CONNE US 2011 | Volume 2 | Number 2
The Baker Hughes Magazine
A Technical Evolution
Creating New Material
Learning the nature of shale reservoirs is key to ultimate recovery
FracPoint completion system is a result of customer demand for new technology
Innovative chemistry leads to groundbreaking nanostructured material
Balancing the Risks and Rewards In this issue of Connexus—as well as upcoming issues—you will find articles on projects with a scope much larger than the traditional oilfield service model. We are living through an inflection point in the market and, increasingly, customers are requiring service companies to provide not only products and services for well construction, completion and production, but also project management, logistics and other activities. This is the world of integrated operations, or IO, as we call it in Baker Hughes. A growing number of the projects we compete for today are being driven towards an integrated service model that allows our customers to simplify contractual and operating practices while improving efficiencies and mitigating technical and commercial risks. This trend started as national oil companies matured and began working directly with oilfield service companies to provide more holistic solutions, but now integrated operations is embraced by independents and even the world’s largest integrated oil companies.
> Martin Craighead President and chief operating officer < Darrell Howard President, integrated operations
At the highest level we are focusing on two tracks of integrated operations: multiservice integrated packages, which include project management and turnkey services; and field management projects that encompass reservoir studies, field development plans, procurement, project construction and some production management support. We are establishing centers of excellence where we can build bench strength and grow in a structured, deliberate way along these two tracks in the IO space.
Integrated operations is the fastest growing segment in our industry. The reopening of the Iraq exploration and production market was an inflection point for this business. Today, a significant amount of the IO activity is centered in the Middle East, but other emerging markets include Russia, Asia, Africa and Latin America. For instance, Mexico is embracing the field management model to redevelop mature fields. Even U.S. unconventional shale projects are moving to a full-service model where oilfield service companies are contracted to manage multiwell developments. It’s a global phenomenon across all of our market sectors and a trend that looks set to continue. With this explosive growth comes challenges for oilfield service companies like Baker Hughes. This can be a high-reward business, but IO business models typically require a longer-term view to return on investment and a wider perspective on the understanding and management of risk. This evolution from a predominantly transactional product and services project scope is changing our perspective on implications for growth over the next few years. It has organizational, portfolio, process and talent implications. It is important to recognize that not all IO projects are a good fit for us. The service sector can’t just look at IO projects through the lens of market share—we must clearly understand which IO projects give us the best chance to meet our customers’ objectives, where we believe we can add some critical advantage, and where we can identify suitable profit margins to deliver sustainable value to our shareholders. Projects that foster long-term working
relationships with our customers and that lock in volume for our more traditional businesses are the most attractive.
could be busy for many years on this project, delivering both Petronas’ and Baker Hughes’ business drivers.
Many of the portfolio decisions we’ve made in recent years were driven, in part, by our need to enhance our capabilities to make IO a more convenient business. The acquisition of several expert reservoir companies that today make up the Baker Hughes reservoir development services group was vital to compete for field management IO projects. And the acquisition of BJ Services was important to round out our well construction capabilities. Additionally, our reorganization to a geomarket structure is positioning us extremely well in the IO space. Our business segments and geomarkets are working together to leverage the depth of our product lines to build differential solutions for the IO business. We have the strongest downhole portfolio in the industry and we are organized to take full advantage of our strengths.
The exponential growth in the IO market is highlighting a critical shortage in the demand for skills in our sector. There are several important competencies needed for this business including petroleum and drilling engineering skills; wellsite supervisory personnel qualified to drill complex wells; commercialization specialists to understand the commercial requirements of a project to effectively align the risks and rewards; and project coordination and logistics specialists. These are all skills that are in equal demand on the operating side of the business and the industry is starting to recognize the need for more comprehensive recruiting and training programs in this area—particularly in combination with the high technology side of the services business.
The year 2011 has been one of step change for us in terms of business growth for IO and the foundations laid this year promise continued growth into 2012 and beyond. Just a few examples include a recent well construction IO contract award by Lukoil for the West Qurna field in Iraq. In Mexico, we were awarded a production incentivized contract by Pemex in Mexico’s Burgos basin. This award was based on our successful execution of a Chicontepec basin field laboratory project for Pemex. Earlier this year, Petronas awarded us a reservoir study project for a major field redevelopment project for block D-18 offshore Malaysia. Our teams of geoscientists, along with our well construction and production experts,
Finally, we have recently recruited a toptier executive to lead our IO team. Darrell Howard joined Baker Hughes in August from VICO Indonesia, a BP-Eni joint venture. Prior to his appointment with VICO, Darrell’s long career with BP spanned various global assignments covering all aspects of the technical and commercial side of this business. With Darrell’s guidance we are building a clear charter to combine the best of operating practices and service technologies together, creating a differential value proposition in this space.
12 On the Cover The unusual properties of cylindrical carbon molecules found within multiwalled carbon nanotubes are valuable for nanotechnology and other fields of materials science and technology.
2011 | Volume 2 | Number 2
Anything but Conventional The Baker Hughes FracPoint™ multistage fracturing system is one of the many innovative technological advances developed to support the needs of operators in shale plays. Because its modular system can be optimized according to customer specifications, it is a technical evolution in progress.
Understanding Stress A recent Baker Hughes study in West Virginia’s Huron shale uncovers some surprising answers on how unconventional reservoirs reveal themselves and where operators should best place their wells to be profitable.
Clean and Green The Baker Hughes integrated operations group is managing the well construction and data collection operations of a CO2 storage project for the University of Wyoming’s Carbon Management Institute.
Starting from Scratch
As far as numbers go, OGX Oil & Gas is a small player in Brazil, directly employing fewer than 300 people. However, the company is making a big splash in the offshore exploration arena, and Baker Hughes is helping manage its operations.
OGX Oil & Gas executives Paulo Mendonça and Reinaldo Belotti share insight into what sets the private sector company apart from the larger oil and gas companies operating in Brazil.
Norway’s niche operators are rethinking integrated operations and relying on companies like Baker Hughes to provide innovative approaches to project management.
Drill Power The Baker Hughes AutoTrak™ rotary steerable drilling system transformed the practice of directional drilling when it was introduced. See what’s next.
Faces of Innovation
Meet Soma Chakraborty, a nanotechnology expert at the Baker Hughes Center for Technology Innovation. The girl who loathed chemistry in elementary school went on to synthesize multifunctional organometallic systems at the internationally acclaimed Indian Institute of Technology in Mumbai.
For the past 12 years, the Baker Hughes Express cycling team has been a part of “the world’s biggest party on wheels,” riding more than 150,000 collective miles and raising more than $840,000 to help find a cure for multiple sclerosis.
Baker Hughes develops and delivers new technologies to solve customer challenges in the areas of reservoir characterization, coring services and wellbore cleanup.
A Look Back In 1914, William S. Barnickel developed a chemical process for separating water-in-oil emulsion. His TRETOLITE™ brand of fluids separation technologies is still an important product offering from Baker Hughes.
One Colossal Discovery Baker Hughes materials scientists have discovered a groundbreaking nanostructured material technology that is lightweight, high strength and capable of disintegrating down hole. Baker Hughes has incorporated the technology into its IN-Tallic™ disintegrating frac balls used with the FracPoint™ multistage fracturing system.
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Editorial Team Kathy Shirley, corporate communications manager Cherlynn “C.A.” Williams, publications editor Tae Kim, graphic artist Tiffany Fernandez, contributor Erica Bundick, contributor Monique Hitchings, contributor Printed on recycled paper
> The Baker Hughes FracPoint multistage fracturing system uses packers to isolate intervals of the horizontal section with frac sleeves between the packers. The frac sleeves are opened by dropping balls between stages of the fracture treatment program. As the ball reaches the sleeve, it shifts the sleeve open—exposing a new section of the lateral and temporarily plugging the bottom of the sleeve. This provides greater control of the fracture treatment and allows for fracture treatments along the full length of the horizontal wellbore.
A completion system that’s anything but conventional Unconventional shale plays in the U.S. have been developed at a fever pitch in recent years due to the combination of horizontal drilling and multistage fracturing technologies. This activity has also spawned a frenzy in development of downhole technology to enable operators to produce wells more economically. “When it comes to unconventional shales, there has been an extremely rapid introduction of new products. The best way I can describe it is a ‘technology rat race,’” says Jose Iguaz, U.S. Land business development manager for Baker Hughes completions. “It’s like nothing we have ever seen in the past for completion systems, where product life has typically been five, six, or maybe 10 years, and, now, we are seeing products becoming obsolete within two to three years.” The Baker Hughes FracPoint™ multistage fracturing system is one of the many 4
innovative technological advances developed to support the needs of operators in the shale plays. The system provides operators a way to economically complete horizontal wells in unconventional formations that require fracturing operations, while accelerating and increasing their net production, eliminating wireline and coiled-tubing operations, and reducing expensive pumping operations. The FracPoint multistage fracturing system is a modular system that can be optimized according to customer specifications. “Everything we’re doing with FracPoint technology is operator driven,” says Jack Farmer, Baker Hughes product line manager of unconventional completions. “The whole evolution of FracPoint technology has come about from U.S. customers asking for new developments—from our first frac sleeve system that could do five stages to today’s incredibly long laterals with 24 to 30 and up to 40 stages.”
The FracPoint multistage fracturing system uses Baker Hughes’ openhole packers and specially designed ball-activated frac sleeves that isolate zones or intervals of a horizontal section and pinpoint fracture placements in the wellbore without cementing. The system comprises five major components: the wellbore isolation valve; the pressure-activated frac sleeve or P-sleeve; either the FracPoint shortradius hydraulic-set openhole packer or the Baker Hughes REPacker™ (reactive element packer) system; the ball-activated frac sleeve; and the liner hanger packer incorporating a tieback receptacle. The tieback receptacle gives the operator the ability to tie back the casing to the surface if needed at a later date. Aaron Burton, product line strategist for FracPoint technology, explains how the system works: “Typically, the first stage of this system involves the P-sleeve, which www.bakerhughes.com
is opened by simply pressuring up to the predetermined activation pressure. Once the sleeve is opened, the first-stage fracture begins. After completing the first-stage fracture, a fluid flush is pumped, and the ball that corresponds to the second stage is dropped into the flush.” When the ball reaches the seat, pressure is applied to the ball to open the sleeve, and the second-stage fracture is performed. During the fluid flush between the second and third stages, the ball corresponding to the third-stage frac sleeve is dropped, and the process repeats itself until all stages have been completed.
fracturing process of the wellbore is critical as the total completion cost for a horizontal shale well ranges between 40 and 60 percent of the total well AFE [authorization for expenditures].” Introduced in 2006, the FracPoint openhole fracturing system has been continuously enhanced through various generations,
technology uses patented ball seats that provide additional mechanical support to the ball during pumping operations.”
nanotechnology-enabled material that is being used to produce disintegrating frac balls. (See related article on Page 8.)
In March, using the FracPoint EX-C system, Baker Hughes installed a record-setting 40-stage openhole completion system in North America’s Williston basin, which is known for extremely long laterals. This was the most stages ever performed in a single lateral frac sleeve/packer completion system.
This interventionless technology uses a new class of engineered materials that is fully degradable. The high-strength, lightweight nanostructured material is composed of controlled electrolytic metallics technology and has been incorporated into the nextgeneration FracPoint completion system with IN-Tallic™ disintegrating frac balls.
The FracPoint system is currently used to complete an average of 19 stages per well in the U.S.
multistage fracturing system is one of the many innovative technological advances developed to support the needs of operators in the shale plays.
“Each time the sleeve is shifted open, a new section of the lateral is exposed and the previously fractured section is temporarily plugged by the ball sealing on the ball seat,” Farmer adds. “Each of the newly exposed sections is referred to as a stage, and each stage is isolated by openhole packers spaced out on either side of the sleeve. This provides greater control of the fracture treatment and allows fracture treatments along the entire length of the horizontal wellbore, increasing production.” Compared to the plug and perf method, FracPoint technology eliminates perforating and liner cementing operations. It saves time during fracturing operations, due to the fact that the ball-activated system allows a nonstop fracturing operation. Other benefits include reducing fluid usage during fracturing and allowing the well to be put on production immediately, without the need for clean up or milling operations. “It’s easy to see that by eliminating multiple operations and speeding up the fracturing process with this one-trip system, operators are realizing considerable cost savings while gaining control of the fracturing process,” Iguaz adds. “The efficiency gained during the
A smarter frac ball
With all its advantages, the one-trip installation system has drawbacks. One is the potential loss in production if the balls and ball seats hinder production. “If the differential pressure between two of the stages is great enough, the ball could remain sealed on the seat, and the production from all stages below that ball would be lost,” Burton says.
including the FracPoint™ EX-C frac sleeve system that earlier this year set a new record for the number of fracturing stages.
“Even though every shale formation is different, there is a growing consensus in the industry that more stages equal more production; so, our clients are continually requesting increasing numbers of stages per well to shorten the frac spacing interval, improve fracture efficiency and increase their production on a per well basis,” Farmer says.
In these situations, removal of the balls and ball seats has conventionally been done by drilling them out of the wellbore before circulating the remains back to the surface, which can be a time-consuming and costly process. “Another risk if the balls remain in the well is that they can pile up at a low point because the production rate is not great enough to bring them back to the surface,” Burton continues. “If this occurs, additional well debris could pile up on top, and a debris barrier would once again hinder production.”
“The FracPoint EX-C system extends the high efficiency of ball-activated fracturing stages beyond what is available industrywide,” Farmer continues. “This was made possible by smaller incremental changes in ball sizes down to 0.875 in. In addition, the EX-C
Realizing that operators valued the concept of a fully disintegrating ball material to guarantee an open flow path for each fractured zone without having to perform drill-out operations, Baker Hughes has developed a groundbreaking
The IN‑Tallic disintegrating frac balls have been field tested in FracPoint system applications in the Bakken shale, as well as the Anadarko basin. “The balls have also proven to be a value-added technology to plug and perf applications in the Northeast and other areas of the U.S.,” says Paul Madero, Baker Hughes engineering manager, completions, for U.S. Land. “In many situations, operators are unable to secure rigs in a timely manner to allow for removal of composite plugs and, therefore, they have opted to produce the wells without removing the plugs. In these situations, the balls trapped between the plugs left in the well have caused restrictions in the wellbore that have resulted in lower initial production rates. By using the IN-Tallic disintegrating frac balls, the balls trapped in the wellbore disintegrate; therefore, eliminating the possibility of restricted production.” The IN‑Tallic technology is currently in the commercial stage and is expected to be at full production by the last quarter of 2011.
> Constant technology advances have pushed the number of frac stages higher and higher. The FracPoint system is currently used to complete an average of 19 stages per well in the U.S. www.bakerhughes.com
Bennett Richard, research and development director at the Baker Hughes Center for Technology Innovation, challenged Dr. Zhiyue (Zach) Xu and the advanced composites group to do what seemed impossible: develop a lightweight, high-strength “Houdini-like” material that must disintegrate down hole. There was only one problem: the material didn’t exist.
Rewriting the science books
Colossal Discovery Materials science breakthrough creates nanostructured material of immense proportions The future of global energy could greatly depend on economically exploiting shale reserves, estimated to be more than 6,500 trillion cubic feet. Judging by the activity in the U.S. alone, one would think that bringing it all online is as simple as punching a hole in the ground. Not only is producing oil and gas from shale plays difficult, it’s expensive, and hydraulic fracturing—necessary to stimulate production from shale reserves—is among the most costly expenditures.
“Our newly formed team at Baker Hughes knew this was going to be a real challenge. In fact, it seemed as though we were being challenged to rewrite the materials science textbook,” says Xu, senior materials scientist and team lead for the Baker Hughes advanced composites group. “All the conventional wisdom pointed to the fact that high-strength materials are usually nondissolvable or, if they are dissolvable, the rate of dissolution is so slow that it’s not suitable for an interventionless downhole tool,” Xu says. “The automotive and aerospace industries were already trying to develop a high-
strength and corrosion-resistant material to avoid dissolution failure of the material. Basically, the required material defied physical engineering.” With the key material properties identified and with an application goal in mind—setting balls for the Baker Hughes FracPoint™ multistage fracturing system—Xu’s team set out to develop a material with unique chemical and mechanical properties that did not exist in conventionally available materials. “Traditional materials that easily disintegrate by dissolution with wellbore fluids are usually low in mechanical strength,” Xu explains. “On the other hand, a material high in mechanical strength does not often corrode fast enough for disposal within the required time. The challenge that we, as materials engineers, faced was to design all three competing properties into a single material structure.” “This required innovative chemistry and processes that led to the groundbreaking nanostructured material technology called controlled electrolytic metallics [CEM], which has a combination of high-strength and in-situ disintegration characteristics that, to the best of our knowledge, did not exist in any other known metal composite materials,” Richard says. “The first product application of CEM material was the Baker Hughes IN-Tallic™ technology that was incorporated into the FracPoint multistage fracturing system,” he adds. “However, the
mechanical properties of CEM material enable its use in a variety of completions processes while providing a truly high-performance interventionless technology.”
Discovering a new path CEM material is a true composite solution based on the fundamental understanding of materials science and engineering. “Our small team was forced to think outside the box, as there was nothing in existence that could be tweaked,” Xu recalls. “We resorted to material fundamentals and started putting together material modules. Success came in bits and pieces. Though it was a fundamental science project, we never lost track of the ultimate goal of commercialization. And, after a while, there was an underlying optimism of discovering something that had never existed. There was no looking back after that!” A magnesium-based alloy was chosen for the first-generation CEM material because of its light weight and its high specific strength. The material is also reactive, providing the foundation for a fast corrosion rate. However, because
Those costs include removal of flow-control devices, like setting balls or plugs that are used for sleeve actuation or stimulation diversion during fracturing. Milling or drilling out these components in order to recover the original size fluid pathway for production is a time-consuming and expensive operation that customers would prefer to avoid. 8
“The potential for nanotechnology is This is only the start.”
Dr. Zhiyue Xu Senior materials scientist and team lead for Baker Hughes’ advanced composites group
> Time-lapse photography shows the disintegration of an IN-Tallic frac ball made with controlled electrolytic metallic material.
together so, after recovery, the material will dissolve in the body’s own fluids.
> Dr. Zhiyue Xu loads a frac ball made from controlled electrolytic metallic material into the scanning electron microscope at the Baker Hughes Center for Technology Innovation in Houston.
“There is one problem, however. It corrodes and generates corrosion byproducts too fast, and the human body is not able to adapt to it. The corrosion rate needs to be slowed and controlled.” the magnesium itself is weak in mechanical strength, its corrosion rate cannot be adjusted or controlled; therefore, additional modules were needed. “It’s very interesting that magnesium is an ideal material being used in medical research because it has the same density as our bones and because it is a biodegradable material,” Xu says. “Researchers are trying to develop this material for use in screws that can bind bones
Xu’s team discovered a similar corrosion-rate control issue while researching the CEM material. “We needed to strengthen the material and control the corrosion rate, and the way we achieved this was through building a system with several different modules,” he explains. One of these modules involved nanostructured material.
“Our goal was not necessarily to develop a material with nano inside, but nanostructured material was ideally suited for what we wanted to accomplish,” Xu continues. “Once we had these system modules, we looked for precision processing techniques that could reliably assemble these modules to produce a homogeneouslooking composite.” The result is the CEM material that exhibits substantially continuous, cellular metallic grains dispersed in the nanomatrix. The nanomatrix has a dual role of providing reinforcements for high strength, as well as having the unique chemical property that conventional materials do not provide. The composition and structure of the nanomatrix can be customized to applications or well conditions.
“Ions present in typical seawater, completion brines, formation fluids or remediation acids, along with typical downhole temperatures of 120°F (49°C) or higher, trigger a predictable homogeneous corrosion of CEM composites,” explains Gaurav Agrawal, enterprise research director for Baker Hughes. “This is accomplished through engineered nanostructures between metallic grains that become the activation points for corrosion and can be triggered on demand. Salt dissolves while CEM material corrodes. This is an important distinction. CEM is a highly engineered material composite.” In 3 percent potassium chloride at 200°F (93°C), 3½-in. balls made from this material can completely degrade in-situ in days.
“In the processed state, these nanostructures act as intermetallic adhesion promoters, which yield metal composites that can withstand an impact of 95 bbl/min of fluid flow and 10,000 psi differential pressure,” Agrawal says. “As a comparison, typical flow rates in hydraulic fracturing are below 15 bbl/min.”
Applying the nanocomposite Baker Hughes has incorporated CEM technology into IN-Tallic disintegrating frac balls used with the FracPoint multistage fracturing system. To date, more than 500 IN-Tallic balls have been successfully deployed in completion systems in Bakken shale oil wells. Yet another commercial product incorporating the IN-Tallic material is a temporary barrier in gas-lift mandrels. These plugs
enable the operator to run production tubing with gas-lift valves in place while cementing the production tubing in the same trip without compromising the integrity of the valve with cement. The plugs disappear after the cementing operations, saving the operator the expense of having to fish them out. Several successful applications have been implemented for a major operator in Asia Pacific, resulting in additional orders. Buoyed by this success of the first-generation CEM material, Xu and his colleagues believe that nanotechnology has huge potential in the energy industry. However, like any other new technology, it has its quirks. “Traditional processing techniques may not be applicable for nanomaterials. They certainly will require additional caution in handling,”
Xu adds. “To develop new nanotechnology-based products, we’ll have to continue to learn and understand the scientific aspects.” Baker Hughes is hiring additional Ph.D.s to join the composite materials team. Believing that a new materials science textbook is warranted, Xu and his expanded team are being challenged to write a new chapter in the book— the development of secondgeneration CEM material targeted to deliver two times the strength of the first-generation material while maintaining the uniqueness of a controlled disintegration rate to extend the application of CEM technology to other interventionless downhole systems. “The potential for nanotechnology is huge,” Xu says. “This is only the start.”
Understanding “One thing our study proves is that the earlier you acquire petrophysical and geomechanical knowledge, the more valuable it is.”
Unconventional reservoirs reveal themselves slowly, and that’s a problem for reservoir engineers. To be profitable, operators have to develop their fields quickly, but where should the wells go, and what is the best way to complete them? A recent Baker Hughes study in West Virginia’s Huron shale has some surprising answers.
This is a story about rocks. In particular, it’s about the type of rocks that trap vast amounts of natural gas in shale and tight gas reservoirs. The message is that if you take the time to learn the nature of the reservoir rock itself, you’ll have more success extracting the natural gas it contains. Unconventional gas reservoirs have been discovered throughout much of North and South America, Europe, North Africa, Asia and Australia. Each play has its own unique properties, but they all share a common challenge: the reservoir is almost solid rock. Under typical reservoir conditions, a single gas molecule will move through the matrix of shale between one and 10 ft (0.3 and 3 m) over the life of a well.
To recover natural gas from shale, the reservoir rock must be fractured—typically with highpressure fluids—to create paths for the gas molecules to flow toward the wellbore. “All rocks in the earth have discrete, visible fractures,” says Dan Moos, a technology fellow at Baker Hughes. “Most of these fractures formed millions of years ago. Over time, other materials sealed the cracks, but a little bit of shear slip is enough to break them open again.” The goal of hydraulic fracturing is to force open primary hydraulic fractures in the reservoir rock and to create a surrounding secondary network of fractures that will allow gas molecules to flow toward the fracture and then into the wellbore.
It’s easy to imagine that hydraulic pressure causes an organized network of smaller cracks to grow at right angles from the primary fractures, but Moos and his colleagues suggest that isn’t the case. As geoscientists, they realize that new cracks are simply a reopening of the fractures already in the ancient rocks. “Many people in our industry believe that in stimulating a well, they are creating new fractures in a very organized network,” Moos says. “The implication is that the only thing they need to know is the difference between the two horizontal stresses.” Geologists can estimate the current stress on the reservoir rock, but according to Moos and his associates, that’s not
enough to predict where the new fractures will form when you add hydraulic pressure. What you really need to know is the orientation of the ancient fractures, and that orientation shifts over time. “By combining the knowledge of the natural fractures and the stress state of the rock, you should be able to predict the shape of the stimulated zone around the primary hydraulic fracture,” Moos explains. If operators can predict how these stimulated zones will form, then they will know how far apart to place their wells and how far apart the fracture zones should be. Spacing them too close wastes money. If the fracture zones are too far apart, they’re not draining all of the reservoir.
Dan Moos Baker Hughes technology fellow
could let the fractured zones close too soon.
The next thing operators want to know is how to optimize the fracture zones and how to predict how much gas they will yield.
From model to the field
“It’s very important to predict the ultimate recovery and the drop in recovery over time,” Moos adds. “Operators need that information as early as possible in the life of the field. The irony is that shale gas wells have to produce for a long time before you can determine how much gas they will ultimately deliver.” The way the wells are run may also have an effect. Field data suggests that if operators allow a well to produce as much gas as possible from Day One, then the ultimate recovery from that well may suffer because rapidly reducing the reservoir pressure
For several years, Moos and his colleagues worked to build a computer model that could predict where and how fracture zones would form and how much gas a fractured well was likely to produce over time. While theories and models are fine, at some point, they must be tested in the field. In 2010, a Baker Hughes client agreed to a trial run of the model on data from a producing well it had just drilled in the Huron shale. “We applied our analysis to the client’s extensive data set,” Moos says. “They had collected everything we needed. In a nutshell, our project involved taking our
Distance from heel, ft 2500 3000
600 Stage 1
Distance from wellbore, ft
Stage 2 Stage 3
Stage 4 Stage 5
Stage 6 Stage 7
Stage 8 Stage 9
Natural fracture/joint density
Production from production logging tool
> Graphic shows that stimulated zones tend to initiate and grow along a pre-existing set of joints and that production is better correlated to the joint density than to the number of microseismic events.
Microseismicity Ports Packers
01> JewelSuite™ software renders a dramatic visualization showing the pressure depletion at different frac stages from the main target well (shown in green). The colored regions indicate the extent of depletion for each stage at a single point in time after production has begun. The dots are the microseismic events (their colors indicate the times at which each occurred, from early in blue to late in red) that were produced by each stage. 02> In 2010, Baker Hughes tested a model of where and how fracture zones would form and how much gas a fractured well might produce over time on data from a producing well in West Virginia’s Huron shale.
03> Image depicts the four horizontal wells drilled for the study and the cloud of microseismicity that roughly outlines the extent of the near-field region affected by stimulation of the horizontal wells.
to predict the well’s ultimate performance early in the process.
theoretical understanding and applying it to an actual well using as much data as we could, then making predictions of the early-stage production.” One of the most important things the client had was microseismic data that was collected while the well was being fractured. Most people in the oil business are familiar with seismic surveys, which use recorded sounds from the surface to create 3-D images of rock formations deep inside the earth. A similar science uses receivers placed inside nearby wells to listen to the earth 14
while a target well is being fractured. As hydraulic pressure builds, the rock in the stimulated zone will crack and pop like ice cubes dropped in a glass of water. These microseismic events are recorded to form a picture of the fractured zone. Most people assume that the microseismic cloud shows the area of the reservoir that will produce most of the gas. What Moos and his team learned surprised the operators. “We learned that in this case, there was a very poor correlation between the microseismic cloud and the actual producing
zone,” Moos says. “We found a much better correlation for the amount of natural fractures that intersected the well within the stimulated zone.” Shale gas operators, of course, already target natural fracture zones. One lesson from the new study is that there may be more efficient and productive ways to design the stimulation. Another valuable lesson from the study is that it is possible, based on a better understanding of the relationship between natural fractures and those induced by hydraulic fracturing,
With that knowledge, for example, Baker Hughes can run a variety of scenarios for producing the well. Based on those projections, the operator could then make the economic decision to either choke back the production and ultimately recover more gas, or allow the well to run full-bore for a faster return on investment.
“It’s exciting to see how well the model works,” Moos says. “It is already generating a lot of interest from our customers. One thing our study proves is that the earlier you acquire petrophysical and geomechanical knowledge, the more valuable it is.” 03
> The University of Wyoming’s Carbon Management Institute chose the Rock Springs Uplift as the drilling site because of its specific geology and proximity to Pacific Corp.’s Jim Bridger coal-fired power plant.
From the Oil to the
Baker Hughes leverages its oil and gas expertise for CO2 storage project
> Baker Hughes deployed the TruTrak automated directional drilling system to drill through tough layers of shale, sandstone, limestone and dolomite to a total depth of 12,810 ft (3904 m).
As the largest coal-producing state in the U.S., Wyoming provides nearly 40 percent of the nation’s coal, used primarily to generate electricity. Coal supplies in the U.S. are far more plentiful than either oil or natural gas, and Wyoming’s easily mined, clean-burning, low-sulfur coal is in high demand. Although coal is a reliable and low-cost energy source, coal-fired power plants produce billions of tons of carbon dioxide (CO2)—a greenhouse gas—each year. The University of Wyoming’s Carbon Management Institute (CMI) promotes research and development of advanced carbon capture and storage technologies. CMI’s efforts are critical to the success of sustaining Wyoming’s energy economy and instrumental in reducing greenhouse gas emissions worldwide. In
Photos courtesy of Meg Ewald, Carbon Management Institute
For more than a century, Baker Hughes has been finding new and innovative ways to help operators extract oil and gas from hydrocarbon reservoirs. It’s now using those same technologies to find a completely different kind of reservoir—and one that doesn’t contain hydrocarbons.
> Shanna Dahl, CMI deputy director, and Sam Zettle, former director of North America integrated operations for Baker Hughes, discuss the progress of drilling operations.
2009, CMI launched a study to identify Wyoming’s most promising potential carbon sequestration site, and it chose the Baker Hughes integrated operations group to manage the well construction and data collection portion of the project. “Planning and engineering for the drilling phase of CMI’s Wyoming Carbon Underground Storage Project (WY-CUSP) began in 2009 with detailed discussions between CMI, the University of Wyoming and Baker Hughes integrated operations staff,” explains Paul Williams, director for CO2 storage projects for Baker Hughes. Along with project management, Baker Hughes has provided a full range of integrated services including site preparation; supply chain management; drilling equipment and all formation evaluation services, including coring and wireline; drilling fluids and cementing.
A promising storage solution While CO2 has been injected into geological formations before, deliberately using formations for long-term storage is a relatively new concept, Williams says. “Geological sequestration, or the longterm, below-ground storage of CO2, can take place in deep saline aquifers, depleted oil and gas reservoirs, and unmineable coal seams. Of these, deep saline aquifers are considered the most promising and have by far the largest storage volume,” he notes. “The ideal site for CO2 sequestration would provide large storage capacity, a caprock capable of preventing leakage and escape, injectivity at commercial scale, minimal seismic activity, and the absence of other valuable natural resources such as gas or oil.” Preliminary regional data and computer modeling by the University of Wyoming suggested that the Rock Springs Uplift,
which was chosen for its specific geology and proximity to Pacific Corp.’s Jim Bridger coal-fired power plant, could store up to 26 billion tons of liquefied CO2.
predetermined intervals, with 916 ft (280 m) of whole core cut with a 98 percent recovery rate. The well’s total depth of 12,810 ft (3904 m) was reached in August.
Two specific rock formations in the Rock Springs Uplift, the Weber sandstone and the lower Madison limestone, met storage criteria. Both formations lie well below the region’s underground drinking water sources (the deepest of which is 1,700 ft [518 m] below ground), and both contain highly mineralized salt water currently unsuitable for drinking, agricultural or industrial use.
Determining the next steps
To accurately characterize the two formations, CMI needed to augment its preliminary data and computer modeling with geologic logs, core and fluid samples, and actual geophysical data. “Baker Hughes supplied its well construction expertise to design and cost a 13,000ft (3962 m) characterization well,” Williams explains.“The well engineering design details, together with the other project objectives, were submitted to the U.S. Department of Energy, which funded the well construction project. The wider three-year, $16.9-million project is being funded by the Department of Energy and the state of Wyoming.” Drilling began in April 2011 with a small air rig, which was used to drill the first 2,000 ft (610 m) of the well. After surface casing was cemented in place, a larger conventional rig was sourced in June to drill the deeper sections of the well. For the deeper drilling phase, Baker Hughes provided polycrystalline diamond compact bits and the TruTrak™ automated directional drilling system to drill through tough layers of shale, sandstone, limestone and dolomite. Multiple coring trips were made at
Reservoir characterization integrates all available engineering and geological data into a model that simulates the behavior of the reservoir under a variety of circumstances. “In this case, 3-D seismic data, logs, cores and geophysical surveys were needed to provide porosity, permeability and resistivity information for a 25-sq-mile [65-sq-km] area of the Rock Springs Uplift, as well as data regarding the long-term integrity of the caprock,” says Sam Zettle, former director of North America integrated operations for Baker Hughes. To gather the needed information, Baker Hughes ran a large number of wireline formation tests. (Please see related story on Page 20.) “If Phase One goes well and the data we provide shows that CO2 can be safely contained in one or both of the formations, we will have a much better idea of the Rock Springs Uplift’s suitability for CO2 storage. A potential second phase could involve injecting liquid CO2 into a small area of the formation[s] and monitoring it using 3-D seismic to confirm the integrity of the storage site,” Williams says. Phase Two, if implemented, could last for several years and include the design of a commercial-scale CO2 injection operation as well as a displaced fluid management plan. “As the CO2 is injected into the aquifer, it will, at some point, displace the brine,” Williams explains. “Another part of the project involves looking at the feasibility of treating the produced brine to put it to beneficial use back on the surface. It could
be treated for industrial, agricultural or possibly residential use if the economics prove out.” “This has been a very good collaborative working relationship with the University of Wyoming,” Zettle adds. “Our focus from the beginning has been to work closely with CMI in order to provide the information needed to substantiate the longer term objectives for the project. Baker Hughes provided a fully integrated and multidisciplined program that included reservoir and geomechanics evaluation through to the successful drilling and testing of the well. This has been a model project, making use of Baker Hughes expertise, wellsite execution and technology. We look forward to furthering our relationship with both CMI and the University of Wyoming.” CMI Deputy Director Shanna Dahl says, “This project has been an exciting and rewarding joint venture. Baker Hughes has been great to work with, and thanks to the data collected by the company’s team, the Rock Springs Uplift will be one of the best characterized potential CO2 storage sites in the country. We at CMI look forward to working with Baker Hughes on any potential subsequent phases of WY-CUSP.”
> Paul Williams, director of CO2 storage projects for Baker Hughes
Capturing the right data
Storing CO2 in geological formations must be done in a safe and sustainable way, which requires a systematic approach to the selection, characterization and qualification of proposed sites. This ensures that potential sites are well-suited for the long-term sequestration of CO2 before an ounce is injected.
XMAC F1™: Locates and maps formation features such as fractures and bedding planes more than 50 ft (15 m) away from the wellbore.
A vital component of site qualification is data acquisition, which tests whether a formation has all of the elements required for the safe and permanent storage of the greenhouse gas, including:
Compensated Z-Densilog™: Provides formation bulk density and photoelectric absorption index data, which are useful in the evaluation of complex formations to determine lithology and porosity.
Physical capacity, or the available volume within a formation (porosity and thickness) Injectivity, or the ease with which CO2 can be injected (permeability) An adequate caprock (seal) to prevent CO2 leakage A stable geological environment (minimal seismic activity, faulting or fracturing) Minimal presence of other natural resources of value (hydrocarbons, natural gas storage, groundwater or geothermal energy).
While working with the University of Wyoming’s Carbon Management Institute, Baker Hughes collected and evaluated geological and environmental data from a variety of sources to augment preliminary regional data and computer modeling by the university. All of this data is being used to assess whether the Rock Springs Uplift is a suitable site for CO2 storage. Much of the data was acquired while drilling a 13,000-ft (3962 m) characterization well. During the drilling process, Baker Hughes ran a number of wireline services to evaluate the formation and determine whether it meets the requirements above. They included the following services:
High-Definition Induction Log™: Provides formation resistivities and water saturation at multiple depths to provide a detailed analysis of formation resistivity.
Compensated Neutron™ (CN™): Identifies porous formations and provides data for porosity analysis. FOCUS™ Compensated Z-Densilog™: Gathers density porosity data in a wider range of borehole conditions, even at high logging speeds. FOCUS™ Gamma Ray: Measures the natural radioactivity of the formation being surveyed to identify the type of rock along the wellbore. EARTH Imager™: Acquires simultaneous high-resolution resistivity and acoustic borehole image data. Circumferential Borehole Imaging Log™: Provides 360° highresolution borehole images in difficult wellbore conditions, including highly porous, unconsolidated formations. Zero-offset Vertical Seismic Profile: Integrates with surface seismic data to identify and describe reservoir compartments not visible with surface seismic alone. Reservoir Characterization Instrument™: Obtains precise formation pressures and high-quality fluid samples to determine reservoir volume. WellLink™ LiveWire™: Securely connects the rigsite to any location in the world, enabling immediate geoscience interpretation of wireline data to assist critical decision making.
Starting Scratch from
IO project a first in Brazil for Baker Hughes, a necessity for OGX When Brazilian entrepreneur Eike F. Batista launched his own oil and gas exploration company in June 2007, some thought that the billionaire’s Midas touch might finally be waning. Batista, founder of the industrial group EBX, has a proven track record in developing new ventures in the natural resources and infrastructure sectors.
01> Baker Hughes Technician Saulo Nespoli tests electrical systems on a SoundTrakTM acoustic logging-whiledrilling tool that has come into the Macaé drilling operations base for maintenance. With 1.2 miles (2 km) of wiring, the 9½-in. SoundTrak tool is 32 ft (9.8 m) long and weighs 6,800 lbs. (3084 kg), making it the largest formation evaluation tool in the Baker Hughes fleet. 02> Vinny Hibner (seated) and Rafael Pereira monitor actions on the Pride Venezuela drilling rig at the Baker Hughes BEACON remote operations center in Rio de Janeiro. 03> Higor de Oliveira Silva Araujo and Cintia G. Emerick perform routine maintenance on a Reservoir Characterization InstrumentTM service tool at the Macaé wireline base. 04> Brazil’s IO team includes (from left) Alessandro Oliveira, drilling engineer; Christian Resende, logistics manager; Marcello Marangon, project manager; Carlos Gonzalez, drilling engineer; and Alana Dos Santos, logistics coordinator. Not pictured are Drilling Manager Miguel Mollinedo and Logistics Coordinator Manoel Marfrini, who works in São Luís in the state of Maranhão.
“When Mr. Batista started OGX, people said he was dreaming. Then, when we launched our IPO [initial public offering], they asked how could we raise $4.1 billion without having a drop of oil and with no rig to drill,” says Reinaldo Belotti, production director, OGX Oil & Gas. “We were seen as crazy people and that it would be impossible to rent a rig, get a seismic crew, and so on. However, we got eight rigs. We have a short history, but we have a great future.” By employee numbers, OGX is a small player in Brazil, employing fewer than 300 people directly. However, the company is making a big splash in the offshore exploration arena. By focusing on shallow-water exploration concessions in Brazil’s prolific Campos basin— where more than 85 percent of the country’s crude is produced—OGX has enjoyed a stunning amount of success in only four years. “OGX is a new company with few employees. We are not in business to compete with the national oil company, but we do intend to have a presence here in Brazil,” says Jésus Pereira, drilling manager for OGX. “Most of the oil companies that have come to Brazil have drilled one or two, or maybe three wells
a year. In the first two years OGX drilled more than 30 wells. It is for this reason we have to have knowledgeable people working with us.” OGX has more than 6,000 people partnering with the company to provide products and services, and to manage all aspects of the projects included in its ambitious business plan which, by 2019, calls for 19 floating, storage, production and offloading (FPSO) vessels, 24 wellhead platforms and five tension-leg wellhead platforms. With a diversified portfolio of high-potential exploration blocks in the Campos, Santos, Espírito Santo, Pára-Maranhão and Parnaiba basins, OGX is effecting the largest privatesector exploratory campaign in Brazil. Concessions in these five basins cover an offshore area of approximately 7000 km2 (2,702 sq miles), as well as an onshore area of 24 500 km2 (9,459 sq miles). Additionally, OGX has five onshore exploratory blocks in Colombia that cover approximately 12 500 km2 (4,826 sq miles) in the Cesar-Ranchería, Lower Magdalena Valley and Middle Magdalena Valley basins.
Putting together a team When Marcello Marangon, project manager for the Baker Hughes integrated operations (IO) team in Brazil, needs to discuss a change in the drilling program on an appraisal well in the Campos basin with the operator’s drilling manager, he doesn’t have far to go. Marangon, along with five members of the IO team and the 24/7 real-time drilling optimization team who are helping manage Baker Hughes’ first IO project in Brazil, office at the operator’s headquarters in Rio de Janeiro. Several team members, as well as Clarissa Thomson, Baker Hughes’ account manager for OGX, and other Baker Hughes employees who office across town often sit in on daily operations meetings with OGX’s geosciences and drilling teams. Together, they make decisions affecting the operations of the drilling rig that Baker Hughes manages with OGX. “Our goal with any of our customers is getting them to feel that we are
an extension of their team,” says Mauricio Figueiredo, vice president of the Brazil geomarket for Baker Hughes. “Reaching a high level of integration and building a strong relationship depends on how we react to our customers’ requests and their needs.” Baker Hughes is one of two service companies assisting OGX in managing its rigs. “We are managing the Pride Venezuela rig, which has drilled four wells within the exploratory/appraisal campaign in the Campos basin about 80 km [50 miles] offshore Brazil,” Thomson says. Under the IO contract, Baker Hughes provides drilling services with directional drilling, formation evaluation and surface logging; formation evaluation and cased hole wireline services, and drill bits, as well as project management for well engineering, operations support and logistics on the appraisal well drilling program. In addition, Baker Hughes provides 24/7 real-time operations monitoring from its BEACONTM remote operations center in Rio de Janeiro.
“We are a new company, and we don’t have many employees, but OGX has a lot of experienced people managing the business,” Pereira says. “What we don’t have are specialists in all the areas it takes to produce oil and gas. That’s where a company like Baker Hughes comes in. It can provide specialists who can direct us in directional drilling, hydraulic fracturing programs, fluids, bits, logging—everything we need to drill and produce these basins. This is the importance of Baker Hughes to OGX.”
Delivering the right technologies Baker Hughes entered the Brazilian market in 1973 when Hughes Tool Company acquired a roller cone bit manufacturing facility in Salvador, the capital of Bahia state. The company has been a major drill bit supplier to the Brazilian oil industry ever since. Today, Baker Hughes is also a leader in directional drilling technology in Brazil, and its artificial lift product line holds the leading market share in electrical submersible pumping (ESP) systems. Because of its commitment to investors, OGX is on a fast track to produce oil and www.bakerhughes.com
> Clarissa Thomson, Baker Hughes’ account manager for OGX, and Jésus Pereira, drilling manager for OGX
By the numbers In June 2008, OGX went public, raising USD 4.1 billion which, at the time, was the largest amount ever raised in a Brazilian primary IPO. OGX has approximately USD 5.45 billion in cash to fund its E&P investments and new opportunities. OGX currently has approximately 10.8 billion bbls of prospective resources in its portfolio. OGX expects to achieve 150,000 BOPD of production from the Campos basin in 2013 in two production complexes from 10 horizontal wells producing an average of 15,000 BOPD each. Also in 2013, OGX expects to have three FPSOs and two wellhead platforms in place to handle production from these 10 wells. In addition to these three FPSOs, OSX has acquired two very large
is keen on employing new technology, Thomson says. As a streamlined organization, decisions on investing in technology can be made almost on the fly. “That gives OGX the flexibility to be open to proposals on new technology and, if the company decides to use it, it can be deployed at the next opportunity,” she adds. Baker Hughes has introduced several of its drilling services technologies to OGX, including the AutoTrak™ rotary steerable drilling system; the SoundTrak™ acoustic logging-while-drilling (LWD) service; the CoPilot™ real-time drilling optimization service; the MagTrak™ LWD magnetic resonance service; and the LithoTrak™ service, which offers measurement of formation density, neutron porosity, borehole caliper and formation imaging. In a three-year contract, separate from the IO contract, Baker Hughes is providing all artificial lift services needed by OGX, including those for the 9-OGX-26HP RJS well due to produce first oil for the company by the fourth quarter of 2011. The extended well test contract includes the provision of downhole ESP equipment for the subsea wells. Baker Hughes will also staff a DNV-certified ESP control room on the OSX-1 FPSO, consisting of variable speed drives, transformers and monitoring systems. The combination monitoring and 24
control system is designed to ensure extended run life for ESP systems. “Right now, OGX is in the planning and development phase for the Waimea and Waikiki fields,” says Leandro Neves, completion and production sales manager for Baker Hughes in Brazil. “Baker Hughes is focused on supporting OGX in whatever it needs to plan and execute this new phase. Engineers are being moved to OGX’s office to support the company on the ESP specifications.” The ESP systems are designed to increase oil production and to provide more flexibility in understanding the reservoir behavior based on the ESP systems’ capability to produce different flow rates by changing the speed of the downhole motor through frequency adjustments in the variable speed drive located on the surface. In addition, the ESP systems’ gauges supply real-time downhole temperature, pressure and discharge pump pressure measurements; important in monitoring the reservoir during that are production.
Adding value by sharing objectives Project management calls for having a broader picture in mind, Marangon says. “Baker Hughes is now looking beyond its role as a provider of well construction services and solutions and looking at
the well-delivery process. We are now sharing the objectives of the customer. We worry about aspects that we were not involved in before,” Marangon explains. “When you’re trying to optimize the [USD] half-a-million dollar daily operational costs, you start weighing the difference between spending money on an extra transport to the rig versus taking the risk of incurring rig downtime.
crude oil carriers that will be converted into FPSOs. It is anticipated that both vessels will have approximately 1.3 million bbl of storage capacity and approximately 100,000 B/D of installed oil processing capacity. This equipment
will be leased to OGX, with delivery expected in 2014. In the Campos basin, production will begin from the first project (Waimea complex) in the fourth quarter of 2011, with anticipated production of up to 20,000 BOPD from the OGX‐26 well. The second project (Waikiki complex) production is expected to begin in the fourth quarter of 2013. * Statistics compiled from the OGX website and business plan
“You have to prove that you’re adding value to their operations technically and commercially, so you are well motivated to deliver and, in the end, achieve joint objectives.” “Baker Hughes is known for its technology, its research and development, the quality of its services and the quality of its people,” Thomson adds. “All this is known, but the fact that we can sit down and work side by side with a customer and do what they do and take over part of their burden closes the gap between the two entities. “Baker Hughes has experience working in many fields around the world. We can bring a different approach to a customer’s problems and offer different solutions to all of them. This is what I think we do the best, and this is a true advantage of using Baker Hughes to do the procedures and project management and the integrated operations.” www.bakerhughes.com
OGX is a relatively new player in the energy industry. What was the philosophy behind establishing an oil and gas company to compete in an arena as large as Brazil where the national oil company is so dominant? Belotti: OGX was founded in 2007 by Brazilian entrepreneur Eike Batista. From the beginning, our philosophy has been to be a small company with the best people having the most knowledge, with the best partners to build relationships with, and with the courage to face the risks. That is our model.
Q&A Paulo Mendonça,
with general executive officer and exploration director
and production director, OGX Oil & Gas Part of the EBX group of companies, OGX is responsible for the largest private-sector exploratory campaign under way in Brazil. OGX’s portfolio consists of 29 exploratory blocks in the Campos, Santos, Espírito Santo, Pará-Maranhão and Parnaíba basins in Brazil, and five exploratory blocks in Colombia’s Middle Magdalena Valley, Lower Magdalena Valley and Cesar-Ranchería basins. 26
I think that because Petrobras has long dominated the industry here, many companies were scared to come to Brazil. This is a big arena. To give you an example, only 5 percent of Brazil’s sedimentary basin concessions are in the hands of different companies—only 5 percent. It is still relatively unexplored. Mr. Batista saw this and started his own company with people who know very well the logistics of this country. Mendonça: When you look at the northern part of Brazil, you can correlate it with West Africa countries like Liberia, Ghana and the Ivory Coast. We see that in our northern coast we do not have any commercial discoveries up to now. We are sure that the country is under explored. A lot
of things have to be done, and OGX is here for this. We are not competing. We don’t want to compete with Petrobras. This is not our message. We want to do our best—our job—and get our own roots.
What sets OGX apart from the larger oil and gas companies operating in Brazil? Belotti: We have said that we have the assets of the NOCs and the management of the IOCs. Here, we are doing the same things they are all doing but easier and faster. We can decide very quickly everything that needs to be done, including negotiating and signing contracts, such as the one we have with Baker Hughes for integrated operations. We don’t have the legal constraints of the state-owned company. We know Brazil, its rules and logistics, and we have a team of geologists that knows more about Brazil than any other team in the world. Mendonça: The investment in the right personnel is very important. We have 274 direct employees and more than 6,000 people working with us. Our golden asset is the quality of all of our people. We have good people in exploration, drilling, production and reservoir.
When we went out to the blocks in the south Campos, everybody said, “They are fools. They are not able to discover a drop of oil,” and we discovered a province of oil. And all because of the quality of our people. You know this expression, “philosopher’s stone”? That describes our exploratory people. I understand that to discover oil it takes 70 percent knowledge and 30 percent technology. The technology everybody can access in the market, but the knowledge is in your mind. This belongs to you. Along with all of this, we have Mr. Batista who has the capacity to look at something and to discover a new opportunity. That is a big advantage.
Lacking the infrastructure and human resources of the larger NOCs and IOCs, what do you consider as key elements to the company’s success?
can we use this gas? Are we going to depend on another company’s pipeline? No. We will build our own pipeline and go on for ourselves. Then a lot of other companies will provide the gas to you because they need the pipeline, and they only have the state-run company to negotiate with. So, because of this, we have another opportunity. In Brazil, there are a lot of oil and gas companies who will be able to sell us their products, mainly gas. Some basins are oil-prone like Campos, and some, like Santos and Parnaiba, are gas and condensate prone. In the Parnaiba basin, which covers an area of 21 000 sq km [8,108 sq miles], we also have three gas discoveries. We already declared two of them commercial to the National Petroleum Agency [ANP] and we are, of course, preparing to develop all of these discoveries. In addition to this, we intend to continue discovering more gas and possibly light oil. This is what we plan.
With some of the greatest minds in the energy industry on this team, what else do you need for this company to be successful?
Mendonça: We are walking by our own legs. What does this mean? It means we are able to build the elements that we need for all of our programs—infrastructure, pipelines, roads, ports. We discovered a new gas province in Santos. Now, how
Mendonça: To grow the company, we must increase our portfolio and have more
Of course, if we don’t get blocks in Brazil, we will go outside of Brazil. Our first step toward reducing the dependency on legislation was to go to Colombia where we’ve got five blocks—very nice blocks. Everybody knows the Maracaibo basin, but nobody knows the Cesar-Rancheria basin. Our Cesar-Rancheria basin is the continuation of Maracaibo in Colombian territory. We got almost all this basin in the last round.
OGX is moving from discovery to development in less than 24 months. How were you able to fast track this project? Belotti: Everybody has access to the same technology in the market, so the quality of your team is what makes the difference. We put together a very good exploration team. We have, until now, a 100 percent success rate in the Campos basin. It means we have discovered a lot of oil. It’s time to appraise and develop this discovery and generate revenue to make some cash. We are now starting the development phase and intend to produce our first oil in the next few months. We intend to start production in the fourth quarter of 2011, but it depends specifically on the environmental license. That is
Paulo Mendonça received a bachelor’s degree in geology from the University of São Paulo. Before joining OGX in July 2007, Mendonça’s career spanned 35 years with Petrobras, where he held several leadership positions, including general manager of the Petrobras E&P Sergipe-Alagoas business unit, general manager of the Petrobras E&P business unit in Colombia, and exploration manager for the Americas and the Middle East. In 2002, Mendonça became general manager and later executive manager of Petrobras’ exploration division and remained in this position until July 2007 when he joined OGX.
the last hurdle that we have, because the well is complete. Everything that we need is in place. The FPSO left the shipyard in Singapore in midAugust. The last big question is the environmental license. Then we will start to put on line our first production.
Baker Hughes is project managing one well for OGX in the Campos basin. How do you perceive Baker Hughes adding value to your company? Mendonça: Technology, people, prices, it’s all very important, but technology and well-trained people for me is the big issue in Brazil. We have projects. We have money, but what we need is good people, and Baker Hughes is doing a very nice job
The Macondo accident has established a new baseline for oilfield operations. How does this affect OGX safety-wise?
and trying all the time to help us meet our objective to keep improving our performance. Belotti: When we started to develop this company, we decided to have only one service company supplier, and it was not Baker Hughes. One reason was because Baker Hughes at that time was one of the biggest contractors for Petrobras. Later, we decided to start with a second service company so we could balance and compare the performance of the two, and we chose Baker Hughes.
Belotti: Macondo affected the entire world and, because of it, the regulations are stronger now. In our company, it is our intent to have the best safety possible, and in order to have that, each person knows very well what is expected from them. We have some of the best drilling engineers in this country. A lot of people have more than 30 years of experience in the best school that we have here, which is Petrobras. All of these people worked there for a long time, on the rigs, managing the rigs, etc. and now they are here working with us. They know as much about safety as anyone does.
We have known Mauricio [Figueiredo] for 30 years or more. We understand that the key to the success of Baker Hughes in Brazil is to have the same person in charge for a long time. The people trust him in Baker Hughes for decisions. So, for this reason, we decided on Baker Hughes as the second company to work for us.
Photos courtesy of OSX
areas to explore. Our intention is to discover any drop of oil that is in all of the blocks we have, but five years from now, this will finish. Then we need more areas. It will be very difficult for us to develop more fields if the ANP does not offer more blocks.
OGX expects to be the largest private sector oil producer in Brazil by 2015. How do you plan to reach this goal? Mendonça: We have already discovered the oil. So now, it’s just executing the development and getting all the equipment we need such as FPSOs, wellhead platforms, completion systems. Production will begin in the first Campos basin project in the fourth quarter of 2011, and production is expected to begin from the second project in the fourth quarter of 2013. Also in 2013, we expect to have three FPSOs [OSX‐1, OSX‐2 and OSX‐3] and two wellhead platforms in place with a total of 10 horizontal production wells on‐stream in these two projects.
Belotti: The OSX-4 and OSX-5 will be built by OSX, the EBX Group ship building company created in order to comply with the local content rule, a very important tool that the government has. To meet this local content rule, we have to have 65 percent of local content. It will be the largest shipyard in Brazil and should be finished in 2013. The shipyard will be a big player in this market. They can build wellhead platforms, rigs, FPSOs for all the oil companies working here in Brazil and in Africa. They have a partnership with South Korea’s Hyundai Heavy Industries Co. for 10 percent of the investment in the shipyard. All the technology will be transferred from Hyundai to OSX in a very aggressive plan to get the same productivity that the Korean people have.
“Aggressive” is a word often associated with OGX. Why is this? Mendonça: Mr. Batista has the capacity to look at something and to discover a new opportunity, and Brazil is a big opportunity for oil. Even with the knowledge that our group possesses, it is very, very important to note the presence of the company’s founder. Some people think that it is easy to start an E&P company in a country like Brazil, but it is not easy. You must have the right team. You must have cash. You must have people with courage to take the big risks that are represented by exploration and production. And you must be aggressive.
> After its conversion in Singapore, the FPSO OSX-1, the first floating production, storage and offloading vessel in OSX’s fleet, set sail for Brazil in mid-August.
Reinaldo Belotti received a bachelor’s degree in electric engineering from Federal University of Espírito Santo. He worked with Petrobras for 32 years, serving as logistic superintendent and production manager of Campos basin, CEO of Petrobras America Inc.’s business unit in Houston, general manager of Petrobras E&P’s Bahia unit, executive manager of Petrobras E&P Services and director of service stations for Petrobras Distribuidora.
> Downsizing on Statoil’s Oseberg East was the foremost driver for Baker Hughes to implement 24/7 technical support to the platform.
Well known for embracing new technology and for being at the forefront of applying new approaches to the oil industry, Norway has had a surprisingly conservative approach to integrated operations— until recently.
Photos courtesy of Øyvind Hagen, Statoil
A new integrated operations perspective in Norway
“Rig-share agreements allowed Det norske the flexibility to drill several wells at a stage in our growth as a company where we could not commit to hiring a rig on a long-term exclusive basis. …Det norske now has rigs on our own multiwell contracts, but we continue to utilize rig sharing where it fits our business needs.” Stig Are Nilssen,
Dominated by only a few operators until the late 1990s, the landscape has changed rapidly in the past decade from a mere handful of companies that were licensed to operate offshore Norway to almost 40 today. Coupled with the fact that discoveries have tended to be smaller, this has led to a rich diversification in the Norwegian oil industry. Some niche players, without the resources needed to fully develop discoveries,
senior drilling engineer, Det norske
are finding and selling discoveries, while others are looking to develop new fields and add value organically by discovering to produce as opposed to buying reserves. “The major operators are still here and flourishing,” says Barry Jones, sales director for Baker Hughes in Norway, “but, they are now joined in the hunt for hydrocarbon resources by mid-sized players and small
specialized explorers all seeking to make their mark. While the majors have large professional staffs with every capability imaginable, smaller operators need to execute projects with lean, flexible organizations.”
“The high investment required to meet Norwegian regulations has made rig owners reluctant to enter into short-term contracts that historically left operators who had only a few wells to drill with limited and expensive options,” Jones explains.
Rig-sharing agreements A prime example of this “need to think lean” has been the introduction of rig-sharing agreements.
In 2006, AGR Petroleum Services came to market with an innovative approach. AGR facilitated the accumulation of three years of rig time for www.bakerhughes.com
a semisubmersible, acting as the drilling department for seven operators who had minimal resources in Norway. The planning, permitting and operations were all conducted by a continuous AGR team. All service contracts were established by AGR, which assigned them to operators on a well-to-well basis. Rig slot times were shared between operators based on the expected duration of the exploration wells to be drilled. Jones explains: “The rig was contracted by a set of operators for 1,095 days. Each operator committed upfront to a portion of these days based on planned requirements of their drilling program. AGR facilitated the process while all economical risk and commitment rested with the operators based on rig schedule, which was established jointly. “The rig constantly moved from location to location, rarely drilling back-to-back slots, so they had time to plan and catch their breath between wells.” A similar approach was taken by a group of operators who formed a consortium in 2009, contracting the semisubmersible Songa Delta for three years. Wintershall and Det norske, two companies with positive experiences from the Bredford Dolphin rig-sharing project, were the prime movers in the consortium, Jones adds. Stig Are Nilssen, senior drilling engineer at Det norske, states: “Rig-share agreements allowed Det norske the flexibility to drill several wells at a stage in our growth as a company where we could not commit to hiring a
> Barry Jones and Elin Vargervik, business development personnel in Norway, see the country’s traditional business model changing.
Trolla Beta Brent
Ronaldo Grosbeak Ap* Total
> Baker Hughes is providing a 24/7 total service approach to Statoil at its Oseberg East platform that includes cross training of personnel and a host of remotely supported functions from its BEACON remote operations center in Stavanger.
* well test
rig on a long-term exclusive basis. As we have grown in size and capability, Det norske now has rigs on our own multiwell contracts, but we continue to utilize rig sharing where it fits our business needs.” As part of its approach, the Songa Delta consortium decided to contract all key drilling and well placement services with a single supplier—Baker Hughes—an interesting arrangement in Norway where single-service agreements were the standard. “Baker Hughes was chosen as the key contractor and has supplied directional drilling, measurement-while-drilling, logging-while-drilling, wireline, drilling fluids, coring, drill bits, mud logging, cement, liner hangers and coring since Day One,” Jones says. “Coinciding with the advent of a reorganized Baker Hughes, the project allowed us to demonstrate our strength in depth, with
all service lines under the guidance of one Baker Hughes’ project manager.” One of the highlights of this ongoing project has been the efficiency and performance of Baker Hughes. As indicated in the table above, reliability and performance has been excellent, with nonproductive time at 2 percent— far below industry norms.
24/7 total service approach Statoil’s Oseberg East project is another prime example of just how different one integrated operations project in Norway can be from the next. Despite a very small platform structure, the Oseberg East field (located 25 km [15.5 miles] from the Oseberg field center where oil and gas is processed) had operated with a full drilling crew of 53 drilling contractor and service personnel during the development phase, thanks to the presence of a flotel (living quarters on top of the platform).
Later in the field development phase, the flotel was no longer on contract, leaving the operator with the challenge of how to drill and complete wells with only 36 bed spaces when a crew of 53 was still required. The Baker Hughes Norway team surprised the operator with a total service approach, says Elin Vargervik, executive account manager for Baker Hughes Norway. “Baker Hughes proposed a novel approach that included cross training of drilling crew personnel—cementers with drilling fluids engineers, directional drillers with completions engineers, etc.—and a host of remotely supported functions from its BEACON™ remote operations center in Stavanger,” Vargervik explains. “As an example of the complexity of this project, a team of Baker Hughes technical staff spent several months analyzing workflows and tasks, identifying more than 700 key processes and process owners, and ultimately mapping each task in a
responsibility assignment matrix. Following 25,000 hours of training, which included Baker Hughes, Statoil, the drilling contractor and other service provider personnel, this innovative project is ongoing and is currently drilling the third in a planned program of seven wells.” Unlike in other single-service projects, it is now the responsibility of Baker Hughes to ensure there are smooth and seamless transitions among services, such as drilling, completions and cementing, and that systems and technology are compatible. “This calls for tight project management, a transparent working methodology, a low degree of protectionism and a high level of involvement with regards to personnel, use of collaborative environments, and software and technology,” Vargervik says. Plans are to increase oil recovery by some 39 million barrels, with Baker Hughes integrated operations an integral part of this value chain.
“The down-manning on Oseberg East was the foremost driver for implementation of a 24/7 technical support function in Norway,” Vargervik adds. “The new approach is that whatever needs to be done on the rigsite will be done on the rigsite, but what can be done from onshore operations centers, workshops and collaborative environments will be handled from there.”
Looking forward “From the recent Statoil ‘FastTrack’ projects awarding all services and a degree of project management to one provider, to the startup in June 2011 of the Borgland Dolphin consortium project (where Baker Hughes is again providing the majority of services on approximately 15 wells to a group of operators), there is no doubt that the innovative approach to drilling and completing wells in Norway will continue to develop new ways to secure energy supplies—with Baker Hughes right at the forefront,” Jones concludes.
DRILL Power The latest generation of a revolutionary drilling system that once turned one of the world’s largest offshore gas fields into a prolific oil field is now being brought on land to maximize unconventional shale reservoirs.
As the largest gas discovery on the Norwegian continental shelf, the Troll field is the cornerstone of Norway’s offshore gas production. Reservoir engineers estimate the field’s gas will continue to be produced economically for at least 70 more years. Troll is also one of Norway’s largest oil fields with production in 2010 of 6.86 million Sm³ (43.2 million bbl), according to the Norwegian Petroleum Directorate. When Troll was discovered in 1979, the Norwegian petroleum industry knew the field was a profitable gas producer that also held a considerable amount of oil. The directional drilling and completion technology available at the time rendered Troll’s oil reserves uneconomic to produce because of its low accessibility in an extremely thin reservoir.
To recover them, researchers would have to find ways to overcome extreme technological challenges and develop new drilling techniques. Test drilling indicated that, although the reservoir was large in area, it was very thin vertically. Norsk Hydro, which had acquired the operatorship for Troll in 1983, knew that trying to drill efficient production wells was going to be very challenging unless new technology could be developed to accurately drill horizontally and stay within the thin layers of oilbearing rock. Driven by the large volumes of oil it knew existed, Norsk Hydro entered into
> The Troll field is one of Norway’s largest oil fields. It was developed using the world’s most complex multilateral wells to maximize production and recovery from a thin reservoir.
an agreement with Baker Hughes to study cutting-edge drilling and completion technology with the goals of extending the length and precise placement of horizontal wells at Troll, along with introducing multilateral well technologies. The result was Baker Hughes drilling systems’ breakthrough technology of the decade, which transformed the practice of directional drilling: the AutoTrak™ rotary closed-loop drilling system. The development of the AutoTrak system was originally part of a collaborative project involving Agip Eni for a field in Italy. Norsk Hydro realized that there was a need for this technology at Troll and implemented it for all future drilling in the field. All of the production wells in Troll oil are horizontal wells, according to the Norwegian Petroleum Directorate. Introduced in 1997, the technology allowed operators to precisely steer horizontal wellpaths, staying within reservoirs with less than 1 m (3 ft) true vertical depth while
maintaining continuous drillstring rotation at high penetration rates. The system’s unique capabilities enabled well planners to design innovative multilateral, extended-reach and 3-D well plans to maximize recovery with fewer total wells. The AutoTrak system is a programmable tool that takes commands from the surface to drill in the desired direction and inclination. Sensors track where it’s going, and it can automatically adjust its steering pads to keep the well on course in a “closed loop” without human intervention until it receives instructions from the surface to change direction or angle. It also sends a continuous stream of position and formation measurement data to surface. As of June 2011, 188 wells have been drilled in the Troll field and more than 797 km (495 miles) of reservoir have been drilled with Baker Hughes drilling technology. In 2006, the Norwegian Petroleum Directorate acknowledged the impact of the technology developed for the Troll field
by awarding Baker Hughes its Improved Oil Recovery prize for progressive development and application of advanced drilling and well solutions for oil recovery enhancement.
Building on performance Since its introduction, Baker Hughes has continued to improve the rotary steerable drilling system. The AutoTrak™ G3™ third-generation system was introduced in 2002. It set the standard for rotary steerable performance in terms of precision and efficiency. The AutoTrak X-treme™ high-speed system, which incorporated a modular high-performance X-treme mud motor for additional downhole power, was commercialized in 2005 for demanding environments and extended-reach drilling (ERD) applications. The AutoTrak eXpress™ system, designed for lower spread-cost environments and well-documented geology, was introduced in 2008. “Continued advancements in rotary steerable systems made the AutoTrak system the standard technology for directional drilling in offshore markets,” says Olof www.bakerhughes.com
Hummes, product manager for Baker Hughes rotary steerable systems. “We kept expanding the envelope to ultradeepwater Gulf of Mexico and Brazil, to ERD on Sakhalin Island [eastern Russia] and offshore Africa, and to complex multitarget wells in mature fields in Norway, the U.K. and the Middle East.” “Baker Hughes has been at the forefront of directional drilling technology in all these areas,” says Svein Egil Steen, product line manager for Baker Hughes advanced drilling systems. “Take the Sakhalin Island project for example where, in the mid-2000s, Baker Hughes did some groundbreaking deployments that truly were stepchanges in directional drilling. Drilling from land to an offshore field, more than a dozen wells exceeded 10 km [6.2 miles] measured depth with one well going beyond 11.2 km. [7 miles]. Today, Baker Hughes is focused on setting records in performance and economics in the most diverse environments around the globe.” The AutoTrak system’s closed-loop pad steering technology also has been a key feature in other Baker Hughes
automated drilling devices, including the VertiTrak™ vertical drilling system, the CoilTrak™ coiled tubing drilling assembly, and the TruTrak™ system for efficient, low-angle directional drilling.
Extending the reach “Drilling extended-reach wells requires the latest innovations in drilling engineering and technology,” Steen says. “ERD projects bring engineering challenges from many disciplines, which can cross traditional team boundaries. Integrating drilling and real-time formation evaluation services delivers realtime answers based on accurate, reliable while-drilling data. Such information allows drilling engineers and geoscientists to make informed drilling decisions on-the-spot, leading to reduced operational risk, accurate well placement, improved drilling efficiency and maximum hydrocarbon recovery.” As one example, Baker Hughes provided a comprehensive planning, drilling and evaluation solution on a deepwater ERD well in a high-cost drilling environment offshore West Africa, saving the operator more than $3.5 million.
“We knew that to drill this challenging well profile we would have to kick off at a shallow depth in weak sediments and build almost to horizontal in 17 ½-in. hole before drilling the 12 ¼-in. hole section,” Hummes explains. “This section was accurately maintained at 85° inclination before dropping the angle to intersect each target using the AutoTrak system.” Comprehensive formation evaluation information was acquired while drilling using the OnTrak™ integrated loggingwhile-drilling (LWD) and measurementwhile-drilling (MWD) system; the LithoTrak™ advanced LWD porosity service, the SoundTrak™ advanced LWD acoustic service and the TesTrak™ formation pressure testing LWD service.
the longest ever 12 ¼-in. hole section to be drilled in West Africa.
Steering into shale Rotary steerable drilling technology has rapidly gained acceptance for onshore use because of its clear advantages in directional control, wellbore placement and lateral reach, while matching or exceeding the drilling performance of conventional drilling systems. However, growth of rotary steerable system drilling in unconventional oil and gas reservoirs has been limited by buildup-rate capabilities on these systems. Because of lease spacing issues in the U.S. and limited vertical depths to achieve horizontal orientation, operators require greater buildup rates to maximize the lateral lengths in the reservoir.
“Shale gas plays and other unconventional resources have experienced massive growth in North America over the past few years and more recently in other parts of the world,” Hummes says. “These applications require standard well profiles of vertical, curve and horizontal reservoir sections. Maximizing well productivity and improving drilling efficiency are the major customer needs. “Well placement in the sweet spot and extended laterals help maximize productivity. Drilling a high build-rate (BUR) curve allows deeper kick-off and increases the length of lateral in the productive zone, which is often dictated by lease lines rather than technical limitations. Wells in U.S. shale gas plays and other unconventional resources require a BUR of 10° to 14° per 100 ft. drilled.”
Baker Hughes has been field testing its latest rotary steerable system innovation—a high build-rate system—to meet high dogleg-severity challenges particularly in unconventional reservoirs in North America.
Using closed-loop control and a short steering sleeve that decouples steering from drilling dynamics, the new system can drill high BUR curves and extended reach laterals in a single bottomhole assembly run, without the sliding intervals required
The 12 ¼-in. hole section was drilled to total depth in a single run and was, at the time,
with motors, resulting in significant time savings and a much smoother wellbore for subsequent completion operations. Globally, AutoTrak systems have proven their capabilities to maximize drilling performance, hole quality and wellbore placement in more than 13.4 million m (44 million ft.) of hole, Hummes says. “The new high build-rate rotary steerable system will continue to add to that impressive statistic. During field testing, it has already proven its capability to safely deliver the required build rates and some record performance in unconventional formations,” he says. “We will continue to test the system to establish its full potential and look forward to its commercialization in early 2012. Our drivers are not always to be first, but rather to deliver the best and most cost-effective technology to our clients and the most benefits to our shareholders.” The first edition of Connexus in 2012 will carry a full story on the new high build-rate rotary steerable system technology.
AutoTrak system introduced; first pilot series in Italy and Norway
AutoTrak drills 10,184 ft (3104 m) of reservoir; world record for longest horizontal section
AutoTrak drills deepest horizontal section at 18,307 ft (5580 m)
AutoTrak sets single run-time record of 241 drilling hours
Third-generation AutoTrak G3 introduced
AutoTrak drills 15,472 ft (4714 m) in single-bit run at average ROP of 95 ft/hr
AutoTrak breaks world record for 12¼ in. hole in single run
AutoTrak X-treme service introduced
AutoTrak X-treme gains commendation in BG Chief Executive Annual Innovation Awards for value delivered in a challenging multilateral well development offshore India
AutoTrak sets ERD record by drilling a MD of 37,014 ft (11 282 m)
AutoTrak breaks its own ERD drilling record, surpassing 38,910 ft (11 860 m), over 7.3 miles of hole
Cumulative AutoTrak distance drilled surpasses 35 million ft (10.67 million m)
Introduction of AutoTrak VTM automated verticalseeking rotary steerable system
AutoTrak sets world record for single-run distance of 13,247 ft (4038 m) AutoTrak drills hole at record 164.7˚ inclination
The development well was drilled in water 1000 m (3,280 ft) deep to intersect multiple stacked reservoir targets positioned 1700 m (5,577 ft) below the seabed and 4,500 m (14,763 ft.) laterally from the surface location.
AutoTrak X-treme extends horizontal section of offshore Denmark ERD well 6,000 ft (1828 m) past prior limits First commercial deployment of 4¾-in. AutoTrak G3
AutoTrak eXpress service introduced in U.S. and Canada
AutoTrak eXpress introduced in the Middle East
Faces of Innovation
“There are two things that I am extremely passionate about. One is technology—science—I live and breathe it. The other is diversity.”
As a youngster, Soma Chakraborty’s dreams took her far from the steel town of Durgapur, India, where she was born. She wanted to pursue art and architecture in Santiniketan, the Paris of India, and trace the footsteps of Rabindranath Tagore, India’s Nobel Prize winner for literature. However, her parents envisioned a different life for their only child. Although Hindu, Chakraborty was educated in a private Catholic school affiliated with Mother Teresa’s Missionaries of Charity. Her father, a gold medal mathematician and mechanical engineer, detected some inherent strengths in his daughter and persuaded her to take up something “science related” that could become a foundation for her professional future. Chakraborty earned both bachelor’s and master’s degrees in chemistry at the University of Burdwan, not too far from her hometown of Kolkata in eastern India. The Burdwan faculty had kindled in her an irreversible interest in the elements, and she yearned for more.
> A much larger-thanlifesize model of a buckminsterfullerene, more commonly known as a buckyball, at the Richard E. Smalley Institute for Nanoscale Science and Technology at Rice University.
Chakraborty was accepted in the Ph.D. chemistry program at the internationally acclaimed Indian Institute of Technology in Mumbai, where the girl who “absolutely hated chemistry” in elementary school was soon immersed in synthesizing multifunctional organometallic systems and studying their reactivity and structural property relationship through radical stabilization and electron transfer. Art and architecture had been replaced by argon and actinium!
Embracing a global journey In a quest to find a practical outlet to
fundamental chemistry, Chakraborty, who leads the Baker Hughes nanotechnology group at the Center for Technology Innovation (CTI) in Houston, decided to pursue an applied chemistry career in the U.S. She accepted a post-doctorate offer from the renowned organometallic chemist, Professor Richard Eisenberg, at the University of Rochester in New York. (Eisenberg is the 2011 recipient of the American Chemical Society’s Nobel Laureate Signature Award for Graduate Education.) In a bold move not supported by her parents, the 29-year-old Chakraborty left balmy India for blustery upstate New York, arriving in Rochester on Dec. 28, 2002, knowing no one but willing to welcome the new year, and a new life, in an entirely new backdrop. “Snow was much more real and serious than what I had seen on picture postcards,” she says. “A real snow jacket became my first major purchase.” Adapting to an entirely new life in a new country meant getting a social security card and a credit card with zero credit history. It also meant learning to drive in America. “Apart from all these new things, I learned that it is essential to drive here,” she says. “When I started studying for my license, I felt like all the cars were coming
at me at tremendous speeds! In India, you have a lot higher traffic density, but they drive a lot slower. I wondered, how can you even drive at these speeds without bumping into each other!” Once these obstacles were behind her, and having met her future husband, Chakraborty began thinking about the next phase of her life. “I was looking for a university-type environment where there might be a little bit of flexibility, because I wanted to start a family,” she says. “I also wanted to learn something new. Nanotechnology was just becoming very, very important. It was actually the next-generation science, especially when it came to materials. There was something enigmatic about it, and I wanted to be a part of it.” An invitation to join the research team of Professors Ed Billups and Richard Smalley at Rice University rendered her speechless. “It would be a singular honor to work with Professor Smalley, who had won the Nobel Prize in chemistry for discovering the nanocarbon buckyball,” she says. “It was not a difficult decision. I accepted the offer and moved to Houston.” Sadly, before Chakraborty arrived in Houston, Smalley, who had been www.bakerhughes.com
battling leukemia, was hospitalized and passed away.
Houston, when I started looking for a job, I gravitated toward the energy industry.”
“He was one of the most innovative people in science, and I never got the opportunity to work with him,” she says. “Apart from this initial setback, my stay at Rice was extremely enjoyable and productive.”
During her job search, Chakraborty was introduced to Rustom Mody, vice president of completions and production technology for Baker Hughes. “CTI was just coming along, and I felt a job there would give me the relevant opportunities of productizing innovative ideas. At that point, though, there was very little public domain information regarding nanotechnology in the energy industry. I felt that nanotechnology had infinite possibilities in this industry. In this type of job, I could bring my head, heart and hands to work.”
Chakraborty’s post-doctoral work involved extrapolating her chemistry expertise and translating it into modifying nanomaterials, which have very interesting properties but are very difficult to process in different systems, she says. “My professor tasked me with chemically modifying or transforming these nanomaterials by energizing their surfaces and blending them in different compositions so we could translate their exciting properties into nanocomposites— polymers and elastomers for heat-resistant coatings for NASA applications and in-site drug delivery, among other things,” she explains. “I worked with all sorts of carbon-based materials—nanotubes, nanodiamonds, fullerenes—but my main focus was graphene.” Although the research was incredibly exciting, Chakraborty felt the urge to be in an industrial lab where she could “connect the dots” learned over the past so many years to commercialize new materials. “As a child, I had always seen that in my parents’ circle, oil and gas prices were a regular topic of discussion,” she remembers. “They all closely monitored gas prices, so even as a child, I felt that this had to be something important. I saw that people in the oil and gas industry—even in India— were fairly well paid and, in my perception, I thought of them as rich. So, very early on, I had this perception that this industry has got to be important, and obviously, being in 40
If a human is one nanometer tall, the earth would be the size of a green pea. A hummingbird flaps its wings 50 times a second. Therefore, it takes 20,000,000 nanoseconds for a hummingbird to flap its wings once.
through the control and use of matter at the nanoscale, where size-related phenomena and processes may occur. “In other words,” she explains, “it is the purposeful engineering of material, by which we can control its properties. It is actually modifying material at the elemental level.”
surface, by which this modified nanomaterial gets customized for different applications,” she explains. “We can take the same platform technology and, by tweaking it a little bit, we can make it work for a drilling fluid solution, or a cementing solution or a drill bit solution.”
Nanomaterials can be modified to increase mechanical, abrasive, temperature, chemical, electrical and thermal conductivity properties and are used in many industries, including the energy, automotive and aerospace industries, as well as in cosmetics, the medical sector and sporting goods manufacturing.
Chakraborty says the possibilities are endless for carbon-based nanotechnology in the frontier areas of deepwater and unconventional hydrocarbons, as well as high-pressure/high-temperature, reservoir sensing and monitoring, and enhanced oil recovery applications.
With a three-month-old baby at home, Chakraborty joined the Baker Hughes technology group in July 2008 as a scientist.
Chakraborty’s work at Baker Hughes focuses on the applications of carbon-based nanotechnology.
“I have to really compliment my parents, especially my father, for having the vision to see my hidden strengths and for navigating me in the right direction,” she admits.
Living the stuff of science fiction
“Since the Nobel Prize was awarded to two graphene scientists, there has been a rush for graphene-based technology. Luckily for Baker Hughes, we started working on graphene several years ago, so we are already ahead of the curve,” Chakraborty says. “We have locked up some very important intellectual property in that area. [Chakraborty and her team have applied for approximately 20 patents.] But, nanotechnology is not only about graphenes. It is very broad, multidisciplinary, and has several manifestations and embodiments. The nanomaterial can be a particle. It can be a fiber. It can be a fluid droplet. It can be a thin film, or it can even be an inclusion in an alloy.”
The Richard E. Smalley Institute for Nanoscale Science and Technology defines nanotechnology as “the application of knowledge at the nanoscale.”
Chakraborty compares nanomaterial to an actor who puts on different masks and performs on different stages.
Chakraborty likes to use the ISO definition: the application of scientific knowledge
“We take the same nanomaterial and introduce different chemistries onto the
Her father, who passed away earlier this year, was the first person she called after being offered the team lead position for nanotechnology at the end of 2010. “I had a 2½-year-old child at home, and I told him, ‘My responsibilities are going to increase. Do you think this is the right time for me to step up and accept these challenges?’ He was fully supportive and very proud of my accomplishments.”
> Soma Chakraborty enjoys time with her son, Mayuk, at Houston’s zoo.
“We are looking at the material properties of many things we do and developing new materials because, right now, the materials that we use have reached a certain performance envelope. As the industry goes to hotter and deeper domains, we need to make materials that will have a higher performance envelope.” Nanocarbon technology makes materials more durable, more corrosion resistant and lighter weight, as well as better thermal and electrical conductors. “For example, incorporating nanocarbon materials into a tubular will make it stronger. So, if we can double the material performance and corrosion resistance, then we will need a tubular of half the previous thickness, not only reducing the weight but also reducing the associated power involved in transferring the system,” she explains. “In another example, nanodiamonds, when incorporated into a diamond PCD [polycrystalline diamond compact] matrix, can boost the cutting performance of the PDC cutter, giving us better performance from our PDC bits.” One example of a new material the group
has created is a nano-enhanced epoxy that can be used to package electronic components in some logging tools. “We blended nanomaterials with the epoxy system, and guess what? The degradation temperature of the epoxy is now increased by more than 100°F (38ºC) and you have a completely different domain of application previously not feasible,” she says. As the industry moves forward, it will have to develop new materials with better mechanical properties and temperature ratings and that are more durable, reliable and lightweight. Nanotechnology will be a key player and have a predominant impact. “To not leverage nanotechnology is no longer an option,” Chakraborty says. “Our choices are limited either to taking the leadership in this area or leaving it to our competition.”
organization to grow and to compete in today’s global economy, it is important to have rich diversity. “It is very encouraging to see that Baker Hughes leaders at every level are absolutely committed to both gender and cultural/ ethnic diversity, and to bringing a change in the mindset of this organization.” Chakraborty’s passion for championing a diverse organization was a natural segue into her involvement with the CTI Women’s Resource group, as well as the Young Professionals group. “Having lived the struggles of adapting to a new culture and to being a new working mom, I saw this as a tremendous opportunity to work with newcomers to Baker Hughes, to mentor and help them in whatever way I could.
Balancing a not-so-nano life Finding the right balance of wife, mother and scientist reminds Chakraborty of how comedian Jerry Seinfeld once described parenthood: “It is like spinning a blender without the cap on,” she says with a laugh. “That is the situation I go through every day. I am still trying to find the right balance.”
“When I came to Baker Hughes with a small child at home, there were times that I needed a lot of support, and my managers understood that; so, I really commend and appreciate them for the support they have given me the past three years. It has had a big impact on me.
Despite the daily demands, Chakraborty makes time for her roles in the Baker Hughes Diversity Council, the CTI Women’s Resource group and Junior Achievement, as well as in several professional societies and campus recruitment at Rice University and the University of Houston.
“When you have that kind of working environment, you feel that you are valued and that you really want to give back to the organization. In today’s society, you cannot exist on your own. Be it at home or on the work front, you need a team approach to get by. At Baker Hughes, it has been a wonderful opportunity of balancing the daily challenges while looking for growth opportunities with all of the creative learning options that we have and learning from some very talented individuals whom I was very fortunate to meet early in my career.”
“I have a lot going on,” she admits, “but there are two things that I am extremely passionate about. One is technology— science—I live and breathe it. The other is diversity. I truly believe that for any
D, SWEAT and GEARS
Baker Hughes Express team rides to raise money for MS research
The line of bicycles stretches for miles, fluidly wrapping itself around bends and gliding over hills like a giant colorful snake winding through small towns and fields of purplish blue. Clad in psychedelic jerseys emblazoned with names like Cheesy Riders and Kickin’ Asphalt, some 13,000 riders pedal through torrential downpours and extreme temperatures, into blustery headwinds and over seemingly endless hills all for one cause: to eradicate multiple sclerosis (MS).
03> An aerial view of one of the many breakpoints along the route where cyclists stop to rest their weary limbs.
02> Baker Hughes Express riders are all smiles at the finish line in Austin knowing that they have put 176 miles behind them.
Each April, the BP MS 150, the largest fundraising event in the U.S. for the National Multiple Sclerosis Society, rolls from Houston to the Texas state capitol in downtown Austin. For the past 12 years, the Baker Hughes Express team has been a part of “the world’s biggest party on wheels,” cycling more than 150,000 collective miles and raising a total of $842,976 to help find a cure for MS. In towns like Fayetteville, Bellville and Bastrop, locals sit in lawn chairs sipping iced tea, some with radios playing
adrenaline-pumping music, and cheer on the riders as they pass by. People living with MS and their families are familiar fans in the crowds, holding signs bearing messages like “Thanks for riding” and “You’re making a difference.” Team BP, the lead event sponsor since 2001, formed in 1998 with just 13 riders. Today, Team BP has grown to an average of 750 participants annually and raises more than $1 million. “It’s an honor that Team BP can help make the BP MS 150 the
most successful ride of its kind in the United States,” says Eric Cioti, Team BP co-captain, ride marshal and safety committee member. “None of it would be possible without the 200 BP volunteers that do an amazing job planning every step of the way–luggage handling, rider transportation, setting up our overnight sites, managing two break points, etc. The combination of riders, funds raised and volunteerism that makes up our team is truly emblematic of the BP spirit of investing in the community.”
The BP MS 150 celebrated its 27th anniversary this year. As of the end of September participants had raised $16.9 million—99.4 percent of the $17 million goal for the 2011 event.
Photos courtesy of brightroom.com
01> A string of riders casts a long shadow on the roadway as the BP MS 150 stretches long into the afternoon.
MS is a chronic, often disabling disease that attacks the central nervous system, which is made up of the brain, spinal cord and optic nerves. Symptoms may be mild, such as numbness in the limbs, or severe, such as paralysis or loss of vision. In the U.S. today, there are approximately 400,000 people with MS. Worldwide, MS is
thought to affect more than 2.1 million people. Most people are diagnosed between the ages of 20 and 50. “Funds raised in the BP MS 150 and the other Bike MS events around the U.S. support national and local efforts to address the daily challenges of people living with MS,” says Lisa Dannenbaum-Shaw, development manager for the National MS Society. The National MS Society helps fund wellness and exercise programs, social programs
such as camps for individuals and families affected by MS, education opportunities for healthcare professionals specializing in MS, scholarship programs for students diagnosed with MS or those who have parents living with MS, as well as financial and employment assistance. John Groweg, an engineering technologist with Baker Hughes, has seen the evolution of medical technology in MS research and other services since his father-in-law passed away after battling with MS; and after
his wife, Annette, was diagnosed with the disease in 1991. “The society is dedicated to people living with MS and provides a full-range of services from scientific to medical support,” says Groweg, a volunteer for the Baker Hughes Express support team. “The Baker Hughes team and everyone else who supports the National MS Society are doing a lot more than having a fun, challenging weekend on their bikes. They are making a tangible difference in my family’s life
> Baker Hughes employee and volunteer ride marshal Paul Lowson (right) and his son, Chris, arrive in Austin after riding 176 miles from Houston.
as well as many other MS patients, current and future. “It’s a lifestyle-threatening disease,” Groweg continues, “but medications can slow long-term symptoms and reverse acute symptoms. Seminars, support groups, web-based and other education resources offered by the National MS Society help ease the fears of newly diagnosed MS patients and help all MS patients manage their long-term treatment.”
Uniting for a cure Mark W. Baerenwald, vice
president of finance for the Gulf of Mexico region for Baker Hughes, has been a volunteer team captain for the Baker Hughes Express team for the past five years and chief cook for the past two years. “I enjoy every minute of this great event from cooking the gumbo for 120 riders the weekend before the ride to organizing and setting up the team tent in La Grange where the riders stop for the night after the first day’s ride,” Baerenwald says. “I volunteer for this great cause in remembrance of my wife’s father who passed away from this
disease when she was only nine years old. It’s a simple task for a great cause,” Baerenwald adds. Amy Neely, a Baker Hughes human resources generalist in the pressure pumping group, has worked for the National MS Society since she was diagnosed with MS in 1997. That same year, Neely volunteered for the Houston to Austin event. “It inspired me beyond words,” she says. “When you are at the Bellville lunch stop or in La Grange at the overnight camp, you see the
magnitude of the event, and it is overwhelming. It is a huge sea of people and bikes. It is so touching to see so many people participate in an event that does so much for people with MS in the Lone Star state. “MS is so unpredictable, and you never know what course the disease will take. I have had MS for 14 years, and that uncertainty never goes away. Although I have been symptomfree for many years, I always know that when I go to sleep at night that tomorrow may be different. I may not be as
Number of Riders
fortunate tomorrow as I am today. Part of that is because no one knows what triggers MS or why some people have it. No two cases are the same. That is why research is so important. Those with MS need answers about what causes the disease and why some medications work for one person but not necessarily for another.” The National MS Society is helping to answer those questions. For Neely, the organization is a great support mechanism. She says she always knows where to turn when she needs information or has questions about her disease.
“The tool I use most from the society is its online information,” she says. “There is so much on the site, making it very easy to access the latest news and developments on research. “The Baker Hughes Express team is wonderful. There are so many on the team who have been riding for years to help people like me. It may be some of their donations that one day cures MS.”
National Multiple Sclerosis Society
To learn more about the National MS Society, please visit www.nationalmssociety.org.
176.6 miles (284 Km) Austin, Texas
99.6 miles (160.3 Km) Katy, Texas * Information courtesy of the National Multiple Sclerosis Society and Baker La Grange, Texas Hughes Express Team www.bakerhughes.com
Latest Technology from Baker Hughes X-Treme Clean XP Wellbore Cleanup and Displacement System The Baker Hughes X-Treme Clean™ XP wellbore cleanup and displacement system ensures a superior completion that reduces nonproductive time and maximizes production. This cost-effective cleanout solution for deep wells, deviated wells and deepwater applications offers reliable wellbore debris management. “Wellbore cleanup operations manage the risks in completions or interventions and provide operators with insurance in such activities as sand control completion or completion installation,” says Yang Xu, product line manager for wellbore cleanup. “This new Baker Hughes system is designed to work in any deep, deviated and extendedreach wells, and especially in deepwater applications that require effective and reliable wellbore cleaning systems.” High-tensile, high-torque ratings and a one-piece mandrel design significantly mitigates completion and production risks, and the highest allowable rotation speed of 150 RPM improves wellbore cleanup efficiency, reduces operation time and saves costs. “A wellbore cleanup system capable of 120 to 150 RPM rotation, compared to a system rotating at 60 to 80 RPM, could dramatically cut wellbore cleaning and displacement time in deep and deviated wells—meaning considerable cost savings to the operator,” Xu adds. The X-Treme Clean XP wellbore cleanup and displacement system combines several high-performance tools to seek out and collect debris, including: the X-Treme Clean XP casing scraper, casing brush, downhole magnet, multitask wellbore filter, riser brush and boot basket. The tools can be run together as integral parts of a complete wellbore cleaning system or individually to perform specific functions. The helical shape of the casing scraper and brush, which provides 360° contact with the casing/liner ID, improves hole cleaning efficiency by providing a more effective scraping surface and a large flow course for debris removal and fluid circulation, as well as more effectively bringing debris into suspension and scooping the debris bed. The nonrotating feature eliminates the risk of damaging or wearing casing when rotating drillstring. Another highlight of the system is the magnet’s debris-collecting capability. Xu says that the X-Treme Clean XP downhole magnet has several times the collecting capability of a conventional magnet. 46
MaxCOR rotary sidewall coring service The Baker Hughes MaxCOR™ rotary sidewall coring service can recover 1½-in. (3.8-cm) diameter cores, acquiring 225 percent more core volume per unit length compared to 1-in. (2.5 cm) diameter cores recovered with standard rotary coring tools. This allows operators to more accurately evaluate reservoirs and maximize hydrocarbon recovery, especially in extreme environments. Operators are often unable to cut conventional cores and must rely on percussion or rotary sidewall core samples. Rotary core samples are of much higher quality than percussion core samples and are generally 1 in. (2.5 cm) or less in diameter. For many core analysis measurements, the accuracy of the measurement is directly proportional to the pore volume. One way to significantly increase the pore volume of rotary sidewall cores is to cut larger diameter core samples. The MaxCOR service retrieves core with more than three times the volume in the comparable amount of rig time it takes to deploy standard rotary sidewall coring tools. The larger cores provide more accurate measurements of important reservoir attributes, such as porosity, permeability and geomechanical properties. Greater sample volume per trip also enables operators to more accurately evaluate reservoirs and maximize hydrocarbon recovery with the least amount of rig time. The MaxCOR sidewall coring service can retrieve 60 samples in a single run. Plus, coring efficiency is consistent even in hostile environments up to 400°F (204°C) and up to 25,000 psi (172 MPa). The MaxCOR technology is particularly targeted for premium markets, such as unconventional shale reservoirs. High-volume shale core samples enable more accurate characterization of the complex system with both routine and special core analysis. It also allows operators to assess more destructive types of lab measurements, such as crushing rock samples to measure porosity. “In deepwater, the MaxCOR services are setting a higher standard for rotary sidewall coring. Offshore Brazil, Baker Hughes has recovered 94 cores with 100 percent corerecovery efficiency,” says Gigi Zhang, product line manager, drilling and evaluation. “In a second exploration area, we successfully acquired 54 cores in two runs with a 30-core tube configuration. These were the first successful largediameter sidewall coring operations in Brazil deep water.”
> The MaxCOR service is a fast, efficient technology for acquiring high-quality 1½-in. (3.8 cm) core samples that enable accurate reservoir evaluation and maximized hydrocarbon recovery.
> The RCX service delivers reliable formation testing and sampling at up to 395°F (202°C) and 27,000 psi (186 MPa) in extreme and hostile environments.
HPHT Reservoir Characterization eXplorer Service
Eco-Centre CR Centralized Recycling Solution
Operators continually need critical, reliable information to determine an asset’s commercial value, to help develop a recovery strategy, and to make informed production facility decisions. The Baker Hughes Reservoir Characterization eXplorer™ (RCX™) service addresses this need by acquiring accurate pressure data and collecting representative fluid samples in extreme conditions or hostile environments.
The Baker Hughes Eco-Centre™ CR centralized recycling solution is a drilling waste service provided through a semipermanent facility that incorporates fit-for-purpose technology to process fluids in the most cost-effective and environmentally responsible manner. The service is capable of processing a greater variety of drilling fluids and yielding a higher throughput, while ensuring compliance with all applicable laws and regulations.
The RCX service is designed for enhanced reliability in challenging high-pressure, high-temperature wells at up to 27,000 psi (186 MPa) and 395°F (202°C). Its high-capacity pumps also improve operations in highly overbalanced wells. The RCX service provides the highest quality data and service performance that operators increasingly need to reliably assess the commercial value of assets, make important decisions about facility design, develop optimum recovery strategies, and maximize return-on-investment.
The Eco-Centre CR service is rigged up at a centrally located site in close proximity to several drilling operators. This feature potentially reduces the costs and risks associated with transporting drilling waste, while increasing the efficiency and environmental responsibility of operations. The service is also modular in design, which maximizes the ease of rig up and facilitates meeting the needs of clients in regards to drilling waste volume requirements.
“The RCX service extends our customers’ abilities to reliably characterize assets under hostile conditions and to make early planning decisions,” says Chris Morgan, product line manager, wireline fluid characterization and testing. “RCX takes Baker Hughes’ advanced formation testing to the next level and underlines our commitment to advancing reservoir performance.” The RCX tool, which features titanium construction, allows enhanced combinability for improved wellsite efficiency and ensures hydrogen sulfide integrity in collected samples, even at low concentrations.
“The Eco-Centre CR solution offers customers an environmentally responsible solution to handling their drilling waste,” says Gustave Anderson, product manager, fluids environmental services for Baker Hughes. “Baker Hughes partners with customers to deliver a 100 percent reusable fluid through a single-point service for drilling waste management needs.” The Eco-Centre CR service is one of several environmentally focused offerings that the Baker Hughes fluids environmental services group brings to clients. By understanding environmental and operational challenges, Baker Hughes can address clients’ drilling waste management needs in a practical, cost-effective and environmentally minded manner.
A Look Back
At the turn of the 20th century, word of each new oil discovery spread as fast as the crude that was gushing uncontrollably from the earth. Oil towns with names like “Ragtown” and “Whizbang” sprang up almost over night across Oklahoma and Texas. The sudden boom brought wildcatters of the day prosperity beyond their wildest dreams and problems they could never have imagined, including something they called “roily oil”—crude oil mixed with water that virtually meant the demise of an oil well. This wet crude was not only worthless to producers, but it also caused a huge disposal problem. Producers channeled the oil into pits in hopes that the water would settle out or evaporate. Some tried to heat the oil with steam coils, but this method was commercially impractical. Refineries wouldn’t accept the oil/water mixture because the water corroded equipment and, under heat, would generate explosive steam pressures. Pipelines refused to accept it due to corrosion issues. The result was not only lost profits but also a huge environmental concern when dumping roily oil polluted streams, killed livestock, and ruined property. In 1907, a young chemist from St. Louis, Missouri, named William S. Barnickel was working as a consultant in Sapulpa, Oklahoma. At night, he could see fires 48
blazing from the ground, and during the day, he watched the skies turn black with clouds of smoke produced from pits filled with the burning, useless oil. He later wrote: “Large quantities of ‘cut’ oil were going to waste and being burned in all parts of the field. Cut oil, as it is now called in the fields, was then not understood. It was regarded as worse than worthless and was (then) called ‘B.S.’ (for basic sediment)…Large quantities of this B.S. were flowing down the creeks and, at one time during the year 1907, the entire surface of the Arkansas River and even the surface of the Mississippi River at New Orleans were covered with black oil, or B.S., from this oil field.” Motivated by these sights, the 29-year-old Barnickel began searching for a chemical means of separating what he knew as a chemist to be simply a waterin-oil emulsion. After returning to St. Louis, Barnickel studied samples of the B.S. and soon learned that the problem of “cut” or “wet” oil plagued oil fields across the U.S., resulting in millions of barrels of oil being wasted annually.
After fours years of trial and error, Barnickel developed a process for reclaiming crude oil that was both economical and fast acting. In 1914 he was granted the first of several U.S. patents for his process and after outfitting a small factory in St. Louis in 1916, sold his first two drums of a product that he had named “Tret-O-Lite.” Barnickel’s Tretolite company was up and running. By 1920, Barnickel’s business had outgrown the original manufacturing plant. Construction began on a new $200,000 plant outside of St. Louis, which opened in May 1921. The following year, Barnickel’s thriving company sold 10,815 drums of TretO-Lite demulsifier, representing a recovery of an estimated 50 million barrels of “cut” oil. With what seemed like years of struggles behind him and nothing but high hopes ahead of him, Barnickel’s health suddenly began to decline. He died of a perforated ulcer on May 19, 1923, the day after his 45th birthday. While Barnickel was researching a chemical method for separating oil and gas, Dr. Frederick G. Cottrell at the University of California was perfecting a system of precipitating solid particles from flue gases using electricity. When Cottrell learned about the vast quantities of California crude oil being stored or wasted because of its water content in 1908, he successfully conducted
an experiment to demonstrate that his electric technology could separate water from oil. A year later, the first commercial application of this technology was successful and, in 1911, Petroleum Rectifying Company of California (PETRECO) was formed. In December 1930, PETRECO and Tretolite would merge their businesses—and their names—to form Petrolite Corporation. Through the years, Petrolite pioneered new chemistries to solve the problems of demulsification, not just in the oil fields but in refining and other industrial applications. During World War II, the company applied this technology to help pharmaceutical companies overcome the last obstacle in creating a process for the mass production of penicillin, saving countless lives as a result. Petrolite inventors also pioneered such technologies as the filming organic corrosion inhibitors that are a standard in the petroleum industry. Injected into wells, these products work to prevent the highly corrosive effects of dissolved gases, such as carbon dioxide and hydrogen sulfide. The company was also granted the original patents for surfactant flooding used in today’s enhanced oil recovery processes.
salts and other contaminants from crude oil streams that, if left unchecked, would corrode and foul the systems, seriously reducing refinery throughput. Early on, the company also pioneered a process for recovering microcrystalline waxes from crude oil tank bottoms. These refined microwaxes were then sold for use in a wide variety of consumer applications from food packaging to cosmetics. These examples represent only a small sampling of the technological breakthroughs pioneered by Petrolite employees, who historically have been prolific inventors. The most prolific was Dr. Melvin DeGroote, whose career spanned 36 years beginning in 1924. He was named as inventor or co-inventor on 963 U.S. patents, the largest number of chemical patents ever issued to one inventor. In 1997, Baker Hughes acquired Petrolite Corporation and combined it with Baker Performance Chemicals to form Baker Petrolite, the largest oilfield chemical company in the world. Though the spelling and product description has been updated, the TRETOLITE™ brand of fluids separation technologies is still an important product offering from Baker Hughes.
In refineries around the world, electrostatic desalting technology, which was pioneered by Petrolite, helps to remove www.bakerhughes.com