develop a material with unique chemical and mechanical properties that did not exist in conventionally available materials.

Traditional materials that easily disintegrate by dissolution with wellbore fluids are usually low in mechanical strength, Xu explains. On the other hand, a material high in mechanical strength does not often corrode fast enough for disposal within the required time. The challenge that we, as materials engineers, faced was to design all three competing properties into a single material structure.

This required innovative chemistry and processes that led to the groundbreaking nanostructured material technology called controlled electrolytic metallics [CEM], which has a combination of high-strength and in-situ disintegration characteristics that, to the best of our knowledge, did not exist in any other known metal composite materials, Richard says.

The first product application of CEM material was the Baker Hughes IN-Tallic technology that was incorporated into the FracPoint multistage fracturing system,

he adds. However, the

mechanical properties of CEM material enable its use in a variety of completions processes while providing a truly high-performance interventionless technology.

Discovering a new pathCEM material is a true composite solution based on the fundamental understanding of materials science and engineering.

Our small team was forced to think outside the box, as there was nothing in existence that could be tweaked, Xu recalls. We resorted to material fundamentals and started putting together material modules. Success came in bits and pieces. Though it was a fundamental science project, we never lost track of the ultimate goal of commercialization. And, after a while, there was an underlying optimism of discovering something that had never existed. There was no looking back after that!

A magnesium-based alloy was chosen for the first-generation CEM material because of its light weight and its high specific strength. The material is also reactive, providing the foundation for a fast corrosion rate. However, because


the magnesium itself is weak in mechanical strength, its corrosion rate cannot be adjusted or controlled; therefore, additional modules were needed.

Its very interesting that magnesium is an ideal material being used in medical research because it has the same density as our bones and because it is a biodegradable material, Xu says. Researchers are trying to develop this material for use in screws that can bind bones

together so, after recovery, the material will dissolve in the bodys own fluids.

There is one problem, however. It corrodes and generates corrosion by-products too fast, and the human body is not able to adapt to it. The corrosion rate needs to be slowed and controlled.

Xus team discovered a similar corrosion-rate control issue while researching the CEM material.

We needed to strengthen the material and control the corrosion rate, and the way we achieved this was through building a system with several different modules, he explains.

One of these modules involved nanostructured material.

Our goal was not necessarily to develop a material with nano inside, but nanostructured material was ideally suited for what we wanted to accomplish, Xu continues. Once we had these system modules, we looked for precision processing techniques that could reliably assemble these modules to produce a homogeneous-looking composite.

The result is the CEM material that exhibits substantially continuous, cellular metallic grains dispersed in the nanomatrix. The nanomatrix has a dual role of providing reinforcements for high strength, as well as having the unique chemical property that conventional materials do not provide. The composition and structure of the nanomatrix can be customized to applications or well conditions.

> Dr. Zhiyue Xu loads a frac ball made from controlled electrolytic metallic material into the scanning electron microscope at the Baker Hughes Center for Technology Innovation in Houston.

The potential for nanotechnology is This is only the start.

HUGE.Dr. Zhiyue Xu Senior materials scientist and team lead for Baker Hughes advanced composites group

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Ions present in typical seawater, completion brines, formation fluids or remediation acids, along with typical downhole temperatures of 120F (49C) or higher, trigger a predictable homogeneous corrosion of CEM composites, explains Gaurav Agrawal, enterprise research director for Baker Hughes. This is accomplished through engineered nanostructures between metallic grains that become the activation points for corrosion and can be triggered on demand. Salt dissolves while CEM material corrodes. This is an important distinction. CEM is a highly engineered material composite.

In 3 percent potassium chloride at 200F (93C), 3-in. balls made from this material can completely degrade in-situ in days.

In the processed state, these nanostructures act as intermetallic adhesion promoters, which yield metal composites that can withstand an impact of 95 bbl/min of fluid flow and 10,000 psi differential pressure, Agrawal says. As a comparison, typical flow rates in hydraulic fracturing are below 15 bbl/min.

Applying the nanocomposite Baker Hughes has incorporated CEM technology into IN-Tallic disintegrating frac balls used with the FracPoint multistage fracturing system. To date, more than 500 IN-Tallic balls have been successfully deployed in completion systems in Bakken shale oil wells.

yet another commercial product incorporating the IN-Tallic material is a temporary barrier in gas-lift mandrels. These plugs

enable the operator to run production tubing with gas-lift valves in place while cementing the production tubing in the same trip without compromising the integrity of the valve with cement. The plugs disappear after the cementing operations, saving the operator the expense of having to fish them out. Several successful applications have been implemented for a major operator in Asia Pacific, resulting in additional orders.

Buoyed by this success of the first-generation CEM material, Xu and his colleagues believe that nanotechnology has huge potential in the energy industry. However, like any other new technology, it has its quirks.

Traditional processing techniques may not be applicable for nanomaterials. They certainly will require additional caution in handling,

Xu adds. To develop new nanotechnology-based products, well have to continue to learn and understand the scientific aspects.

Baker Hughes is hiring additional Ph.D.s to join the composite materials team. Believing that a new materials science textbook is warranted, Xu and his expanded team are being challenged to write a new chapter in the bookthe development of second-generation CEM material targeted to deliver two times the strength of the first-generation material while maintaining the uniqueness of a controlled disintegration rate to extend the application of CEM technology to other interventionless downhole systems.

The potential for nanotechnology is huge, Xu says. This is only the start.

> Time-lapse photography shows the disintegration of an IN-Tallic frac ball made with controlled electrolytic metallic material.


Unconventional reservoirs reveal themselves slowly, and thats a problem for reservoir engineers. To be profitable, operators have to develop their fields quickly, but where should the wells go, and what is the best way to complete them? A recent Baker Hughes study in West Virginias Huron shale has some surprising answers.

Understanding

This is a story about rocks. In particular, its about the type of rocks that trap vast amounts of natural gas in shale and tight gas reservoirs. The message is that if you take the time to learn the nature of the reservoir rock itself, youll have more success extracting the natural gas it contains.

Unconventional gas reservoirs have been discovered throughout much of North and South America, Europe, North Africa, Asia and Australia. Each play has its own unique properties, but they all share a common challenge: the reservoir is almost solid rock. Under typical reservoir conditions, a single gas molecule will move through the matrix of shale between one and 10 ft (0.3 and 3 m) over the life of a well.

To recover natural gas from shale, the reservoir rock must be fracturedtypically with high-pressure fluidsto create paths for the gas molecules to flow toward the wellbore.

All rocks in the earth have discrete, visible fractures, says Dan Moos, a technology fellow at Baker Hughes. Most of these fractures formed millions of years ago. Over time, other materials sealed the cracks, but a little bit of shear slip is enough to break them open again.

The goal of hydraulic fracturing is to force open primary hydraulic fractures in the reservoir rock and to create a surrounding secondary network of fractures that will allow gas molecules to flow toward the fracture and then into the wellbore.

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Its easy to imagine that hydraulic pressure causes an organized network of smaller cracks to grow at right angles from the primary fractures, but Moos and his colleagues suggest that isnt the case. As geoscientists, they realize that new cracks are simply a reopening of the fractures already in the ancient rocks.

Many people in our industry believe that in stimulating a well, they are creating new fractures in a very organized network, Moos says. The implication is that the only thing they need to know is the difference between the two horizontal stresses.

Geologists can estimate the current stress on the reservoir rock, but according to Moos and his associates, thats not

enough to predict where the new fractures will form when you add hydraulic pressure. What you really need to know is the orientation of the ancient fractures, and that orientation shifts over time.

By combining the knowledge of the natural fractures and the stress state of the rock, you should be able to predict the shape of the stimulated zone around the primary hydraulic fracture, Moos explains.

If operators can predict how these stimulated zones will form, then they will know how far apart to place their wells and how far apart the fracture zones should be. Spacing them too close wastes money. If the fracture zones are too far apart, theyre not draining all of the reservoir.

The next thing operators want to know is how to optimize the fracture zones and how to predict how much gas they will yield.

Its very important to predict the ultimate recovery and the drop in recovery over time, Moos adds. Operators need that information as early as possible in the life of the field. The irony is that shale gas wells have to produce for a long time before you can determine how much gas they will ultimately deliver.

The way the wells are run may also have an effect. Field data suggests that if operators allow a well to produce as much gas as possible from Day One, then the ultimate recovery from that well may suffer because rapidly reducing the reservoir pressure

could let the fractured zones close too soon.

From model to the fieldFor several years, Moos and his colleagues worked to build a computer model that could predict where and how fracture zones would form and how much gas a fractured well was likely to produce over time.

While theories and models are fine, at some point, they must be tested in the field. In 2010, a Baker Hughes client agreed to a trial run of the model on data from a producing well it had just drilled in the Huron shale.

We applied our analysis to the clients extensive data set, Moos says. They had collected everything we needed. In a nutshell, our project involved taking our

One thing our study proves is that the earlier you acquire petrophysical and geomechanical knowledge, the more valuable it is. Dan Moos Baker Hughes technology fellow


theoretical understanding and applying it to an actual well using as much data as we could, then making predictions of the early-stage production.

One of the most important things the client had was microseismic data that was collected while the well was being fractured. Most people in the oil business are familiar with seismic surveys, which use recorded sounds from the surface to create 3-D images of rock formations deep inside the earth.

A similar science uses receivers placed inside nearby wells to listen to the earth

while a target well is being fractured. As hydraulic pressure builds, the rock in the stimulated zone will crack and pop like ice cubes dropped in a glass of water. These microseismic events are recorded to form a picture of the fractured zone.

Most people assume that the microseismic cloud shows the area of the reservoir that will produce most of the gas. What Moos and his team learned surprised the operators.

We learned that in this case, there was a very poor correlation between the microseismic cloud and the actual producing

zone, Moos says. We found a much better correlation for the amount of natural fractures that intersected the well within the stimulated zone.

Shale gas operators, of course, already target natural fracture zones. One lesson from the new study is that there may be more efficient and productive ways to design the stimulation.

Another valuable lesson from the study is that it is possible, based on a better understanding of the relationship between natural fractures and those induced by hydraulic fracturing,

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> Graphic shows that stimulated zones tend to initiate and grow along a pre-existing set of joints and that production is better correlated to the joint density than to the number of microseismic events.

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01> JewelSuite software renders a dramatic visualization showing the pressure depletion at different frac stages from the main target well (shown in green). The colored regions indicate the extent of depletion for each stage at a single point in time after production has begun. The dots are the microseismic events (their colors indicate the times at which each occurred, from early in blue to late in red) that were produced by each stage.

02> In 2010, Baker Hughes tested a model of where and how fracture zones would form and how much gas a fractured well might produce over time on data from a producing well in West Virginias Huron shale.

03> Image depicts the four horizontal wells drilled for the study and the cloud of microseismicity that roughly outlines the extent of the near-field region affected by stimulation of the horizontal wells.

to predict the wells ultimate performance early in the process.

With that knowledge, for example, Baker Hughes can run a variety of scenarios for producing the well. Based on those projections, the operator could then make the economic decision to either choke back the production and ultimately recover more gas, or allow the well to run full-bore for a faster return on investment.

Its exciting to see how well the model works, Moos says. It is already generating a lot of interest from our customers. One thing our study proves is that the earlier you acquire petrophysical and geomechanical knowledge, the more valuable it is.

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Baker Hughes leverages its oil and gas expertise for CO2 storage project

For more than a century, Baker Hughes has been finding new and innovative ways to help operators extract oil and gas from hydro-carbon reservoirs. Its now using those same technologies to find a completely different kind of reservoirand one that doesnt contain hydrocarbons.

From the Oil PatCh to theGreenhouse

> Baker Hughes deployed the TruTrak automated directional drilling system to drill through tough layers of shale, sandstone, limestone and dolomite to a total depth of 12,810 ft (3904 m).

As the largest coal-producing state in the U.S., Wyoming provides nearly 40 percent of the nations coal, used primarily to generate electricity. Coal supplies in the U.S. are far more plentiful than either oil or natural gas, and Wyomings easily mined, clean-burning, low-sulfur coal is in high demand. Although coal is a reliable and low-cost energy source, coal-fired power plants produce billions of tons of carbon dioxide (CO2)a greenhouse gaseach year.

The University of Wyomings Carbon Management Institute (CMI) promotes research and development of advanced carbon capture and storage technologies. CMIs efforts are critical to the success of sustaining Wyomings energy economy and instrumental in reducing greenhouse gas emissions worldwide. In

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Greenhouse

> The University of Wyomings Carbon Management Institute chose the Rock Springs Uplift as the drilling site because of its specific geology and proximity to Pacific Corp.s Jim Bridger coal-fired power plant.

2009, CMI launched a study to identify Wyomings most promising potential carbon sequestration site, and it chose the Baker Hughes integrated operations group to manage the well construction and data collection portion of the project.

Planning and engineering for the drilling phase of CMIs Wyoming Carbon Underground Storage Project (Wy-CUSP) began in 2009 with detailed discussions between CMI, the University of Wyoming and Baker Hughes integrated operations staff, explains Paul Williams, director for CO2 storage projects for Baker Hughes. Along with project management, Baker Hughes has provided a full range of integrated services including site preparation; supply chain management; drilling equipment and all formation evaluation services, including coring and wireline; drilling fluids and cementing.

A promising storage solutionWhile CO2 has been injected into geological formations before, deliberately using formations for long-term storage is a relatively new concept, Williams says.

Geological sequestration, or the long-term, below-ground storage of CO2, can take place in deep saline aquifers, depleted oil and gas reservoirs, and unmineable coal seams. Of these, deep saline aquifers are considered the most promising and have by far the largest storage volume, he notes. The ideal site for CO2 sequestration would provide large storage capacity, a caprock capable of preventing leakage and escape, injectivity at commercial scale, minimal seismic activity, and the absence of other valuable natural resources such as gas or oil.

Preliminary regional data and computer modeling by the University of Wyoming suggested that the Rock Springs Uplift,

> Shanna Dahl, CMI deputy director, and Sam Zettle, former director of North America integrated operations for Baker Hughes, discuss the progress of drilling operations.

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which was chosen for its specific geology and proximity to Pacific Corp.s Jim Bridger coal-fired power plant, could store up to 26 billion tons of liquefied CO2.

Two specific rock formations in the Rock Springs Uplift, the Weber sandstone and the lower Madison limestone, met storage criteria. Both formations lie well below the regions underground drinking water sources (the deepest of which is 1,700 ft [518 m] below ground), and both contain highly mineralized salt water currently unsuitable for drinking, agricultural or industrial use.

To accurately characterize the two formations, CMI needed to augment its preliminary data and computer modeling with geologic logs, core and fluid samples, and actual geophysical data.

Baker Hughes supplied its well construction expertise to design and cost a 13,000-ft (3962 m) characterization well, Williams explains.The well engineering design details, together with the other project objectives, were submitted to the U.S. Department of Energy, which funded the well construction project. The wider three-year, $16.9-million project is being funded by the Department of Energy and the state of Wyoming.

Drilling began in April 2011 with a small air rig, which was used to drill the first 2,000 ft (610 m) of the well. After surface casing was cemented in place, a larger conventional rig was sourced in June to drill the deeper sections of the well.

For the deeper drilling phase, Baker Hughes provided polycrystalline diamond compact bits and the TruTrak automated directional drilling system to drill through tough layers of shale, sandstone, limestone and dolomite. Multiple coring trips were made at

predetermined intervals, with 916 ft (280 m) of whole core cut with a 98 percent recovery rate. The wells total depth of 12,810 ft (3904 m) was reached in August.

Determining the next stepsReservoir characterization integrates all available engineering and geological data into a model that simulates the behavior of the reservoir under a variety of circumstances. In this case, 3-D seismic data, logs, cores and geophysical surveys were needed to provide porosity, permeability and resistivity information for a 25-sq-mile [65-sq-km] area of the Rock Springs Uplift, as well as data regarding the long-term integrity of the caprock, says Sam Zettle, former director of North America integrated operations for Baker Hughes.

To gather the needed information, Baker Hughes ran a large number of wireline formation tests. (Please see related story on Page 20.)

If Phase One goes well and the data we provide shows that CO2 can be safely contained in one or both of the formations, we will have a much better idea of the Rock Springs Uplifts suitability for CO2 storage. A potential second phase could involve injecting liquid CO2 into a small area of the formation[s] and monitoring it using 3-D seismic to confirm the integrity of the storage site, Williams says.

Phase Two, if implemented, could last for several years and include the design of a commercial-scale CO2 injection operation as well as a displaced fluid management plan. As the CO2 is injected into the aquifer, it will, at some point, displace the brine, Williams explains. Another part of the project involves looking at the feasibility of treating the produced brine to put it to beneficial use back on the surface. It could

be treated for industrial, agricultural or possibly residential use if the economics prove out.

This has been a very good collaborative working relationship with the University of Wyoming, Zettle adds. Our focus from the beginning has been to work closely with CMI in order to provide the information needed to substantiate the longer term objectives for the project. Baker Hughes provided a fully integrated and multidisciplined program that included reservoir and geomechanics evaluation through to the successful drilling and testing of the well. This has been a model project, making use of Baker Hughes expertise, wellsite execution and technology. We look forward to furthering our relationship with both CMI and the University of Wyoming.

CMI Deputy Director Shanna Dahl says, This project has been an exciting and rewarding joint venture. Baker Hughes has been great to work with, and thanks to the data collected by the companys team, the Rock Springs Uplift will be one of the best characterized potential CO2 storage sites in the country. We at CMI look forward to working with Baker Hughes on any potential subsequent phases of Wy-CUSP.

> Paul Williams, director of CO2 storage projects for Baker Hughes


Capturing the right dataStoring CO2 in geological formations must be done in a safe and sustainable way, which requires a systematic approach to the selection, characterization and qualification of proposed sites. This ensures that potential sites are well-suited for the long-term sequestration of CO2 before an ounce is injected.

A vital component of site qualification is data acquisition, which tests whether a formation has all of the elements required for the safe and permanent storage of the greenhouse gas, including:

Physical capacity, or the available volume within a formation (porosity and thickness)

Injectivity, or the ease with which CO2 can be injected (permeability)

An adequate caprock (seal) to prevent CO2 leakage A stable geological environment (minimal seismic activity, faulting or fracturing)

Minimal presence of other natural resources of value (hydrocarbons, natural gas storage, groundwater or geothermal energy).

While working with the University of Wyomings Carbon Management Institute, Baker Hughes collected and evaluated geological and environmental data from a variety of sources to augment preliminary regional data and computer modeling by the university. All of this data is being used to assess whether the Rock Springs Uplift is a suitable site for CO2 storage. Much of the data was acquired while drilling a 13,000-ft (3962 m) characterization well. During the drilling process, Baker Hughes ran a number of wireline services to evaluate the formation and determine whether it meets the requirements above. They included the following services:

XMAC F1: Locates and maps formation features such as fractures and bedding planes more than 50 ft (15 m) away from the wellbore.

High-Definition Induction Log: Provides formation resistivities and water saturation at multiple depths to provide a detailed analysis of formation resistivity.

Compensated Z-Densilog: Provides formation bulk density and photoelectric absorption index data, which are useful in the evaluation of complex formations to determine lithology and porosity.

Compensated Neutron (CN): Identifies porous formations and provides data for porosity analysis.

FOCUS Compensated Z-Densilog: Gathers density porosity data in a wider range of borehole conditions, even at high logging speeds.

FOCUS Gamma Ray: Measures the natural radioactivity of the formation being surveyed to identify the type of rock along the wellbore.

EARTH Imager: Acquires simultaneous high-resolution resistivity and acoustic borehole image data.

Circumferential Borehole Imaging Log: Provides 360 high-resolution borehole images in difficult wellbore conditions, including highly porous, unconsolidated formations.

Zero-offset Vertical Seismic Profile: Integrates with surface seismic data to identify and describe reservoir compartments not visible with surface seismic alone.

Reservoir Characterization Instrument: Obtains precise formation pressures and high-quality fluid samples to determine reservoir volume.

WellLink LiveWire: Securely connects the rigsite to any location in the world, enabling immediate geoscience interpretation of wireline data to assist critical decision making.

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When Brazilian entrepreneur Eike F. Batista launched his own oil and gas exploration company in June 2007, some thought that the billionaires Midas touch might finally be waning. Batista, founder of the industrial group EBX, has a proven track record in developing new ventures in the natural resources and infrastructure sectors.

Starting from ScratchIO project a first in Brazil for Baker Hughes, a necessity for OGX


When Mr. Batista started OGX, people said he was dreaming. Then, when we launched our IPO [initial public offering], they asked how could we raise $4.1 billion without having a drop of oil and with no rig to drill, says Reinaldo Belotti, production director, OGX Oil & Gas. We were seen as crazy people and that it would be impossible to rent a rig, get a seismic crew, and so on. However, we got eight rigs. We have a short history, but we have a great future.

By employee numbers, OGX is a small player in Brazil, employing fewer than 300 people directly. However, the company is making a big splash in the offshore exploration arena. By focusing on shallow-water exploration concessions in Brazils prolific Campos basinwhere more than 85 percent of the countrys crude is producedOGX has enjoyed a stunning amount of success in only four years.

OGX is a new company with few employees. We are not in business to compete with the national oil company, but we do intend to have a presence here in Brazil, says Jsus Pereira, drilling manager for OGX. Most of the oil companies that have come to Brazil have drilled one or two, or maybe three wells

a year. In the first two years OGX drilled more than 30 wells. It is for this reason we have to have knowledgeable people working with us.

OGX has more than 6,000 people partnering with the company to provide products and services, and to manage all aspects of the projects included in its ambitious business plan which, by 2019, calls for 19 floating, storage, production and offloading (FPSO) vessels, 24 wellhead platforms and five tension-leg wellhead platforms.

With a diversified portfolio of high-potential exploration blocks in the Campos, Santos, Esprito Santo, Pra-Maranho and Parnaiba basins, OGX is effecting the largest private-sector exploratory campaign in Brazil.

Concessions in these five basins cover an offshore area of approximately 7000 km2 (2,702 sq miles), as well as an onshore area of 24 500 km2 (9,459 sq miles). Additionally, OGX has five onshore exploratory blocks in Colombia that cover approximately 12 500 km2 (4,826 sq miles) in the Cesar-Ranchera, Lower Magdalena Valley and Middle Magdalena Valley basins.

01> Baker Hughes Technician Saulo Nespoli tests electrical systems on a SoundTrakTM acoustic logging-while-drilling tool that has come into the Maca drilling operations base for maintenance. With 1.2 miles (2 km) of wiring, the 9-in. SoundTrak tool is 32 ft (9.8 m) long and weighs 6,800 lbs. (3084 kg), making it the largest formation evaluation tool in the Baker Hughes fleet.

02> Vinny Hibner (seated) and Rafael Pereira monitor actions on the Pride Venezuela drilling rig at the Baker Hughes BEACON remote operations center in Rio de Janeiro.

03> Higor de Oliveira Silva Araujo and Cintia G. Emerick perform routine maintenance on a Reservoir Characterization InstrumentTM service tool at the Maca wireline base.

04> Brazils IO team includes (from left) Alessandro Oliveira, drilling engineer; Christian Resende, logistics manager; Marcello Marangon, project manager; Carlos Gonzalez, drilling engineer; and Alana Dos Santos, logistics coordinator. Not pictured are Drilling Manager Miguel Mollinedo and Logistics Coordinator Manoel Marfrini, who works in So Lus in the state of Maranho.

01 02 03

Putting together a teamWhen Marcello Marangon, project manager for the Baker Hughes integrated operations (IO) team in Brazil, needs to discuss a change in the drilling program on an appraisal well in the Campos basin with the operators drilling manager, he doesnt have far to go.

Marangon, along with five members of the IO team and the 24/7 real-time drilling optimization team who are helping manage Baker Hughes first IO project in Brazil, office at the operators headquarters in Rio de Janeiro. Several team members, as well as Clarissa Thomson, Baker Hughes account manager for OGX, and other Baker Hughes employees who office across town often sit in on daily operations meetings with OGXs geosciences and drilling teams.

Together, they make decisions affecting the operations of the drilling rig that Baker Hughes manages with OGX.

Our goal with any of our customers is getting them to feel that we are

an extension of their team, says Mauricio Figueiredo, vice president of the Brazil geomarket for Baker Hughes. Reaching a high level of integration and building a strong relationship depends on how we react to our customers requests and their needs.

Baker Hughes is one of two service companies assisting OGX in managing its rigs. We are managing the Pride Venezuela rig, which has drilled four wells within the exploratory/appraisal campaign in the Campos basin about 80 km [50 miles] offshore Brazil, Thomson says.

Under the IO contract, Baker Hughes provides drilling services with directional drilling, formation evaluation and surface logging; formation evaluation and cased hole wireline services, and drill bits, as well as project management for well engineering, operations support and logistics on the appraisal well drilling program. In addition, Baker Hughes provides 24/7 real-time operations monitoring from its BEACONTM remote operations center in Rio de Janeiro.

We are a new company, and we dont have many employees, but OGX has a lot of experienced people managing the business, Pereira says. What we dont have are specialists in all the areas it takes to produce oil and gas. Thats where a company like Baker Hughes comes in. It can provide specialists who can direct us in directional drilling, hydraulic fracturing programs, fluids, bits, loggingeverything we need to drill and produce these basins. This is the importance of Baker Hughes to OGX.

Delivering the right technologiesBaker 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. The company has been a major drill bit supplier to the Brazilian oil industry ever since. Today, Baker Hughes is also a leader in directional drilling technology in Brazil, and its artificial lift product line holds the leading market share in electrical submersible pumping (ESP) systems.

Because of its commitment to investors, OGX is on a fast track to produce oil and

04


is keen on employing new technology, Thomson says. As a streamlined organization, decisions on investing in technology can be made almost on the fly. That gives OGX the flexibility to be open to proposals on new technology and, if the company decides to use it, it can be deployed at the next opportunity, she adds.

Baker Hughes has introduced several of its drilling services technologies to OGX, including the AutoTrak rotary steerable drilling system; the SoundTrak acoustic logging-while-drilling (LWD) service; the CoPilot real-time drilling optimization service; the MagTrak LWD magnetic resonance service; and the LithoTrak service, which offers measurement of formation density, neutron porosity, borehole caliper and formation imaging.

In a three-year contract, separate from the IO contract, Baker Hughes is providing all artificial lift services needed by OGX, including those for the 9-OGX-26HP RJS well due to produce first oil for the company by the fourth quarter of 2011. The extended well test contract includes the provision of downhole ESP equipment for the subsea wells. Baker Hughes will also staff a DNV-certified ESP control room on the OSX-1 FPSO, consisting of variable speed drives, transformers and monitoring systems. The combination monitoring and

control system is designed to ensure extended run life for ESP systems.

Right now, OGX is in the planning and development phase for the Waimea and Waikiki fields, says Leandro Neves, completion and production sales manager for Baker Hughes in Brazil. Baker Hughes is focused on supporting OGX in whatever it needs to plan and execute this new phase. Engineers are being moved to OGXs office to support the company on the ESP specifications.

The ESP systems are designed to increase oil production and to provide more flexibility in understanding the reservoir behavior based on the ESP systems capability to produce different flow rates by changing the speed of the downhole motor through frequency adjustments in the variable speed drive located on the surface. In addition, the ESP systems gauges supply real-time downhole temperature, pressure and discharge pump pressure measurements; important in monitoring the reservoir during that are production.

Adding value by sharing objectivesProject management calls for having a broader picture in mind, Marangon says. Baker Hughes is now looking beyond its role as a provider of well construction services and solutions and looking at

the well-delivery process. We are now sharing the objectives of the customer. We worry about aspects that we were not involved in before, Marangon explains. When youre trying to optimize the [USD] half-a-million dollar daily operational costs, you start weighing the difference between spending money on an extra transport to the rig versus taking the risk of incurring rig downtime.

you have to prove that youre adding value to their operations technically and commercially, so you are well motivated to deliver and, in the end, achieve joint objectives.

Baker Hughes is known for its technology, its research and development, the quality of its services and the quality of its people, Thomson adds. All this is known, but the fact that we can sit down and work side by side with a customer and do what they do and take over part of their burden closes the gap between the two entities.

Baker Hughes has experience working in many fields around the world. We can bring a different approach to a customers problems and offer different solutions to all of them. This is what I think we do the best, and this is a true advantage of using Baker Hughes to do the procedures and project management and the integrated operations.

> Clarissa Thomson, Baker Hughes account manager for OGX, and Jsus Pereira, drilling manager for OGX

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By the numbers In June 2008, OGX went public, raising USD 4.1 billion which, at the time, was the largest amount ever raised in a Brazilian primary IPO.

OGX has approximately USD 5.45 billion in cash to fund its E&P investments and new opportunities.

OGX currently has approximately 10.8 billion bbls of prospective resources in its portfolio.

OGX expects to achieve 150,000 BOPD of production from the Campos basin in 2013 in two production complexes from 10 horizontal wells producing an average of 15,000 BOPD each.

Also in 2013, OGX expects to have three FPSOs and two wellhead platforms in place to handle production from these 10 wells. In addition to these three FPSOs, OSX has acquired two very large

crude oil carriers that will be converted into FPSOs. It is anticipated that both vessels will have approximately 1.3 million bbl of storage capacity and approximately 100,000 B/D of installed oil processing capacity. This equipment

will be leased to OGX, with delivery expected in 2014.

In the Campos basin, production will begin from the first project (Waimea complex) in the fourth quarter of 2011, with anticipated production of up to 20,000 BOPD from the OGX-26 well. The second project (Waikiki complex) production is expected to begin in the fourth quarter of 2013.

* Statistics compiled from the OGX website and business plan


with Paulo Mendona, general executive officer and exploration director

and Reinaldo Belotti, production director, OGX Oil & Gas

Part of the EBX group of companies, OGX is responsible for the largest private-sector exploratory campaign under way in Brazil. OGXs portfolio consists of 29 exploratory blocks in the Campos, Santos, Esprito Santo, Par-Maranho and Parnaba basins in Brazil, and five exploratory blocks in Colombias Middle Magdalena Valley, Lower Magdalena Valley and Cesar-Ranchera basins.

Q&a

Industry Insight

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OGX is a relatively new player in the energy industry. What was the philosophy behind establishing an oil and gas company to compete in an arena as large as Brazil where the national oil company is so dominant?

Belotti: OGX was founded in 2007 by Brazilian entrepreneur Eike Batista. From the beginning, our philosophy has been to be a small company with the best people having the most knowledge, with the best partners to build relationships with, and with the courage to face the risks. That is our model.

I think that because Petrobras has long dominated the industry here, many companies were scared to come to Brazil. This is a big arena. To give you an example, only 5 percent of Brazils sedimentary basin concessions are in the hands of different companiesonly 5 percent. It is still relatively unexplored. Mr. Batista saw this and started his own company with people who know very well the logistics of this country.

Mendona: When you look at the northern part of Brazil, you can correlate it with West Africa countries like Liberia, Ghana and the Ivory Coast. We see that in our northern coast we do not have any commercial discoveries up to now. We are sure that the country is under explored. A lot

of things have to be done, and OGX is here for this. We are not competing. We dont want to compete with Petrobras. This is not our message. We want to do our bestour joband get our own roots.

What sets OGX apart from the larger oil and gas companies operating in Brazil?

Belotti: We have said that we have the assets of the NOCs and the management of the IOCs. Here, we are doing the same things they are all doing but easier and faster. We can decide very quickly everything that needs to be done, including negotiating and signing contracts, such as the one we have with Baker Hughes for integrated operations. We dont have the legal constraints of the state-owned company. We know Brazil, its rules and logistics, and we have a team of geologists that knows more about Brazil than any other team in the world.

Mendona: The investment in the right personnel is very important. We have 274 direct employees and more than 6,000 people working with us. Our golden asset is the quality of all of our people. We have good people in exploration, drilling, production and reservoir.

When we went out to the blocks in the south Campos, everybody said, They are fools. They are not able to discover a drop of oil, and we discovered a province of oil. And all because of the quality of our people.

you know this expression, philosophers stone? That describes our exploratory people.

I understand that to discover oil it takes 70 percent knowledge and 30 percent technology. The technology everybody can access in the market, but the knowledge is in your mind. This belongs to you.

Along with all of this, we have Mr. Batista who has the capacity to look at something and to discover a new opportunity. That is a big advantage.

Lacking the infrastructure and human resources of the larger NOCs and IOCs, what do you consider as key elements to the companys success?

Mendona: We are walking by our own legs. What does this mean? It means we are able to build the elements that we need for all of our programsinfrastructure, pipelines, roads, ports.

We discovered a new gas province in Santos. Now, how

can we use this gas? Are we going to depend on another companys pipeline? No. We will build our own pipeline and go on for ourselves. Then a lot of other companies will provide the gas to you because they need the pipeline, and they only have the state-run company to negotiate with. So, because of this, we have another opportunity. In Brazil, there are a lot of oil and gas companies who will be able to sell us their products, mainly gas.

Some basins are oil-prone like Campos, and some, like Santos and Parnaiba, are gas and condensate prone. In the Parnaiba basin, which covers an area of 21 000 sq km [8,108 sq miles], we also have three gas discoveries. We already declared two of them commercial to the National Petroleum Agency [ANP] and we are, of course, preparing to develop all of these discoveries. In addition to this, we intend to continue discovering more gas and possibly light oil. This is what we plan.

With some of the greatest minds in the energy industry on this team, what else do you need for this company to be successful?

Mendona: To grow the company, we must increase our portfolio and have more


areas to explore. Our intention is to discover any drop of oil that is in all of the blocks we have, but five years from now, this will finish. Then we need more areas. It will be very difficult for us to develop more fields if the ANP does not offer more blocks.

Of course, if we dont get blocks in Brazil, we will go outside of Brazil. Our first step toward reducing the dependency on legislation was to go to Colombia where weve got five blocksvery nice blocks. Everybody knows the Maracaibo basin, but nobody knows the Cesar-Rancheria basin. Our Cesar-Rancheria basin is the continuation of Maracaibo in Colombian territory. We got almost all this basin in the last round.

OGX is moving from discovery to development in less than 24 months. How were you able to fast track this project?

Belotti: Everybody has access to the same technology in the market, so the quality of your team is what makes the difference. We put together a very good exploration team. We have, until now, a 100 percent success rate in the Campos basin. It means we have discovered a lot of oil. Its time to appraise and develop this discovery and generate revenue to make some cash. We are now starting the development phase and intend to produce our first oil in the next few months.

We intend to start production in the fourth quarter of 2011, but it depends specifically on the environmental license. That is

the last hurdle that we have, because the well is complete. Everything that we need is in place. The FPSO left the shipyard in Singapore in mid-August. The last big question is the environmental license. Then we will start to put on line our first production.

Baker Hughes is project managing one well for OGX in the Campos basin. How do you perceive Baker Hughes adding value to your company?

Mendona: Technology, people, prices, its all very important, but technology and well-trained people for me is the big issue in Brazil. We have projects. We have money, but what we need is good people, and Baker Hughes is doing a very nice job

and trying all the time to help us meet our objective to keep improving our performance.

Belotti: When we started to develop this company, we decided to have only one service company supplier, and it was not Baker Hughes. One reason was because Baker Hughes at that time was one of the biggest contractors for Petrobras. Later, we decided to start with a second service company so we could balance and compare the performance of the two, and we chose Baker Hughes.

We have known Mauricio [Figueiredo] for 30 years or more. We understand that the key to the success of Baker Hughes in Brazil is to have the same person in charge for a long time. The people trust him in Baker Hughes for decisions. So, for this reason, we decided on Baker Hughes as the second company to work for us.

PAULO MENDONA received a bachelors degree in geology from the University of So Paulo. Before joining OGX in July 2007, Mendonas career spanned 35 years with Petrobras, where he held several leadership positions, including general manager of the Petrobras E&P Sergipe-Alagoas business unit, general manager of the Petrobras E&P business unit in Colombia, and exploration manager for the Americas and the Middle East. In 2002, Mendona became general manager and later executive manager of Petrobras exploration division and remained in this position until July 2007 when he joined OGX.

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The Macondo accident has established a new baseline for oilfield operations. How does this affect OGX safety-wise?

Belotti: Macondo affected the entire world and, because of it, the regulations are stronger now. In our company, it is our intent to have the best safety possible, and in order to have that, each person knows very well what is expected from them. We have some of the best drilling engineers in this country. A lot of people have more than 30 years of experience in the best school that we have here, which is Petrobras. All of these people worked there for a long time, on the rigs, managing the rigs, etc. and now they are here working with us. They know as much about safety as anyone does.

OGX expects to be the largest private sector oil producer in Brazil by 2015. How do you plan to reach this goal?

Mendona: We have already discovered the oil. So now, its just executing the development and getting all the equipment we need such as FPSOs, wellhead platforms, completion systems.

Production will begin in the first Campos basin project in the fourth quarter of 2011, and production is expected to begin from the second project in the fourth quarter of 2013. Also in 2013, we expect to have three FPSOs [OSX-1, OSX-2 and OSX-3] and two wellhead platforms in place with a total of 10 horizontal production wells on-stream in these two projects.

Belotti: The OSX-4 and OSX-5 will be built by OSX, the EBX Group ship building company created in order to comply with the local content rule, a very important tool that the government has.

To meet this local content rule, we have to have 65 percent of local content. It will be the largest shipyard in Brazil and should be finished in 2013.

The shipyard will be a big player in this market. They can build wellhead platforms, rigs, FPSOs for all the oil companies working here in Brazil and in Africa. They have a partnership with South koreas Hyundai Heavy Industries Co. for 10 percent of the investment in the shipyard. All the technology will be transferred from Hyundai to OSX in a very aggressive plan to get the same productivity that the korean people have.

Aggressive is a word often associated with OGX. Why is this?

Mendona: Mr. Batista has the capacity to look at something and to discover a new opportunity, and Brazil is a big opportunity for oil. Even with the knowledge that our group possesses, it is very, very important to note the presence of the companys founder. Some people think that it is easy to start an E&P company in a country like Brazil, but it is not easy. you must have the right team. you must have cash. you must have people with courage to take the big risks that are represented by exploration and production. And you must be aggressive.

REINALDO BELOTTI received a bachelors degree in electric engineering from Federal University of Esprito Santo. He worked with Petrobras for 32 years, serving as logistic superintendent and production manager of Campos basin, CEO of Petrobras America Inc.s business unit in Houston, general manager of Petrobras E&Ps Bahia unit, executive manager of Petrobras E&P Services and director of service stations for Petrobras Distribuidora.

> After its conversion in Singapore, the FPSO OSX-1, the first floating production, storage and offloading vessel in OSXs fleet, set sail for Brazil in mid-August.


thiNkiNg

A new integrated operations perspective in Norway

LEAN

Well known for embracing new technology and for being at the forefront of applying new approaches to the oil industry, Norway has had a surprisingly conservative approach to integrated operations until recently.

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Dominated by only a few operators until the late 1990s, the landscape has changed rapidly in the past decade from a mere handful of companies that were licensed to operate offshore Norway to almost 40 today. Coupled with the fact that discoveries have tended to be smaller, this has led to a rich diversification in the Norwegian oil industry. Some niche players, without the resources needed to fully develop discoveries,

are finding and selling discoveries, while others are looking to develop new fields and add value organically by discovering to produce as opposed to buying reserves.

The major operators are still here and flourishing, says Barry Jones, sales director for Baker Hughes in Norway, but, they are now joined in the hunt for hydrocarbon resources by mid-sized players and small

specialized explorers all seeking to make their mark. While the majors have large professional staffs with every capability imaginable, smaller operators need to execute projects with lean, flexible organizations.

Rig-sharing agreementsA prime example of this need to think lean has been the introduction of rig-sharing agreements.

The high investment required to meet Norwegian regulations has made rig owners reluctant to enter into short-term contracts that historically left operators who had only a few wells to drill with limited and expensive options, Jones explains.

In 2006, AGR Petroleum Services came to market with an innovative approach. AGR facilitated the accumulation of three years of rig time for

> Downsizing on Statoils Oseberg East was the foremost driver for Baker Hughes to implement 24/7 technical support to the platform.

Rig-share agreements allowed Det norske the flexibility to drill several wells at a stage in our growth as a company where we could not commit to hiring a rig on a long-term exclusive basis. Det norske now has rigs on our own multiwell contracts, but we continue to utilize rig sharing where it fits our business needs. Stig Are Nilssen, senior drilling engineer, Det norske


a semisubmersible, acting as the drilling department for seven operators who had minimal resources in Norway. The planning, permitting and operations were all conducted by a continuous AGR team. All service contracts were established by AGR, which assigned them to operators on a well-to-well basis. Rig slot times were shared between operators based on the expected duration of the exploration wells to be drilled.

Jones explains: The rig was contracted by a set of operators for 1,095 days. Each operator committed upfront to a portion of these days based on planned requirements of their drilling program. AGR facilitated the process while all economical risk and commitment rested with the operators based on rig schedule, which was established jointly.

The rig constantly moved from location to location, rarely drilling back-to-back slots, so they had time to plan and catch their breath between wells.

A similar approach was taken by a group of operators who formed a consortium in 2009, contracting the semisubmersible Songa Delta for three years. Wintershall and Det norske, two companies with positive experiences from the Bredford Dolphin rig-sharing project, were the prime movers in the consortium, Jones adds.

Stig Are Nilssen, senior drilling engineer at Det norske, states: Rig-share agreements allowed Det norske the flexibility to drill several wells at a stage in our growth as a company where we could not commit to hiring a

Well Name Ops (hrs) NPT (hrs) NPT %

Grosbeak 1120 37 3.30%

Fongen 1068 10.5 0.98%

Trolla 678 9 1.33%

Beta Brent 1734 39.5 2.28%

Frusalen 791 6.5 0.82%

Draupne 1982 96.5 4.87%

Maria 1844 56.8 3.08%

Stirby 3559 52 1.46%

Gnatcatcher 1049 2 0.19%

Ronaldo 902 2 0.22%

Grosbeak Ap* 1170 9.5 0.81%

Total 15897 321.3 2.02%

* well test

rig on a long-term exclusive basis. As we have grown in size and capability, Det norske now has rigs on our own multiwell contracts, but we continue to utilize rig sharing where it fits our business needs.

As part of its approach, the Songa Delta consortium decided to contract all key drilling and well placement services with a single supplierBaker Hughesan interesting arrangement in Norway where single-service agreements were the standard.

Baker Hughes was chosen as the key contractor and has supplied directional drilling, measurement-while-drilling, logging-while-drilling, wireline, drilling fluids, coring, drill bits, mud logging, cement, liner hangers and coring since Day One, Jones says. Coinciding with the advent of a reorganized Baker Hughes, the project allowed us to demonstrate our strength in depth, with

all service lines under the guidance of one Baker Hughes project manager.

One of the highlights of this ongoing project has been the efficiency and performance of Baker Hughes. As indicated in the table above, reliability and performance has been excellent, with nonproductive time at 2 percentfar below industry norms.

24/7 total service approachStatoils Oseberg East project is another prime example of just how different one integrated operations project in Norway can be from the next.

Despite a very small platform structure, the Oseberg East field (located 25 km [15.5 miles] from the Oseberg field center where oil and gas is processed) had operated with a full drilling crew of 53 drilling contractor and service personnel during the development phase, thanks to the presence of a flotel (living quarters on top of the platform).

> Barry Jones and Elin Vargervik, business development personnel in Norway, see the countrys traditional business model changing.

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Later in the field development phase, the flotel was no longer on contract, leaving the operator with the challenge of how to drill and complete wells with only 36 bed spaces when a crew of 53 was still required.

The Baker Hughes Norway team surprised the operator with a total service approach, says Elin Vargervik, executive account manager for Baker Hughes Norway.

Baker Hughes proposed a novel approach that included cross training of drilling crew personnelcementers with drilling fluids engineers, directional drillers with completions engineers, etc.and a host of remotely supported functions from its BEACON remote operations center in Stavanger, Vargervik explains.

As an example of the complexity of this project, a team of Baker Hughes technical staff spent several months analyzing workflows and tasks, identifying more than 700 key processes and process owners, and ultimately mapping each task in a

responsibility assignment matrix. Following 25,000 hours of training, which included Baker Hughes, Statoil, the drilling contractor and other service provider personnel, this innovative project is ongoing and is currently drilling the third in a planned program of seven wells.

Unlike in other single-service projects, it is now the responsibility of Baker Hughes to ensure there are smooth and seamless transitions among services, such as drilling, completions and cementing, and that systems and technology are compatible.

This calls for tight project management, a transparent working methodology, a low degree of protectionism and a high level of involvement with regards to personnel, use of collaborative environments, and software and technology, Vargervik says.

Plans are to increase oil recovery by some 39 million barrels, with Baker Hughes integrated operations an integral part of this value chain.

The down-manning on Oseberg East was the foremost driver for implementation of a 24/7 technical support function in Norway, Vargervik adds. The new approach is that whatever needs to be done on the rigsite will be done on the rigsite, but what can be done from onshore operations centers, workshops and collaborative environments will be handled from there.

Looking forwardFrom the recent Statoil FastTrack projects awarding all services and a degree of project management to one provider, to the startup in June 2011 of the Borgland Dolphin consortium project (where Baker Hughes is again providing the majority of services on approximately 15 wells to a group of operators), there is no doubt that the innovative approach to drilling and completing wells in Norway will continue to develop new ways to secure energy supplieswith Baker Hughes right at the forefront, Jones concludes.

> Baker Hughes is providing a 24/7 total service approach to Statoil at its Oseberg East platform that includes cross training of personnel and a host of remotely supported functions from its BEACON remote operations center in Stavanger.


As the largest gas discovery on the Norwegian continental shelf, the Troll field is the cornerstone of Norways offshore gas production. Reservoir engineers estimate the fields gas will continue to be produced economically for at least 70 more years.

Troll is also one of Norways largest oil fields with production in 2010 of 6.86 million Sm (43.2 million bbl), according to the Norwegian Petroleum Directorate.

When Troll was discovered in 1979, the Norwegian petroleum industry knew the field was a profitable gas producer that also held a considerable amount of oil. The directional drilling and completion technology available at the time rendered Trolls oil reserves uneconomic to produce because of its low accessibility in an extremely thin reservoir.

To recover them, researchers would have to find ways to overcome extreme technological challenges and develop new drilling techniques.

Test drilling indicated that, although the reservoir was large in area, it was very thin vertically. Norsk Hydro, which had acquired the operatorship for Troll in 1983, knew that trying to drill efficient production wells was going to be very challenging unless new technology could be developed to accurately drill horizontally and stay within the thin layers of oil-bearing rock.

Driven by the large volumes of oil it knew existed, Norsk Hydro entered into

DRill PowerThe latest generation of a revolutionary drilling system that once turned one of the worlds largest offshore gas fields into a prolific oil field is now being brought on land to maximize unconventional shale reservoirs.

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an agreement with Baker Hughes to study cutting-edge drilling and completion technology with the goals of extending the length and precise placement of horizontal wells at Troll, along with introducing multilateral well technologies.

The result was Baker Hughes drilling systems breakthrough technology of the decade, which transformed the practice of directional drilling: the AutoTrak rotary closed-loop drilling system.

The development of the AutoTrak system was originally part of a collaborative project involving Agip Eni for a field in Italy. Norsk Hydro realized that there was a need for this technology at Troll and implemented it for all future drilling in the field. All of the production wells in Troll oil are horizontal wells, according to the Norwegian Petroleum Directorate.

Introduced in 1997, the technology allowed operators to precisely steer horizontal wellpaths, staying within reservoirs with less than 1 m (3 ft) true vertical depth while

maintaining continuous drillstring rotation at high penetration rates. The systems unique capabilities enabled well planners to design innovative multilateral, extended-reach and 3-D well plans to maximize recovery with fewer total wells.

The AutoTrak system is a programmable tool that takes commands from the surface to drill in the desired direction and inclination. Sensors track where its going, and it can automatically adjust its steering pads to keep the well on course in a closed loop without human intervention until it receives instructions from the surface to change direction or angle. It also sends a continuous stream of position and formation measurement data to surface.

As of June 2011, 188 wells have been drilled in the Troll field and more than 797 km (495 miles) of reservoir have been drilled with Baker Hughes drilling technology.

In 2006, the Norwegian Petroleum Directorate acknowledged the impact of the technology developed for the Troll field

by awarding Baker Hughes its Improved Oil Recovery prize for progressive development and application of advanced drilling and well solutions for oil recovery enhancement.

Building on performanceSince its introduction, Baker Hughes has continued to improve the rotary steerable drilling system. The AutoTrak G3 third-generation system was introduced in 2002. It set the standard for rotary steerable performance in terms of precision and efficiency. The AutoTrak X-treme high-speed system, which incorporated a modular high-performance X-treme mud motor for additional downhole power, was commercialized in 2005 for demanding environments and extended-reach drilling (ERD) applications. The AutoTrak eXpress system, designed for lower spread-cost environments and well-documented geology, was introduced in 2008.

Continued advancements in rotary steerable systems made the AutoTrak system the standard technology for directional drilling in offshore markets, says Olof

> The Troll field is one of

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