connexus 1a. ed

Baker Hughes has taken a number of strategic steps to transform the company. Over the past few years, we have reorganized to be more responsive to our customers and provide the right technology and services to meet their needs. We have expanded our technology and service offerings to fi ll gaps and provide comprehensive solutions, and we have invested in technology and in new facilities and infrastructure globally. Together, we believe these strategic moves have enabled us to serve our customers on a global scale and help them participate fully in the energy industry’s most signifi cant opportunities, including deepwater, unconventional gas and heavy oil development, as well as improving productivity from mature fi elds.

on the New Baker Hughes

The fi rst issue of Connexus, our new Baker Hughes magazine, is an ideal opportunity for me to share with you the recent changes we’ve made at Baker Hughes to improve our ability to serve our customers around the world.

In 2009, Baker Hughes fundamentally changed its operating structure and service model to better meet our customers’ needs. For more than 20 years, Baker Hughes had operated its business through divisions that were focused on specifi c product lines. This business model enabled Baker Hughes to develop and apply best-in-class products, but it was not conducive to providing broader solutions. Our new geographic organization has realigned our global service network so that all of our products and services now are delivered through a single organization comprised of geomarkets that provide a single customer interface in each local market.

This issue of Connexus includes an interview with Dato’ Wee Yiaw Hin, executive vice president of exploration and production with PETRONAS, the national oil company of Malaysia. His views of the energy industry and the role of service companies validate our geomarket approach, which improves our ability to deliver solutions tailored to meet local requirements and places senior managers closer to customers, enabling us to make decisions at “customer speed.”

Leading up to our geographic reorganization, Baker Hughes made a determined and successful effort to hire local talent to make up the largest share of our regional management, and we have development plans in place to help employees build the skills and experience needed to take on leadership roles at all levels of the organization. Baker Hughes also supports scholarships for promising students considering careers in our industry, as exemplifi ed by our program in Angola, which is featured in this issue.

We have broadened our technology portfolio on two fronts. First, recognizing our clients’ need to understand every aspect of developing their hydrocarbon reservoirs, Baker Hughes has formed its Reservoir Development Services group through the acquisition of several engineering and consulting fi rms including Gaffney, Cline & Associates, GeoMechanics International, RDS and Epic Consulting. As discussed in this issue, Baker Hughes now has considerable capability to help our customers evaluate and exploit the potential of their reservoirs.

Chairman and CEO

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Our recent acquisition of BJ Services adds pressure pumping, cementing and coiled tubing services to the Baker Hughes product portfolio, enhancing our ability to provide comprehensive solutions to our customers. With pressure pumping, we can better serve customers in the unconventional gas markets in North America and the rest of the world. In addition, BJ Services’ offshore stimulation and cementing capabilities have greatly enhanced our ability to provide solutions for deepwater operators.

Baker Hughes continues to expand and improve its product portfolio by developing new technology. The total annual research and engineering budget for our technology groups is approximately $500 million. This magazine presents many examples of the advancements that have resulted from our technology programs, including unique fi ber-optic monitoring technology, a new hybrid drill bit, a smart intervention system and an innovative pumping system for subsea applications. This issue also includes a profi le of one of our Baker Hughes Fellows, whose contributions to technology innovation have earned him an international reputation.

Baker Hughes operates in more than 90 countries. Serving the global oil and gas industry requires an extensive footprint. Baker Hughes is in the midst of an ongoing infrastructure expansion program which has included a major headquarters in Dubai, more than 100 operations facilities, and our Center for Technology Innovation in Houston, as well as improvements to our other technology centers. The map on Page 46 shows the magnitude of this global expansion to support our customers.

As I look at today’s Baker Hughes, I am excited about our geomarket organization and our strong commitment to customers. With our broader product portfolio and a global footprint, we’re ready to provide our full suite of services virtually anywhere in the world. Looking forward, I believe our local application knowledge and our in-depth reservoir expertise will not only help our customers optimize production from their reservoirs, but will also help us develop the next generation of innovative technologies.

And it goes without saying that without the ongoing support of our customers, none of this would be possible. Thank you for your business.

| 3www.bakerhughes.com

Speaking the Same LanguageReservoir Development Services experts and technology build market and customer understanding.

Bringing it All TogetherThe Hughes Christensen Kymera™ hybrid drill bit system delivers hard rock performance in Oklahoma.

Optical RealityA powerful new fi ber-optic monitoring system jointly developed by Shell International Exploration and Production and Baker Hughes monitors sand screen deformation and detects the slightest changes to downhole well tubulars and casing—all in real time.

Industry Insight Dato’ Wee Yiaw Hin, executive vice president of exploration and production for PETRONAS, discusses his views on the energy industry, the outlook for E&P growth in Malaysia and the role of national oil companies globally.

Drilling Below Lake GenevaBaker Hughes provides services at a high-profi le exploration project in Switzerland, where the top priority is striking a balance between protecting the environment and fi nding hydrocarbons.

Faces of InnovationMeet Baker Hughes Fellow David Curry, internationally known for his research contributions in physical metallurgy/fracture mechanics and drilling mechanics.

Wise EyesOperators use SMARTTM wellbore intervention technology to “see” down hole and save millions on a plug and abandon project.

Contents 2010 | Volume 1 | Number 1

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

©2010 Baker Hughes. All rights reserved. No part of this publication may be reproduced without the prior written permission of Baker Hughes.

www.bakerhughes.com

On the Cover Light pulses from a bundle of optical fi bers Story on Page 20

Editorial Team

Kathy Shirley, corporate communications managerCherlynn “C.A.” Glover, publications editorTae Kim, graphic artistPam Boschee, writerErica Bundick, writer

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Equalizing the FlowThe Baker Hughes EQUALIZER™ technology is helping optimize production by delaying water coning in a complex Russian reservoir.

Baker Hughes in Your BackyardFrom 2007 through 2011, Baker Hughes will invest more than $1.1 billion to build and expand its infrastructure where customers need it most—in their own backyards.

Keeping Waste at BayA new Eco-CentreTM waste management facility in Peterhead, Scotland, delivers a complete drilling waste treatment and disposal solution in a single facility.

Good Neighbors Baker Hughes scholarships enable young Angolans to pursue their wildest dreams —college degrees.

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

A Look BackBit by bit, Howard Hughes Sr. built an empire.

Boosting Perdido’s ProductionIn extreme water depths and low reservoir pressure, Baker Hughes’ Centrilift XPTM enhanced-run-life ESP systems are bringing oil to surface.

Boosting Deepwater Production Technology

When Shell started planning its deepwater Perdido development, the technical challenges were akin to the fi rst moon landing. Certainly, the industry has a wealth of experience in deepwater drilling and production—just as NASA had put people in space before 1969—but the 8,000- to 10,000-ft water depths, coupled with low reservoir pressures at Perdido, required an entirely new approach to deepwater development.

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UP from the Deep

The extreme water depths and low reservoir pressures were a particular challenge for the completion and production designs—engineering teams were faced with tying back multiple subsea completions and then lifting the production stream 8,000 ft from the seafl oor to the production facility. It was obvious early on that natural formation pressure was insuffi cient to deliver the production stream to the surface and that some form of artifi cial lift would be required. But exactly what type of artifi cial lift was the question.

That’s where Baker Hughes came in.

“When we were looking for an artifi cial lift solution, we wanted a company with proven technology that fi t our ultradeepwater application,” says Dusty Gilyard, senior completions engineer at Shell, who has been working on Perdido since its inception. Shell considered several different types of artifi cial lift, but ultimately decided electrical submersible pumping (ESP) systems were the best proven technology with a track record of reliable operations.

“Shell looked at two major companies, one being Baker Hughes, because we knew that we couldn’t go with just anybody due to the technology that was going to be implemented in the project,” says Gilyard. When it came time to making a decision, Baker Hughes was selected based on its history of technology innovation. “Shell chose Baker Hughes because it had the greatest technology and the best system to support new technologies,” says Gilyard.

In January 2006, Shell awarded Baker Hughes the contracts for seabed production boosting systems at two deepwater subsea projects: BC-10 offshore Brazil and Perdido in the Gulf of Mexico. Perdido is the fi rst development in the Gulf of Mexico to use ESP systems in seabed vertical booster stations.

Baker Hughes ESP systemsBaker Hughes was contracted to provide fi ve Centrilift XP™ enhanced-run-life ESP systems, as well as engineering design, qualifi cation and testing services. Each system installation includes a liquid/gas separator to maximize ESP system performance. The vertical booster stations are

designed to handle production from three subsea satellite fi elds tied back to the Perdido spar host facility.

There are three ESP systems already in place, and the fi nal two will be installed by year’s end, says Baker Hughes’ Jeff Knight, the Shell in-house ESP surveillance engineer.

ESP booster systems offer several advantages over alternative methods, including deployment from vessels of opportunity, redundant system designs to maximize run time, and confi gurations that use existing infrastructure to house the ESP systems. All of these features provide operators economic solutions to maximize production from subsea fi elds.

The 1,600-hp ESP systems are installed in fi ve 350-ft caissons connected directly to the platform’s top tensioned production risers. The caissons are located beneath the spar production facility. Each caisson is equipped with cylindrical-cyclonic gas separation systems to separate natural gas entrained in the fl uids before the fl uids enter the ESP system.

Ryan Semple, manager of critical wells for Baker Hughes

Dusty Gilyard, senior completions engineer at Shell

Jeff Knight, Baker Hughes’ in-house ESP surveillance engineer at Shell


“Shell chose Baker Hughes because it had the greatest technology and the best system to support new technologies.” Dusty Gilyard

Senior completions engineer Shell

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01> The Perdido spar, in the Gulf of Mexico, is the world’s deepest offshore drilling and production platform.

02> The subsea layout below the Perdido spar

03> Schematic of the ESP system in a vertical boosting station

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“Without some form of artifi cial lift, Shell essentially does not have a project. With our high-horsepower ESP capabilities and our large-volume pumps, the ESP systems were a technology that they could consider to lift oil from this fi eld,” says Knight.

Each pumping system is capable of delivering anywhere from 10,000 to 30,000 barrels of oil per day (BOPD). For this application, the pumps were designed for approximately 20,000 BOPD. “From Shell’s perspective, if they have all fi ve systems running at their nominal

fl ow rate, you are looking at upwards of about 100,000 BOPD of production to that platform,” says Ryan Semple, manager of critical wells for Baker Hughes. The ESP systems also control the spar riser head pressures.

“In the case of Perdido—with long subsea tiebacks, extreme water depths and a low-pressure reservoir—the wells would not naturally fl ow to surface, so we needed something that would handle the boost and was extremely reliable. We have basically 100,000 BOPD that we plan to pump, and unless the fi ve pumps that are in the ground are working, we’re not going to make any production. We needed this caisson on the ocean fl oor, so the wells could fl ow to it, and we could pump the fl uid to surface,” says Gilyard.

Pushing the limitsBefore the ESP systems were installed on Perdido, adjustments to the systems were necessary to meet the requirements of this deepwater development. Both Shell and Baker Hughes conducted extensive R&D to design ESP systems for this application. “Baker Hughes has a very active R&D program under way to make our systems more robust and to make them more applicable to varying customer needs. We understand the harsh environments where these ESPs often have to perform. Perdido certainly fi ts that harsh

environment description. We are dedicated to pushing the envelope on ESP technology in terms of gas handling, producing viscous fl uids and also in high-horsepower situations—all of which are often encountered in offshore environments,” says Knight.

Early in the project, the Baker Hughes team was involved in pre-engineering for this complex application. The ESP system design had to take into account all the possible pumping scenarios at Perdido. Much of the application engineering work was done to ensure the best possible match of the ESPs with the required operating conditions. The technology planning was approached within the context of varying potential operating conditions, such as the required boost pressures and fl ow rates—all while considering a multitude of different fl uid compositions since production fl uids from each well would be commingled at the ESPs. There was no one particular application that Shell could focus on for Perdido. “Instead of designing for one fi xed point, you must design for every possible scenario,” says Semple.

During the design phase, Baker Hughes and Shell constructed more than 200 sensitivities to run different scenarios and then determine the ESP system that would work best in the application. “Many people working within both teams had their own way of designing the

system. However, we all made sure that we arrived at the same conclusion at the end of the day,” says Semple.

Shell’s front-end engineering requirements included thorough qualifi cation testing of the new system designs. Because of the unique challenges of this installation, Shell and Baker Hughes worked together to defi ne the expected demands on the ESP systems, while also reviewing the systems’ run life and run history. “We worked with them to develop a plan to qualify a particular design. For example, if we were planning to utilize a particular elastomer for a seal bag, we would devise a test plan and conduct rapid gas decompression testing on that material at our R&D testing facilities to ensure the equipment met Shell’s specifi c requirements,” says Semple.

With regard to the pumping systems, Gilyard agrees that various applications needed to be tested for every possible environment. “The most critical aspect was the functionality of the ESP system. It needed to be able to work in any type of environment. The ESP was put in a subsea separator system and tested for operability using different monitoring functions and level control methods. We considered combinations of multiple temperature and fl ow rate environments. The ESP had to be able to work both mechanically, as well as electronically, without any gauge interference,” says Gilyard.


In the process of designing a system for Perdido, some enhancements were developed to meet the run life expectations of the project. One of these was changing the confi gurations of the seal section to include the addition of an extra chamber. A standard seal confi guration for this size equipment has two chambers, but a third was added for redundancy. Two seal sections were run in tandem, providing a total of six chambers.

Another new technology development for Perdido was the thrust bearing in the seal. “Based on our application review, we determined that the existing highest-capacity thrust bearing in the seal was exceeded in a couple of pumping conditions. In the end, we developed a new, enhanced high-load thrust bearing to account for the thrust in the pump. We went through an extensive qualifi cation process to qualify that for service as well,” says Semple.

A big challenge of the Perdido project was adapting to the continual changes. ”We began designing Perdido’s artifi cial lift system in 2003. Many changes occurred in the early stages of the project. We began with ESPs in the wells and eventually landed on ESPs in caissons. We looked at several different kinds and layouts for the caisson systems, as well as several operating systems. The

collaboration between both companies was essential, and Baker Hughes accommodated our every need within this project,” says Gilyard.

Installation technology Baker Hughes designed specialized installation equipment for Shell’s specifi c requirements, including new tooling to meet the lifting and hoisting standards. Newly designed equipment baskets, lifting subs and control line push arms were created. “Due to the nature of installing this complex string of equipment on this particular offshore platform, the project required specialized technology from a fi eld service perspective,” says Semple.

Baker Hughes’ intelligent production systems (IPS) group designed new equipment for the project as well, including special spooling units to deploy the heavy armored power cable that supplies electricity to the ESP motors. Normally, 8,500 ft of cable would be supplied on two reels and spliced together during installation. Shell specifi ed that the ESP cable needed to be supplied on one large reel to avoid the need for switching of the reel on the platform. “The cable itself was extremely heavy, weighing about 40,000 pounds, and those reels became unmanageable. With the help of the IPS group, Baker Hughes developed a heavy-duty spooling unit that could advance and take up the cable as we ran

into the hole. We also designed transportation frames that could store extra cable or an empty reel.” says Semple.

Custom conex boxes were also developed. The boxes are fi eld service work centers where all the tooling required to install and service the ESP systems is contained. “We developed special lifting devices to meet the lifting and hoisting standards for this heavy equipment. Special tables to set the equipment down on and custom racks were also designed,” says Semple.

According to Gilyard, Baker Hughes was not only selected for its technology, but also for its staff and facility locations. “The company has some of the best and brightest leaders in the ESP industry. We wanted to work with Baker Hughes because of its strong engineering support and a great manufacturing facility. Baker Hughes’ manufacturing facility appeared superior to its competitors by actively employing the latest in manufacturing technology. We knew it would lead to better quality. Your processes seemed to be well-advanced compared to the others, so the technology and quality in manufacturing was far superior as well,” says Gilyard.

Shell was impressed that the manufacturing and engineering departments in Claremore, Oklahoma, were located in one

area, which simplifi ed the work process and allowed the project to operate more smoothly.

Gilyard also noted the collaborative relationship between the various groups in Baker Hughes. “Baker Hughes basically could supply the whole package. It helped to have one person in the company to communicate with on the entire project,” says Gilyard.

Continued successBaker Hughes continues to contribute to the success of Perdido. By year-end all the ESP systems will be installed in the fi ve vertical subsea boosting stations. Baker Hughes will continue to work with Shell over the long term to ensure reliable operation of the production systems. Over time, as production from the fi elds increases, the two companies will collaborate to maximize the performance of the systems and to optimize production. “This project was an important learning experience for everyone involved. The technology developed for Perdido, along with the lessons we learned from working together as a cohesive team, has advanced subsea development capabilities for the entire industry,” notes Semple.

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Reservoir Development Services experts and technology build market and customer understanding

In today’s complex plays and maturing fi elds, oil companies increasingly expect service providers to fully understand their reservoir challenges and to deliver solutions—not just discrete products. Meeting those expectations requires integrating reservoir knowledge into the culture of the company so we can speak the customer’s language.


> Derek Mathieson, president, products and technology, for Baker Hughes

Recent moves by Baker Hughes—including acquiring world-class reservoir consulting fi rms, expanding the global infrastructure and reorganizing into a business segment/ geomarket structure—are part of a necessary evolution to enhance client understanding and to align the technology portfolio with market challenges. Reservoir expertise is fundamental to this process.

“Historically, the Baker Hughes product line structure delivered operational excellence in well construction and production systems. This business model was highly successful,” relates Derek Mathieson, president, products and technology, for Baker Hughes. “But we recognized that today’s industry needs require connecting the product lines to generate comprehensive solutions for key market segments, such as unconventional hydrocarbons, deepwater and enhanced oil recovery. This integrated catalog of products, combined with our trusted consultancy services, creates a company that understands a client’s holistic

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SEISMIC TO SIMULATION

> The Baker Hughes RDS teams help clients understand and improve reservoir performance through the power of data integration and accurate 3-D reservoir modeling. These images (from left to right) show: importing seismic surfaces into a 3-D framework; taking the surfaces into a 3-D cube with additional well data to construct complex geocellular models; building a dynamic geologic model and distributing sands and shales; taking the dynamic modeling data into a simulation model that includes fl uids modeling; then analyzing the results within one software environment.

problem and can derive the best solution to that problem.”

Baker Hughes initially expanded its reservoir capabilities with the acquisition of international advisory fi rm Gaffney, Cline & Associates (GCA) and geomechanics software and training consultants GeoMechanics International in 2008. In 2009, Baker Hughes further grew its reservoir capabilities with the acquisition of two subsurface and wells consultancies, Helix RDS and Epic Consulting.

These four leading consultancies form the bedrock of Baker Hughes’ Reservoir Development Services (RDS) business segment. The combination of these strong individual organizations into a world-class reservoir consultancy service positions Baker Hughes as a top-tier partner for oil companies throughout the asset life cycle, from the earliest phases of project development through enhanced oil recovery.

John Harris, president of RDS, agrees with Mathieson that bringing reservoir capabilities into the portfolio is critical to the shift from delivering individual products to providing solutions to clients’ problems. “Our clients’ ultimate goal is to improve the performance of their assets. Within Baker Hughes, the connectivity that comes from a baseline reservoir understanding allows us to bring together the right tools and services that help them meet that objective,” says Harris.

The value of RDS is both its people and its technology. The expert staff uses a full suite of reservoir modeling technologies to provide clients comprehensive fi eld development studies. This world-class modeling technology covers every facet of fi eld development, including reservoir mechanics over time, wellbore integrity, fracture identifi cation and sand control, just to name a few. Underpinning all of these technologies are proprietary techniques and in-house tools that enable

the 3-D geomechanical characterization of a fi eld—comprising formation strength and subsurface stress magnitude estimation and the distribution of properties across both the reservoir and overburden. These technologies also enable evaluation of changes in the reservoir properties resulting from pressure changes (depletion or injection).

One recent addition to the RDS suite of reservoir tools is the JewelSuite™ subsurface modeling software that integrates seismic data, the geological model, fl ow simulation and full-fi eld geomechanics in one workfl ow. The software brings together static and dynamic modeling with a smooth translation between the geological model and the simulation models, which means scientists can test multiple scenarios quickly and accurately.

These supporting technologies are all part of an integrated platform that, when combined with effi cient workfl ows, allows rapid response to a client’s concerns.


01> John Harris, president of Reservoir Development Services for Baker Hughes

02> Jim Curry, Marie Meyet and Julian Hornak with the Baker Hughes RDS group discuss data related to a reservoir modeling study.

0201

Of course, technology is only one part of the equation. Relationships are the foundation of the reservoir consulting business. Harris contends it’s those relationships that allow service companies to see problems from clients’ perspectives. “We need to understand how their business functions so we can help them grow their business. Our industry moves very fast. Operators have a multitude of demands on their shoulders, and Baker Hughes has a multitude of talented teams with global experience that—when we understand each other—result in solutions that benefi t both sides. There are all kinds of ways we can apply Baker Hughes technology experience to answer our clients’ technical challenges.”

Baker Hughes acquired the reservoir consulting companies for their expertise and their strong client relationships, Harris points out. Ninety-fi ve percent of the consultancy staff comes from operating companies, so they understand that perspective. “What we want to do is change the model from Baker Hughes working on a 45-day drilling program to Baker Hughes partnering on a four- to fi ve-year fi eld management project. That takes a huge degree of trust and understanding, and the only way we can get there is for us to think the same way as our

clients, which means not always pushing to sell our individual products, but rather pushing for mutual value over the life of the relationship. We do that with the application of the right technology, the right people and the right degree of advice.”

According to Harris, Baker Hughes can work with clients in a number of ways: as a project advisor that only incorporates reservoir consulting; as an advisor that combines reservoir understanding with products and technology to develop the best solution for the project; and, fi nally, as a partner in the overall fi eld development. It’s up to clients to determine how comfortable they are with moving along in that relationship. If they want to maintain a relationship with an impartial consultancy, they can do that, because Baker Hughes supports and values that relationship. If they want to hand over more project responsibility, Baker Hughes can facilitate that as well.

Reservoir consulting dramatically enhances Baker Hughes’ ability to provide a collaborative, single point-of-contact solution to complex integrated projects, or what Baker Hughes calls integrated operations (IO), relates Mathieson.

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Traditionally, the company could deliver a well to a client’s specifi cations and manage all the third-party interfaces. The addition of reservoir capabilities allows Baker Hughes to work across the entire life cycle of a project.

Primarily, Baker Hughes IO projects have focused on the drilling segment, but the future vision of IO includes expanding the production optimization portfolio—rehabilitating mature fi elds that may or may not involve drilling any new wells. These projects require building an intimate knowledge of the reservoir over time and then bringing together the proper products and services, whether it’s wireline, coiled tubing, artifi cial lift or chemical management, to maximize the life of the fi eld from existing wells.

Harris sees RDS’ role not only as a critical interface with clients, but also as a catalyst to drive a more effi cient, focused research and development program. As the teams that engage clients very early in the fi eld development or optimization process, RDS understands clearly the needs of operators and can feed that knowledge back into the product development cycle to ensure new product offerings are addressing a real industry challenge.

Mathieson agrees. Adding reservoir capabilities makes an immediate impact by binding the product technology groups together to focus on market segment solutions. But the real transformation occurs when technology development and workfl ow are based on real-time, fi rst-hand intelligence of operators’ critical challenges. “The RDS organization is about bringing a new set of capabilities to align our workforce to provide answers to the problems our clients are wrestling with today and anticipating for the future,” he says. “We have to diversify the skill set so we are not a company of pure geoscientists or pure designers, but a combination that truly is more than the sum of its parts.”

RDS is helping to drive that diversifi ed skill set. The team is assisting in restructuring Baker Hughes’ training and career path development programs. RDS is delivering training courses to help Baker Hughes’ engineering staff understand the infl uence particular tools and services have on the reservoir—where they fi t in the full spectrum of a project. And people have been receptive to expanding their knowledge base. “Since joining Baker Hughes, I have noticed that the workforce is characterized by people who are enthusiastic to expand

their skill set to bring value to clients. This is a very motivated bunch of people, and they are hungry for new knowledge and new ways to work,” notes Harris.

Training isn’t the only way Baker Hughes’ reservoir capabilities will impact the larger workforce. The portfolio expansion gives engineers and scientists throughout the company a wider array of career paths as well. With a portfolio that spans from the reservoir through the refi nery to a comprehensive understanding of the market, Baker Hughes can move people with potential into various roles to ensure a wide knowledge base. “A scientist can rotate through the consultancy group into a project management group, into a project delivery group, into product development. It’s fantastic,” Harris says.

Integrating RDS into all aspects of the business is changing the equation for Baker Hughes, notes Mathieson. “We want to shift the conversation to ‘how can we help you maximize reserves and ultimate recovery from your fi eld?’”


Kymera: Bringing it all together

Technology Delivers Improved Performance in Hard Rock Formations

Driving through south central and western Oklahoma, you’ll see drilling rigs dotting the fl at plains and rolling hills. The idyllic countryside belies the unforgiving rock that lies deep beneath those rigs. The hard, abrasive formations comprising mixes of shale, sand, erosional granite, interbedded sand stringers, limestone and anhydrite challenge the industry’s most advanced drilling technology. But the unique Hughes Christensen Kymera™ hybrid bit technology is changing all that, delivering improved drilling performance in these heterogeneous formations.

Fit-for-purpose hybrid drill bit technologyEarly concepts of hybrid drill bits date back to the 1930s, but the development of a viable drilling tool became feasible only with the recent advances in polycrystalline diamond compact (PDC) cutter technology. This new generation of hybrid bits is based on proven PDC bit designs with rolling cutters on the periphery of the bit.

A Kymera hybrid drill bit can aggressively and effi ciently drill shale and other formations with problematic plastic, or malleable, characteristics two to four times faster than a roller cone bit. Leveraging the strength of the PDC bit in soft formations and the roller cone in hard formations, the Kymera bit uses technology that can maintain an overall rate of penetration (ROP) much higher than a roller cone or PDC

bit alone. With the synergistic combination of the diamond scraping and roller cone crushing, the bit can survive even in conglomerates. The rolling cutters improve the bit dynamics by reducing torsional oscillations, and the scraping diamond cutters produce a smooth borehole bottom, which reduces bit bounce. Compared to conventional PDC bits, torsional oscillations are as much as 50 percent lower; stick/slip occurs at lower revolutions per minute (RPM); and whirl is reduced at high RPM.

The Kymera hybrid drilling system is designed to be fi t-for-purpose for the following: traditional roller cone applications that are ROP-limited; large-diameter PDC and roller cone bit applications that are torque-on-bit or weight-on-bit limited; highly interbedded formations where high torque fl uctuations can cause premature

failures; and motor and/or directional drilling applications where a higher ROP and improved build rates and tool face control are desired.

Kurtis Schmitz, a Baker Hughes application engineer based in Oklahoma City, says close collaboration with two customers in Oklahoma, Devon Energy Corp. and Chesapeake Energy Corp., resulted in advancement of the Kymera technology and improved the two companies’ drilling performance in western Oklahoma and in Canadian County.

“Our technology was developed specifi cally for diffi cult intervals experienced by Devon in Canadian County deep Woodford wells and by Chesapeake in western Oklahoma deep intermediate applications,” Schmitz says. “Baker Hughes aligned its account

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Chimera |kī•mir•ah|Noun: a mythological creature with disparate parts derived from two or more animals.

Kymera |kī•mir•ah|Adjective: a Baker Hughes hybrid drilling technology, combining advanced technologies from roller cone and PDC bits that address diffi cult-to-drill formations where neither of the conventional bit technologies delivers satisfactory performance.

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teams comprising engineering, marketing and operations with the

customer’s drilling team. From the ground up, our technical fi eld representative meets with the customer, the technical marketing representative calls on the customer’s superintendents, and our account manager communicates with the customer’s engineer in the offi ce. Our engineering group then takes the input from this team and coordinates the product development resources to meet the customer’s needs.”

Technology and operations meet customer needsDescribing the drilling challenges in Canadian County, Mark Williamson, Devon drilling manager, says, “In drilling these Woodford horizontal wells, we encounter a lot of problematic formations that give us great diffi culty and consume a lot of rig time.

“These problems were noticed early on. The center of the drilling region is a pretty forgiving area, generally requiring four bits to drill a 9,000- to 10,000-ft interval. However, as we started expanding the

limits of the fi eld, going from the center out in the acreage, it took three times as many bits to drill that same footage interval. So, instead of drilling consistently, the rig is drilling in 200-ft spurts. You spend all your time changing bits, tripping in and out of the hole.

“We have an old saying in drilling that the drilling rig is a factory for making hole, and if the drillstring is just going up and down, coming in and out of the hole, your factory is shut down—you’re not making any progress.”

A unique characteristic of this fi eld is that, unlike many areas in the U.S. where formations were laid down fairly uniformly over large areas, Devon can “drill a well and

move the rig a mile away, and it will be a whole different ballgame in some intervals,” according to Williamson.

“Collaboration isn’t just one or two people working together;

it’s your drilling mechanics lab, it’s our guys in the fi eld, it’s the sharing of data, and it’s the ability of Baker Hughes to analyze the data.”

Mark Williamson Drilling manager, Devon Energy

> Mark Williamson, Devon Energy


Having faced these tough drilling conditions in 10 wells and wanting to minimize nonproductive time, Devon realized it needed a better understanding of bit technology to improve its drilling performance in this area. About 18 months ago, Devon invited several bit suppliers to present options and advice. “We wanted to see what the bit companies had to offer, how we could collaborate with them to redesign bits purpose-built for our fi eld and to help us drill faster,” says Williamson.

“Baker Hughes rolled up its sleeves right from the start and started working closely with us to redesign bits for our specifi c applications. Other companies were very reluctant to redesign bits, wanting us to run with their standard designs. We would never see improvement if we did that.”

Williamson adds, “Kurtis, Troy Hinkle [technical marketing representative] and Jeff Due [account manager] were very good to work with, listening to what our problems were and how we would attack them. We dissected the problem into smaller intervals to make it more manageable and also worked on the curve and lateral part. We fi rst worked on the redesigned bit for the 12¼-in. hole section because that was where we could have the biggest early success, and it actually played out that way.”

Williamson retrieves data from real-time rig monitoring systems in 10-second intervals or on a depth basis in half-foot increments for the whole bit run. He adds, “Collaboration isn’t just one or two people working together; it’s your drilling mechanics lab, it’s our guys in the fi eld, it’s the sharing of data, and it’s the ability of Baker Hughes to analyze the data.”

By analyzing the data, consulting with

Devon’s drilling team and dissecting dull bits post-run, Baker Hughes has shortened the time required for bit redesign from four to six months to four to six weeks. As Williamson points out, with completed well costs running about $8 million and requiring 45 to 50 drilling days, shorter cycle times for bit redesign signifi cantly improved drilling times.

According to Schmitz and Williamson, from 2007 to 2010, the average days on well have been reduced by 20 percent, and average bit consumption has been reduced by two bits. The deepest well drilled by Devon has been 14,700 ft total vertical depth, and the longest well has been 19,600 ft measured depth.

Taking on tough vertical drilling in OklahomaChesapeake Energy faced vertical drilling challenges in its western Oklahoma deep intermediate applications where the cost per completed well is approximately $18 million. Drilling depths are generally 16,500 to 17,000 ft, and drilling time ranges from 180 to 200 days. Chesapeake sought a drilling solution from Baker Hughes that would signifi cantly reduce the number of days on well.

Greg Bruton, Chesapeake drilling engineer, says, “The section gets thicker and shallower, depending on where we are across the fi eld. Our PDC bits historically have been played out because of the rock strength. Whether it’s due to the abrasiveness or the carbonate nature, they won’t drill. We haven’t had to go to the hard 12¼-in. roller cone bits, but it was just a little beyond the capabilities of PDCs. The PDC bits would typically drill to 12,500 to 13,000 ft, and then we’d struggle to achieve 9⅝-in. casing points at about 16,500 ft. The Kymera system can now fi nish up the last 3,500 to 4,000 ft of

these wells, also replacing a turbine/impregnated bit run in the fi nal 1,500 ft to total depth—and it’s doing a very good job.”

Schmitz says the Baker Hughes solution was based on dual product strategies—PDC conversion and Kymera bit technology. The application was dominated by tricone technologies, but it was undrillable with the then-existing PDC technology. With the advent of the Baker Hughes Quantec Force™ PDC cutter technology, the Chesapeake account team provided a step-change in drilling performance, reducing the number of bits from 18 to 20 to four on one well.

The fi rst Kymera hybrid bit run in Chesapeake’s wells in western Oklahoma resulted in a 32- to 118-percent improvement in ROP compared with offset wells. However, despite its impressive drilling performance, the bit lost one of its welded roller cone leg assemblies during the run.

Bruton says, “We hauled the bit in to the offi ce, straight from the rig. It still had mud on it when the Baker Hughes guys pulled up in the parking lot. While this bit did have a catastrophic failure when the weld broke, the bit was in extremely good shape, indicating much more life available, possibly replacing multiple bit runs.”

The forensic analysis of the bit revealed a poor weld groove geometry and weld process. The weld groove geometry has been redesigned, and the welding process has been optimized to incorporate an overlapping multistage process. Each weld is inspected ultrasonically to ensure its quality.

“They brought the design team in and said, ‘Okay, this is what we found. This is

18 |

what we’re doing to fi x it. This is when they’re going to be ready,’” says Bruton.

The updated Kymera hybrid bit technology has been fi eld-tested without failures. Welds verifi ed post-run by ultrasound showed no incidence of cracks. The improvements are deemed successful and are now implemented as standard features in the Kymera system technology, according to Schmitz.

Bruton cites vertical drilling performance improvements of doubled ROP and interval lengths; in some runs, the interval length

has tripled. “The Kymera product line has a very broad set of variables, such as roller cone and PDC features, blade features and hydraulics that can be changed to address most issues.”

Collaboration between Baker Hughes and Chesapeake occurs on a regular basis. Bruton says, “These guys stop by regularly. We discuss our areas of opportunities, and Baker Hughes steps up to work on these issues. These are 170-, 180-day wells. With all of the changes we’ve done here in the last six months, we’ve been able to wrangle off about 40 to 50 days.”

“These are 170-, 180-day wells. With all of the changes we’ve done here in the last six months, we’ve been able to wrangle off about 40 to 50 days.”

Greg Bruton

Drilling engineer, Chesapeake Energy

> Greg Bruton, Chesapeake Energy

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Fiber-Optic Technology Monitors Sand Screen Deformation in Real Time

A powerful new fi ber-optic monitoring system jointly developed by Shell International Exploration and Production and Baker Hughes monitors sand screen deformation and detects the slightest changes to downhole well tubulars and casing—all in real time.

This reservoir surveillance system, known as Real-Time Compaction Monitoring (RTCM™), is permanently deployed in a well to collect a range of data related to reservoir compaction and other geological subsurface movements that impact production and economics and, in the worst of cases, complete loss of the well.

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01

02

01> Charles Giebner, a member of the Baker Hughes optical systems group in Blacksburg, Virginia, makes preform, the raw material from which glass “fi ber-optic” strands are made.

02> Preform is heated to the melting point so the glass can be drawn and shaped into fi ber strands. The fi rst glass droplets to come out of the furnace are tear-shaped pieces of scrap that Blacksburg workers call “gob drops.”

How it worksThe RTCM system monitors sand screen deformation and casing shape in real time through a special fi ber-optic cable containing tens of thousands of closely spaced (~1 cm) strain sensors (fi ber Bragg gratings), which are helically attached to a wellbore tubular. Each is capable of measuring submicrometer deformations (1x10-6 m).

Each fi ber Bragg grating consists of periodic variation of the refractive index of the optical fi ber’s core. Effectively, it behaves as a partially refl ecting mirror by refl ecting particular wavelengths of light based on the grating period and transmitting all others. When strain is applied to the sensing fi ber, the individual

gratings in the fi ber stretch or contract and cause a shift in the wavelength of light refl ected, which allows the gratings to function as strain gauges. By inscribing a large number of gratings into a single optical fi ber, the RTCM system achieves highly sensitive distributed strain measurements with extremely short spatial resolutions.

An optical frequency domain refl ectometer—the Baker Hughes SureView™ distributed sensing system—located at the surface and connected by a lead-in cable to the sensing fi ber, simultaneously records the strains measured by the individual gauges. Through the large number of sensors, the RTCM system acquires a profi le of the strain distribution and directly interprets

it into a 3-D, high-resolution image of the tubular deformation in real time.

Through these extremely high-resolution measurements, operators receive information on axial strain, radius of curvature of bend and crushing. These measurements also allow differentiation of the mode of deformation. The primary deformation modes considered are:

Axial compression Bending Ovalization Shearing Thermal expansion

In addition, the tool is used in conjunction with other downhole fi ber-optic measurements.


These real-time measurements give operators suffi cient time to properly plan and execute remedial interventions, such as changing the rate of drawdown or supporting the reservoir to prevent completion damage.

Traditionally, fi ber optics in reservoir environments are plagued by hydrogen darkening, a physical degradation of the optical properties of glass. Free hydrogen atoms are able to bind to the silica glass compound, forming silicon hydroxyl—a chemical compound that interferes with the passage of light through the glass. However, Baker Hughes controls this issue by manufacturing its own proprietary hydrogen-resistant optical fi bers. Baker Hughes is the only service company that manufactures its own optical fi bers—widely considered to be among the best on the market today, and the most resistant to hydrogen darkening, according to Philippe Legrand, Baker Hughes optical systems product line manager.

Expanding the technologyIn 2005, Baker Hughes signed a collaborative agreement with Shell to develop the fi ber-optic technology to monitor deformation of well tubulars and casing. The system underwent trial tests at Shell’s Pinedale, Wyoming, operations in 2008.

The Baker Hughes sand control and cased-hole engineers at the Center for Technology Innovation (CTI) in Houston and its fi ber-optics experts in Blacksburg, Virginia, then expanded the monitoring technology to include sand control applications.

The sand control applications necessitated the creation of an innovative, patented downhole fi ber-optic wet-mate connect system. The system’s connector ensures that

up to six optical channels per connector are successfully completed by exactly connecting two ends of separate optical fi bers together, each the diameter of a human hair and located deep within the wellbore.

“The enabling technology of the fi ber-optic wet connect is truly revolutionary,” says Graeme Young, Baker Hughes director of well monitoring. “Without this, optical sensing of lower and multitrip completions would not be possible.”

The RTCM system for sand control

systems was successfully tested at the Baker Hughes Experimental Test Area (BETA) rig near Tulsa, Oklahoma, in 2009. Field trials commenced in California in early 2010, Young says, and, depending on the outcome of those tests, a commercial product launch is expected in 2011.

“The RTCM technologies mark a major step forward in monitoring well integrity and the geomechanical effects of production,”

> RTCM system readings cover 360º of the sand screen. The close spacing of the many thousands of fi ber Bragg gratings results in fi ner resolution than distributed temperature sensors (DTS). In this example, the RTCM system resolution is 1 cm, 100 times fi ner than the DTS resolution of 1 m.

“The RTCM technologies mark a major step forward inmonitoring well integrity and geomechanical effectsof production. The rapid development of this exciting technology underpins its expected value for the industry.”

Vianney Koelman Manager, in-well monitoring technology Shell International Exploration and Production

22 |

01> The RTCM system on casing awaits deployment in a Bakersfi eld, California, well.

02> The enabling technology of the RTCM system is the fi ber-optic wet-mate connect system, which ensures that up to six optical channels are successfully completed by exactly connecting two ends of separate optical fi bers together—each about the size of a human hair.

03> High-resolution measurements in real time give operators suffi cient time to plan and execute remedial interventions to prevent completion damage.

says Vianney Koelman, manager of in-well monitoring technology for Shell International Exploration and Production. “The rapid development of this exciting technology underpins its expected value for the industry.”

Future capabilities Potential uses for the revolutionary fi ber Bragg grating-based system are:

Deepwater environments where compaction issues can cause costly downtime

Carbon capture and sequestration projects to monitor the integrity of the caprock

Steam assisted gravity drainage projects where the completion is under severe strain as the steam front hits the producing well completion

“Because fi ber Bragg gratings respond to both a thermal strain and a mechanical strain, RTCM technology has the huge potential of being capable of producing 3-D images describing the infl ow of fl uids on sand screens with a resolution that no existing tools have ever achieved,” Legrand adds. “This has been demonstrated during testing at our Rankin facility in Houston, and we are eagerly awaiting fi eld trial deployments to confi rm the laboratory results.”

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01

Q&A with Dato’ Wee Yiaw Hin executive vice president of exploration and production

for PETRONAS

Industry Insight

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After several years as managing director of Sarawak Shell Bhd/Sabah Shell Petroleum Co. Ltd., how will you use your experience with an international oil company to raise the bar at PETRONAS?

If you look at how PETRONAS is performing, it is like looking at a glass of water that is probably more than half full because PETRONAS has done well. If you name successful national oil companies, it is among the top three or four. But the thing is, if you look at that glass of water, while we have done very well, there is this bit at the top which we can fi ll. And I hope that is what I can bring—to get that last bit fi lled. Now, how do we accomplish this?

First, we must ensure that we have quality assets in our business portfolio, both globally and domestically. We have quite a large global portfolio, and we need to take a deep review of all these projects and prioritize them from a sharper business and commercial point of view.

Second, while we grow globally, we need to also look at our domestic plan and determine if we can do more in both the shallow, more mature areas and in deepwater. Can we be more aggressive—meaning more and faster exploration, more and faster production? And, if so, can we also be profi table and sustainable?

Now, to do all of this, we must retain our business philosophy while shifting our mindset to a higher gear to be more business-oriented and commercially driven. There must be clear accountability throughout the organization. We want to set high standards and motivate people to want to deliver, exceed expectations and grow.

I have a very simple, three-step model that I’ve used in managing businesses,

and it has worked very well. The fi rst step is knowing what you have promised and then delivering it. The second step is setting higher expectations of yourself—asking yourself if you can do more. I would like for the whole organization to adopt the culture of “I’m accountable. I must deliver. I can do more with our current business or assets.” Then, the last step is growth. Here, we should be looking at major strategic actions or moves to grow the current portfolio; for example, entry into new countries, acquiring or exploring new reserves, development, production or businesses.

So, very simply, I’d like for everyone in the entire organization to be accountable, to know exactly the role they play and what is expected of them to help deliver and grow the business.

The world economy has experienced unprecedented volatility in recent years. In your view, what are the biggest challenges to a sustainable future for the energy industry?

The challenges we face today are familiar ones, but the reality is we are faced with a multitude of issues at one time: volatility in oil prices, the pace of the global economic recovery and its infl uence on future energy demand, the sustainability of the price of oil per barrel, increasing demand for less environmental impact and better risk management, and the role of technology in both conventional and unconventional resources.

The response from the industry has to be making sure that our capabilities can continue to deliver in all these diffi cult environments in the most effi cient and effective way.

The year 2010 marked a century of oil exploration and production in Malaysia. What is the outlook for future oil exploration in Malaysia?

The outlook for future oil exploration in Malaysia is good. The high level of activities by PMU [Petroleum Management Unit] of PETRONAS Carigali, and international oil companies and service contractors continues.

However, we need to understand the demographics of our resources and match our strategies to maximize the exploration, development and production activities. While there are still opportunities for large material resources and new plays, there are also areas which are now fairly mature.

In the mature areas, which are mainly in the shallow water, the focus is on increasing ultimate recovery through comprehensive full-fi eld studies, proper reservoir management and aggressive improved oil recovery/enhanced oil recovery programs. At the same time, we are actively looking at new and innovative models—production sharing agreements [PSAs], for instance—to aggressively develop some of the existing discoveries in these areas. We hope these initiatives will involve some niche, fast-moving and lower-cost best players, including existing players.

On exploration, we are moving to more aggressive domestic exploration covering all resource areas in the near term of the next two to three years: mopping up all near-fi eld exploration prospects in existing shallow water and mature areas; drilling identifi ed prospects in material and new acreages such as deepwater; and exploring in new play types like deeper high-pressure, high-temperature and basement plays.

We are also de-risking new or less evaluated blocks and basins to identify plays and


prospects for exploration drilling in the medium term following the two- to three-year aggressive program.

I look to oil and gas service companies who can align with us and our objectives and be able to play a role with PETRONAS and PETRONAS Carigali in our aspiration to maximize the value of our resources for the nation.

The role of the national oil company in a global energy industry has expanded dramatically in the last decade. What is your vision of the future with respect to the role of PETRONAS?

Again, with our goal to maximize the value of the resources within the country, we have to be clear about what we have and what we want.

Then, we have to ask, ‘How do we do it? How do we achieve our objective of getting more reserves faster?’

In the fi rst instance, we have our operator, PETRONAS Carigali. We must know our own capabilities, where we need to further develop capabilities ourselves or jointly with other oil companies and service contractors, and lastly, where oil companies can add more value if they take on the exploration and development of our resources.

Here is an analogy: Say, I own the land. I build my own houses. I invite people to come and build houses on my land. Eventually, the result is a town. In a similar way, if PETRONAS tries to do something all by itself, we may not get the best town.

We have to look at who are the right players who are willing to share in the risks and rewards to work with us and help us reach our objective of exploring, developing and producing our resources effectively and contribute value to the nation.

In your view, how does PETRONAS promote local talent and set the bar to international quality standards?

PETRONAS has been a leader in Malaysia at building international industry standards and with 8,000 employees, we have become a catalyst among other companies in building and promoting local talent—both within PETRONAS and outside the company.

A couple of years ago, we established an initiative called the Accelerated Capability Development program to focus on accelerating the development of young professionals. And, as part of our agreements with all the PSA operators, we require a local talent plan. It makes good sense because if you are doing business here, surely the best way to do it is to have local people running your business. It’s more cost-effective and it supports the local culture.

Malaysia has come a long way in this regard in the past 20 to 25 years. For example, back then, most of the fabrication work was done in Korea and other places. Today, you would never think of going to other countries to fabricate a structure. Malaysia is a world-class deepwater center, and we take projects from all over the world.

Malaysia is generally known as a favored recruiting ground for oil and gas companies—strong evidence that local talent has reached international standards.

PETRONAS has expanded its operations to more than 30 countries and views itself as a strategic partner in the development of hydrocarbons in these nations. Please explain the PETRONAS philosophy as a strategic partner for growth.

Our global agenda is based on a business-driven philosophy. Whenever we go into another country, we are going there because there is bona fi de business that will provide a return on our investment. However, we will only go into a country where we feel comfortable because we have relationships that we can rely on and where we know that we can contribute to the development of the oil and gas industry in that country.

You don’t simply go where we might want to go. We go to countries where there is a business case for ourselves and a business

Dato’ Wee Yiaw Hin joined PETRONAS on May 1, 2010, as executive vice

president, exploration and production, after having served as vice president of

Talisman Malaysia.

From 1988 to 2009, he held management positions in the Shell organization,

overseeing key portfolios in Sarawak Shell and Shell South Africa.

26 |

case for the country who wants the oil and gas industry, and who sees PETRONAS as a company that can help develop the resources for the mutual benefi t of everyone.

For example, in Sudan, we recognized that we could help partner with the host authority, as well as the national oil company, to develop the oil resources and petroleum industry for mutual benefi ts. PETRONAS has also worked together with the government to implement various initiatives focusing on capability development of the petroleum host authority and company, as well as the community at large.

What is your view of the relationship between operators and service companies? How can this relationship be strengthened?

I think it can be strengthened through understanding what our capabilities and needs are and then aligning them with those of the oil companies and service companies. With this strength, we can mutually leverage our capabilities on a more global basis.

An example, and one that I’ve been involved in, is the PETRONAS-Shell relationship. It is not an operator/service company relationship, but similar rules apply. The two companies have been working together for decades in the upstream area, and we have built a dynamic working relationship

and pursued innovative arrangements like the gas gathering project BARDEGG [Baram Delta Gas Gathering Scheme], where the evolution of the business model is customized to the changing landscape, and that fulfi lls mutual business needs. We have swapped roles in the Baram Delta Operation production sharing contract where PETRONAS Carigali became the operator and Shell the partner, to support PETRONAS Carigali in building operatorship capabilities.

As for relationships with service companies, we see many of them who are building operations centers locally so they can better support us and the region by putting people in the right places to align with PETRONAS.

Vast untapped sources of power lie within the geothermally active Pacifi c Ring of Fire. How is PETRONAS exploring the potential of alternative energy sources, such as geothermal energy?

PETRONAS will continually look at alternative or renewable energy sources as a mixture with fossil fuels from a strategic or commercial angle because it’s what people expect. We have identifi ed two areas of alternative energy—solar and biomass—where efforts are ongoing to determine and fi rm up our position moving forward. However, the strategic and commercial basis of any ventures on alternative energy

needs to be clear before we commit any major investment. We currently do not have geothermal on our radar screen, but we continually review a renewable energy agenda on a strategic and commercial basis.

Baker Hughes has shifted from a product line business approach to a geomarket organization designed to better align with clients. How has this realignment affected the way we do business with PETRONAS?

At PETRONAS, we see this as a positive move. Baker Hughes is a global company, but you do business locally—whether it is in Asia, the Middle East or any other part of the world.

I think global and local functions are both business-driven. Both parts of it—the local and global—are important, but in a global company, there is a lot of business going on within the company that the local parties never see, and that can be confusing.

Global is the organization, local is a face that should be seen as, and act as, the business executive. I think that was your intention with the reorganization, and it helped.

Dato’ Wee holds a fi rst class honors degree in civil engineering

from the University of Wales and a master of science degree from

Imperial College London, a world renowned education center in

the fi elds of science, technology and medicine.

Dato’ Wee is a fellow of the Institute of Engineers, Malaysia; a

member of the Board of Engineers, Malaysia; a graduate member

of the Institution of Civil Engineers, U.K.; and a director of the

Society of Petroleum Engineers’ Northern Asia Pacifi c region.


From Zermatt to Zurich, Switzerland’s glittering alpine peaks, towering cathedral spires, cheeses, chocolates and edelweiss have long enchanted and enticed the rest of the world.

With four national languages, the picturesque European country that borders France to the west, Germany to the north, Austria and Liechtenstein to the east, and Italy to the south has it all. Almost.

28 |

Switzerland has no known oil or gas reserves. It is totally dependent on hydrocarbon imports. But one company hopes to change that. With natural gas prices at around $6.50/MMbtu, and future energy supply security issues looming, Swiss exploration company Petrosvibri began an in-country exploration drilling project in 2009. “Switzerland imports all its consumed hydrocarbon products, which is two-thirds of its annual energy consumption,” explains Petrosvibri’s Vice President Philippe Petitpierre. “Finding hydrocarbons here would be of strategic importance to Switzerland.” (The remainder of Switzerland’s energy consumption comes from hydropower, nuclear power and some renewable energy sources.)

Seismic surveys identifi ed potential hydrocarbons in the Chablais subsurface structures that lie partially beneath crescent-shaped Lake Geneva, the largest natural freshwater lake in western Europe. Petrosvibri chose Baker Hughes as a contractor to deliver a package of services at this high-profi le exploration project in the Canton of Vaud and within Les Grangettes, an internationally signifi cant nature preserve for migrating songbirds and a habitat for water and wading birds.

“Petrosvibri, as a private organization not yet fi rmly embedded in the drilling industry, is reliant on excellent and professional support of specialized companies based on partnership relations,” says Petitpierre. “Baker Hughes offered a package of services with professional cooperation of several product lines and high project support value, all of which promised technical and economical advantages.”

Baker Hughes is providing directional drilling services, drill bits, wireline logging, drilling fl uids and coring services.

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Protecting the environment“The selection of the wellsite was a balance between environmental issues and its proximity to the structural culmination, which is situated between Saint-Gingolph and Vevey,” says Andreas Macek, operations manager of the Noville-1 well and consultant with the Swiss company GeoWell.

“Because drilling ‘offshore’ Lake Geneva was prohibited due to technical and environmental reasons, the rig had to be placed near the water’s edge. Positive aspects of the well location, however, are the long distance to densely populated areas and the proximity to existing gas pipeline infrastructure,” notes Macek.

“Preserving Les Grangettes, one of the most protected parks in Europe, from noise emissions, potential contamination of the nearby marshlands and drilling waste disposal were of utmost concern to the community, the government and the operator,” says Mario Aufi ero, vice president of continental Europe for Baker Hughes. “The elevated ecological aspects of this true wildcat well make it very exciting for us to be a part of.”

Petrosvibri’s number one issue when planning the Noville-1 well on the banks of Lake Geneva was preservation of the ecology, according to Trey Clark, director of technical support for Baker Hughes in continental Europe. “To minimize risk, it was advantageous for Petrosvibri to select experienced service companies that could provide a broad range of oilfi eld applications,” he says. “Baker Hughes’ operations in Germany and Italy, which support the Noville-1 activity, has had an integrated quality and environmental system compliant to ISO 9001/14001 standards since 2006,” he says.

“In addition to the standard health, safety and environmental (HSE) training requirements for all Baker Hughes

employees, Italy personnel completed additional environmental training in the management and risk of air emissions, waste management and environmental noise reduction,” notes Nicola Ruzzi, Baker Hughes HSE specialist for continental Europe.

And, along with preproject and ongoing environmental training, Baker Hughes fi eld service engineers received dedicated training to understand and use materials safety data sheets (MSDS). “The MSDS outline specifi c information about a product or a chemical within a product—how it’s stored, transported and disposed of, as well as its eco-toxicity and biodegradability,” adds Roberto Sestilli, Baker Hughes HSE manager for continental Europe.

Managing wasteSpecial consideration was also given to the safe storage and transportation of chemicals and radioactive materials. Before being shipped to the wellsite from the Baker Hughes facility in Pescara, Italy, the fl uids laboratory was outfi tted with a special storage unit for laboratory chemicals and a kit to contain potential spills. Chemicals stored outside the unit (necessary for mixing mud) were segregated to a dedicated area with no risk for environmental pollution.

Ensuring that the transportation and usage of any radioactive materials necessary to identify important reservoir characteristics had zero impact on the environment was another important consideration. Continental Europe dangerous goods specialists Fabio Guerra and Andries Beugeling worked closely with Petrosvibri and local health authorities to make sure that any radioactive materials used on the project were fully compliant with the stringent local regulatory requirements.

To minimize liquid and solid waste production and to improve the reuse of fl uids on-site, Baker Hughes introduced an online fl occulation process. This

technology—consisting of a fl occulation unit for automatic fl occulants dosaging and high-speed, low-volume centrifuges—enhances solids removal from the mud in the active system.

“Part of the mud coming out of the well after separation through the shale shakers is fl occulated in the fl occulants unit and pushed through the centrifuge to separate fl occulated colloidal solids,” Ruzzi explains. “This gives us enhanced separation of the solids from the active mud system. The liquid part is transferred back to the active system. By doing this, we have reduced the need for major water dilution of the active system, thereby reducing signifi cant volumes of the mud build. The fi nal result is less liquids and solids waste that has to be disposed of by the operator.”

01

30 |

Petrosvibri will soon know whether or not economic quantities of producible gas exist below Lake Geneva. If they do, Switzerland’s need for natural gas could be sustained for the next 20 years, according to some estimates. If they don’t, the possibility for geothermal potential or porous deep aquifers for gas storage would mean a partial success, says Petitpierre.

“Switzerland may never be the next oilfi eld boom,” says Clark. “The market here may be in more nontraditional segments such as underground gas storage, geothermal, shale gas and carbon sequestration, to name a few, but each of these projects is vital to the success of our clients. By joining forces across product lines like we did on Noville-1, Baker Hughes can deliver fi t-for-purpose technology and service packages to the European marketplace.”

04

03

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01> Cezary Smol (left), directional drilling engineer, and Torben Liedke, MWD fi eld engineer, on the Noville-1 rig on the shores of Lake Geneva in Switzerland.

02> Petrosvibri Operations Supervisor Karl Gollob (left) visits with Baker Hughes’ Torben Liedke on the job site.

03> Sandra Ludwig (in red coveralls), a geologist with PetroServices GmbH, and Petrosvibri’s Karl Gollob (far right), confer with Baker Hughes personnel on-site.

04> Smol and Liedke descend the Noville-1 rig.

Faces of INNOVATION

Those who dedicate their lives to research tend to have a great respect for time.

David Curry is among those people. He doesn’t fancy the rat race. He takes his time warming up in the morning. He cherishes the rare times that he can be with his four children all at once. And he imagines a time when, ensconced somewhere in the south of France, he can leisurely write a textbook—between the occasional nap and, depending on the time of day, with a glass of beer or wine within easy reach.

Curry’s measured pace is a product of his roots. He grew up in Princes Risborough, a small village about 40 miles northwest of London that was already well-established when William the Conqueror’s Doomsday book was compiled in 1086. For university, he chose Cambridge, less than two hours—yet, eventually, worlds away—from Princes Risborough.

“I had gone to university wanting to be a theoretical physicist and discovered very quickly that I wasn’t bright enough for that,” Curry says. “Physics was a subject I had enjoyed and was good at in high school. Cambridge had a reputation, and I think it still does, for theoretical physics. I guess it hadn’t dawned on me just how much math was involved, and I’m not really a mathematician—certainly not at the level required to be of any use at all as a physicist.”

Though his name may not be associated with those who rationalize, explain and predict physical phenomena, Curry, who went on to earn a bachelor’s degree in natural

sciences and a doctorate in fracture mechanics, is internationally known for his research contributions in drilling mechanics and physical metallurgy/fracture mechanics.

Today, Curry is a Baker Hughes Fellow, a title he shares with only two other people in the company—Hartley Downs and Dan Georgi. As fellows, they serve as the “external faces of Baker Hughes technology” and, internally, they promote technical excellence and provide strategic standards and advice to the technology groups. They also serve as symbols of technology career excellence within Baker Hughes by championing knowledge-sharing across the enterprise.

When Curry joined the Baker Hughes OASIS™ Engineering Services in 1996, he led the effort to provide a secure technical infrastructure for this new service, drawing on more than a decade of experience in drilling mechanics research.

After graduating from Cambridge, Curry was hired by Central Electricity Research Laboratories in Leatherhead, England, to do research on the structural integrity of nuclear power generating plants. But, when he heard that Schlumberger was opening a research laboratory in Cambridge and was looking for someone who could apply a background in fracture mechanics to drilling, he left his seemingly secure role as a research offi cer in the nationalized nuclear power industry and, in 1983, joined the “hire-and-fi re world of the oil fi eld,” as he calls it.

Curry spent six years with Schlumberger before managing the establishment of the International Drilling and

Baker Hughes Fellow

David Curry


Downhole Technology Centre in Aberdeen, Scotland. From there, he migrated to the U.S. where he served as drilling manager of TerraTek’s drilling and completions laboratory in Salt Lake City, Utah, before going back to the U.K. in 1996 to begin his career with Baker Hughes.

For eight years, Curry managed the technical support group of OASIS Engineering Services, a commercial service provided by Baker Hughes that helped customers drill more effi ciently using thorough analysis of the full drilling environment: identifying and diagnosing potential problems and the most appropriate ways to address those problems, including equipment selection, process planning and appropriate operating practices. “And, perhaps most importantly, closing the loop—after you drill the well, analyzing what happened to identify lessons learned and then carrying them to the planning for the next well,” Curry says.

His experience with the OASIS service led him back to the U.S. in 2004 as director of research at Hughes Christensen, a product line of Baker Hughes. He later served as senior technical adviser before being named a Baker Hughes Fellow in 2008.

This expert on rock property estimation and drilling performance prediction is one of the company’s most highly respected researchers.

“David exemplifi es the position of a fellow,” relates long-time friend, colleague and once competitor Dan Scott, Baker Hughes’ group leader for hard materials research. “He is a talented professional, mentor, teacher, leader and expert—a cross-functional and multidimensional person whom you meet once in a decade.”

Curry has cowritten a book, Underbalanced Drilling Manual, and more than 40 technical

papers. He also is named inventor on fi ve U.S. patents. He is a fellow of the Institute of Mechanical Engineers; a professional member of the Institute of Materials, Minerals and Mining; and to call him a “member” of the Society of Petroleum Engineers (SPE) would be a gross understatement.

Curry dedicates a great deal of time to SPE. As an example, he spent one weekend in the spring rating some 100 abstracts submitted to the Deepwater Drilling and Completions Conference in Galveston, Texas.

Curry has served on numerous committees and was executive editor of SPE Drilling and Completions journal. In 2007, he was named a charter member of SPE’s “A Peer Apart,” an elite group of editorial review committee members who have reviewed 100 or more technical papers.

> Curry and the family’s border collie, Oreo

One of SPE’s Newest Distinguished Members

David Curry was honored as a 2010 SPE Distinguished Member during this year’s Society of Petroleum Engineers Annual Technical Conference and Exhibition in Florence, Italy, in September.

Established in 1983, the SPE Distinguished Member Award honors members who achieve distinction deemed worthy of special recognition. Limited to 1 percent of SPE members, it acknowledges members who have attained eminence in the petroleum industry or the academic community, and/or who have made unusually signifi cant contributions to SPE.

34 |

Among his current organizational roles in SPE, Curry is a member of the books development committee, drilling and completion advisory committee and European forum—Automated Well Construction Factory organizing committee. He is also chairman of the R&D technical section and an ex-offi cio member of the R&D committee.

When asked why he is so involved with SPE, he quietly admits, “A lot of the things we do are actually fun, and the Society itself serves a valuable function in assisting its members to develop capabilities that are of use to society. “However, I think the real answer is that I haven’t worked out how to say ‘no,’” he quips.

In addition to all of his responsibilities and commitments, Curry makes time to counsel and coach those just beginning their careers.

“Oh, I could pontifi cate at length on that,” he admits. “I say, be prepared to admit what you don’t know and set about learning it. People will help you. There will be plenty of

graybeards around who are only too happy to point you in the right direction. Listen to them. Enjoy the instruction.

“Realize that a career is a lifelong commitment to learning—to improving your knowledge and understanding—and

to improving the way in which you use it. Understand that it can be satisfying to develop something that endures, to provide solutions, if you like, that help our clients and ultimately help Baker Hughes or the industry. There’s a lot of satisfaction to be had in that.”

Curry’s latest enthusiasm is “to stimulate the development of a single Baker Hughes subsurface model that we can use for all the different things that we do for our clients, for their particular fi eld or wells,” he explains. “We pulled together about

40 people earlier this year from different aspects of Baker Hughes to take inventory of what we are doing, how we use models of the subsurface, how we create those models and how we move forward to all work from a single, shared model.

“This is one example in which the fellowship can identify areas where we need seamless technical solutions that span the entire enterprise, and then make it happen.”

He hopes to be actively involved in this effort, but he will do it from the U.K., where

he and his wife, Jane, have returned to be closer to their children—Katie, Edward, Charles and Rachel.

In late September—between SPE’s Annual Technical Conference and Exhibition, Deepwater Drilling and Completion Conference, and the Automated Well Construction Factory—Curry is taking some well-deserved time to travel down to Cambridge for a college reunion, where the only time that will matter happened many years ago.

“Realize that a career is a lifelong commitment to learning—to improving

your knowledge and understanding—and to improving the way in which you use it.”

While a student at Cambridge, David Curry was a contestant on “University Challenge,” a televised quiz show based on the U.S. “GE College Bowl” series that pitted university squads against one another. Curry’s team, which actually won the series in 1973, was invited to participate in a 40-year anniversary competition hosted by the show’s organizers in 2002. Shown in this photo from 1973 are the bearded Curry and his Cambridge teammates, along with Bamber Gascoigne (far right), the original presenter of “University Challenge” who made “Fingers on the buzzers,” “I’ll have to hurry you,” and “Your starter for 10” now-famous catchphrases of the era.


Using guesswork while

trying to retrieve a 500-lb.

fi sh from a 30,000-ft

wellbore full of

doglegs and ‘S’

curves is like trying

to perform surgery

wearing boxing gloves.

The only way to know

with certainty that you’ve

successfully retrieved the

fi sh is to pull out of hole

and take a look at what

you’ve caught.

Operators ‘See’ Down Hole with

SMART TECHNOLOGY

As wells become deeper—and more torturous and technically challenging—the need to know more about what is actually occurring down hole becomes even more critical, as unproductive trips in and out of the well cost time and money. Traditional surface-based indicators and gauges often provide inaccurate readings of the forces exerted at and around the downhole tools.

“One of the most frustrating and costly aspects of any wellbore intervention operation is when little or no progress is made during a trip in the well, and tools are returned to surface showing no visible signs of performing work,” says Garry Garfi eld, wellbore intervention manager for Baker Hughes in Norway. “Conversely, but equally frustrating, is when a downhole tool becomes worn or damaged beyond its useable life, and the operator continues to try to make progress based on readings from traditional surface-based indicators and gauges.”

Building on existing technologyIn 2006, the Baker Hughes drilling, formation evaluation and intervention product lines set about solving these well intervention dilemmas, and the result was the Sentio™ sub—a downhole data acquisition tool based on drilling optimization technology.

SMART™ intervention services incorporate a short, modular measurement-while-drilling-style sensor sub that is integrated into the bottomhole assembly (BHA). The Sentio sub contains an array of sensors that sample critical static measurements such as weight on-mill, torque, RPM, bending moment, vibration and differential pressures. These measurements are gathered down hole to provide a clearer picture of what is occurring at and around the downhole tools. Information is then transmitted using mud-pulse telemetry to the surface where data can be analyzed in near real time at the rigsite. The system allows the operator to make informed decisions and take immediate action to optimize well intervention operations and to signifi cantly reduce nonproductive time and risk exposure.

That same information can also be transmitted to a real-time operating center where even a broader audience of experts can witness the procedure.

36 |

Answering a customer’s callIn the Norwegian sector of the North Sea, where many of the older fi elds have reached the end of their economic life and hundreds of wells are waiting to be plugged and abandoned (P&A), Baker Hughes sees a real need for SMART intervention services.

So does one major North Sea operator who recently came to the Baker Hughes Norway wellbore intervention team seeking a cost-saving solution to numerous P&A campaigns. One of those campaigns was on eight water injection wells drilled between 1990 and 1991. In 2008, the P&A of two wells took an average of 65 days. The operator was facing a large fi nancial outlay to P&A the remaining six wells.

“Their well operations team came to us and said, ‘We need a 50-m window with a section mill in a single run,’” Garfi eld remembers. (For P&A operations in Norway, the government requires that 50 m of casing be removed to expose the formation for a

qualifi ed cement plug.) Milling the window in a single run would signifi cantly reduce operation time in a geographic area where world-class North Sea jackup rig rates are signifi cant. “We knew this would be a challenge because, in the past, it normally took us several runs to mill a 50-m section of casing. Knives wear out; tools wear out.”

Fortuitously, the Houston-based research and development team had recently completed the initial lab testing of a new prototype cutter that was ready for fi eld trials.

The Norway wellbore intervention team presented the new cutters to the operator as a possible solution to its challenge of cutting a 50-m window in a single run. The team also suggested including the Sentio sub in the BHA to evaluate the effectiveness of the new cutters during this initial fi eld trial.

The result? On its fi rst attempt using the real-time SMART intervention system, Baker

Hughes delivered a 50-m window in one run, saving the operator four days of rig time.

“The most important part of this technology—and why it’s a step-change for well intervention—is that we are able to get real-time information about the downhole operation. Historically, we relied on the tools coming to surface, then making an interpretation of whether or not we were successful. With real-time information, we are able to make changes in our operational parameters while in hole,” says Vaughn Griffi n, director of the conventional fi shing product line for Baker Hughes.

“For this operator, we have been using new technology cutters and have doubled or tripled the amount of footage milled per set of cutters. Using Sentio’s real-time data, we have been able to closely monitor downhole equivalent circulating density (ECD) well characteristics to prevent well losses, resulting in huge savings for our client.”

> Data gathered from SMART™ intervention services can be analyzed in near real time at the rigsite and in real-time operating centers like this one where experts around the world can witness the procedure.


That successful fi rst run in the fourth quarter of 2009 led to a series of successes on the six-well P&A campaign that ended in April 2010.

“This was an enormous success for this customer,” Garfi eld relates. “These wells required multiple barriers of 50-m windows at different depths and different casing confi gurations. Our consistency in delivering the required 50-m window in one or two runs continued to improve throughout the campaign.

“It would take four, six or even eight runs to do a single section without SMART intervention or the new cutter technology, so it’s easy to see the huge savings to our client.”

The Sentio subThe Sentio sub is a downhole data acquisition tool based on drilling optimization technology developed by Baker Hughes. After the data are digitized, a digital signal processor in the tool analyzes all data streams simultaneously at a high data rate and out puts static measurements and computed diagnostics. The outputs are prioritized into the most suitable job-specifi c data sequence and transmitted to a rig fl oor display screen (and, if desired, to a remote real-time operations center), where they are presented in the clearest and most meaningful manner. Portions of the information can also be recorded in the on-board memory and stored, then retrieved later at surface for detailed evaluation. The Sentio sub affords the operator a completely new level of control with real-time decision-making capabilities that can lead to more effi cient and reliable wellbore intervention jobs and signifi cantly reduce operators’ risk exposure.

The ‘P’ cutterIn 1985, Baker Hughes advanced the fi shing industry with the introduction of the Metal Muncher™ cutting structure. This cutter, and its patented application for milling tools, has increased penetration rates and mill life by as much as 1,000 percent. Metal Muncher “buttons” provide downhole milling similar to the quality achieved on a machine shop lathe.

In 2009, Baker Hughes took the next evolutionary step with its introduction of a new prototype cutting structure. The “P” cutter, as it is called, has an extended or oblong shape that is one-and-a-half times as long as the standard Metal Muncher cutter. The elongated shape has greater volume to absorb impact for better breakage resistance. The elongated shape also cuts faster on the face of the mill because of fewer uncut spaces between cutters. The “P” cutter is designed in a standard grade for cutting steel and in an enhanced grade for cutting high-nickel-content metals such as Inconel† alloys. The “P” cutter structures have a controlled cutting angle and chip-breaking feature that is effective on high-chrome-content steels, and they are engineered to cut the metal away instead of grinding it.

01> Differential and annular pressure readings in the Sentio memory data show issues with packoffs and hole cleaning, enabling technicians to set up the next SMART intervention run to monitor in real time these readings, as well as ECD trends, to investigate whether the packoffs were occurring above or below the Sentio sub.

02> Technicians prepare to run a real-time SMART intervention system.

02

† Inconel is a registered U.S. trademark of Special Metals Corp.

01

38 |

The good news is the Verkhnechonskoye green fi eld is the largest oil and gas condensate reservoir yet to be discovered in eastern Siberia and holds great promise for expanding Russia’s hydrocarbon reserve base. The bad news is the immense production challenges due to the reservoir’s geologic complexity, the remote location and the lack of existing infrastructure.

To make the Verkhnechonskoye Field economically viable, the latest in sand control completion technology was required to overcome the geologic challenges and to

maximize production and ultimate reserve recovery from the reservoir.

The Verkhnechonskoye reservoir consists of shallow marine and alluvial sediments. The productive zone is represented by two Cambrian sandstone layers that range in thickness from 2.2 to 26 m (7.2 to 85 ft) and 5.5 to 20.2 m (18 to 65.6 ft), respectively, with an average depth of approximately 1650 m (5,412 ft). The layers are separated by a gradually narrowing shale deposit. As a result, both sandstone layers form a hydrodynamically connected reservoir with

a thickness of 2.7 to 22.8 m (8.8 to 75 ft).An alluvial sedimentary environment implies highly inconsistent and heterogeneous reservoir parameters.

“Due to the lack of an active aquifer, a water injection system is required to maintain the reservoir pressure,” explains Lukasz Ostrowski, director, completions and reservoir services for Baker Hughes Russia.

EQUALIZER Technology Optimizes Production, Delays Water Coning in Complex Russian Field

01> A rigsite in eastern Siberia’s Verkhnechonskoye Field on a day last winter when temperatures dipped to minus 56ºC (minus 70°F)

02> Production Optimization Engineer Ray Morrison with an EQUALIZER section

02

01


> Eddie Bowen, EQUALIZER product line manager (left), and Lukasz Ostrowski, director, completions and reservoir services for Baker Hughes Russia

2-7/8 in. Tubing

114 mm Liner Top

4-1/2 in.Casing

178 mm @ OC 152 mm, 6 in. Open Hole

Interval #5Interval #6 Packer #4 Packer #3 Packer #2 Packer #1Packer #5 Interval #4 Interval #3 Interval #2 Interval #1

“The reservoir oil is saturated, and any reduction in the reservoir pressure is undesirable.

“Although horizontal wells increase drainage area and improve recovery, water and gas tend to cone toward the heel of the well because of friction pressure drop from toe to heel and breakthrough anywhere in the well because of permeability variation along the horizontal section.”

Baker Hughes’ EQUALIZER™ infl ow control devices are widely used as a permanent part of the well completion to control fl ow from the reservoir to the wellbore along the length of the horizontal section. They manage infl ow by applying a resistance to fl ow at the reservoir face.

Choosing the optimal completion designUsing geological data from existing wells, minimum and maximum permeability values from core and well test analysis, permeability profi les are created. The success of any infl ow control device

system depends on the accuracy of this geological information, as permeability distribution along the horizontal section is a key point in completion design.

Using various possible permeability profi les, a well completion design is proposed—including the number of equalizers and the length of intervals—to effectively equalize the infl ow. The main objective of this evaluation stage is to determine whether a positive effect can be reached using the Baker Hughes EQUALIZER drainage system.

“There is a lot of interest in this technology in these Russian fi elds, where the biggest challenge is water breakthrough,” says Eddie Bowen, EQUALIZER product line manager. “Any time there is an oil/water contact, there’s the question of ‘How do you keep the water at bay as long as you can to maximize reserve recovery?’ This technology allows the operators to do that.”

“Initially, the technology is more expensive to run than conventional

slotted liners or conventional screens, but we can illustrate the value of this technology to the client through reservoir modeling before the fact,” Bowen adds.

In 2007, using production history and reservoir data supplied by the operator, Baker Hughes provided an initial concept study for completion and monitoring methodology to alleviate the infl ow balance issues in the Verkhnechonskoye reservoir. Based on the precompletion modeling, Baker Hughes recommended using the EQUALIZER system on two producing wells to obtain the best value for the operator from this complex environment.

“In our predictive modeling analysis, we took the known permeability variables confi rmed through production logging tests (PLTs), and we determined the best design for these particular wells,” Ostrowski explains. “Then, we compared that to conventional technologies and did some forecasting to show the value of the installation.”

Bowen says that an EQUALIZER installation could cost an additional $200,000 to $300,000 versus a conventional solution, “but the net present value may be 200 percent.”

(Net present value [NPV] compares the value of a dollar today to the value of that same dollar in the future, taking

Illustration 1. Typical completion design

40 |

infl ation and returns into account. If the NPV of a prospective project is positive, it is often accepted.)

Measuring the EQUALIZER system performanceThree wells were completed in this fi eld with the the EQUALIZER technology: two producers (No. 1 and No. 2) and one injector (No. 3). The planned design for the producers included a uniform arrangement of packers and EQUALIZER joints (seven EQUALIZER joints per each of fi ve zones created with fi ve openhole packers). The design for the injector included three EQUALIZER joints per each of fi ve zones. The typical completion design is shown in Illustration 1.

After drilling the candidate well, the actual profi le of permeability was built based on fi nal logs, and the completion design was updated. Packer placement depth was selected to isolate high and low permeability. The number of EQUALIZER joints was determined to mitigate high infl ow from high-permeability zones and to allow fl ow with little completion resistance for low-permeability zones. Low reservoir temperature required use of Baker Hughes’ REPacker™ reactive element packers that could swell in the given reservoir conditions.

After an initial production period, the operator ran PLTs in each well. Engineers then compared the actual to predicted infl ow profi les for the same wells without the EQUALIZER systems.

The real infl ow profi le was matched by a simulation model. Based on these models, it was possible to create a complete infl ow profi le for an openhole completion. Figures 1 to 3 show the actual infl ow profi le for the EQUALIZER system well from PLT measurement (blue), the predicted infl ow profi le for an openhole well (green) and predicted infl ow profi le for an EQUALIZER system well (orange).

“It is important to note that the predicted infl ow profi le curves for the EQUALIZER system well were calculated only after fi nal logging and were based on the anticipated liquid rate and pressure drawdown,” Ostrowski says. “However, the true production rates sometimes differ signifi cantly from the predicted rates. The model curve for the openhole completion was generated based on the actual production data.”

The infl ow profi les indicate good performance from the EQUALIZER designs in well No. 2 and well No. 3, as opposed to well No. 1. “In the case of well No. 1, we were unable to construct the appropriate permeability profi le due to lack of data.

The actual permeability was lower than anticipated, and, as a result, the EQUALIZER system did not provide any value as the real liquid rate per EQUALIZER joint is much lower than designed,” notes Ostrowski.

Even in a fi eld where reservoir uncertainty is very high, infl ow control devices can successfully equalize oil infl ow in horizontal wells. “Baker Hughes has run more than 2 million ft of EQUALIZER technology with zero reported sand failures,” Bowen notes. “The keys to optimizing infl ow control device design are accurate fi eld data, especially an accurate permeability profi le, and good reservoir modeling—the exact sort of information we had on these wells in the Verkhnechonskoye Field.”

25

20

26

00

26

80

27

60

28

40

29

20

30

00

length MD, m

% o

f liq

uid

rate

Producer Well No. 150

40

30

20

10

0

EQ factOH calcEQ calc


25

00

25

80

26

60

27

40

28

20

29

00

29

80

% o

f liq

uid

rate

Producer Well No. 250

40

30

20

10

0

length MD, m


25

90

26

70

27

50

28

30

29

10

29

90

Injector Well No. 3

% o

f liq

uid

rate

50

40

30

20

10

0

length MD, m

Fig. 1

Fig. 2

Fig. 3


LOCATION, LOCA

01 02 03

01> Baker Hughes’ facility in Barmer, India

02> Technology Innovation Center in Celle, Germany

03> Attendees view Baker Hughes’ latest technology at the opening of the Saudi Arabia facility in Dhahran. The facility is part of Baker Hughes’ expansion plans for the Kingdom of Saudi Arabia, a key growth market for the company.

04> Baker Hughes’ Vankor, Russia, facility

No company can survive without adapting to market evolutions. That is certainly true in the oil and gas industry where the players and the playgrounds shift with each new resource trend. For the oilfi eld service business, that means pushing technology boundaries and building the necessary infrastructure to effectively service the most active basins and trends.

For 100 years, Baker Hughes has been a technology leader, and in recent years the company has invested heavily to build a world-class service infrastructure to deliver that technology. From 2007 through 2011, Baker Hughes expects to invest more than $1.1 billion to add nearly 9 million ft2 (836 000 m2) of infrastructure space. This expansion includes a major Eastern Hemisphere headquarters in Dubai, more than 100 operations facilities, three major technology centers, training facilities and manufacturing plants.

Of course, none of that matters if the investment isn’t in all the right places. As they say in real estate: location, location, location. Baker Hughes heeded that axiom. The new facilities are strategically placed in growth markets around the world.

Baker Hughes in your BACKYARD

42 |

04

Middle EastThe Middle East is a major target for Baker Hughes’ expansion plans. In 2008, the company opened its Eastern Hemisphere headquarters and education center in Dubai, and this year the training capabilities at the center will be enhanced with the addition of seven test wells designed to train employees and customers under real-well conditions.

Another addition this year is an 11 148-m2 (120,000-ft2) operations center in Dhahran, Saudi Arabia. The facility, which houses laboratories, offi ces, repair and maintenance operations, and a BEACON™ real-time remote collaboration center, is part of Baker Hughes’ expansion plans for the Kingdom of Saudi Arabia—a key growth market for the company. Dhahran also will be home to a Baker Hughes technology center set to open in 2011. The center will focus on

applied research in the areas of reservoir optimization, drilling effi ciency, production and reserve recovery optimization, and specifi c technology needs to unlock Saudi Arabian tight gas reservoirs.

“Saudi Arabia is characterized by increased market growth, particularly in the gas market,” Chariag says. “The strategic placement of the operations base and the technology center shows our commitment to the Saudi Arabia and larger Middle East market. These facilities are going to play a very important role in positioning Baker Hughes as the market leader in the region.”

Russian and CaspianWith more than 9 percent of the world’s proven oil reserves*, the Russia and Caspian region is another important growth market today and for the future. Baker Hughes is

expanding its footprint through both newly built facilities and acquisitions to effectively serve Russia and Caspian customers. Earlier this year the company acquired Oilpump Services, adding four major service bases throughout western Siberia. New facilities in Usinsk, Russia; Vankor, Russia; and Baku, Azerbaijan, will further enhance operations capabilities.

“In Russia, where Baker Hughes historically didn’t have a large presence, we now have several service centers where we can locate our people in proper accommodations with closer access to our customers’ locations,” explains Chariag. “Much of the oil and gas reserves in the Russia and Caspian region are in extremely remote locations, which can create serious logistical issues. Our expanded footprint eliminates many of those headaches.”

Eastern Hemisphere“We want to invest in places for the long term, so we very carefully planned our infrastructure expansion with an eye to both today’s industry needs and future growth,” says Belgacem Chariag, Eastern Hemisphere president for Baker Hughes.

ATION, LOCATION


Western HemispherePresalt hydrocarbons offshore Brazil, shale plays in the U.S., and the Canadian oil sands have prompted facilities expansion throughout the Western Hemisphere.

> Baker Hughes’ new Leduc, Canada, facility was built to better serve operators in the oil sands and other northern Canadian oil fi elds. The chemical facility, opened in 2009, is engineered to reduce process waste by more than 10 percent compared to conventional plants.

Latin AmericaWith contracts for 50 percent of Petrobras’ offshore drilling activity, Baker Hughes is expanding its Brazil operations to support the growth of the national oil company’s activities in the Santos and Campos basins. A 5600-m2 (60,278-ft2) regional technology center in Rio de Janeiro; an expansion of existing operations bases in Macaé, including a test well for completion and artifi cial lift systems; and a 4000-m2 (43,040-ft2) manufacturing plant that will soon be announced are among the new construction projects planned for Brazil. “The number of rigs working offshore Brazil continues to expand, and we are preparing ourselves for the activity increase,” notes Nelson Ney, president of Latin America for Baker Hughes.

In 2009, Petrobras and Baker Hughes signed a cooperation agreement to develop technology that will address the different challenges for the Brazilian presalt discoveries. Under the agreement, Baker Hughes and Petrobras will open the Rio Technology Center in 2011. The technology

center will facilitate collaboration among Petrobras, CEMPES, Baker Hughes and local universities. Projects at the research facility will focus on reservoir characterization and modeling, drilling optimization and completion and production technologies to lower drilling and wellbore construction costs, as well as to optimize production and recovery through better reservoir understanding.

Baker Hughes in Latin America also is expanding its footprint in Mexico. To support increased business activity, the company is opening a new facility in Poza Rica to consolidate the different product lines and support the work in the Aceite Terciario del Golfo (ATG) fi elds. Baker Hughes has also started building a new location in Ciudad del Carmen to support PEMEX offshore operations. Both mega facilities, with 15 800-m2 (170,000-ft2) each, will have similar capabilities. “The new consolidated locations will tremendously increase our operational capacity to effectively service PEMEX projects and continue growing our market share,” Ney says.

Another area where Baker Hughes is investing in new facilities is Colombia. “Baker Hughes is very focused on supporting the growth in activity that the country is experiencing. The activity increase is driven by Ecopetrol, the national oil company, which is executing its aggressive E&P plan, as well as vast investments by international oil companies, and small and medium independent operators,” Ney says. Baker Hughes is constructing a new 7000-m2 (75,347-ft2) operational base in Neiva to consolidate all product lines, as well as initiating a project in Los Llanos to support activity related to heavy crude oil fi elds.

North AmericaLast fall Baker Hughes solidifi ed its strong market position in the Canadian oil sands with two new facilities in Alberta—a chemical blending plant in Leduc and an operations and testing center in Fort McMurray. The chemical blending plant houses a modern oil sands laboratory to produce water-treatment and fl uid-separation chemical products for heavy oil, oil sands mining, and steam assisted gravity drainage (SAGD) projects.

“We have a leadership position in the fl uids separation business in the Canadian thermal market. In order to maintain that market position, we have to keep moving the bar and advancing our product lines. This facility allows us to do that,” relates Tom Whalen, marketing vice president for Baker Hughes in Canada. “In addition, we’re the only oilfi eld chemical company with two strategically located blending facilities in western Canada. We can service all of western Canada from these locations. There’s no other company that has a similar scope of capabilities.

“The Fort McMurray facility further supports our commitment to the oil sands market. We are now able to store fl uid-separation specialty chemicals close to our customers’ operations in the Fort McMurray area,” he says. The multipurpose center houses a full range of Baker Hughes products and services, including oilfi eld chemicals, artifi cial lift systems and formation evaluation services.

Since entering the oil sands market in 2000, Baker Hughes has dramatically increased its artifi cial lift market share in the oil sands. The Fort McMurray operations center supports that growth market. “Earlier this year, we

44 |

West Africa’s deepwater fi elds present great opportunities for the future, particularly those lying offshore Nigeria. Baker Hughes has been awarded major contracts to deliver a wide range of deepwater technologies for many of these projects, including Total’s USAN Field, discovered in 2002. Through USAN, Total E&P Nigeria Ltd. expects to make a signifi cant contribution toward helping Nigeria achieve its objectives of increasing its daily oil production. To support deepwater Nigeria projects, Baker Hughes embarked on a $15-million infrastructure investment program in 2007.

Baker Hughes opened a completions and production facility at the Onne Port Federal Lighter Terminal, which is the hub for offshore oil and gas operations and logistics in west and central Africa. Construction started on the base in April 2008 and was completed in December 2009. The 463,000-ft² (43 000-m²) facility began full operations in February 2010. The workshop—designed for optimal workfl ow—includes a high-load torque machine, NAS-6 intelligent well system preparation system, tubing-conveyed loading, and large pressure-test bays.

Baker Hughes Nigeria is headquartered in Lagos and also operates a 333,681-ft² (31 000-m²) drilling and evaluation facility in Port Harcourt, as well as a newly expanded and renovated liquid mud plant and laboratory in Onne Port.

were fi rst-to-market with a much anticipated ultra temperature ESP system. Our focus on advancing ESP technology for SAGD projects has paid off, and we continue to increase our market share,” says Whalen.

Shale gas is heating up in both Canada and the U.S., and Baker Hughes is aligning to support its customer base in these plays. In Canada, the company has committed $10 million to build a fully integrated operations center in Fort Nelson, British Columbia, to support the Horn River Basin shale play. The facility is slated for completion in 2011.

In the U.S., Baker Hughes is building new facilities in Bossier City, Louisiana, and Carthage, Texas, to support the expanding Haynesville shale gas play. A new location in New Stanton, Pennsylvania, will expand the fi rm’s capabilities in the Marcellus shale area.

The fully integrated Bossier City operations center will improve effi ciency and response time for Haynesville projects. “Bossier City is in the heart of the Haynesville. The facility will allow us to respond quickly and effi ciently to operators in the play,” says Paul Butero, president of U.S. Land for Baker Hughes. The Carthage facility is shared by the Baker Hughes oilfi eld chemical and artifi cial lift product lines—both of which needed more delivery capacity and a stronger presence in the Haynesville. “Customers will get chemicals almost immediately because of the proximity of the warehouse—the turnaround should be reduced from three days to one,” relates Butero.

The 85,000-ft2 (7897-m2) operations center in New Stanton will provide offi ces, warehouse and workshop space for drilling and completion activities in the Marcellus shale. Baker Hughes has been systematically expanding its support structure in the region, and the new facility will provide much-needed local access to tools and personnel.

Deep Commitments to

Nigeria’s Deepwater Capabilities

*BP Statistical Review of World Energy, June 2010.

> Baker Hughes’ new Onne Port facility supports some of the industry’s most advanced completion and production services. On-site capabilities include NAS-6 intelligent well system preparation, tubing-conveyed loading, large pressure-test bays and a high-load torque machine.


Bakersfield, California 2010

Estevan, Canada 2009

Williston, North Dakota 2011

Dickinson, North Dakota 2009Mountain Top, Pennsylvania 2009

New Stanton, Pennsylvania 2010

Operations Base / Offices

Technology Centers

Education Centers

Manufacturing

Drilling Waste Treatment Facility

Deadhorse, Alaska 2010

Anchorage, Alaska 2009

Fort Nelson, Canada 2011

Fort McMurray, Canada 2009

Leduc, Canada 2009

Bossier City, Louisiana 2011

Carthage, Texas 2010

Lafayette, Louisiana 2009

Houston, Texas 2008 2010

Poza Rica, Mexico 2010

Monterrey, Mexico 2010

Macaé, Brazil 2011 2011 2011

Takoradi, Ghana 2009

Accra, Ghana 2010

Tripoli, Libya 2010

Onne Port, Nigeria 2010

Port Gentil, Gabon 2012

Pointe Noire, Congo 2011

Luanda, Angola 2010 2010

Rio de Janeiro, Brazil 2009 2011

Ciudad del Carmen, Mexico 2011

Bogota, Colombia 2010

Lima, Peru 2010

Neiva, Colombia 2010

Villavicencio, Colombia 2011

Baker Hughes Expansion Projects Around the World

46 |

Dubai, UAE 2010

Abu Dhabi, UAE 2010

Doha, Qatar 2010

Ras Laffan, Qatar 2011

Dhahran, Saudi Arabia 2010 2010 2011

Basrah, Iraq 2010

Labuan, Malaysia 2010

Kuala Belait, Brunei 2009

Broome, Australia 2010

Kakinada, India 2010

Barmer, India 2009

New Delhi, India 2009

Chongqing, China 2010

Sichuan, China 2010

Urumqi, China 2011

Baku, Azerbaijan 2010

Uglich, Russia 2009

Usinsk, Russia 2010

Vankor, Russia 2010

Nizhnevartovsk, Russia 2009

Tananger, Norway 2011

Paris, France 2009

Peterhead, Scotland 2010

Chiswick, England 2009

Celle, Germany 2010


Keeping Waste at Bay New Eco-Centre solution delivers one-stop waste management

> New Slains, one of Scotland’s most famous castle ruins, was inspiration for Bram Stoker’s “Dracula.” The ruins are located about fi ve miles south of Peterhead.

Like a lot of guys, Frank has a morning routine. He showers, eats a piece of toast, hugs his wife and kids, and heads out the door for work. Only his wife’s regular reminder of “Don’t forget to take out the garbage!” breaks the routine.

Frank dutifully carries the garbage, along with a bin of recyclables, out to the curb. When he comes home that evening, all the garbage his family has generated has been taken away. In a few weeks, a statement arrives in the mail. Frank pays the bill online and only thinks about the family garbage the next time he’s reminded to carry it out.

For millions of households like Frank’s, waste management is a service provided to us, and something most of us don’t spend much time thinking about.

But, waste disposal is a concern all over the world, no matter if you’re a family of four that generates a few bags of trash each week or a corporation that generates tons of waste each day to produce necessary goods and services. It all has to go somewhere.

Oilfi eld wasteStrict environmental guidelines in the North Sea—and increasingly in other parts of the world—call for the proper disposal of waste from oil and gas drilling and production. But disposing of such huge volumes is no easy, or inexpensive, task.

Offshore waste consists of both solids and liquids in the form of drill cuttings, and drilling fl uids and oil-contaminated water known as “slops.” It’s not uncommon for the drilling process of a North Sea well to produce 800 metric tons (882 tons) of solid waste and more than 850 m³ (30,000 ft³) of fl uid waste. Where does it all go?

Current legislation in the North Sea prevents discharging cuttings containing more than 1 percent oil into the sea, but current solids control equipment on drilling rigs cannot remove suffi cient oil to meet this requirement. As a result, operators have two options:

Contract with waste management companies to transport the cuttings

and the fluids to separate treatment facilities onshore where they are recycled, incinerated or sent to a landfill

Reinject cuttings by mixing drill cuttings and other oilfield wastes with water and pump it at high pressure into a dedicated disposal well. This eliminates the need to transport the waste to shore, but it requires the additional costs of drilling an injection well.

Single-source clean solutionWith the opening of its new Eco-Centre™ waste management facility in Peterhead, Scotland, in June, Baker Hughes introduced a complete drilling waste treatment and disposal solution in a single facility. No longer do operators have to send solid and liquid drilling wastes to separate companies for treatment and disposal. Both can be processed and recycled at one location in this modern, purpose-built facility that meets or exceeds all local environmental standards. The center has the capacity to process and recycle 30 000 metric tons (33,069 tons) of drill cuttings and 14 000 m3 (495,000 ft³) of slops per year.

01

“Our experience is that to date, millions of liters of slops are being stored around the northeast of Scotland with no viable, complete, treatment solution available,” says Rohan Cree, U.K. sales manager for FES. “The Eco-Centre waste management facility’s slops treatment technologies will address this problem and also offer reuse of the recovered components.”

In short, it’s a single-source environmental solution to operators’ waste management requirements to ensure full compliance with regulatory mandates while providing a fully auditable trail via Baker Hughes’ game-changing EcoLink™ online tracking system.

Strategically located at a Baker Hughes-owned location close to the busy Peterhead Harbor, the Eco-Centre facility also recycles and reuses onsite waste streams—including recovered base oil from both drill cuttings and slops fl uids—reducing the overall carbon footprint of the facility.

Following processing, recovered solid materials are used in place of quarried aggregates to cap landfi lls. Recovered water is used to cool and rehydrate the recovered solids; recovered oil is used as fuel for the processing unit. Even rainwater is collected and used on site.

A unique feature of the 75,000-ft2 facility is the Baker Hughes global drilling waste management research and development department—a group of researchers dedicated to developing the next generation of waste management solutions. (See related story, Page 51.)

Game-changing technologyPerhaps the key value of the Eco-Centre solution is the ability to provide operators 24/7 online access to the overall processing of their waste streams. From the rigsite to its fi nal disposal, the waste streams are clearly tracked and documented according to regulatory requirements, giving clients a consolidated audit trail to demonstrate the complete accounting of their wastes from “cradle to grave.”

The EcoLink online tracking system, developed by the Baker Hughes IT group, makes this documentation possible.

“Operators have a legal obligation to the government to know where all the waste produced at their wellsite is at any given time,” Cree notes. “They have to provide reports on a regular basis detailing how much waste has been produced from a project and where all that waste is following treatment.”

The EcoLink system streamlines this process. “Our customers can sit in their offi ces, open a Web portal and have immediate access to a wealth of reports that we’ve generated for them,” Cree says. “They have never had access to anything like this before. They also have the knowledge that we are using best available technology to treat their wastes in an effi cient and compliant manner.”

Cree calls the EcoLink technology a true “game-changer” in that, historically, waste management and its cost has been an afterthought. “A month or two after a well is fi nished, an invoice will land on an

operator’s desk asking for so many tens of thousands of pounds,” he says. “With our software tracking system, we’re going to give them quantitative data throughout the entire waste management process. Within a matter of hours, we can show clients where all of their waste is and give them an estimated fi gure on the costs incurred.”

The role of an Eco-Centre facility goes beyond serving as only a physical processing center. It represents a fully integrated solution to address customer needs no matter where they are located. The Peterhead facility is a template upon which other similar waste management centers can be modeled. Future facilities are under consideration in Norway, Brazil, Africa, Australia and the U.S.

“Being able to treat all wastes associated with drilling a well at one location eliminates a lot of hidden costs like mileage, fuel and skip rental that are involved in storing waste fl uids and solids,” Cree says. “It also reduces the risk involved with numerous vehicles going up and down the roads in the U.K. taking waste to different facilities. Our aim is to provide an exceptional level of service and do it with an eye on our environmental future.”

01> Peterhead has long been a major fi shing port in eastern Scotland. Today, the busy harbor is shared by fi shermen and vessels servicing the oil and gas industry.

02> John Cleary, Eco-Centre manager, left, and Rohan Cree, U.K. sales manager for Fluids Environmental Services group

02

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50 |

Bluer Waters Greener Futures

The visionaries behind the creation of the Eco-Centre™ waste management concept wanted to fi nd solutions to drilling waste management challenges faced by offshore operators today without leaving an unfavorable environmental legacy for the generations of tomorrow.

The result is a fully licensed facility capable of not only treating and recycling drilling wastes (slops and drill cuttings), but also housing a R&D center designed with the future in mind.

“The products that we are looking to develop are not just for use at this or future Eco-Centre facilities we plan to build,” explains Martin Gilbert, global R&D manager for Baker Hughes. “These products are being developed for our global markets, and because of the hazardous classifi cation of drilling waste, we can’t just develop these solutions anywhere. This is why we need a global R&D facility on a licensed site.”

Drilling wastes that contain oily residues are classifi ed as hazardous waste and must be disposed of by following strict local and federal environmental guidelines.

Facilities that treat hazardous waste in the U.K. must adhere to Scottish Environmental Protection Agency (SEPA) guidelines and have an Integrated Pollution Prevention and Control (IPPC) Directive permit that outlines operational measures to control emissions to the environment.

The Peterhead Eco-Centre waste management facility gives Baker Hughes the opportunity to showcase and develop best-in-class drilling waste management solutions at the only dedicated R&D facility on an IPPC-licensed site in the U.K.

“This R&D facility will become a global center of excellence to develop the next generation of drilling waste management environmental solutions,” Gilbert says. There is no other R&D facility like it with direct access to drill cuttings and waste fl uids.”

In addition to developing an onshore drilling fl uid slops water treatment system that is now part of the center’s operations, researchers are working on three additional development projects. They include:

A solid-liquid-liquid oil-base mud reclamation system that recovers all valuable fractions of the waste stream for reuse

A manless tank/vessel cleaning system combined with a mesophase engineering solution to enhance cleaning operations. (Mesophase is a chemistry developed by Baker Hughes that can solubilize oil on contact and water-wet drilling waste.) This system will demonstrate a commitment to create a step-change to remove tank-cleaning personnel from potentially hazardous environments.

An offshore drilling fluid slops processing system that will reduce the operator’s carbon footprint and associated CO2 emissions from shipping waste onshore for processing and disposal.

01> Charles Knight transfers segregated drill cuttings from dedicated bulk storage silos to the thermal cuttings cleaner for processing.

02> Scientist Fiona Bruce tests chemical oxygen demand concentrations—one of the facility’s requirements for discharging wastewater to foul sewer.

01

02

R&D


TRUE COLORS

Children from St. Fergus Primary School designed a special tartan to commemorate the opening of the new Baker Hughes Eco-Centre™ waste processing facility in Peterhead, Scotland.

The company invited local schools to come up with a design that incorporated the Baker Hughes corporate colors and the green credentials of the Eco-Centre facility, and the 17 youngsters in Sarah

Warrander’s class, who happened to be doing a project on Scotland, rose to the challenge.

Six-year-old Callum Watson designed the winning tartan. The distinctive blue, orange and green tartan was then woven into scarves and travel rugs by a local mill, Smiths of Peterhead. The students were special guests during the Eco-Centre facility’s opening ceremony on June 23.

Claire Adam, marketing specialist for Baker Hughes Fluids Environmental Services, says, “The children’s enthusiasm in coming up with suitable tartan designs shone through, and we had some remarkable entries. We also had some great help and advice from Smiths of Peterhead, and I am sure the rugs and scarves will prove to be very popular.”

TRUE COLORSBaker Hughes Blue Woven into Commemorative Tartan

> Claire Adam, marketing specialist for Baker Hughes Fluids Environmental Services, with winning tartan designers from St. Fergus Primary School: Callum Watson (far right), who designed the winning pattern; and Tyler Holroyd and Faith Allan who were chosen as runners up.

52 |

Growing up the son of illiterate farmers in

rural Angola, Helder Nzuzi Domingos knew

that his chances of going to college were

remote. Still, he dreamed of opportunities

that a college degree could bring.

ANGOLA

LIBYA

NIGERIA

SUB SAHARAN

AFRICA

NORTH AFRICA

Baker Hughes Scholarships Open Doors to

OPPORTUNITY

Now, as an electrotechnical engineering student in the capital city of Luanda, Helder’s dream is even bigger—making electricity available to the majority of people in his native land.

“In my opinion, one of the greatest problems in Angola is the lack of electricity for most of the country’s population,” the 23-year-old

says. “Only 20 percent benefi t from having electricity, and I feel responsible for doing something to improve this condition in the future.”

Thanks to help from Baker Hughes, Helder and 85 other young people are pursuing college degrees—and the opportunity to change the world around them.

With a $2.5 million grant from the Baker Hughes Foundation in 2008, the company launched the Baker Hughes Scholars Program in Angola as a four-year commitment to the growth of Angola’s educated, skilled workforce. The program is designed to encourage the next generation of technology and business leaders to become important contributors in advancing the country’s development goals.

> Scholarship recipients are honored at a ceremony hosted by Baker Hughes.

Good Neighbors


While Baker Hughes established the application criteria, the Institute of International Education administers the program and selects independent academic panels to determine scholarship recipients. All recipients are chosen by merit. Forty-two scholarships were given out in 2008; 44 were presented in 2009; and another 20 were awarded recently. Nearly all of the students are the fi rst in their families to pursue higher education.

The all-inclusive scholarships indirectly benefi t entire families by covering everything from students’ tuition and textbooks to laptops and transportation—even meals, says Jennifer Cutaia, Baker Hughes’ government relations director and company liaison for the program.

“When we approached the universities to address needs, we learned that many have faced tremendous hardships as heads of households to their younger siblings,” Cutaia recounts. “We knew then that successful completion of their degrees meant offering support beyond their tuition payments.”

“This scholarship changed everything in my life,” says 23-year-old geophysics student António João Gunza Eduardo. “Just before I got the Baker Hughes scholarship, I was thinking about dropping out of college. With the scholarship, I can actually buy books, and I have purchased my fi rst computer. I can also spend the whole day in the library studying without being hungry. I could never thank Baker Hughes enough for this. Thanks to Baker Hughes, I will graduate next year.”

The 86 scholarship recipients attend eight different colleges and

universities in and around Luanda, but most (62 percent) attend Angola’s largest and most prestigious university, Agostinho Neto. The majority of students are enrolled in engineering and science fi elds, although 12 percent are pursuing business degrees.

In return for the renewable grants, the students are obligated to maintain a certain grade point average. They are not obligated to Baker Hughes in any way, although six have earned internships in the company’s Luanda offi ce, says Duncan McWilliam, managing director of Baker Hughes Angola.

“These bursaries are extremely important to the students, to our industry and to the future of Angola,” McWilliam relates. “Because they are given on the basis of merit, the country’s best and brightest students will soon be entering the marketplace. We have been making other companies in the oil and gas industry aware of the potential of these soon-to-be new graduates and encouraging them to consider hiring some of them.”

With a fi rm belief in these young people and their ability and willingness to help improve their world, Baker Hughes has expanded its commitment to $6.2 million to extend the scholarship program through 2016.

“There is no end to the demand for these scholarships,” McWilliam said. “These young people see them as an opportunity to help accelerate the economic growth of their homeland, and Baker Hughes is proud to be a part of that legacy.”

01

02

01> Helder Nzuzi Domingos with Miriã Cazanova, one of his professors at the Universidade Agostinho Neto

02> During a scholarship awards ceremony, Heather Theisen-Gandara, assistant director for International Exchange Programs at the Institute of International Education, presents a Baker Hughes backpack to António João Gunza Eduardo, now a geophysics major at the Universidade Agostinho Neto.

54 |

18.5million

Population of Angola

481,354 square miles

Land area in Angola

13.5 billion barrels

Angola’s proven oil reserves

$2.5 million

Funds the Baker Hughes Foundation provided to establish the Baker Hughes Scholars Program in Angola

$6.2 million

Baker Hughes’ planned contributions to continue the scholarship program through 2016

106 Scholarship recipients over the last three years

84percent

First-generation college students

24 percent

Female scholarship recipients

Hiring, training, building

Investing in Angola’s FutureOil is the backbone of Angola’s economy, making up more than 90 percent of the country’s exports. With production at one million barrels per day (B/D), Angola is ranked as the second largest producer of oil on the African continent, and according to the Angolan Embassy in Washington, D.C., it is expected to soon surpass Nigeria, which has a current output of more than two million B/D.

For more than 30 years, Baker Hughes has provided products and services to the Angolan petroleum industry. Today, more than ever, Baker Hughes is committed to providing superior technology advancements and operational excellence to recover Angola’s vast hydrocarbon resources.

Equally important is the company’s plan to drive the local economy and to contribute to social programs that will improve the quality of life for Angolans. Baker Hughes employs more than 460 people at its four Angola locations, and almost 75 percent of the fi rm’s workforce is Angolan. Along with hiring and training local nationals, Baker Hughes is investing more than $80 million in capital projects across the three regions in which it operates: Luanda, Soyo and Cabinda. This infrastructure expansion project, which began in 2009, is one of the largest single investment programs by Baker Hughes anywhere in the world.

The expansion includes:

Construction of a new $22-million operations facility at the Sonangol Integrated Logistic Services (Sonils) base in Luanda, where the Baker Hughes Angola operations have been based since 1999

A $29-million investment in new staff housing in Luanda A $14-million investment spanning two years to build a new service facility in Malongo/Cabinda

Other projects include opening a new BEACON™ remote collaboration center; a production chemicals bulk storage and mixing facility at the Sonils base; new headquarters for the Angola leadership team; an upgrade to the Soyo drilling service facility and expansion of the existing production chemicals blending plant in Soyo that is operated by Baker Petrolite Angola Ltd., a joint venture with Vernon Angola Services Inc.

By the Numbers

> The newly opened $22-million operations facility at the Sonils base in Luanda


LATEST TECHNOLOGY from Baker Hughes

NEXT-DRILLThe Baker Hughes NEXT-DRILL™ system is a customized, invert emulsion drilling fl uid, providing superior wellbore stability when compared to conventional oil-based muds while satisfying the performance and economic expectations in the conventional/unconventional shale market.

A fl exible high-performance invert emulsion system, NEXT-DRILL fl uids will enable an operator to drill highly dispersive or reactive formations, depleted zones with tight equivalent circulating density constraints and pressured sands, and also effectively handle loss of circulation problems. The NEXT-DRILL offering can be formulated with diesel or mineral oil depending upon rheology requirements, anticipated hole problems, fl uid density and base oil availability.

The system is an upgrade of the CARBO-DRILL™/CARBO-SEA™ system, the long-standing industry standard invert emulsion system. The NEXT-DRILL system gives the customer the fl exibility of applying novel technologies and best practices, along with patented engineering modeling to meet the specifi c requirements of a well. While some of the components and performance mechanisms are similar to the CARBO-DRILL/CARBO-SEA system, NEXT-DRILL varies signifi cantly in that it leverages improved products and wellbore modeling to reduce whole mud losses and associated nonproductive time.

The NEXT-DRILL fl uid is compatible with a wide range of internal phase salinities and can be used with calcium chloride (CaCl2) or sodium chloride brines. However, the system has been designed with lower internal phase salinities (10 to 15 percent wt CaCl2) to provide a fl uid that is more balanced with the activity of the formation—an integral component for wellbore strengthening.

AutoTrak VThe AutoTrak V™ system, the latest addition to the Baker Hughes fl eet of AutoTrak™ rotary steerable systems, lets operators effi ciently drill vertical intervals with excellent borehole quality and little, if any, surface intervention. By eliminating the need for the correction runs often required with conventional drilling systems, the AutoTrak V system maximizes overall rate of penetration (ROP) and can drill a straight, vertical hole in environments where deviation control is problematic, or whenever the need to drill a precise vertical interval to intersect a target is required.

Unlike competing products, the AutoTrak V tool features a real-time, continuous inclination measurement service that guarantees on-target well placement without the use of an additional measurement-while-drilling (MWD) tool. It is built on Baker Hughes’ 15-year experience in developing high-performance, automatic vertical-seeking systems that have drilled millions of feet.

The perfectly straight vertical borehole delivered by the AutoTrak V system minimizes the risk of wellbore collision in pad drilling applications, and the superior hole quality reduces operational risks during wireline logging and when running casing. The AutoTrak V system also saves rig time by minimizing—or even completely eliminating—reaming operations.

ROP is improved because the AutoTrak V system eliminates time-consuming sliding intervals experienced with conventional drilling systems. Real-time, near-bit inclination measurement enables operators to drill to target without additional MWD tools, further improving economics and simplifying operation.

The AutoTrak V tool is guided by three hydraulically controlled steering ribs that provide continuous steering control, resulting in a smooth wellbore that minimizes reaming prior to completion operations. The fully rotating system keeps the well vertical, just as planned, and gives operators a cost-effective wellbore on time, on plan and on budget.

To further increase drilling speed, the AutoTrak V system can be enhanced with the addition of one of Baker Hughes’ proven Navi-Drill™ downhole motors to match your specifi c application and maximize ROP. A comprehensive choice of motor confi gurations provides exactly the right performance characteristics for the application and allows for reduced drillstring RPM in order to reduce wear and tear when drilling through abrasive formations.

56 |

Ultra-Temperature ESP System Baker Hughes has installed the world’s fi rst ultra-temperature electrical submersible pumping (ESP) systems in steam assisted gravity drainage (SAGD) wells in the Canadian oil sands. The ESP production systems are capable of operating in fl uid temperatures up to 250°C (482°F), allowing operators to increase their production, reduce their steam-to-oil ratio (SOR), skip the gas lift phase, and produce immediately by steaming through the ESP. These new ultra-temperature systems can also be used to extend system run life in cooler SAGD applications.

The ultra-temperature ESP systems are the result of several years of intensive research and development in specialized testing facilities at Baker Hughes’ ESP product center in Claremore, Oklahoma. The one-of-a-kind testing facilities allow Baker Hughes’ research and development engineers to not only design and test ESP equipment at fl uid temperatures up to 300°C (572°F), but also to simulate the horizontal orientation and temperature cycling characteristics of SAGD wells. The tests conducted in the dedicated high-temperature test loop ensure that the highest levels of reliability are designed into the ultra-temperature ESP systems. Reliability for longer run life means increased production and lower operating costs for customers. Industry experts believe the increase in production is due to a larger steam chamber and more missive oil at higher temperatures.

The ultra-temperature system completes the Baker Hughes elevated temperature family of ESP production systems. The high-temperature systems operate reliably in fl uid temperatures up to 163°C (325°F). The extreme temperature systems operate reliably in bottomhole temperatures up to 220°C (428°F).

TORXS Expandable Liner Hanger Packer SystemThe Baker Hughes TORXS™ liner hanger system is the only expandable liner hanger system that can be run and installed conventionally, without requiring a critically timed high-pressure plug bump as the primary activation method for the hanger or packer, or for release of the running tool. The high-torque and hydraulically balanced system is ideal for extended-reach drilling wells, and a reduced outside diameter enables it to provide better cement jobs in low equivalent circulating density environments.

The TORXS system eliminates dependence on a plug bump, because all hydraulic activations, including tool release, occur with pressure acting on a positive seal in the running tool. This minimizes the risk of poor-quality liner-to-cement bonding that can occur when a liner is ballooned with a high-pressure plug bump.

The TORXS packer system can be used in a variety of operations, including deviated wells, deep or shallow wells, extended-reach wells, straight holes, frac liners, liner tiebacks, scab liners and monobore completions. It is compatible with the Baker Hughes Hyfl o™ diverter valve for fast-running in close tolerance liners or liners run in weak formations.

The TORXS system is now available in a 7-in. x 9⅝ in. size, and two other sizes—a 5-in. x 7-in. and a 7⅝-in. x 9⅝-in. system—are scheduled to be commercially deployed later this year. Ultimately, the system will be available in six different sizes.

> SAGD project in the Canadian oil sands > Adjustable swage in the TORXS system compensates for any

variations in casing diameter to assure constant swaging forces.


It’s no small wonder that, wherever oil is found, the Baker Hughes name is synonymous with drill bit technology. After all, it was the original two–cone rotary drill bit that launched the Hughes Tool Co.—and revolutionized the fl edgling petroleum industry.

Howard Hughes Sr. was among the turn-of-the-century entrepreneurs who took a chance on striking it rich in the booming oil fi elds of Texas. Born in Missouri in 1869, he attended Harvard

College and the State University of Iowa Law School. For a short while, he practiced law with his father in Iowa, but he yearned for a more adventurous (and lucrative) career. The bustling lead and zinc mining industry near Joplin, Missouri, seemed like a good place for a young man to try his luck. But, like so many others of his day, when the oil boom in east Texas beckoned, he heeded the siren’s call, leaving law and mining behind. It didn’t take Hughes long to fi nd his fortune.

Bit by Bit, Howard Hughes Sr. Built an

A Look Back

58 |

906

Hughes teamed up with Walter Sharp to start a contract drilling business, operating in Louisiana and Texas. Hughes was eager to develop a better way of drilling that would outdo the cable tool (impact) method used by most drillers or the rotary method that used fi shtail bits. Because fi shtail bits could only scrape the rock away, they were limited to drilling in soft formations. By 1906, Hughes was working on ways to effi ciently drill through harder formations using a rotary method that pulverized the rock.

While visiting a machine shop where his drilling tools were being repaired, Hughes noticed an emery wheel with two outer wheels moving in one direction and an inner wheel moving in the opposite direction. Applying the same concept to a multicone rock-cutting tool, he built a wooden model of a drill bit with two cone-shaped, rolling cutters.

What happened next would change the way oil wells were drilled for the next 100 years.

In 1908, Hughes and his partner built the fi rst two-cone bit made of steel. On Aug. 10, 1909, the Sharp-Hughes bit was granted a U.S. patent. That same year, the partners formed the Sharp-Hughes Tool Co. in a rented space in the corner of the Houston Car Wheel and Machine Co.—within walking distance today of the Baker Hughes

corporate headquarters. Walter Sharp died in 1912, and Hughes purchased Sharp’s half of the business. It was renamed Hughes Tool Co. in 1915.

After Hughes’ death in 1924, his only child, Howard R. Hughes Jr., assumed control of the company as its sole owner. Nine years later, Hughes Tool engineers created a tricone rotary drill bit and, from 1934 until 1951, when other companies started making similar bits, Hughes’ market share approached 100 percent. The Sharp-Hughes rock bit drilled for virtually all the oil discovered during the initial years of rotary drilling, and Howard Hughes Jr. became one of the wealthiest people in the world. In 1972, he took Hughes Tool Co. public and realized $150 million the day it sold, according to an article in Texas Monthly magazine.

The company’s engineers continued to lead the industry in drill-bit innovations. In 1976, Hughes Tool introduced bits with synthetic diamond cutters called polycrystalline diamond compact (PDC) bits.

The merger of Hughes Tool Co. and Baker International in 1987 created Baker Hughes Incorporated. Today, Baker Hughes continues to develop and manufacture world-class PDC and tricone rotary drill bits at several locations around the world.

The Sharp-Hughes rock bit drilled for virtually all the oil discovered during the initial years of rotary drilling.
