2013 | Volume 4 | Number 1
CONNE US The Baker Hughes Magazine
Well of the Future
A Solid Bond
A Total Solution
Equion builds ambitious, sustainable business plan on nontraditional relationship
Deploying the right tools and technologies to ensure well integrity
Small independents have less overhead, expert network with total well solution package
Building Service Solutions based on
It wasn’t long ago that the energy conversation was all about hydrocarbon scarcity and peak oil. Now, thanks to the deepwater and unconventional resource booms, the conversation has changed. Today, the buzz is all about the potential prosperity that comes with an abundant global energy supply. However, as we run the race to “unconventional” prosperity, the ﬁnish line constantly moves because new technical and economic challenges are uncovered every day. And breakthroughs in technology and service models will be required to meet these challenges. We believe the next breakthrough for unconventional resource development will be to leverage our understanding of the subsurface to optimize drilling, completions, and production.
Building Service Solutions based on
It wasn’t long ago that the energy conversation was all about hydrocarbon scarcity and peak oil. Now, thanks to the deepwater and unconventional resource booms, the conversation has changed. Today, the buzz is all about the potential prosperity that comes with an abundant global energy supply. However, as we run the race to “unconventional” prosperity, the ﬁnish line constantly moves because new technical and economic challenges are uncovered every day. And breakthroughs in technology and service models will be required to meet these challenges. We believe the next breakthrough for unconventional resource development will be to leverage our understanding of the subsurface to optimize drilling, completions, and production.
One of the major lessons from the
they can make the most productive
In the Northeast U.S., Baker Hughes
initial unconventional “era” is that
decisions is a fundamental goal of the
is delivering a total well solution for
to build a truly sustainable global
Baker Hughes unconventional resource
Gastar Exploration Ltd. The operator
shale business, we must ﬁrst reframe
strategy. We recently enhanced that
is seeing increased production after
our current approach—which relies
strategy by entering a collaborative
changing its standard fracturing
heavily on empirical data and a
relationship with CGG, a fully
design to an irregular spacing design
factory drilling mindset—to an
integrated geoscience company that
based on a developing technique
approach that is based on geologic
provides geological, geophysical, and
that uses reservoir lithology and
measurement and scientiﬁc models.
geomechanical stress measurements to place the laterals.
We know that no two unconventional
By employing reservoir models that
resource plays are the same. Even
integrate log-derived, near-wellbore
Reframing our unconventional resource
large source rock shale deposits
geomechanical and petrophysical
strategies around the geosciences and
have sweet spots and nonproductive
properties from Baker Hughes with
advancing these new ideas mean we
sectors. So, our desire over the last
calibrated seismic data from CGG,
can extract hydrocarbons in the most
half decade to engineer the shale with
operators can optimize well placement
effective, efﬁcient, and sustainable
a one-size-ﬁts-all approach cannot
and completion design earlier in the
be sustained on a global basis.
asset life cycle for more efﬁcient well construction and more productive wells.
As we move to commercialize
It also means that as an industry we can build a sustainable global
unconventional unconventional resources in places
In this issue of Connexus , two articles
unconventional unconventional resource business that
like China, Saudi Arabia, and South
about total well solutions for customers
minimizes our footprint, improves
America, we’re going to be less
producing unconventional unconventional resources in
recovery, and, ultimately, delivers
and less inclined to drill hundreds
North America relate the importance of
energy to help transform communities.
of wells in one play to use the law
of averages to predict results. In South Texas, Baker Hughes is Instead, we have an opportunity
providing a total well solution to
to integrate prediction techniques,
Cheyenne Petroleum, one of numerous
such as hydraulic fracturing models,
smaller producers in the Eagle Ford
with geomechanics, petrophysics,
shale. The Baker Hughes reservoir
and reservoir simulation to identify
solutions team created a hydraulic
commercial prospects earlier and
fracturing model using our proprietary
to derisk the entire ﬁeld faster and
fracturing simulator and then
experimented with different fracturing
Martin Craighead Chairman and CEO, Baker Hughes
scenarios to see which methods Providing our customers with a more
produced the best results. A production
comprehensive view of their reservoirs
simulator then showed how each
to accurately pinpoint sweet spots so
change would affect ultimate recovery.
Back to the Future
With operations reaching a performance plateau with current technology, knowledge, and experience, Equion and Baker Hughes have embarked on an ambitious, sustainable plan to design the well of the future.
In-house Baker Hughes coordinators enable small independent Gastar to operate with less overhead but still have access to all the engineering and R&D experts it needs for its operations in the Marcellus shale.
J. Russell Porter, president and CEO of Gastar Exploration Ltd., shares his thoughts on the outlook for natural gas production in the U.S. and how smaller independent companies are playing a big role in the production growth from unconventional resource plays.
A Solid Bond
Baker Hughes is working closely with operators to understand their well integrity challenges, and then deploy the right combination of tools to address them.
Cheyenne Petroleum is ﬁnding cost savings in almost every aspect of its Eagle Ford shale operations with a Baker Hughes total well solution.
The Right Advice
Gaffney, Cline & Associates’ global expertise is providing the technical, commercial, and strategic advice to enable Baker Hughes to bridge the gap between delivering products and services and delivering total solutions.
More and more operators are introducing the smart ﬁeld value-added concept to their business plan, which means much more than just automating a ﬁeld or c ompleting the wells with “intelligent” devices.
After the Frac
As shale oil feedstocks move from the wellbore through the reﬁnery and into the market as ﬁnished products, the downstream industry is looking for the right technologies to minimize reﬁning bottlenecks, maintain reﬁnery reliability, and ensure product quality.
Faces of Innovation
Experience with time-released medicine led DV Satya Gupta to the oil patch and his work in time-released additives in fracturing ﬂuids and the Sorb™ line of long-term production assurance products. 2
The Gulf of Mexico’s frontier ultradeepwater Lower Tertiary trend has pressures up to 27,000 psi and reservoir temperatures up to 325°F (163°C). Baker Hughes has a single-trip frac-pack deployment system for that.
The Joy of Software
Drilling and evaluation software can be complex. Running it shouldn’t be, say the folks in the group that performs “usefulness” testing on software that is integral to many of the tools that Baker Hughes designs and manufactures.
As much as 30% of the nonproductive time on a deepwater drilling rig is the result of debris in the wellbore. Baker Hughes may now have the industry’s best integrated system for removing it.
The Marcellus shale is a sedimentary rock formation stretching from upstate New York to the rolling Appalachian Mountains of West Virginia, shown here.
is published by Baker Hughes Global Marketing. Please direct all correspondence regarding this publication to [email protected]
www.bakerhughes.com ©2013 Baker Hughes Incorporated. All rights reserved. 38453 05/2013 No part of this publication may be reproduced without the prior written permission of Baker Hughes.
Kathy Shirley strategic marketing manager, brand
Cherlynn “C.A.” Williams publications editor
Tae Kim senior graphic designer
Shirley Leong senior graphic designer
New sponge liner coring systems, electrical submersible pump designs, and hydraulic fracturing pump designs help solve customer challenges.
On the Cover
Baker Hughes supports the PETRONAS Petroleum Education Center, dedicated to the development of future industry leaders by providing hands-on training in real-world applications and by promoting the development of new products and technologies.
An App for That
Lan Pham web designer Contributors
Ann Liggio Peter Schreiber
A Look Back
H. John Eastman is called “the father of directional drilling” because of his role in killing a giant oilwell ﬁre in 1934 using his newly developed techniques for controlled directional drilling. www.bakerhughes.com
With most of its licenses set to expire progressively through 2020, Equion is challenged to improve on an operational plateau for wells being drilled in the Colombia foothills. With Baker Hughes, it is seeking a step change in time and cost performance.
Speaking at a technology leadership conference last year, Martin Craighead, chairman and CEO of Baker Hughes, said the lines between the players in the energy industry are blurring. He said that, going forward, success will require nontraditional “balanced” partnerships between operators and service companies. Together, they must learn to apply technology better and faster in a trusting, collaborative way. “Primary responsibility for technology development shifted decades ago to service companies, and as these technologies—and the problems they are intended to solve—have become more exotic, and as the ﬁnancial and other resource requirements increase, there is a necessity for nontraditional business relationships,” Craighead said. The speech resonated with Carlos Vargas, vice president of Drilling and Completions for Equion Energia Ltd., a joint venture company between Colombia’s state-owned oil company Ecopetrol and Talisman Energy, a Canada-based exploration and production company. Equion acquired all of BP’s oil and gas exploration, production, and transportation holdings in Colombia in January 2011. Among the assets were interests in ﬁve producing ﬁelds in the Casanare foothills of eastern Colombia that, for more than 20 years, have been among the world’s most challenging drilling and completion environments. Equion’s full-time workforce is fewer than 500 people, primarily former BP employees. Without the resources of a supermajor, Vargas and other leaders at Equion knew that reinventing the company and meeting its ﬁnancial objectives were daunting challenges.
“When I took this position as vice president, I knew I had to do something different to improve our performance,” Vargas says. “It’s very expensive to operate in the foothills, and we are no longer a company that can support the capital expenditures needed to develop these ﬁelds. We need a breakthrough in our performance by improving the way that we are drilling and completing our wells. “Martin Craighead was right. The only way to overcome the challenges that we have in the industry today is to work differently by working together.”
A plan for the future With a limited amount of time to recover hydrocarbon reserves in some of its contract areas, and with operations reaching a performance plateau with current technology, knowledge, and experience, late last year Equion embarked on an ambitious, sustainable plan it calls “The Well of the Future.” Equion’s ultimate goal is to make the wells 30% more efﬁcient in time and in cost. The ﬁrm chose Baker Hughes as its technology partner to complement its own capabilities to innovate and optimize the processes needed to construct and complete the challenging foothills wells. With so much relying on The Well of the Future concept, choosing a committed partner with world-class technical resources was paramount, says Alexander Valdivieso, Well of the Future project manager for Equion.
> Among the Well of the Future team are (from left) Jairo Peñuela, Jose Luis Gómez, Jae Song, Wilson Carreño, Mario Pacione, Alexander Valdivieso, Pedro García, Graeme Symons, Luis Carlos Alzate, Cesar López, and Diego Ramirez.
“Baker Hughes is a leader in drilling technology with substantial foothills experience with Equion and other operators in the area,” Valdivieso explains. “We have a very good relationship in terms of delivery, technology, and trust built over many, many years. We wanted a partner who could align with our goals and realize our sense of urgency to develop the project, and we have that visible commitment from all levels within Baker Hughes.” “At Baker Hughes, we pride ourselves on helping our customers solve their most difﬁcult challenges,” says Adam Anderson, president, Latin America. “Further, we always look for opportunities to collaborate with customers in innovative ways. In this case, a critical customer came to us with an open mind and asked us to help them achieve breakthrough performance in drilling some of the world’s most difﬁcult wells. It was a natural ﬁt for Baker Hughes and Equion to work together on the Well of the Future project, and having partners from our customers such as Carlos and Alexander will make this a tremendous success for both our companies.” Embedded since December 2012 in Equion’s Bogota headquarters, a dedicated team of Baker Hughes and Equion employees with “multidisciplinary expertise and an interdisciplinary attitude” is 100% focused on designing a plan that will deliver signiﬁcant and sustainable value versus the current wells. “Equion has a challenging deliverable that will be operationally complex and
ﬁnancially demanding to achieve,” says Edgar Peláez, Baker Hughes vice president of business development for Latin America and executive cosponsor of The Well of the Future. “Well construction in the Casanare piedemont [foothills] currently requires substantial investment in both time and money, leading to a low return on investment for shareholders and compromising business sustainability. “The Well of the Future team’s goal is to analyze 20 years of history, then canvas the world’s ‘best practices’ to see what can be applied through different processes, equipment, and technologies to do things 30% faster and with 30% lower total cost through innovative well designs that can be extrapolated to all the future wells in the hydrocarbon-rich Piedemonte license area and beyond. With some of these wells taking 300 days to drill and complete at costs up to $100 million, a 30% savings in time and cost is signiﬁcant.” Reaching these operational goals will take a global network of high-level technical and management support, as well as a steering committee of upper management from both companies to govern the project.
The complexity of the Well of the Future project can be readily appreciated by looking at just one aspect of the well construction process:
running the 11 ¾-in. casing and not getting it to bottom as planned. Among the questions that might arise are:
“The Well of the Future team is really a global network of experts on each of the relevant technologies that may provide a solution,” Peláez says. “We don’t know where the next solution might come from, but we’re going to promote creativity and connectivity through both of our organizations.”
Why can we not rotate the casing to get past the obstruction? Is the well profile creating too much torque and drag? Are we exceeding the torque limit of the casing couplings? Are the casing couplings hanging up? Is the hole being cleaned effectively? Has the hole collapsed? Why? Have we got the mud rheology right? Have we got the mud weight right? Was the kickoff point too deep? What about the hole geometry itself? What are the geomechanical stresses at the stuck point? Have we reactivated a fault? Are there ledges? Do we have interbedded formations?
It’s clear to see from this one example that the task at hand is not a simple one, and though some of these questions occur every day on every well in the world, what’s different in the Colombian foothills is that they can all happen on every well.
A mountain of challenges The 17,000 ft (5182 m) of dipped and folded geology between the drilling rig and the producing zones beneath the Andean foothills is nothing short of hellish. The complexities of the formations are numerous: high tectonic stresses and activity; multiple faults; geological uncertainty; strong natural tendencies; lost-circulation zones; very hard and abrasive formations; and deep, low-porosity reservoirs. Taken together, it means low rates of penetration (ROP), challenging tool and equipment reliability, an abundance of nonproductive time (NPT), and huge costs in rig time. Poor seismic quality
Almost every obstacle calls for a contingency plan, but the reliability and quality of seismic interpretation in the foothills are poor, according to Olga Carvajal, the Baker Hughes geomechanics expert assigned to the project. “High-dip angles and successive faults make the acquisition of good seismic data extremely difﬁcult,” Carvajal says. “Lateral variation—another important factor that increases the geological uncertainty—is so high that instead of these wells being called development wells, we need to think of them as exploratory wells.” High NPT
The last seven wells that Equion has drilled in the Piedemonte have averaged 16% NPT. Invisible lost time was even higher at 25%. “Almost all the NPT is related to the complexity of the geology and the stability of the wellbore,” explains Jose Luis Gómez, senior drilling engineer for Equion. “Packoff events. Stuck bottomhole assemblies. Mud losses in the 26-in. and 18 ½-in. hole sections. Difﬁculty running casing to bottom.
Many of these costly NPT issues occur in the upper and middle hole sections long before we even get near the reservoir. In the reservoir itself we also have opportunities to reduce invisible lost time such as improving drilling efﬁciency. And, because we have to use a large, powerful rig to get to the deeper reservoir sections, rig down time becomes very expensive, as well.” Fluid inconsistencies
“Oil-based muds have been the preferred choice over the last 20 years for drilling across these challenging intervals, but even after all these years of experience, we are still facing many problems that have not being resolved,” explains Jairo Peñuela, ﬂuids advisor for Baker Hughes. “Borehole instability along the intermediate sections is one example. There is a clear opportunity to reduce costs by improving the drilling mud system, especially considering the development of water-based technologies in recent years.” Drilling difﬁculties
Management Commitment and Support
The Well of the Future
As a senior directional drilling advisor for Baker Hughes, Graeme Symons has worked in some of the most challenging drilling environments on earth, including Colombia. “I don’t think there’s any place exactly like this,” Symons says. “Obviously, from a directional drilling standpoint, the geologic complexity is our challenge. On top of that, the hardness of the rock in this area makes it an extremely difﬁcult place to drill, so drilling dynamics and tool reliability become issues.”
the Well of the Future team. “Finding the best combination of drilling system and drill bit to improve the ROP performance in the sandstones will have great impact in reducing the time and cost of the wells.”
“Sandstones in the overburden and the reservoir are very hard and abrasive and they are normally drilled at a very low ROP—1.5 to 4 ft [.45 to 1.2 m] per hour,” explains Pedro Garcia, Baker Hughes senior drilling optimization engineer assigned to
“If these wells are split into sections, we see similarities to wells in Bolivia, Algeria, and Kazakhstan,” Symons adds. “So, we will be able to pull experience from those locations and bring it into this project. Equion is expecting us to go worldwide and
> While the Well of the Future project focuses primarily on reducing the time and cost to drill, making adjustments in casing design could help allevia te the problems of hole instability and severe mud losses, while a multilateral well design could make a huge difference in improving productivity.
identify places where we have done similar work and incorporate that experience.” Completions questions
“Due to the complexity of the reservoir itself, and to the uncertainties attached to the stress regime that exists in the reservoir rock, the ﬁnal completion method and its design needs to be ﬂexible enough to perform within a range of possibilities,” adds Juan Carlos Alzate, senior geologist for Equion. “We never know until the reservoir is actually being drilled whether
the wellbore has intersected a section with large fractures, natural fractures, drilling-induced fractures, no fractures, low porosity, or a combination of all of these. We have to have contingency plans in place to fracture or not to fracture the reservoir to increase production prospects. “The one thing we do know for certain about all of these challenges,” Alzate concludes, “is that they need to be well understood from an interdisciplinary point of view before we drill the ﬁrst well.”
The 17,000 ft (5182 m) of dipped and folded
geology between the drilling rig and the producing zones beneath the Andean foothills is nothing short of hellish.
“The only way to overcome the challenges that we have in the industry today is to work differently by working together.” Carlos Vargas
vice president, Drilling and Completions, Equion
Interdisciplinary solutions Traditional well operations typically follow a sequential pattern. The drilling team generally focuses on getting the well to total depth as fast as possible before it’s handed over to the team running completions and puting the well on production. While this approach is usually sufﬁcient for designing “normal” wells, the Well of the Future team quickly realized that a total interdisciplinary approach was in order to maximize innovation, synergy, and value. “Going forward, all disciplines will work together on each other’s technical needs and challenges,” says Mario Pacione, Well of the Future project manager for Baker Hughes. “A typical example of this is the interrelationship between geomechanics, directional drilling, and ﬂuids to obtain the best hole quality possible, especially in a stressed environment like the Andean foothills.”
“This holistic approach is vital due to the multitude of interlinked challenges,” Peñuela adds. “For example, due to the reactive shales, it is necessary to use an oil-based mud system to reduce shale instability. But logging-while-drilling tools work better in water-based systems. Oil-based mud is also more expensive and, in the event of a lost-circulation event, even more costly. Counter to that, oil-based mud is better able to combat the effects of abrasive formations on drilling tools. So, there always exists this conﬂicting scenario where one solution creates another problem.” Before drilling begins in 2014, these are the issues the team will be grappling with to reach the best combination of systems, parameters, and procedures to accentuate the positives and minimize the negative impacts of every procedural decision. “We are going to pick apart the way that wells were drilled in the past and put every equipment choice and every process step under the microscope and collectively ask ‘why was it done this way?’ and, ‘what if we do it this way?’” Valdivieso says. “We will be applying a continuous improvement technique called DMAIC [deﬁne, measure, analyze, improve, control], which will guide our engineering approach. It will lead us to deﬁne each problem, determine its impact, work out the causes, and determine the best solutions for every problem; then learn from
their implementation and feed ﬁndings back into the learning loop.” And every step of the process is team driven. “The team is divided into task force groups, putting together people who have related skills,” Valdivieso explains. “We work from the bottom up, and when an approval of the project managers is required for a decision, we meet together—everybody as a team— and we make the decision to proceed to the next step of the planning process. At the end of every stage of the planning process, the sponsors and the steering committee will receive a report, and then that governing body will give approval to continue to the next gate. That is a clear goal—having a process that facilitates our decisions.” “This is an exciting and nonconventional project for Baker Hughes,” concludes Ramón Reyes, business development manager for Baker Hughes. “We are looking at 20 years of history and helping to project the next 20 years for Equion. It is not often that a service company is invited to be a part of the conceptualization and the vision of such a project. We are not here to sell products and services. We are here to understand the business of the future.”
a i g r e n E n o i u q E f o y s e t r u o c s o t o h P
Colombia by the
Colombia’s ranking in the world as an exporter of cut ﬂowers, after the Netherlands, shipping more than USD 1 billion in blooms annually
2 nd 500
Amount of ﬂowers Colombia exported to the U.S. for Valentine’s Day in 2013
Distance the national bird of Colombia, the Andean condor, can ﬂy in one day
Barrels of proven oil reserves (January 2013)
Barrels per day of oil production in 2012
Area of Colombia covered by natural forest
Number of species of plants indigenous to Colombia (15% of the world’s existing species)
Species of birds indigenous to Colombia (20% of the world’s total bird species)
Colombia’s ranking in the world for most species of butterﬂies, roughly 3,000
Colombia’s ranking in the world for Spanish-speaking population
FIFA world ranking as of April 2013
Population of Colombia, second largest in South America after Brazil
Height of Pico Cristobal Colon, Colombia’s tallest mountain peak
Percentage of Colombian coffee a product must consist of to obtain a license to use the Juan Valdez trademark
Number of people employed in Colombia’s coffee industry
Sources: Embassy of Colombia , Washington, D.C.; www.cia.gov; World Intellectual Property Organization
When a small company invests the majority of its capital budget into one project, every spending decision becomes a big one.
Less than three years ago, Gastar Exploration Ltd. found itself a long way from its legacy assets i n the deep Bossier natural gas play of East Texas when it ventured east into Appalachia and one of North America’s busiest unconventional resource plays—the Marcellus shale. The good news for Gastar was that its 75,000-plus net acres in northern West Virginia and southwestern Pennsylvania contained “wet-gas” resources—a hidden treasure in the predominantly dry-gas Marcellus basin. The bad news was that it was 2010, and service companies could pick and choose who they wanted to do business with in the Marcellus and every other unconventional play in the U.S. Gastar found itself with prime acreage and a plan to drill a lot of wells but no one willing to do the work—except Baker Hughes. “At the time, it was really busy up here with the Marcellus coming on, and we didn’t have any idea how we were going to get our wells completed,” says Mike McCown, vice president for Gastar’s Northeast operations. “We had drilled our ﬁrst well in November 2010, and it was obvious that the company providing drilling services on the well had no interest at all in providing us fracturing equipment. I convinced the folks that I knew at Baker Hughes that we were serious and that we were going to be here to stay.” A two-page agreement and a handshake between McCown and John Fishell, director of strategic integration for Baker Hughes in the Northeast, forged a deal for
a “total well solution” on all of Gastar’s wells in the Marcellus. “It basically means that Baker Hughes will provide competitive services at a competitive price, and Gastar will allow Baker Hughes to provide every service that it has available to us, including reservoir services, drilling systems, ﬂuids and solids control, completions equipment, pressure pumping, wireline services, water management, and production chemicals,” McCown explains. By early March 2013, Gastar had drilled and completed 56 wells using some of the most innovative technologies in the Baker Hughes portfolio.
“There’s a lot of moving parts out there. These wells are complex and, because we have so few employees, we rely on an excellent group of consultants out in the ﬁeld. The coordination of all the different disciplines within Baker Hughes is essential and key to our success.” Guzman and Bolyard work at Gastar’s Clarksburg, West Virginia, ofﬁce. “Having in-house contacts coordinating activities enables us to operate with less overhead but still have access to industry experts,” adds Tom Rowan, Gastar drilling and completion engineer. “The communication level is tremendous because more heads come together to ﬁnd solutions, but the main beneﬁt is continuity. The concept has strengthened both companies.”
Building relationships Even though Gastar is a well-ﬁnanced, publicly traded company with a strong acreage position in the Marcellus, it is still a relatively small operator. With approximately 45 employees, managing the ﬂow of products and services from multiple suppliers on every well adds costs by creating delays and nonproductive time. Realizing that the efﬁciency of continuous operations is a key component to improved economics, Baker Hughes has assigned two coordinators— Jorge Guzman for drilling and Jeremy Bolyard for completions—to manage the dynamics among the various product lines that are constantly moving on and off Gastar’s wellsites. “The coordination of all these various product lines is a signiﬁcant beneﬁt to our working relationship,” McCown says.
The partnership between Gastar and Baker Hughes goes beyond producing natural gas and oil. For example, Gastar’s health, safety and environmental (HSE) coordinator went to work for another company last summer, leaving Gastar without an HSE lead. “The Baker Hughes safety manager for this area offered to step in and help us out,” McCown says. “He went out and reviewed our drilling rigs and performed onsite inspections of facilities that didn’t even impact our business with Baker Hughes. That speaks volumes about our working relationship. And, by the way, I’m aware of only one recordable injury—a minor ankle sprain—among all the hundreds of employees between the two groups that have been out on location daily for the past two years. That’s an excellent safety record that speaks for itself.”
Driving down costs Part of the total well solution for Gastar is having immediate access to a global network of experts. “We depend on the research and development and engineering abilities of Baker Hughes as if they were our own,” McCown says. “The AutoTrak™ Curve high-buildup rate rotary steerable system is the best example I can think of. When that technology was communicated to us and we saw the savings that operators were getting in other parts of the country, we knew we wanted to use it because the savings were dramatic. Using the AutoTrak Curve system, we’ve reduced drilling time from 27 days to 18 days.” “Gastar was the ﬁrst customer in the Northeast to run the AutoTrak Curve system,” says Wayne Symons, Baker Hughes directional drilling services manager, Northeast area. “These wells are around 6,500 ft to 7,000 ft (1981 m to 2134 m) true vertical depth, and the lateral probably averages 6,500 ft (1981 m). The ability to stay in the targeted area as you drill with the AutoTrak Curve system creates such a true wellbore and enables you to drill in a very timely fashion. We’ve also introduced the Talon™ high-efﬁciency PDC bits, which use proprietary polished cutters and improved mechanical and hydraulic designs to optimize drilling performance. The Talon bits are providing faster rates of penetration and longer run life in the shale formations. And, everyone in this business knows that time is always money.”
“That’s right,” McCown says. “If a larger E&P company saves $200,000 or $300,000 on a well it has much less impact in the big scheme of things than it does on Gastar when 80% of our capital budget is here in the Marcellus. The things that we do up here really matter.”
Embracing new technology “Let’s face it, the Barnett shale has been drilled through for years,” McCown says. “The Marcellus has been drilled through on the way to deeper formations for probably 70 or 80 years and if it weren’t for new technology the nonconventional formations in these basins would never have been exploited and developed the way they are today. So, I think we have to embrace new technology.” That willingness to implement new and innovative technologies is manifesting itself in quantiﬁed results for Gastar. Gastar’s standard frac design that placed a stage every 290 ft (88 m) was changed to an irregular spacing design based on results of the Baker Hughes cased-hole Reservoir Performance Monitor (RPM™) pulsed neutron services and the XMAC ™ acoustic logging services. Both services were run on tractor in the lateral to measure reservoir lithology and mechanical
S t e e r a b l e M o t o r S y s t e m
h t p e D
A u t o T r a k C u r v e S ys t e m
s e t a i c o s s
A n a y R s e l r a
h C f o y s e t r u o c s o t o h P
properties, says Eric Claus, account manager for Baker Hughes wireline systems, who introduced the technology to Gastar. “Working with our wireline group, Gastar chose the perforation stages for a nongeometric frac design based on information obtained from these logs,” adds Randall Cade, manager of the Baker Hughes reservoir solutions team. “The team analyzed production from this well and, compared to four offsets, found it to be 32% better per pound of proppant pumped.” Results were based on 66 days of production from all wells. “Microseismic analysis and basin experience led us to recommend a 30° azimuthal change for horizontals,” adds Kevin Flavin, a senior geologic consultant. “This new direction will enable Gastar to take full advantage of natural fractures occurring at right angles to principal stress. Our recommendation to change well azimuth is being tested now.” With approximately 100 wells remaining to be drilled, the Baker Hughes reservoir solutions team continues to recommend ways to improve well targeting and stimulation, including logging-while-drilling, improved frac designs using logs for lateral characterization, improved proppant, better completion techniques, and improved lift options. The team also is analyzing drilling
pad well architecture, including wellbore inclination and tortuosity, to explain production anomalies. McCown recently attended a presentation on the new Baker Hughes Rhino™ bifuel pumps that use a mixture of natural gas and diesel, reducing diesel use by up to 65% with no loss of hydraulic horsepower. “If Baker Hughes gets a ﬂeet of those up here, hopefully we’ll be the ﬁrst ones to use it,” McCown says. “It’s just a matter of time— due to regulatory pressure—before everyone will be compelled to reduce emissions and what better way to do it than to use your own gas that you’re producing on location?” Another new technology introduced to Gastar, says Robert Todd, senior account manager for Baker Hughes, is the Baker Hughes Alpha Sleeve™ pressure-actuated valve, which is saving approximately USD 20,000 per well by eliminating tubingconveyed perforating and cleanout runs. “This pressure-actuated valve provides interventionless access to the formation during plug and perf operations, saving time and money,” Todd adds. As with any hydraulic fracturing operation, water management is always an added expense. Gastar built a pipeline from the Ohio River to one of its ﬁelds to avoid having to truck in water for its fracturing operations.
Sourcing water is just one part of the water management equation, however. “Companies also face costly water disposal issues—particularly in the Northeast where environmental concerns are paramount,” says Shawn Shipman, area manager for Baker Hughes Water Management. “Gastar is using the Baker Hughes H2prO ™ water management service to further reduce costs and environmental impact associated with water usage by treating produced and ﬂowback water for reuse in hydraulic fracturing operations.” “Based on some of the other experiences in the basin, we started off using 10% ﬂowback water in our fracturing water,” McCown says. “Through recommendations by Baker Hughes, we have increased that to the point where we’re now up to 30%, minimizing our disposal costs and dramatically reducing the amount of water that we need to dispose of. At $7 a barrel, that’s a tremendous savings, and the water quality is excellent so we don’t have to worry about damaging the formation.” “Costs have precluded small companies from drilling Marcellus wells,” McCown concludes. “We know that we do more with fewer people than any other company in the basin, and a lot of that is because of the assistance of Baker Hughes.”
“These wells are complex and, because we have so few employees we rely on an excellent group of consultants out in the ﬁeld. The coordination of all the different disciplines within Baker Hughes is essential and key to our success.” Mike McCown vice president for Gastar’s Northeast operations www.bakerhughes.com
r e t r o P l l e s s u R J.
h t i t w T H G G I N S I Y R T S U D N I
With the rise in production from unconventional resource plays, much has been written about the U.S. becoming energy self-sufﬁcient. What are your thoughts on this? Can this goal be achieved? I don’t see the U.S. becoming truly independent of foreign crude sources to the point where no crude is being brought into the country, but I do think we can greatly reduce our reliance on foreign crude. If we adopt natural gas as a component of transportation fuels and if we continue to allow access for development of our resources in North America, then yes, I think we can greatly reduce our dependence on foreign crude. J. Russell Porter is president and CEO of Gastar
Exploration Ltd. He has approximately 20 years of experience in the natural gas and oil exploration and production sector. Prior to joining Gastar, he served as executive vice president of Forcenergy Inc., a publicly traded exploration and production company, where he was responsible for the acquisition and ﬁnancing of the majority of its assets across the U.S. and Australia. Porter earned a bachelor of science degree in petroleum land management from Louisiana State University and an MBA degree from the Kenan-Flagler School of Business at the University of North Carolina at Chapel Hill.
Smaller independent companies have been a large part of the production growth from unconventional resource plays. Do you see the mix of companies in these plays changing in the future? The smaller companies have been the early movers in some of the unconventional resource plays. They’ve certainly been way ahead of the majors and even ahead of the superindependents. I think consolidation will continue because operators with lower cost of capital are the natural owners of these types of assets later in their life cycles when they’ve been ‘derisked’ and true large-scale
development can take place. I think you’ll see these assets migrate toward the larger companies because they have more attractive cost of capital. But, there are decades of drilling to be done in these plays within the U.S., so I think there’s always going to be a role for the smaller companies to play.
What is your outlook for natural gas in the U.S.? I don’t think there is a lot of price downside, but I do think price is going to be limited because the size of the resource is so great. I think we need to use gas in a more valuable way—as a transportation fuel, for instance, primarily replacing diesel. The announcement in early March that the railway company BNSF is to begin testing a small number of locomotives using liqueﬁed natural gas as an alternative fuel to diesel was very enlightening. BNSF is the second-largest user of diesel in America behind the U.S. Navy. I think the government should embrace the concept and really be supporting development of the infrastructure needed to do this sort of thing.
In your view, how will federal and state regulations affect the future of activity in the Marcellus and other unconventional shale plays?
The two areas we are watching the most are hydraulic fracturing regulations and additional air quality regulations. Both of those would increase the cost of the resource, but I think the resources are too large not to be developed and used domestically. So, I don’t think that they are in danger of stymieing access to the resources, but I think they’ll just increase the cost of the resource and, like everything else, that cost will eventually be passed on to the consumer.
Although the Marcellus is considered a gas basin, Gastar has reported a 28% increase in oil/liquids reserves in just three years. To what do you attribute this increase in liquids reserves? And does Gastar intend to concentrate more on liquids production vs. gas production in the future? We are fortunate that our position in Marshall and Wetzel counties, West Virginia, is in the window of the Marcellus where there is a very liquids-rich gas resource. The increase that we’ve seen has come primarily from the development of those areas, and the fact that each well has about 35% liquids and 65% gas. That makes the economics very attractive. We’ll continue to focus on areas like that because that’s where we generate the highest return. A company our size,
or really any company, should be chasing the highest return available, and right now it’s in liquids plays. We’re fortunate in that our gas play has a very good liquids component to it.
Your total 2013 capital budget is USD 93 million—36% lower than 2012—yet you predict production will continue to increase. What is your strategy behind this? We’re now to the point where we can lower overall spending and still provide production reserve and cash ﬂow growth because the assets are derisked, and we’ve accumulated signiﬁcant assets. We’re not spending nearly as much on land as a part of our overall budget. And, And, we’re really just now into the development phase of the Marcellus, in particular, and we can get more and more efﬁcient. We spent quite a bit on land last year—our total capital was just under $150 million. This This year, year, we will spend in the low $90s but probably still deliver meaningful growth in production and reserves. So we’re sort of reaping the beneﬁt of prior years’ investment.
Baker Hughes is your single-source provider in the Marcellus. How has this improved your efﬁciencies and effectiveness? When we initiated a relationship with Baker Hughes, it was the only service provider that was willing to make the equipment and the personnel available to us on a timely basis. In return, we have been very open to the Baker Hughes total well solution concept of packaging services. Over the past two years, we’ve seen our overall costs per well decrease, and we’ve seen our EURs and our production increase. In my mind, that’s a direct result of the cooperation between Gastar and Baker Hughes, the fact that Baker Hughes is bringing a full suite of services to the project, and our willingness to engage new technologies—the formation imaging logs and the cased-hole logs, for example—that we might have been more reluctant in adopting if not for the relationship. Baker Hughes has been very good to say, ‘Try this and see if you like it. If you do, then we’ll work that into the services.’ Some things can have a real impact going forward. For instance, we’ve taken our average drilling time per well from 27 days to 18 days, and a lot of that has been because of our use of the AutoTrak ™ Curve high-buildup rate rotary steerable system. I think we still have the chance to drive probably half a million dollars of cost out of a $7 million well. Pad drilling
and bundling of services have helped us get more efﬁcient and drive down some of those costs, and also having an attitude as a company that we’ve got to make things more efﬁcient and drive those returns for our shareholders.
Much of the industry doesn’t see the value in applying reservoir studies to the unconventional resource plays. Why are they important to Gastar? I can’t imagine not using every piece of information that’s possibly available at a reasonable cost. We were early adopters of microseismic technology, and we’ve used that extensively in the Marcellus. We’ve been able to constantly adjust and improve our results and our practices by using that data. And, now, we’re tying that microseismic data to our production data, to our reservoir studies, and to our core analysis to bring everything into one comprehensive analysis of ‘What is this rock? What is this rock doing? What is the rock telling us by the way it performs, the way it fracs?’ We’re trying to glean as much information out of all the data as possible.
Is the industry being pushed by regulations toward a more sustainable water strategy? How can you drive down the cost of water to improve your project economics? I don’t think the industry needs additional regulations to move toward a more sustainable water strategy. We’re doing it without regulation. Gastar has reduced the amount of water used and thus the cost of both our water acquisition and our water disposal because doing so makes economic sense. We invested almost
$5 million to build a pipeline from the Ohio River into the area where we’re operating, so we access water at a fraction of the cost compared to buying it from other operators or from local municipalities. And, we’ve greatly reduced the number of water trucks on the roads, which reduces the impact on local communities, making the payback on our investment very attractive. In addition, we are recycling and reconditioning almost all of our produced water using the Baker Hughes Water Management program, which greatly reduces the amount of water we have to dispose of. We have water retention facilities where we can store our produced and ﬂowback water, recycle it, recondition it, and mix it with fresh water to use in fracturing jobs. We’re not seeing any problems associated with using more and more ﬂowback water, and the amount we use just keeps going up. All this means disposal costs go down and the number of vehicles on the road to move that water around goes down. So, we’re spending several hundreds of thousands of dollars less on every well for water as a result of the investments we’ve made—and we’re becoming more efﬁcient in water handling in general.
What is your near-term activity focus in your three core asset areas—the Marcellus, Mid-Continent oil play, and East Texas? We’re focused on continued growth in reserves and production and cash ﬂow per share. Right now, our focus is on those assets that are generating the highest return available—liquids-driven assets—so, we’ll continue developing the Marcellus. We’re derisking our new Mid-Continent oil play and that’s looking very
promising right now. There is a real focus on trying to eliminate costs and keep margins as high as possible in East Texas because that is a dry gas area for us.
How is Gastar investing in the communities in which it works? The ﬁrst way we invest in the communities where we operate is through the payment of tens of millions of dollars in lease bonuses, which later get followed by royalty payments. In addition, we’ve hired and trained local workers. Our staff in the Marcellus is made up of mostly West Virginia, Ohio, and Pennsylvania native s. We interact a lot with local ﬁrst responders, and we support those groups ﬁnancially. We’ve had town hall meetings where we’ve had people from every discipline within Gastar—construction, drilling, completions, fracturing, road crews—available to answer questions from the community. We’ve put tens of millions of dollars into improving and repairing roads that have been damaged by our activities. In one instance, we spent $5 million to build a new road that allowed us to access a large number of our locations without using the local county roads. All that helps create a positive aura about Gastar within the community. I think Gastar has a very good name wherever we operate in the Marcellus. We’ve been very conscious of health, safety, and environment, and we’ve had really no issues, so that’s been something we’ve focused on and we’re proud of because we’re not hurting employees. Overall we’ve got a very cooperative relationship with local community stakeholders—whether they’re royalty owners, surface owners, ﬁrst responders, or the highway department.
“When we initiated a relationship with Baker Hughes, it was the only service provider that was willing to make the equipment and the personnel available to us on a timely basis. In return, we have been very open to the Baker Hughes total well solution concept of packaging services. Over the past two years, we’ve seen our overall costs per well decrease, and we’ve seen our EURs and our production increase.”
Integrated technology solution aimed at
DRIVING INNOVATIONS IN WELL INTEGRITY By collaborating closely with operators and drawing from a comprehensive portfolio of design processes, cementing technologies and equipment, and R&D processes, Baker Hughes helps minimize risks and ensure long-term integrity for wells around the world.
The concept of well integrity is not new to the oil and gas industry, but several dramatic and well-publicized incidents in recent years have made the topic a higher priority for operators, regulatory agencies, and the public at large. “In a world of tightening environmental regulations and increased oil and gas activity in close proximity to high-density population centers, operators must demonstrate the highest competence and commitment to working in a safe and sustainable manner,” says Umberto Micheli, vice president, Baker Hughes Cementing product line. “Without this commitment, an operator may have limited options for sustained production in many regions.”
According to NORSOK standard D-010*, well integrity is deﬁned as the “application of technical, operational, and organizational solutions to reduce risk of uncontrolled release of formation ﬂuids throughout the life cycle of a well.” Baker Hughes’ philosophy on well integrity closely mirrors this deﬁnition, which has driven the company’s development of several technologies and applied solutions designed to improve cementing operations, selectively shut off ﬂow zones, and assure long-term well integrity. With continued expansion into deepwater frontiers and unconventional shale plays onshore, operators need ongoing assurance
that more advanced well integrity solutions are available. “Robust wellbore construction and completions tools will be needed to ensure long-term integrity of more complex wellbores that tap into deeper, hotter, and higher pressure reservoirs,” says Glen Benge, Baker Hughes senior cementing advisor. “This prompted Baker Hughes to conduct a serious review of its integrity technologies two years ago, in cooperation with our clients, to highlight technical gaps that need to be ﬁlled to meet a producer’s operational goals and new well-safety regulations.”
This review identiﬁed new development areas for the company and a need to combine well simulation, cementing, evaluation, and mechanical barrier technologies under one comprehensive well integrity solution. “This offering demonstrates our commitment to work closely with operators to understand their well integrity challenges, and then deploy the right combination of tools to address them,” says Deepak Khatri, director of onshore cementing for Baker Hughes.
Success through simulation An early step to reducing well construction risks is performing an in-depth, prejob evaluation that considers the objectives and challenges of building the well ahead of designing the cementing job. Baker Hughes cementing specialists complete this vital step by creating cementing prejob models using a number of cementing simulation software applications. The CemFACTS™ advanced cement placement software incorporates the planned cement setting depth, hole size, desired pump rates, and bottomhole temperatures and pressures to simulate cement slurry placement. It also performs interactive calculations of the necessary volumes of cement slurry and spacers, mixing and displacement rates, and anticipated pressures. The simulation also factors in ﬂuid compressibility and multiple temperature regimes. Taken together, this allows the operator to better predict rheological changes under bottomhole conditions, and pump rates can be modiﬁed to avoid lost circulation or ﬂuids migration.
Once the cement job has been completed, the CemFACTS software evaluates the results and analyzes how well they compare with the prejob simulation. “The software highlights deviations between the simulation and reality, enabling us to make changes to the cement job design for future wells and further optimize the process,” Khatri says. To better understand the expected wellbore stresses that will act on the cement and impact its long-term integrity, Baker Hughes engineers run the IsoVision ™ software application. Users input the physical properties of the cement, casing, and formation, as well as any expected temperature or pressure changes that might occur during the cementing, fracturing, and production phases. The software then models the radial and tangential stresses
and predicts whether the cement sheath will maintain its integrity throughout the full life cycle of the well. With this information, operators can make changes to their cementing program, such as including different additives in the cement that change its compressive and tensile strength, Young’s modulus, and Poisson’s ratio, and make it more resilient to downhole stresses. “The beneﬁt of these simulation offerings goes beyond the ability to make changes to the cement job design,” Khatri says. “They help engineers to make informed decisions regarding the placement, design, and selection of a cement system to better withstand wellbore stresses and minimize risks throughout the well’s producing life.”
Cementing a solid bond
Once the simulation is completed, Baker Hughes works with the operator to select the optimal spacer system, which helps ensure that the wellbore is free of drilling mud and other debris, and water-wets the casing string and formation rock for vastly improved cement bonding.
The Baker Hughes well integrity service includes the UltraFlush™ ME (micro emulsion) spacer system to assist in this effort. This patent-pending surfactant technology displaces oilbased mud systems and breaks the oil phase down into nanoparticle-sized droplets that are easily carried out in a strong water-external emulsion. To further optimize a cement job, operators need assurances that the cement is delivered to the desired location in the wellbore, without causing lost circulation issues or other damage to the producing formation. The SealBond™ cement spacer system can be deployed to clean the wellbore as well as mitigate the invasion of cement slurry ﬁltrates into the formation by forming a barrier at the wellbore wall, which also acts to strengthen the wellbore. Once the wellbore has been properly conditioned a cement slurry is chosen that will ensure the best long-term resilience against stresses in the cement sheath. Baker Hughes has a wide variety of cementing offerings under the Set for Life ™ family of cement systems—customized solutions that address a host of downhole conditions and well requirements. These solutions include:
The DeepSet™ system for shallow water and gas-flow control in deepwater wells
The DuraSet™ system to withstand stresses induced by hydraulic fracturing, high-injection pressures, and temperature fluctuations The PermaSet™ system for maximized cement longevity in CO 2 and other corrosive environments The XtremeSet™ system to ensure long-term zonal isolation in wells with bottomhole temperatures as high as 600°F (316°C) and pressures up to 40,000 psi (275.8 MPa)
“We continue to develop new Set for Life cement system formulations to respond to more challenging wellbore-stress scenarios,” adds Rob Martin, Cementing product line manager for Baker Hughes. The latest addition to the family is the EnsurSet ™ self-sealing cement system, which seals tiny cracks in the cement sheath that occur as the casing string expands or contracts due to a sudden change in wellbore temperature or pressure. “The EnsurSet system responds to these stresses by sealing cracks up to 0.15 mm [0.006 in.] in size multiple times and wherever they may occur in the cement,” Martin says. “This solution was developed to address the current industry concerns around maintaining sustained casing pressure and preventing microannulus gas migration.” Baker Hughes has designed specialized cementing equipment, including the Falcon ™ land-based units and the Seahawk ™ offshore cementing units to ﬂawlessly execute cementing operations reliably, safely, and cost effectively. This equipment includes fully automated slurry density control, a robust process that allows high-rate, heavyweight, and ultralightweight mixing while providing ergonomic safety and comfort features for the cement unit operator and critical component redundancy.
A new wireless topdrive cement head was recently developed to improve the safety and reliability of ultradeepwater cementing operations. The tool is capable of remotely launching plugs for offshore deployment using a touchscreen and can rotate the string to improve cement placement.
Ensuring excellence “Because the true beneﬁt of the long-term well integrity solution hinges on reliable tools and in-ﬁeld expertise, Baker Hughes invests a great deal of time and resources to test all cementing technologies prior to deployment and to train personnel in the safe and efﬁcient deployment and operation of all cement slurries, tools, and equipment involved in the job,” Khatri says. “We have dedicated innovation centers strategically located around the world, including Tomball, Texas; Dhahran, Saudi Arabia; and Rio de Janeiro, Brazil,” he says. “These centers serve as collaboration engines, where we work with our clients to jointly develop technologies that address speciﬁc regional needs.”
In the cementing arena, Baker Hughes qualiﬁes cement and spacer systems; ﬂuids using equipment that includes a pressurized tensiometer to measure direct uniaxial tensile strength at downhole well conditions up to 15,000 psi (103.42 MPa) and 400°F (204°C); a device to measure cement expansion and shrinkage under various temperatures and pressures; and a device that measures the wettability and compatibility of cements and spacer ﬂuids in downhole conditions. “Our technology centers have served as vital proving grounds for the development of the EnsurSet self-healing cement, where we conducted controlled cracking tests under temperature, allowed the cement to seal, and then attempted to ﬂow oil, gas, and other ﬂuids through it to evaluate the integrity of the resealed system,” Martin explains. “We have also developed multipurpose additives and new cement retarders in various regional centers.” Qualiﬁed personnel are the ﬁnal critical component of ensuring well integrity for the life of the well. Baker Hughes invests
in a comprehensive training program that fosters competence, a commitment to safe operations, and personal development. Through its structured LEAD (Learn, Excel, Achieve, and Develop) training program, employees gain in-depth well integrity and cementing application expertise with both theoretical and hands-on learning. This includes a Web-based Learning Management System, which provides training course catalogs, online access to Web-based teaching modules, access to external learning content, and assignment and management of individual competence requirements and records. “Just as airline pilots use ﬂight simulators to train and gain conﬁdence in their abilities, our ﬁeld specialists train in a classroom environment on cement unit simulators,” says James Curtis, director of offshore cementing for Baker Hughes. “These simulators familiarize our ﬁeld specialists on the Seahawk and Falcon cementing units under various ‘what-if’ scenarios, so that once they get to the ﬁeld, they can run these systems efﬁciently and safely, and correct any operational issues should they arise.”
As operators move into new areas that demonstrate more technical challenges for long-term well integrity, Baker Hughes aims to continue integrating new technologies and services. “We keep looking for new ways to expand and improve our cementing systems, analysis, and modeling software, and in-house expertise to surpass the industry’s well integrity needs for remote and technically challenging wellbore environments around the world,” Micheli concludes. * The NORSOK standard is developed with broad petroleum industry participation by interested parties in the Norwegian petroleum industry and is owned by the Norwegian petroleum industry, represented by The Norwegian Oil Industry Association and Federation of Norwegian Manufacturing I ndustries.
> Baker Hughes trains ﬁeld specialists on cement unit simulators and tests all cementing technologies before they are deployed to the ﬁeld.
Further wellbore isolation can be achieved with the proper application of gel treatments such as the Baker Hughes ZoneSafe ™ gel, which penetrates porous zones and blocks the ﬂow of ﬂuids or gas into or out of treated areas. “The ZoneSafe gel provides the necessary protection for areas where it is vital to ensure nonﬂowing conditions and to keep well production at optimal levels,” says Freeman Hill, product line manager for Baker Hughes Subsurface Water Management Services. “The treatment is easy to use and to deploy in the ﬁeld, and it has negligible impact on operations.” The gel treatment can be added into a cement squeeze just prior to deployment, and the standard kit is applicable in downhole temperatures ranging from 80°F to 140°F (27°C to 60°C). A higher temperature system also is available. “The ZoneSafe treatment has been successfully deployed in multiple annular channel cement squeeze operations to protect critical exposed areas in the well,” Hill adds. An operator in the Marcellus shale in the Northeast U.S. used the gel treatment on 50 horizontal wells that were shut in due to potential health, safety, and environmental (HSE) hazards caused by channeling behind the well casing. These channels can be very difﬁcult to squeeze off using standard squeeze practices, which usually require multiple attempts before achieving satisfactory results. The operator stood to lose approximately USD 12.6 million in production revenue for each cumulative month that the wells were shut in. A ZoneSafe treatment was completed on each well in less than half a day, followed by shutting in the wells to ensure proper setting and curing of the polymer gel and the cement. Once the wells were brought back on production, follow-up analysis showed that the gel treatment had sealed the behind-the-pipe channels, thus eliminating HSE concerns and getting production back on line fast.
It’s no secret that the biggest players in the oil patch get their pick of vendors and services, but what about the rest? When small energy companies drill multimilliondollar wells, they’re putting a sizeable chunk of the company’s cash on the line. Things have to go right the ﬁrst time. That’s tough in a busy market. Good luck scheduling a completion or frac date when the majors can have the biggest service companies tied up for years. “One of our biggest problems in the Eagle Ford has been getting vendors,” says Greg Presley, senior operations engineer for Cheyenne Petroleum. “If you’re not a major company and don’t have other places where you’re using their services, it is very difﬁcult to get reputable companies to do anything for you. The majors are ﬁrst in line for mud and cement and pipe; all the same goods and services we need.” Cheyenne Petroleum is typical of the hundreds of small oil and gas companies in the U.S. Based in Oklahoma City, Cheyenne holds some 17,000 acres in South Texas, where it produces more than 5,000 barrels a day from the Eagle 28
Ford shale and the Pearsall formation. For companies like Cheyenne, it’s a challenge just to execute their development plan when they have to piece together every aspect of each new well. That’s where Baker Hughes comes in.
Improved project management Vincent Palomarez is the business development manager for U.S. Land. His group coordinates activities between the various Baker Hughes product lines for customers in the lower 48 states. Palomarez is also Cheyenne’s single-point of contact with Baker Hughes. The new arrangement is a step-change from the way things have worked in the past. “Baker Hughes and other large service companies are organized around product lines,” Palomarez explains. “Pressure pumping, for example, is separate from the drilling group, which is separate from completions or reservoir services.” That corporate structure works well enough for large customers who are often organized along the same lines, but for Cheyenne and other independents, it means coordinating
with dozens of different service groups and vendors for everything they need to construct a well and get it on production. Large energy companies typically have the staff and experience to do it, but smaller companies don’t. “What we’re offering is a uniﬁed front across all of our project lines,” Palomarez says. “For smaller companies, it greatly simpliﬁes the process to have one person to contact for anything they need.” Baker Hughes calls this approach “total well solutions”—a well that is built almost entirely using equipment and services it provides. It’s not just efﬁcient in terms of teamwork, there are cost savings as well. If the pressure pumping crew takes longer than expected, for example, the wireline crew doesn’t charge for standby time, and vice versa.
A bigger toolbox “At Cheyenne, we’ve been working with Vincent Palomarez and Justin Pitts for about two years,” Presley says. “Using Baker Hughes for the majority of services has really opened up our toolbox. Now that we have access to better technology
“Without this arrangement, we’d need a lot more people. The good thing is that we’re able to stay relatively small in the ofﬁce and still get a lot done.” Greg Presley
senior operations engineer, Cheyenne Petroleum
and more reliable service, it makes our drilling and completions go a lot faster.” The client still plans each new well, but Baker Hughes handles the service coordination details. Presley and his colleagues at Cheyenne monitor the progress to see if anything needs to be changed. From the client’s viewpoint, one beneﬁt of having the same person to contact for all of the services they need is that if something goes wrong, there’s no one else to blame. “When we were still using separate contractors for everything, and there was a problem, each of them blamed someone else,” Presley says. Now, it’s not just the drilling company or the mud company or the casing company. It’s all Baker Hughes. If something does go wrong, I just call Vince and he says, ‘Okay, we’ll ﬁx it.’” Presley notes that the close alignment with Baker Hughes allows Cheyenne to drill wells that are as consistently good as anything the majors do, yet still remain compact and efﬁcient. “Without this arrangement, we’d need a lot more people,” Presley says. “The good
thing is that we’re able to stay relatively small in the ofﬁce and still get a lot done. We’ve gotten pretty consistent, especially on the drilling side. We are growing as a company and getting more efﬁcient all the time. We’re saving money and producing good wells. Baker Hughes is helping to coordinate things, instead of us having to make 50 phone calls a day to make sure everything is lined up.”
Reservoir solutions The Eagle Ford and other tight oil and gas plays tend to be vast areas of dense, and what many believe to be relatively homogeneous rock. But, drilling experience is proving that unconventional reservoirs are geologically complex. Some of the smaller producers who lack the manpower, expertise, and cash for extensive reservoir modeling settle on one well plan and repeat it over and over, but that seldom produces the best results. In Cheyenne’s case, there was an option. Sergio Centurion is part of the Baker Hughes reservoir solutions team that was called in to help Cheyenne develop an affordable 3D model of its ﬁeld.
“We looked at all the information they had to see what we could do,” Centurion says. “First we did some data mining, using well logs from Cheyenne’s existing wells, as well as production data and other published information about the neighborhood. Gradually, we pieced together a complete picture.” Centurion and his team were able to use the Baker Hughes JewelSuite™ reservoir modeling software to begin building a reliable 3D model of the reservoir. “Next, we created a hydraulic fracturing model using our proprietary fracturing simulator,” Centurion adds. “We experimented with different fracing scenarios to see which methods produced the best results.”
‘Firsts’ in the Eagle Ford Some might worry that as a smaller company, Cheyenne would have less access to the latest tools offered to the majors. “Not so,” says Presley, whose company was among the ﬁrst to try several advanced completion and drilling technologies, including the Baker Hughes AutoTrak ™ Curve high-buildup rate rotary steerable system, www.bakerhughes.com
which shaved an average of ﬁve days off the time it took to drill each new well with conventional motors. In many cases Cheyenne realized a reduction of eight to 10 days in drilling time. The transition has helped Cheyenne reduce its overall drilling costs by USD 200,000 to 300,000 per well on average while achieving better borehole quality and little to no issues running production casing strings. Another technology drawing a lot of industry attention is a bifuel system that uses a blend of natural gas and diesel fuel to power the high-pressure pumps used for hydraulic fracturing. Cheyenne was among the ﬁrst to try the Baker Hughes Rhino ™ bifuel hydraulic fracturing pumps. “Our initial runs were very promising,” Palomarez says. “Using LNG [liqueﬁed natural gas] that we trucked to the site, we were able to substitute up to 65% of the diesel fuel with natural gas. Now, we’re trying to determine if Cheyenne has enough dry gas from its own wells to use as fuel for future frac jobs. If not, we will continue using LNG.” These examples reﬂect a dynamic that provides a great beneﬁt to both Baker Hughes and its customers by introducing technology sooner and by providing a value
proposition that impacts multiple service lines when they are deployed in unison. “The ideal scenario with all Baker Hughes customers is to promote the value of our complete suite of services to their projects,” Palomarez says. “If we can demonstrate an ability to introduce new technology to customers like Cheyenne Petroleum, and be able to quantify a positive effect on their AFE or production, the industry will take notice and be more open to the concept of integrating services for total well solutions.”
The personal touch “What we are trying to offer to our smaller customers is a different type of project management,” Palomarez says. “The most critical point I’ve learned is that success depends on the people involved. It is important that critical people stay connected to the customer.” By the end of the year, Palomarez hopes to have at least six new people in the role of integrated services ﬁeld coordinators—new positions that will be ﬁlled primarily from within Baker Hughes. Not just anyone can ﬁll the role. “We’re looking for people experienced in drilling, fracturing, and completions,” he says. “We will train them, based on their experience, to be familiar with all of our product lines in the region. They will also need to spend enough time together to understand the customer’s needs and personality. The ﬁt has to be right, and that is very hard to do.” Presley agrees. “Having Vince represent all the Baker Hughes product lines has smoothed things out for us. I don’t think it would have been possible for Baker Hughes to keep this relationship if Vince and Justin weren’t in the game.”
Gaffney, Cline & Associates’ global expertise is providing the technical, commercial, and strategic advice to enable Baker Hughes to bridge the gap between delivering products and services and delivering total solutions to maximize the value of a customer’s asset.
ADVANCING RESERVOIR PERFORMANCE with the
In 2008, Baker Hughes launched a strategy to expand its reach beyond the wellbore and into reservoir and asset management. The company built its Reservoir Development Services (RDS) business unit on the acquisition of four separate companies: EPIC Consulting (a Canada-based reservoir engineering company with CO 2 and heavy oil expertise), Helix RDS (a provider of reservoir engineering, geophysical, production technology, and associated specialized consulting services), geomechanical software and training consultants GeoMechanics International, and international advisory ﬁrm Gaffney, Cline & Associates.
“The acquisition of these companies enabled Baker Hughes to provide more customer-focused solutions and a resource pool for ﬁeld development projects, as well as to support Integrated Operations projects and to provide a career path for geoscientists and petroleum engineers within Baker Hughes,” says Chris Ward, vice president, Subsurface Integrity and Evaluation Services.
As a standalone product line unlike any other in the Baker Hughes portfolio, Gaffney, Cline & Associates, which today also consists of the former Helix RDS and EPIC Consulting companies, provides human capital with consulting abilities and training that enables it to see things from a larger perspective, complementing the traditional product lines that offer unique products and services. “Clients basically want solutions to help them maximize the value of their assets, and that requires an understanding of the subsurface, the reservoir, and the entire economics of asset delivery,” says Scott Reeves, president, RDS. Over the past ﬁve decades, Gaffney, Cline & Associates’ employees have supported governments, ministries, national oil companies, and international oil companies at the very highest levels to address changing and complex needs in geophysical, geological, petrophysical, and commercial information to make investment decisions that will improve clients’ return on their investments. “Gaffney, Cline & Associates’ relationship with Baker Hughes means we can offer, when appropriate, a complete service package ranging from ﬁeld development planning, execution, and operational management with the full breadth of Baker Hughes products and services to span the entire asset life cycle,” Reeves adds.
A 50-year legacy In 1962, American Ben Cline and Englishman Peter Gaffney founded Gaffney, Cline & Associates to provide expert, impartial, and in-depth advice to oil and gas companies wishing to develop and improve the performance of their hydrocarbon assets. While working on a joint venture project in Venezuela’s Las Mercedes ﬁeld, Cline and Gaffney had an idea on how to optimize the project’s production operations. Their proposal (which was declined by the operator) broke with the then-traditional structure that separated the geoscience, engineering, and commercial functions within oil companies, creating instead a consultancy that integrated all of those disciplines for better focus on the best solution for the issues in question. Not deterred by rejection of their new approach, the pair established a consulting company called Technical Services Limited S.A. (TSL) in Caracas, Venezuela. The partners opened their ﬁrst ofﬁce in Fyzabad, Trinidad, and soon changed the name of the company to Gaffney, Cline & Associates when they discovered another company in Fyzabad named TSL (Trinidad Steam Laundry). Today, Gaffney, Cline & Associates maintains ofﬁces and operations in all of the world’s major petroleum centers and employs teams
of geoscientists; petroleum economists; reservoir, production, and petroleum engineers; operations specialists; midstream and downstream specialists; and principle advisors on exploration strategy, ﬁscal infrastructure, and licensing. Its client base ranges from the smallest start-up to the largest major, and includes governments, ministries, national oil companies, banks, and transnational ﬁnancial institutions. One of the notable functions of Gaffney, Cline & Associates is to provide thirdparty veriﬁcation and/or valuation of oil and natural gas reserves for company annual reports and for U.S. Securities and Exchange Commission ﬁlings.
Integrating capabilities “Gaffney, Cline & Associates’ expertise is the subsurface—providing the technical work and doing the economics that leads up to the products and services that Baker Hughes delivers,” says Edwin Jong, manager, Gaffney, Cline & Associates, Aberdeen. “We translate to Baker Hughes what our clients’ issues are and say, ‘Okay, they have these speciﬁc ﬁeld or reservoir optimization or production issues, so here’s the perfect opportunity for Baker Hughes to now deliver the great products and services it’s known for. And all that advances a customer’s reservoir performance.” When Sasol Petroleum, a South African oil and gas company, and Talisman, an independent Canadian operator, hoped to develop a play within a 51,000-acre reserve in western Canada’s Montney shale, it also wanted to investigate the economic viability of a gas-to-liquids fuels plant.
Baker Hughes used a multidisciplinary team that included Gaffney, Cline & Associates and the Subsurface Integrity and Evaluation product line, along with experts from the Baker Hughes Geosciences and Pressure Pumping groups, to assess the technical and economic merits of the investment opportunity. The integrated Baker Hughes team supplied experts covering disciplines in geophysics, geology, petrophysics, reservoir engineering, drilling, completions, facilities, and related costs, as well as knowledge of the gas-to-liquids industry. “Assessment efforts included evaluating the shale gas potential at the subsurface, the surface, and infrastructure levels, providing a comprehensive technical evaluation,” says D. Nathan Meehan, senior executive advisor, reservoir and geosciences. “The team efﬁciently addressed complex technical
and logistical issues in-depth, using its established ‘shale engineering’ approach. Additionally, RDS supplied geomechanical and reservoir simulation models that are better suited to predict long-term shale production performance compared to the usual ‘type curve’ approaches. From the RDS integrated assessment, Sasol was able to properly assess the reserve and enter a partnership with Talisman for a commercially viable play.” Working together in the Gulf of Mexico, Gaffney, Cline & Associates and the Subsurface Integrity and Evaluation product line carried out a regional reservoir study of the deepwater Wilcox formation to identify the range and trends of the formation’s petrophysical and geomechanical properties, particularly its Paleocene challenges. The study provided insights into the reservoir
characteristics impacting commercial development of the world-class hydrocarbon play that can be addressed with present-day technology and identiﬁed technology gaps. “These initial studies gave the Baker Hughes Gulf of Mexico team a better understanding of the subsalt reservoir and earned trust from a major Gulf of Mexico deepwater operator, which asked Baker Hughes to prepare a front-end engineering design proposal to help solve the challenges of the Lower Wilcox completion design,” states Lisa Li, principle advisor for Baker Hughes reservoir management, Gulf of Mexico. “Through collaboration with the operator, Baker Hughes will design and provide new completion technology focused on system reliability that will maximize reserve recovery, improve reservoir management, and extend well life 20-plus years.”
The Art of Making
FIELDS SMART More and more operators are introducing the smart ﬁeld valueadded concept to their business plan, which means much more than just automating a ﬁeld or completing the wells with “intelligent” devices. It involves people, technologies, and processes that deal with a much broader scope of work across all of the activities embedded in managing an oil and gas asset.
In today’s world of high oil prices, visionary companies— including major resource holders such as national oil companies (NOCs)—are developing and executing intelligent ﬁeld strategies to ensure that they can maximize their assets’ value in the long-term when oil prices may not be as robust as they are now. Intelligent ﬁeld strategies can add value at any oil price. During periods of low prices, process optimization enabled by intelligent solutions is critical to enterprise/asset value maximization. “We have observed that the dynamics of the oil and gas industry are shifting signiﬁcantly from what they were a decade ago,” says Leonel Pirela, intelligent ﬁelds global director, Gaffney, Cline & Associates. “For example, by developing and adopting intelligent technologie s and solutions under a lean-six sigma methodology through designing and implementing organizational change programs, companies can become more efﬁcient and effective at maximizing value from their resource base. “These visionaries are looking for companies like Baker Hughes that have the capabilities and the ﬂexibility to offer vendor-neutral integrated and scalable asset solutions to ensure there is minimum waste when integrating intelligent ﬁeld solutions into their existing infrastructure at all levels—wells, plants, information technology/ information management/telecommunications, enterprise processes, analytical software applications, and so on.”
Making the right decisions The terms “digital ﬁeld,” “smart ﬁeld,” and “intelligent ﬁeld” all encompass a process that should be applied to everything along the asset’s life cycle: from reservoir management to production optimization to the actual daily operations that ensure the safety and integrity of assets, people, and the environment.
“The West Kuwait integrated digital oilﬁeld conceptual study project was developed through close collaboration between the KOC team and a Baker Hughesled consortium of companies. ...This is the initial step of a journey that will bring KOC to a world leadership position in digital ﬁelds and to a world-class example of excellence.” Bader Al-Matar
team leader, research and technology subsurface, KOC
“By having the right data with the right workﬂows and associated business or technical processes in the right hands at the right time, the right decisions can be made,” explains Pirela. “Each and every decision has follow-on consequences, so the better the quality of any one decision the more effective the myriad of following decisions becomes.” “We have all seen how access to data streamlines our daily lives: Where can we buy the lowest priced items? What’s on at the cinema? What’s the weather going to do? We can change our plans as better data becomes available,” Pirela explains. “And, so it is with oil and gas assets. With every decision-making group within an operating company that is managing an asset—including corporate functions like accounting, procurement, and legal—constantly updating, reevaluating, and running ‘what-if’ scenarios, it can maximize the return on large investments.”
Decision making along an asset life cycle
I m pleme n t r i tal Pr og
C ompar e Ac tual
I n terve n e
M e a
& e e
u u s d a c
o t e d e s
P D d l
p e r
R e s er v o i r a r a c t e r i z a t i o n
“For Baker Hughes,” Pirela says, “it means having all the elements required to offer integrated smart-ﬁeld solutions through intelligence-driven product lines and asset management capabilities that reside in our technology centers, geomarkets, and within the consultancy arm of Gaffney, Cline & Associates and selected best-in-class, thirdparty vendors. “It means being a service company that thinks like an operator to better serve the needs of its client base.”
Realizing the smart-ﬁeld vision A few years ago, Kuwait Oil Company (KOC) introduced a Digital Oil Field culture within its management organization aimed at modernizing the monitoring and management of its upstream oil and gas operations. |
S e t t i n g s
l a n
Being able to speak an operator’s language at the asset level and to understand this decision-making hierarchy and subsequent business processes is crucial in today’s marketplace.
I m p l e m e n t
P t e
e i F
D i a g n o s e
In a strategic initiative to deploy integrated digital ﬁeld (IDF) technology to maximize the value of its hydrocarbon assets, KOC conducted three pilot projects to test different technologies to maximize ultimate reserves recovery by improving the management of its reservoirs and associated enhanced oil recovery programs. “KOC then commissioned a fourth pilot project to marshal the extensive knowledge base derived from the ongoing pilots, together with evolving best practices from the industry at large, to implement a stateof-the-art, large-scale pilot that can form the foundation for ongoing IDF implementation throughout Kuwait,” Pirela explains. KOC invited Baker Hughes to submit a proposal to prepare a front-end concept selection study for implementation of the fourth pilot. Realizing there was an opportunity for Baker Hughes to participate in the area of the digital oil ﬁeld, Gaffney, Cline & Associates [the consulting arm of the Baker Hughes Reservoir Development Services business unit] assembled a
multidisciplinary team of subject matter experts from within Gaffney, Cline & Associates and other Baker Hughes product lines, along with some third-party providers for services that Baker Hughes does not offer—that could better understand what KOC wanted to achieve in one of its giant oil ﬁelds that is being redeveloped under the umbrella of KOC’s IDF vision. KOC accepted the Baker Hughes proposal and the project team, led by Gaffney, Cline & Associates, completed the concept selection study in August 2012. “An asset is not only about the subsurface or the wellhead. It is everything that goes from the reservoir downstream all the way to the ﬂange at which you hand off your products,” Pirela says. “So, from a proﬁtability perspective, we wanted to provide a ﬂexible, integrated solutions plan, meaning that if Baker Hughes could not provide a service, we would source those services—whether they are technology advisory services or technologies—from vendors that can provide ﬁt-for-purpose
> Leonel Pirela, intelligent ﬁelds global director, Gaffney, Cline & Associates
while preparing to kick off Phase 2 of this complex, but high-value IDF project.
solutions, with a preference for open source [nonproprietary] technologies.” To better enhance client service and to build a strong communication network between the two parties, the project team “mirrored” KOC’s technical organization. “This closeness not only spurred a team culture of co-creation and co-ownership, it also enabled us to get a very good feel for KOC’s technical needs,” Pirela says. The concept selection work was well received by KOC. “We had identiﬁed KOC’s major issues and we delivered our recommendations to bridge the gap between the current operating environment and KOC’s vision for an end-to-end integrated solution with IDF technologies to yield the desired production and oil recovery optimization capabilities,” Pirela adds. KOC has now invited Baker Hughes to lead implementation of the IDF-based redevelopment project in the giant 200,000 BOPD Minagish ﬁeld. The two companies are discussing contractual arrangements
Baker Hughes is now making advance preparations to design an integrated surface and subsurface monitoring, control, and optimization solution that includes intelligent wells, waterﬂood management, seismic technologies, integrated asset modeling, production loss management, H2S monitoring and visualization, integrated information technology/information management (IT/IM) architecture, IT/IM security, and collaboration center design. “In addition, the most important asset—the people making it all happen—are being considered through a detailed change management plan,” Pirela adds. “The West Kuwait integrated digital oilﬁeld conceptual study project was developed through close collaboration between the KOC team and a Baker Hughes-led consortium of companies,” says Bader Al-Matar, team leader, research and technology subsurface, for KOC. “This milestone covered the full understanding of the surface, subsurface, IT, connectivity, and change management aspects that are important to develop the next phase of the project. This is the initial step of a journey that will bring KOC to a world leadership position in digital ﬁelds and to a world-class example of excellence.” The Minagish ﬁeld redevelopment involves drilling a signiﬁcant number of
new wells and reentering and retroﬁtting approximately 30 to 40 existing wells with intelligent well completions, including electrical submersible pumping (ESP) systems and inﬂow control devices that can be monitored and controlled remotely. Approximately one-third of the 100 wells in the ﬁeld are naturally ﬂowing oil producers; one-third are ﬁtted with artiﬁcial lift systems in the form of ESPs, and another one-third of the wells are water injectors. “This is truly a ﬁrst-of-its-kind project because it involves so many experts from within the Baker Hughes intelligence-driven product lines, technology centers, and geomarket ofﬁces, as well as consortium parties from all over the world, many with operator and asset director experience who understand what KOC wants to achieve with this digital ﬁeld project,” concludes Pirela, who piloted Shell’s ﬁrst smart ﬁeld in Asia Paciﬁc as the decision-making executive. “It also highlights the value-added factor that Gaffney, Cline & Associates brings through its large and diverse skill pool, and it positions Baker Hughes as a company that can speak the operator’s language at the asset and enterprise level. “This project presents Baker Hughes with an opportunity to set a new reference in the international oil and gas industry for large-scale, brownﬁeld redevelopment supported by IDF technology. Baker Hughes greatly appreciates the opportunity to partner with KOC in this unique and challenging undertaking.” www.bakerhughes.com
The upstream industry has seen monumental growth and proﬁts from the recovery of oil from shale plays, thanks to advances in horizontal drilling and hydraulic fracturing. Now, the downstream industry is looking for the right technologies to minimize reﬁning bottlenecks, maintain reﬁnery reliability, and assure product quality as these new feedstocks move from the wellbore through the reﬁnery and into the market as ﬁnished products.
A decade ago, the oceans of hydrocarbons trapped in the Eagle Ford, Bakken, and Marcellus shales lay virtually undisturbed, and how to produce the oil from those tight shale formations was still a mystery.
faced a decade ago when heavy Canadian crudes grew as a feedstock.
Today, these and many other shale plays have helped boost U.S. production to record highs and, in 2011, contributed to the U.S. producing more oil domestically than it imported for the ﬁrst time in decades.
Deﬁning reﬁning’s issues
The unique combinations of challenges associated with shale oil require reﬁners either to accept lower throughput—and consequently lower margins—or to look for ways to improve its processability so that the oil can be reﬁned without causing operating or product quality problems. This new source of crude oil has breathed new life into both companies and communities, while providing a secure oil supply. Shale oil is a light crude with low viscosity and low sulfur content, making it a desirable feedstock for U.S. reﬁners. Its abundance throughout much of the country makes it a secure source of domestic energy that enables reﬁners to do more accurate long-term planning. And, it’s cost effective for reﬁners to acquire. These winning characteristics have landed shale oil as a feedstock in an increasing number of reﬁneries. But as shale oil continues to gain favor, reﬁners are also beginning to recognize a parallel pattern of operational issues not unlike the processing challenges
In other words, this reversal of fortune is impacting both upstream and downstream economics.
“Because reﬁneries are set up to handle more conventional crudes, the unique combinations of challenges associated with shale oil require reﬁners either to accept lower throughput—and consequently lower margins—or to look for ways to improve its processability so that the oil can be reﬁned without causing operating or product quality problems,” says Scott Bieber, commercial development manager for Baker Hughes Downstream Chemicals. “Baker Hughes is aware of these challenges surrounding processing oil from shale and is responding with a proactive approach to help manage the negative impacts that can occur through the production, transportation, and reﬁning of shale oil.” To ensure delivery of the best possible solutions to the downstream industry, Bieber and others within the Downstream Chemicals group participated in a technology exchange with experts in the Baker Hughes Pressure Pumping and Upstream Chemicals product lines to get a better understanding of the hydraulic fracturing process and the chemicals that are used to stimulate and to optimize production.
“Because of the high levels of parafﬁn in shale oil, as well as the potential for asphaltene incompatibility if these oils are blended with more asphaltenic crudes, fouling risk increases.” Jenny Thomas
product line manager for process chemicals
“We felt it was important to understand what happens at the production stage and if any of the processes could affect what happens to our downstream customers,” Bieber says. “In the end, we didn’t discover any overarching issues in relation to the way wells are stimulated, and we now know that nothing we are doing on the production or completion side of our business is negatively affecting the quality of the oil and the way it behaves at the reﬁnery. The truth of the matter is, it’s mostly the characteristics of the oil itself that creates the challenges.” “The composition of shale oil varies from basin to basin throughout the U.S.,” explains Larry Kremer, technology advisor for Downstream Chemicals research and development. “In fact, an analysis of three samples of Eagle Ford crude delivered to a reﬁner in just one week showed the crude density ranging from 44.6° to 55.0° API. Their appearance ranged from light yellow to dark brown to an opaque-reddish color. The only thing the three samples had in common was a bottom layer of sludge occupying between 10% and 15% of the sample volume.” Other problematic characteristics of shale oil include high parafﬁn content, low asphaltene and low sulfur content, hydrogen sulﬁde content, and tramp amines (a result of chemical treatments to control hydrogen sulﬁde), all of which can potentially
lead to signiﬁcant disruptions across the reﬁning supply chain—from transportation from the oil ﬁeld to processing at the reﬁnery. “The good news is that there are proven solutions for almost every step in the process to optimize the economics of reﬁning shale oil and to keep proﬁts ﬂowing,” Bieber says.
The right reﬁning solutions In much the same way that reﬁners have responded to other crude challenges, there are solutions available to manage shale oil issues. “Baker Hughes has researched and carried out testing of shale oils both in the ﬁeld and at its research and development center in Sugar Land, Texas, in an effort to deﬁne programs to help manage the negative impacts that occur in various segments of the downstream industry,” says Jerry Newberry, product line manager, fuel additives. “Understanding the composition of the crudes to be blended before they arrive at the terminal is a more proﬁtable approach for reﬁners to take to determine the most economical path for making those crudes compatible, including pretreatment options. Various tests offered through Baker Hughes technologies can help reﬁners make more accurate crude blending decisions.” One of the biggest issues facing the downstream industry is fouling, adds Jenny Thomas, product line manager for process chemicals. “Because of the high levels of parafﬁn in shale
Understanding the composition of the crudes to be blended before they arrive at the terminal is a more proﬁtable approach for reﬁners to take to determine the most economical path for making those crudes compatible, including pretreatment options.
oil, as well as the potential for asphaltene incompatibility if these oils are blended with more asphaltenic crudes, fouling risk increases,” Thomas explains. “Both parafﬁns and asphaltenes can contribute to fouling and sludging that reduce capacity in pipelines and crude tanks, generate emulsions in desalter units, and foul process unit preheat exchangers and furnace tubes.” In worse-case scenarios, fouling can lead to unplanned reﬁnery shutdowns, resulting in millions of dollars in lost revenue. “A reﬁner processing Eagle Ford shale oil blended with foreign crude oil found itself in a costly, unplanned shutdown due to a blend that caused severe rapid fouling of the preheat train,” says Nick Black, district manager for Baker Hughes Downstream Chemicals. The reﬁner now uses the Baker Hughes Field ASIT services™ tool, a ﬁeld-deployed testing service for rapid stability testing of asphaltenes on a wide range of crudes and crude blends. “This testing service
allows operators to optimize their crude diet, thus maximizing their proﬁtability and minimizing reliability risks,” Black explains. “The tool is used speciﬁcally to track the asphaltene stability of crude blends and can serve as a ‘gatekeeper’ for acceptable crude blends. This information, used in tandem with information obtained from other crude stability testing, can provide the reﬁner with a very good predictive tool to prevent unplanned events.” By setting minimum asphaltene stability index (ASI) levels with the Field ASIT services tool, the reﬁner can anticipate processing challenges and avoid costly outages. A higher percentage of Eagle Ford crude in the crude blend has also caused an increase in the tramp amine content in the crude distillation units. This, in conjunction with high overhead chloride content, can cause an increase in overhead corrosion rates, and overhead bundle life reduction by 75%. This decrease in bundle life increases the risk of an unplanned shutdown.
The amount of caustic used in the process can be increased to reduce the overhead chloride level and the Baker Hughes EXCALIBUR ™ contaminant removal program can be adjusted to maximize amine removal at the desalter. “These changes can successfully reduce the overhead salt formation temperature, which reduces the risk of corrosion,” Black adds. “The reﬁner can also reduce the amine salt corrosion risk by maintaining a higher minimum overhead exchanger temperature target. With revised operating and treatment strategies, the reﬁner can reduce maintenance costs by extending the bundle life and also minimize the risk of an unplanned shutdown. “Baker Hughes will continue to work collaboratively with our customers to better understand these ever-changing feedstocks with the goal to proactively help reﬁners prevent unplanned events in the future.”
Faces of Innovation
DV satya None of Steve Jobs’ smart technology would have hit the market and changed our lives if it weren’t for little-known chemical engineer Yoshio Nishi. He invented the lithium ion rechargeable battery that powers the Jobs-inspired gadgets full of apps that bring the world to our ﬁngertips. It takes only a quick look outside the pages of a chemistry book to see the impact that chemical engineers have had on the world: plastics, polymers, and petrochemicals; foods, fertilizers, and pharmaceuticals. They make products from raw materials, and they ﬁnd ways to convert one material into another useful form.
DV Satya Gupta is a Baker Hughes chemical engineer whose name appears on more than 130 patents relating mostly to technologies for well stimulation. He’s credited with research in everything from carbon dioxidecompatible, nonaqueous crosslinked fracturing ﬂuids to cat litter. Among the many technological achievements credited to Gupta is a line of scale inhibitor products based on the chemistry found in diatomaceous earth, a naturally occurring substance used in everyday cat litter. Gupta, business development director for the Baker Hughes Production Enhancement product line, explains what led to the discovery: “I was having lunch with a production chemical scale inhibitor scientist some years ago, and he was talking about the need for a product that could be dumped into a rat hole that would release scale inhibitor over a period of time to protect tubulars. I came up with a very simple solution. Essentially, we took cat litter and put scale inhibitor into it, and the litter slowly adsorbed the chemical. My background was fracturing, so I said, ‘Why can’t we put this in a frac ﬂuid and slowly release it?’ The technology took off like crazy, and it has become the Sorb ™ line of products for Baker Hughes. That’s how simple the concept was. It wasn’t brilliant, but it was fun.” And, more importantly, it was the kind of out-of-the-box thinking that solves customer challenges. The Sorb family of solid inhibitors can be compared to time-released, encapsulated medicine. It works preventively to slow or
to eliminate unwanted material deposition before it becomes problematic, then continues to treat the well, tubulars, and production facilities throughout their productive life. Today, the Sorb family of solid inhibitors includes the ScaleSorb ™, ParaSorb™, BioSorb™, SaltSorb™, CorrSorb™, and AsphaltSorb ™ products.
University of Miami in Florida but turned it down in favor of the chemical engineering Ph.D. program at Washington University.
The path to chemical engineering Satya Gupta was born in Chennai, India. Formerly known as Madras, Chennai is situated on the Bay of Bengal and is known as the cultural capitol of south India. His father was an accountant for the Reserve Bank, and his mother was a stay-at-home mom to Gupta and his three sisters. Out of approximately 200,000 students who applied for entrance into the Indian Institutes of Technology (IIT), Gupta was one of about 2,000 chosen for the low-tuition, ﬁve-year engineering program. (The IIT were started as institutions of national importance and there were ﬁve of them at that time. Gupta joined the institute in Madras.) His thesis on artiﬁcial kidney membranes was noticed by a professor at Washington University in St. Louis, Missouri, who was doing chemical research in biomedicalrelated studies on membranes and encapsulations. As Gupta looked at options for advanced studies, he was offered a medical doctor Ph.D. program at the
“I wasn’t interested in medicine,” he says. “I was interested in solving problems.” Gupta accepted an airline ticket to the U.S. in exchange for an assistantship at the university where, for his master’s degree, he worked on an encapsulated product for treating people who had overdosed on barbiturates. For his Ph.D., Gupta worked on an encapsulated, injectable contraceptive for women, which eventually was funded and commercialized by a Norwegian company under the name Depo-Provera. His fascination with time-released chemistry led to a job at Gulf Research and then Pennzoil, where he worked on the GUMOUT™ line of products. “At the time, GUMOUT was mainly used by men,” Gupta says. “Because of the way you had to open the can women didn’t like using it because it was easy to spill and it smelled bad. I made a big Tylenol-type capsule of GUMOUT gas line
antifreeze that could be dropped into the gas tank when you pumped your gas so women would use it. It was called Gas Caps. I wasn’t in marketing obviously.”
From Gas Caps to oil patch
Among the many technological achievements credited to Gupta is a line of scale inhibitor products based on the chemistry found in diatomaceous earth, a naturally occurring substance used in everyday cat litter.
Gupta remembers well the day he discovered the oil patch. It was in 1987, and he was interviewing for a position to establish a research and development department for the Western Company of North America, a service company specializing in acidizing, fracturing, and cementing. “I had gone to Fort Worth [Texas] and was sitting in the HR vice president’s ofﬁce having an interview when this old man in a crumpled up suit walked into the ofﬁce, sat down, and said, ‘Vince, what’s going on?’ The VP told him that he was interviewing me for the lab R&D position,” Gupta recalls. “The old guy says, ‘Son, tell me about yourself.’ So, we talked for a little bit and he stood up and said, ‘Hire him,’ and just walked out. The VP looked at me and said, ‘I guess you’re hired. He’s the CEO, and no one’s going to tell Eddie Chiles you’re not hired.’ “ (Chiles founded the Western Company in 1939. He became somewhat of a cult ﬁgure through his 1970’s TV commercials featuring the mantra, “If you don’t own an oil well, get one!” and his radio commercials that began with the announcer asking: “Are you mad today, Eddie Chiles?” to which Chiles would always answer, “Yes, I’m mad!” before launching into a monologue about how poorly Americans were being represented by a too-liberal Congress.)
When BJ Services bought the Western Company in 1995, Gupta left the company and joined Frac Master, where he set up an R&D department in the company’s Calgary, Alberta, Canada, headquarters. In 1999, BJ Services acquired Frac Master, and three years later Gupta relocated to BJ’s headquarters in Tomball, Texas, as senior research leader for fracturing technology. In April 2010, Baker Hughes acquired BJ Services, and the following year Gupta traded his lab coat for a sport coat when he was appointed to his current role in business development. “I have a business development title, but I’m still in technology, so I do a different type of business development than the conventional sales person would do, which means I do more technology transfer and deal with our customers’ engineering and technical issues,” he explains. “I still dabble in technology solutions.” Looking around at the mounds of “research” stacked about his ofﬁce, Gupta admits he could never completely give up ﬁnding solutions to apply in the ﬁeld. “Sometimes I forget I’m not in R&D anymore, so when I have ideas I still have papers and things that I want to work on. Sometimes I give it to somebody else to do something with, but it’s what I do, and what I ﬁnd fun.”
A portfolio of solutions To say Gupta is an expert in well stimulation would be an understatement. In January, Baker Hughes recognized him with the company’s Lifetime Achievement Award. A sampling of technologies that Gupta has developed or helped develop includes: encapsulated breakers, polymerspeciﬁc enzyme breakers, premium
The next bright idea
performance aqueous ﬂuid systems, nonaqueous ﬂuid systems, ultralightweight proppants, and the Sorb line of longterm production assurance products.
Whether it’s ﬁnding a way to fracture wells in the middle of the Arabian Desert with CO2 where there is no water to be found, fracturing with natural gas, or producing natural gas from gas hydrates, Gupta believes the next big technology breakthrough is just around the corner. Or in the case of encapsulated inhibitors—over lunch.
Much of the development work on encapsulated breakers took place in the early 1990s, but the entire line of products is still on the market today and is essential for hydraulic fracturing. When a well is fractured hydraulically, the water or other ﬂuid being used may be viscosiﬁed, or thickened, with polymers (gelling agents). This viscosiﬁed ﬂuid suspends the sand or ceramic grains used to prop open the created fractures. After the pumping process ends, the polymer tends to remain in the fractures, along with the proppant. “We want the proppant to stay in but everything else we want to bring back out,” Gupta explains. “The polymer keeps the oil or gas from ﬂowing through the fractures, so we want to ‘break’ the viscosity of this fracturing ﬂuid in order to recover it. The chemical we add to the ﬂuid is called a ‘breaker.’ And, because we don’t want it to work until we’re ﬁnished fracturing, it’s time released. That’s the concept behind encapsulated breakers.” “Since the initial product launch in 2005, Baker Hughes has treated more than 15,000 wells with Sorb long-term production assurance technologies, and new business continues to be generated through collaboration with our Production Chemicals group,” says Harold Brannon, vice president, technology, Pressure Pumping. “In 2012, Sorb product usage was up 80% from 2011, resulting in 3,000 wells being treated with 8.26 million pounds of Sorb products.
“The core invention, or technology, of controlled time-release additives is actively being used as a platform for product development in other service lines, including cementing and multizone production monitoring products,” Brannon adds. “A new proppant material made from nano alumina called SorbUltra is slated to be introduced later this year and will extend the product line into the deepwater market.” Most recently, Gupta’s research has helped lead to the development of a replacement for guar (the most popular gelling agent for preparing aqueous-based fracturing ﬂuids) and to a method for making fracturing ﬂuids from produced water.
“I gave a talk recently and I said, ‘Make it a point to have lunch with somebody in a different group at least once a week. Some of the things I’ve developed are because I did that. I’ve learned a lot from talking to people from other disciplines, ﬁnding out what they know and what their challenges are. “Sometimes, what others think of as a big challenge is a simple thing to solve. And what you might think is a big challenge is really somebody else’s simple solution.” GUMOUT ® is a registered trademark of Illinois Tool Works Inc.
Some of the fracturing solutions Gupta has worked on, however, didn’t involve water at all. “When a lot of people think of fracturing, they think there has to be a hydraulic medium, typically water or gelled water,” he says. “One of the unique things I have worked on is nonwater-based fracturing, where we do frac jobs with alcohol or seawater or liquid CO 2. Some of these are unique in the sense that nobody else does it. If everybody can do it, my interest wanes.”
Collaboration Delivers Deepwater Completions Multizone, single-trip frac pack reduces completion time, costs in frontier ultradeepwater ﬁeld The Petrobras subsea developments at the Cascade and Chinook ﬁelds in the Gulf of Mexico have been a proving ground for new technologies and services, having delivered several deepwater ﬁrsts. The ﬁelds, located in the Walker Ridge area 180 miles (290 km) off the Louisiana coast, are tied to the Gulf of Mexico’s ﬁrst ﬂoating production, storage, and ofﬂoading (FPSO) vessel. And at a water depth of 8,250 ft (2515 m), they represent the outer limits of deepwater development to date. Baker Hughes has been closely involved with the development of the Cascade and Chinook ﬁelds since their early development days and continues to provide a wide range of services, including directional drilling, logging-while-drilling, drilling and completion ﬂuids, wireline
logging, wellbore cleanup and completion ﬁshing services, sand control equipment, and upper completion systems including surface controlled subsurface safety valves. “The deepwater wells at Cascade and Chinook require completions that incorporate frac packs, which involve the simultaneous hydraulic fracturing of the reservoir with the placement of a gravel pack,” says Kevin Joseph, a Baker Hughes completions engineer working with Petrobras on the Cascade project. “For the highly consolidated, low-permeability reservoirs at Cascade, frac packs provide a two-fold beneﬁt.” The “frac” component of a frac pack allows for hydraulic fracturing to stimulate the formation and boost production rates. The “pack” component provides well integrity beneﬁts, such as preventing the production of formation sand. A properly deployed frac pack provides high-conductivity channels that penetrate into the formation, while leaving undamaged packing gravel near the wellbore and in the perforations. However, the conventional method of deploying frac packs, in which each zone or pack is deployed in an individual trip, adds signiﬁcantly to logistical costs, rig time, and the number of trips down hole. Minimizing these trips to reduce costs was a major driver for Petrobras to select a multizone, single-trip frac-pack deployment system, which would allow the operator to treat multiple zones during a single trip down hole.
“We considered the use of multizone, singletrip systems early on as a way to reduce completion time and risk without sacriﬁcing the beneﬁts of a standard frac pack, including the creation of a conductive fracture network to stimulate the reservoir and provide robust sand control at the same time,” says Scott Ogier, a completion engineer for Petrobras. “The safety and operational reliability of these systems were also major factors in our decision, along with the opportunity to work with a service provider such as Baker Hughes, to keep advancing the technology for new deepwater challenges.” These systems are not necessarily new to the industry. The Baker Hughes Multi-zone Single-trip (MST) completion system had a proven track record in wells in India and Indonesia where it helped reduce the costs of sand control operations by 40% to 60%. In addition, the MST’s large internal ﬂow area minimized inside diameter restrictions in the production casing, allowing for improved production rates. However, using the technology in the Gulf of Mexico at these water and reservoir depths posed unique challenges and required careful planning, with close involvement and input from Petrobras.
Cascade and Chinook Fields in the Gulf of Mexico Austin
UNI TED S TATES
f t 0 0 5, 0
Gulf of Mexico
l f S h e
0 f t , 0 7 5
f t 0 0 0 , 1
t e r a p w e e Lower D ME XI CO
Collaboration begins early “Baker Hughes’ MST capabilities, which were enhanced by our acquisition of BJ Services, had to be upgraded to meet the speciﬁc challenges of deep and ultradeepwater wells,” says Colin Andrew, product line manager for multizone systems for Baker Hughes. “For example, we had to make improvements to maximize production rates, and to boost the pressure and temperature ratings for the Cascade reservoirs. We also had to ensure that each zone could be tested after setting an isolation packer to give Petrobras conﬁdence that zonal isolation was achieved.”
> Since its introduction in 2007, the MST system has been successfully deployed in 40 wells in the Eastern Hemisphere, treating more than 180 zones.
Baker Hughes and Petrobras worked closely on these projects, beginning with comprehensive prejob planning that captured all relevant operational parameters that the upgraded MST was expected to encounter during deployment. Simulation modeling was performed using Baker Hughes’ proprietary InQuest PayZonePro ™ software, which simulated downhole tool movement and was instrumental in providing a dependable gauge of weight on the tool during all phases of the sand control operation. PayZonePro accounts for the ever-changing conditions that occur during a frac pack such as workstring shrinkage, expansion, and ballooning due to temperatures and pressures; ﬂuid and slurry friction; downhole hydraulic pressures; and piston effects. This helps ensure that the tools remain in speciﬁc locations, that the ratings of the tools are not exceeded and, ultimately, a successful frac pack. The companies collaborated on internal and external peer reviews, and well review workshops. In these workshops, all critical parties, from upper management to tool assemblers, reviewed every aspect of the ﬁeld execution plans, providing the greatest opportunities for success.
“The deployment of the MST system met our objectives in delivering a robust completion, while greatly reducing the completion time over a conventional stacked, frac-pack system.” Scott Ogier
Petrobras completion engineer
The team also jointly developed a list of potential ﬁeld scenarios that might hinder the MST’s deployment and operation, and formulated decision trees and contingency plans to address these scenarios and guarantee a successful installation. “Thanks to this early collaborative effort with Petrobras, we gained an in-depth understanding of the expected operational challenges, which led to further upgrades by Baker Hughes to the MST,” Joseph says. This included upgrading the pressure rating of critical components of the MST from 10,000 to 12,500 psi [69 to 86 MPa]. “We also conducted a major testing campaign on our frac ports, with Petrobras involvement,” Andrew says. This included erosional testing to conﬁrm that the frac ports could withstand the high proppant pumping rates required on the Cascade well.
Field deployment Petrobras approved a ﬁeld trial of the newly redesigned MST system to complete its Cascade 5 well, located in 8,149 ft (2484 m) of water. The MST was to be used to conduct frac-pack completions through 10 1/8-in. casing in this high-pressure, Lower Tertiary formation. Ensuring successful deployment began with having the right personnel involved at the right time. To that end, Baker Hughes and Petrobras jointly deployed a ﬁeld operations team consisting of highly qualiﬁed professionals from both companies—personnel that both understood the speciﬁcs of their role and could work together to achieve the overall goals of the project.
“This relationship allowed us to quickly eliminate any bottlenecks that were identiﬁed during the process,” Joseph says. “The lines of communication were kept open within manufacturing and across product lines, divisions, and disciplines to support a ﬂawless offshore execution.” To keep Petrobras up to date on any logistics or delivery issues, Baker Hughes project managers and other designated personnel were charged with communicating to the right people in the Petrobras organization. The offshore team consisted of four tool specialists, split into two crews on 12-hour shifts and staggered to the rig crew’s shift changes, to manage effective handovers. Two Baker Hughes engineers working under a similar staggered shift system supported these specialists. The specialists and engineers maintained a close working relationship with Petrobras operations to accurately track and document all tool ratings, and to ensure that they complied with regulations set forth by the U.S. Bureau of Safety and Environmental Enforcement. During the frac pack, Baker Hughes had dedicated representatives in Petrobras’ remote operations control room, with an open communications line to both the frac boat and the rig, to support the operation and any decision making during the sand control operation. Finally, an operations coordinator at the Baker Hughes operations base in Lafayette, Louisiana, stood ready to dispatch back-up www.bakerhughes.com
equipment in the event that one or more MST components were damaged during surface make-up. Having this coordinator tied into Baker Hughes’ logistics and supply chain to guarantee efﬁcient replacement of critical components could save days, and several hundreds of thousands of dollars in rig cost.
Realizing results The collaborative working relationship between Petrobras and Baker Hughes allowed the MST to successfully fracture multiple zones in the Cascade 5 well in a single trip. The well had a bottomhole pressure exceeding 19,000 psi (131 MPa) and was successfully stimulated at a pumping rate of 32 barrels per minute, with an average of 260,000 lbm of proppant per zone. The MST was deployed and set at each zone without incident, with the production sleeves opening and closing as planned and the isolation assembly successfully installed. The isolation packers and production packers were set and tested to conﬁrm complete well integrity prior to performing the frac pack. After stimulating all zones, the system was pulled to surface and inspected. Even after pumping more than 500,000 lbm of proppant through the tool at high injection rates, the crossover section of the MST demonstrated minimal wear. Petrobras did not incur any lost-time incidents or nonproductive time related to the deployment and operation of the MST, and achieved additional deepwater ﬁrsts in the process. The well’s total depth was 26,586 ft (8103 m), making it one of the deepest frac packed wells on record and the deepest application of the MST system. “This was the ﬁrst MST installation for the Baker Hughes Gulf of Mexico team, and Petrobras’ willingness to work so closely with us was critical to our success,” says Matt Falgout, operations coordinator for Baker Hughes sand control systems. “They treated us as part of a team from the outset, participating in some of the training exercises with our personnel and sharing their lessons learned from the completion of the initial Cascade and Chinook wells. Anytime we encountered a roadblock, we worked together to ﬁnd a solution, and ultimately, delivered a ﬂawless completion for the well.” In terms of operational savings, Petrobras achieved approximately USD 5 million in rig rate reductions alone. “The deployment of the MST system met our objectives in delivering a robust completion, while greatly reducing the completion time over a conventional stacked, frac-pack system,” Ogier concludes. “We currently plan to use the MST for the remainder of the Cascade/ Chinook project, and lessons learned from the ﬁrst deployment will aid us in future completions. “This close working relationship, both in the ofﬁce and in the ﬁeld, ensured smooth deployment of the MST system in Cascade 5. It was truly a joint project that shared a common goal, which we will strive to repeat in future wells.”
Lower Tertiary team dedicated to delivering game-changing completion systems for
ultradeepwater Gulf of Mexico Baker Hughes is adopting a crossfunctional team approach that prioritizes projects to address major industry challenges and meet customers’ speciﬁc needs—projects like designing completion systems for the frontier ultradeepwater Gulf of Mexico. Integrated product teams (IPTs) are commonly used in many engineeringcentric industries. Baker Hughes will use the structure to develop innovative industry solutions. The cross-functional teams will take a systems approach to problem solving and are comprised of employees from diverse disciplines like operations, customer service, engineering, reliability, and supply chain. Integrating supply chain and operating processes will optimize the ordering, manufacture, assembly, test, and deployment of these systems solutions.
Tertiary trend (also referred to as the Paleogene or Lower Wilcox) stratigraphy in the Gulf of Mexico. This study was completed using publically available data, updated in 2012, and also addressed such subjects as subsalt drilling, formation evaluation and, during the operations phase, sanding, compaction, and ﬂow or production assurance. This study provided insight into the problems to be addressed while drilling, completing, and producing Lower Tertiary wells through the entire asset life cycle. In collaboration with Gulf of Mexico customers, the IPT will design and build an integrated completions system for the Gulf of Mexico’s frontier Lower Tertiary, where water depths reach 10,000 ft (3048 m) with a potential total well depth of 30,000 ft (9144 m).
“This is a change in the way we traditionally approach problem solving and innovation,” says Mike Sanders, vice president of Enterprise Engineering for Baker Hughes. “While the composition and size of a team will vary depending on the project, they are all created with the express purpose of delivering a product or service to customers faster.”
Baker Hughes estimates that 150 or more wells will be drilled and completed in the Gulf of Mexico through 2020. The frontier ultradeepwater environment has pressures up to 27,000 psi (186 MPa) and reservoir temperatures up to 325°F (163°C). Wells in this area will be designed for a life expectancy of 20 to 30 years, so it’s critical the completion and production systems are reliable.
In 2009, Baker Hughes Reservoir Development Services completed a study that characterized the Lower
“The industry doesn’t currently have completion and production systems that can handle the temperatures
and pressures that the earth exerts at this depth,” says Bob Bennett, vice president, Lower Tertiary IPT. “Baker Hughes has the opportunity to establish itself as a leader in this emerging market. To capitalize on this opportunity, we’re assembling a team of approximately 100 people to deliver a system to meet the highly specialized requirements of the Lower Tertiary.” Bennett adds, “Our goal is to deliver a state-of the-art integrated tubing hanger-to-toe injection well and production well completion systems for the frontier Lower Tertiary.” This process will include lower completion systems, intelligent production systems, sandface surveillance and control, upper completion systems, in-well and seaﬂoor electrical submersible pumping systems, and subsea marinization. A phased technology development plan spanning 2013 through 2017 has been adopted to provide the solutions required to meet and exceed the needs of frontier ultradeepwater operators in the Gulf of Mexico. To date, about 60% of the team members are in place working at the Baker Hughes Center for Technology Innovation in Houston, which has testing capabilities up to 40,000 psi (275 MPa) and 700°F (371°C).
ne visit to the Baker Hughes User Lab and the notion that oil and gas companies are stodgy places where creativity can’t be found goes right out the window.
“User experience involves a person’s emotions about using a particular product or system and includes a person’s perceptions of the practical aspects such as utility, ease of use, and efﬁciency of the system.” Joel Tarver manager, user interface/ user experience group
As a guest lecturer to students studying human–computer interaction at Houston’s Rice University, Joel Tarver was attempting to explain what Baker Hughes does and to give the students a preview of the capabilities of the company’s new usability lab. “My class really wants to know what an oil and gas service company is doing with a high-tech usability lab that measures user experience,” interrupted Professor Michael Byrne. Tarver turned to the Internet for support, doing a quick search result for “Microsoft CEO Steve Ballmer and Baker Hughes.” “I showed the class a copy of a speech that Ballmer delivered in Houston at IHS’s CERAWeek™ 2011 where he mentioned a partnership between Baker Hughes and Microsoft that involves the software company’s cloud infrastructure it calls ‘Windows Azure™.’ The technology is enabling Baker Hughes scientists and engineers to run more accurate simulations and to deliver better results at a much, much faster pace. “All of a sudden, the students saw Baker Hughes as more than muscle and steel.”
Making the complex simple
> A background in the gaming industry prepared user experience specialists Steven Pierce (left) and Daniel Casslasy to deliver quality, innovation, and a unique culture among developers.
Tarver manages the Baker Hughes user interface/user experience (UI/UX) group that performs user experience testing, or “usefulness” testing, on software that is integral to many of the tools that Baker Hughes designs and manufactures. “User experience involves a person’s emotions about using a particular product or system and includes a person’s perceptions of the practical
aspects such as utility, ease of use, and efﬁciency of the system,” he says. In other words, it measures subjective satisfaction. “Through every aspect of software development and workﬂow design, the user experience must be considered, measured, and reﬁned,” explains Daniel Casslasy, one of the team leads for drilling and evaluation software. “Drilling and evaluation software is complex. It supports directional drilling, measurement-while-drilling (MWD), and logging-while-drilling (LWD) tools so, if we can design and build software in such a way that the complexity is shielded from the user, it takes much less time to learn how to use the software and for the user to be fully productive with it. “In short, our goal is to make our software a joy to use.” Some of that is accomplished by data visualization—being able to communicate information clearly and effectively through graphical means. Some of it comes from pure simpliﬁcation. For instance, anyone who has purchased a smart phone or a touch-screen tablet knows they no longer come with a binder full of operating instructions. The learning curve for operating a smart phone is so ﬂat that most children know how to scroll through photo albums and listen to their favorite Justin Bieber songs by the time they’re 2 years old. The bottom line is this: Today’s users want a pleasant and uncomplicated experience whether they are making a phone call or logging a well.
> Joel Tarver demonstrates the eye-tracking equipment used by development teams to monitor a user’s experience, including body language.
Functionality vs. usability While engineers typically are concerned with functionality, the visual communication and interaction experts on the user interface team focus on not only how a system looks but how it works. They rigorously test Baker Hughes software as it’s being developed: not just for reliability, but for performance, usability, and consistency—all of which help drive efﬁciency for customers, no matter their level of experience or comfort when using any of the tools. “Without science and software, the tools needed to get hydrocarbons out of the ground would be just a pile of metal,” Casslasy says. “The tools we develop at Baker Hughes are all well and good, but without software to control them and to interpret the readings that the tools take, we may as well be lowering chains of paperclips down the borehole. “As a company, one of our primary objectives is to help our customers get to the pay zone as quickly as possible. Slow or difﬁcult-to-use software impedes their ability to do so.”
Knowing what customers want in the software they’ll be using on their wellsites is paramount to the UI/UX group and its research in the usability lab. The lab, located in the Baker Hughes Houston Technology Center, opened in January 2012. The Silicon Valley-inspired complex has an observation room with one-way glass, surveillance cameras, and eye-tracking equipment so development teams can monitor a user’s experience, including body language, ﬁrsthand. The lab also includes “war rooms” complete with video and audio conferencing to encourage cross-team interaction and an “innovation room” where users can write and draw on “smart walls” that transmit the data as notes directly to the participants’ computers.
A culture of innovation Situated along a second-ﬂoor walkway that overlooks a football ﬁeld-sized area where drilling and evaluation tools are assembled, the usability lab is “a microcosm of culture change” for Baker Hughes, according to Tarver.
What was once a storage area for old hardware is now a modern and inspiring environment for people to work and to interact. Some of the equipment is the same as that used in Google’s usability lab. The lab’s visitor list includes people from technology’s “Big 3” (Apple, Google, and Microsoft) who have come to Houston to meet with Baker Hughes software developers. In one of the project rooms, a developer takes cues from an LWD tool operator from the Africa region who will be using the software in the ﬁeld, as a life-sized cardboard cutout of Captain Spock from the Star Trek Enterprise oversees the conversation. Explains Tarver: “Software developers are problem solvers who work hard. They’re also creative people, and creativity can’t be turned on like a faucet. If they get stuck, I want them to come in here and play with Legos, watch a movie, play video games—do something that gets those creative juices ﬂowing again.”
The end users of the system are also provided a space to work and provide insight for the system from the beginning. “Involving people who will be running the tools on location is just another way to help them design better solutions for our customers,” Tarver adds. In another room, music from The Black Keys wafts from an MP3 player as user experience specialist Steven Pierce creates a data visualization display for a new software platform called Cadence ™ on his drawing tablet. Cadence, one of the software packages for laptops being tested in the lab, is a replacement for the Advantage ™ surface system used to capture complex data from Baker Hughes LWD tools. Pierce, like Casslasy, joined Baker Hughes from the video gaming industry, which highlights the importance of having the right culture along with an eye for quality and innovation.
“Bringing people in from outside our industry gives us a different perspective,” Tarver says. “I do think that some people think people from the gaming industry are slackers still living in their parents’ basements, but in reality they’re more like special forces. They are exceedingly driven and exceedingly talented. “A lot of what goes into developing games is done through a visual approach. So, we are looking at how we can present things in a more visual, interactive, and smarter way. What I would like is for Baker Hughes to be to data visualization what Google is to search.” The usability lab underlies the Baker Hughes mission of anticipating, understanding, and exceeding the expectations of the customer. “I often give tours to internal groups to let them know about the lab’s capabilities and that it can and should be shared,” Tarver says. “We have some
great technology internally for user testing that can provide real value to us and ultimately to our customers, whether it’s a brochure, an interface for the Baker Hughes Operating System (BHOS), a mobile app for IT, a tradeshow booth, our intranet or corporate websites, or desktop applications. In February, Tarver was invited to a workshop in Aberdeen, Scotland, where he presented concepts for improved data visualization to aid decision making, as well as concepts for automation, to a group of Statoil managers and engineers. The Norwegian national oil company is planning a ﬁeld development that is scheduled to begin in 2016 with a ﬁeld life of 30 years. “We wanted to make the customer aware of concepts that may become reality within the lifetime of this project,” says Marianne Stavland, a Baker Hughes project manager for Statoil Mariner/Bressay. “Our aim was to initiate a discussion around how services could be delivered differently in the future. “I think the industry is spending a lot of valuable time ﬁghting software at the moment. The usability lab can change that by ensuring that the software is working for us, not against us. Also, if we deliver on the concepts, we will turn the multitude of available data into information for improved decision making to enhance our customers’ operations. I also believe the concepts will help the industry attract creative and innovative people.”
> Test-driven development means software is rigorously tested as it’s developed, not just for reliability, but for performance, usability, and consistency.
Tarver agrees. “We need to show that we are a technology company, and it is exciting, and it’s interesting, and there’s a lot to learn here,” he concludes. “We need to show people that Baker Hughes isn’t your typical oil and gas service company anymore. We are a technology company that specializes in oilﬁeld services.”
On average, as much as 30% of the nonproductive time on a deepwater drilling rig is the result of debris in the wellbore—trash that’s
left over from drilling and completion operations. Baker Hughes may now have the industry’s best integrated system for removing it, but don’t take our word for it. World Oil magazine thinks so too. > Joe Cottrell, a ﬁeld operations engineer, inspects key dimensions on the XP riser brush and boot basket. www.bakerhughes.com
01> The X-Treme Clean XP well cleanup system removes debris from the wellbore that could hinder future operations. 02> George Krieg (left) and Joe Cottrell inspect the brush strips on the XP casing brush.
There’s a point after drilling a well when you pull all the drilling tools, replace the drilling mud with completion ﬂuid, and prepare to open a portion of the hole to the reservoir you’re trying to reach. With shallow, uncomplicated wells, the job goes quickly, but with complex, deepwater wells that can cost USD 100 million or more, this critical process is anything but routine. Thanks to drilling mud, most of the rock is gone from the hole by the time the drill bit reaches the bottom of the well. What remains are small bits of rock, pieces of 60
metal, and, if the rig crew wasn’t careful, an occasional wrench or glove.
package, especially in high-pressure/hightemperature wells.
“All of that must be cleaned from the hole as part of the completion process to reduce or eliminate associated risks and costs,” says Yang Xu, Baker Hughes wellbore cleanup product line manager. “This is especially true for high-cost deepwater wells.”
“Maintaining viscosity of the lead spacer— the high-tech weighted push pill used to separate drilling mud from displacement brine—is critical when we’re moving the mud from the hole,” says Clark Harrison, Baker Hughes Completion Fluids product line manager. “When well temperatures top 300°F [149°C], the polymers that make the ﬂuid viscous can easily degrade, and the cleaning products we use can lose efﬁcacy. To effectively clean the wellbore, we have to be sure our products can withstand these harsh conditions.”
Failure to clean the wellbore after drilling operations can cause big, expensive, and even dangerous problems later on. The sand control screen, for example, can become contaminated and plugged before reaching total depth. Packers—expandable devices used to isolate one section of the well from another—can prematurely set at the wrong depth. Debris can even damage the formation, eventually reducing the well’s ability to produce.
Double your clean There are two aspects of cleaning a well. First, a string of mechanical tools is run into the well to physically remove debris from the wellbore. Second, specially designed ﬂuid ﬂushes out loose debris and cleans the inside of the casing. The engineered ﬂuids and well-cleaning tools work together as a
The Baker Hughes MICRO-PRIME™ wellbore cleaning spacer system, for example, is engineered to optimize the removal of synthetic- and oil-based mud residue from the wellbore during the process of displacing drilling mud with completion brine. The solvent-free system solubilizes the oil fraction and water-wets solids found in the synthetic- and oil-based muds and on the wellbore’s metal surfaces. The latest addition to the Baker Hughes X-Treme Clean™ well cleanup portfolio is the
X-Treme Clean XP system, which consists of premium tools that work together ﬂawlessly to deliver extreme performance in the world’s most difﬁcult wells. “The deepwater market has grown rapidly in the Gulf of Mexico, Brazil, Africa, and some areas of Asia Paciﬁc,” Yang adds. “The X-Treme Clean XP system is geared toward these markets and not only meets but exceeds the requirements for deepwater operations. The tensile strength and torque ratings of our tools are higher than those of the drillpipe, which greatly reduces operational risks during cleanup and displacement. The tools also have large circulation areas, which enhance ﬂow and the removal of debris. “Perhaps the outstanding feature of the tool, however, is the high rotational speed that disturbs the debris more effectively and provides for better cleaning in a deviated well.”
The differentiator The X-Treme Clean XP well cleanup system consists of a modular family of high-performance circulation tools, brushes, magnets, scrapers, and ﬁlte rs. They can be run as an integrated one-trip wellbore cleanup system or separately for speciﬁc operations. “We are particularly proud of the highperformance, rugged XP downhole magnet,” Yang says. “Its high-strength, high-temperature magnets and unique arrangement of magnetic bars allow it to capture and carry in one trip much more metal debris than ordinary magnets, while still allowing enough room for ﬂuids to circulate around the tool.”
that allow the drillpipe to rotate through the tool at speeds up to 150 rpm. That means the scraper can move up or down with the rotating drill string, but without rotating itself. This greatly reduces wear on the interior of casing, even when the drill string is being rotated at high speeds to improve circulation and agitate the ﬂuids down hole. “The helical blades and brush blocks of the XP scraper and brush set this tool apart from others on the market in two ways,” Yang adds. “First, the scraper uses both the ends and the sides of the helical blades to scrape the casing, which more than doubles the scraping area of conventional units. Second, the casing scraper and brush provide 360° contact with the inside of the casing, while the helical shape of the blades and brushes increases the area for annular ﬂow. This innovative design allows ﬂuids in the wellbore to circulate at higher rates.”
“The workstring was tripped to bottom over a 22 1/2-hour period with 120 rpm maximum rotational speed,” explains James L. Holloway, Baker Hughes technical support engineer. “It was then ﬂushed with 100 barrels of high-viscosity MICRO-PRIME wellbore cleaning ﬂuid, chosen for its ability to remove synthetic oil-based residue. In a second trip into the hole, a spike ﬂuid was introduced to increase the density of the ﬂuid column, while XP magnets simultaneously recovered more than 130 lbm [59 kg] of metal debris from the well.” A second Gulf of Mexico operator needed to clean a deep well that was deviated as much as 78°. In addition to signiﬁcant ﬂuid compatibility challenges, the depth and angle of the well tested the X-Treme Clean XP system to its full potential.
The industry takes note The full X-Treme Clean XP toolkit had not yet been fully commercialized when the system earned the 2012 World Oil Award for Best Well Intervention. Since then, a sixth tool has been added to the XP family, one designed to jet-clean the insides of the blowout preventer to ensure the massive device will function properly in an emergency. A seventh tool, the XP multicycle ballactivated circulation valve, is being developed. It will give operators the option of boosting the downhole ﬂuid velocity without having to manipulate the drill string. This tool allows up to seven complete cycles and three ﬂow positions: ﬂow to bit, ﬂow to side ports only, and a ﬂow split to the bit and ports.
Reports from the ﬁeld Casing scrapers are commonly used to remove drilling mud, cement, perforation burs, rust, parafﬁn, and other substances from the inside of the well casing. The XP casing scraper has sets of internal bearings
X-Treme Clean XP wellbore cleanup tools and ﬂuid services.
When the operator of one ultradeepwater well in the Gulf of Mexico needed to remove more than 1,600 ft (488 m) of cement and debris from a 27,200-ft (8291-m) well, Baker Hughes recommended the full portfolio of
After the drilling mud was completely displaced with completion ﬂuid, a suite of tools was ﬁrst run to a depth of 29,993 ft (9142 m), to tag the top of the cement. The X-Treme Clean XP system then milled 207 ft (63 m) of cement to reach a total depth of 30,200 ft (9205 m) in approximately 28 hours. As the milling continued, the crew pumped several 70-barrel high-velocity sweeps to remove the cuttings and debris. Finally, a jet sub and multitask ﬁlter were run through the BOP stack. By the end of the operation, some 500 lbm (227 kg) of debris were removed from the ﬁlters and magnets. “In every case, well cleanup is a marriage between hydraulic cleaning and mechanical cleaning,” Holloway concludes. “With the combination of the award-winning XP tools and high-performance ﬂuids, Baker Hughes can provide the best wellbore cleanup and displacement solutions for deepwater applications and ensure the most reliable completions.”
Partnership with Local University Helps Prepare
Malaysia’s Industry Workforce With a commitment to excellence through the advancement of industry knowledge in the region, Baker Hughes launched its Petroleum Education Center at the Universiti Teknologi PETRONAS (UTP) in Malaysia in February. The center is dedicated to the development of future industry leaders by providing hands-on training in real-world applications, and by promoting the development of new products and technologies. Aligned with the mission of UTP, the Petroleum Education Center’s goal is to foster a collaborative environment that enhances the abilities of the industry’s local workforce through a variety of educational activities and development programs, including internships. The center is dedicated to exposing students to upstream oil and gas technologies and processes by offering a walkthrough exhibit entitled “Life of Field: Drilling & Production.” Datuk Wee Yiaw Hin, PETRONAS executive vice president, Exploration and Production, ofﬁciated the opening ceremony of the new center along with Zvonimir Djerﬁ, president of the Baker Hughes Asia Paciﬁc region. The Petroleum Education Center is the result of a collaborative effort between Baker Hughes and PETRONAS, Malaysia’s national oil company. The program began in August 2011, with a commitment from Baker Hughes and three other local energy
industry companies. The heart of the center is the Life of Field exhibit, enhanced by a range of Baker Hughes equipment displays designed to educate and familiarize students and visitors with activities across the entire life cycle of a ﬁeld—from exploration to production. In addition to the Petroleum Education Center, Baker Hughes also provided funds for a research and collaboration program, a lecture and seminar series, a program for the supervision of masters and doctoral students, scholarships, and sponsorships for the very best of the 6,000 students enrolled at UTP. In fact, four UTP students were recipients of Baker Hughes scholarships. “The scholarships are the beginning of what promises to be a successful partnership between Baker Hughes and the UTP student and faculty community,” Djerﬁ says. “The excitement generated by the opportunities for hands-on experience will continue once the students
enter the workforce and view Baker Hughes as a local partner. Also, we anticipate that the experiences gained at UTP will result in unique regional technology breakthroughs that will further enhance Malaysia’s technological drive.” Accompanied by short descriptions that offer technical speciﬁcations, the equipment and models in the Life of Field exhibit include many tools used in the Asia Paciﬁc region for drilling, evaluation, completion, and production activities. Among them:
OnTrak™ integrated measurement-while-drilling and logging-while-drilling systems CoPilot™ real-time drilling optimization service AutoTrak™ Curve high-buildup rate rotary steerable system GeoFORM™ conformable sand management system with Morphic™ shape-memory polymer technology TORXS™ expandable liner hanger system EQUALIZER™ sand and inflow control technology
REPacker™ reactive-element, swellingelastomer packer
Formerly known as the Institute of Technology PETRONAS, UTP is situated on 1,000 acres at Bandar Seri Iskandar, Perak Darul Ridzuan, Malaysia. Opened in 1997, the university offers a wide range of courses for undergraduate and graduate students, with an emphasis on research and development. Rather than simply providing an education, the university’s mission states that UTP strives to “produce well-rounded graduates who are creative and innovative with the potential to become leaders of industry and the nation.” Among its successes, UTP has garnered several awards, including two ratings of excellence under the Rating System for Institutions of Higher Learning and a ﬁve-star rating from the Malaysian Research Assessment Instrument.
from Baker Hughes
Rhino™ bifuel pumps ™
The Baker Hughes Rhino bifuel hydraulic fracturing pumps, which use a mixture of diesel and cleaner-burning natural gas, reduce diesel use by up to 65% with no loss of hydraulic power. The natural gas ﬂowing into the Rhino bifuel pumps is delivered through a closed system,
eliminating multiple refueling operations and associated risks. Lower diesel requirements also reduce fuel transportation costs and the associated road hours. And, if certain criteria are met, the pumps can even be run using ﬁeld gas, further reducing overall costs. “Using a 60/40 mixture of natural gas and diesel, the Rhino bifuel pumps operate continuously twice as long as dieselpowered pumps, improving hydraulic fracturing program efﬁciency and lowering operating costs, while reducing emissions—including nitrogen oxides, carbon dioxide, and particulate matter—up to 50%,” explains Andrey Smarovozov,
product line manager, stimulation. “Even though natural gas has a lower British thermal unit content than diesel, burning more natural gas on a volume basis maintains the output. At a 50% substitution rate, the fuel will last twice as long and nearly eliminate hot fueling. “With diesel-fueled pumps, the safety option requires shutting down operations to let the pump engines cool before adding fuel. With Rhino bifuel pumps, continuous operations actually become continuous.”
Centrilift FLEX™ series electrical submersible pumps The efﬁcient, reliable Centrilift FLEX ™ series electrical submersible pumps (ESP) maximize production and provide the operational ﬂexibility required in dynamic well conditions. FLEX pumps minimize ESP system changeouts and nonproductive time while delivering ultimate reserve recovery from conventional oil ﬁelds, mature oil ﬁelds, and unconventional resource plays in which the production index declines rapidly.
“With innovative technology like the FLEX series pumps, ESP systems can operate in more types of well conditions than ever before,” says Mike Gagner, product line manager for conventional and unconventional ESP systems. “Operators need ESP systems for optimum production and maximum ultimate recovery, and the FLEX series pumps help operators meet those requirements. New, patented technology developed through dedicated engineering research and advanced hydraulic design tooling differentiates the FLEX line of pumps compared to the competition.” The FLEX series pump designs reduce the total hydraulic thrust in both upthrust and downthrust conditions. FLEX series pumps operate efﬁciently and reliably, providing the industry’s widest operating range—from 50 to 10,500 B/D—from a minimal number of pump models. Wider oprating ranges for each FLEX pump minimizes ESP changeouts as production rates change over the life of a well. Lower hydraulic thrust extends operation, and heavier construction of FLEX pump components increases uptime and reliability. Baker Hughes engineers choose the right FLEX pump for each well’s speciﬁc requirements, focusing on what’s most critical to maximize the return on investment for producers from every well.
operating expenses—including power consumption—over the life of the reservoir. From existing assets and new production zones like shale resource plays, tight reservoirs, and deeper zones, where ﬂow conditions can change dramatically over short periods of time, the FLEX series pumps improve reliability by providing stable operations in these varying conditions.
SOr™ sponge liner coring system The Baker Hughes SOr™ (saturation oil remaining) sponge liner coring system provides accurate analysis and measurement of ﬂuid types and oil saturation levels in cores. This information helps operators determine if formations have sufﬁcient reserves to continue ﬁeld development and production. The SOr system uses a 3½-in. inside diameter sponge liner, modiﬁed pilot shoe, proprietary pressure-compensating piston design, LaserCut™ aluminum inner-barrel liner system, and custom-designed coring bit to minimize drilling ﬂuid invasion and capture all of the expelled ﬂuids as the core is brought to surface, holding the oil adjacent to its corresponding core depth. “Conventional sponge coring methods do not always accurately determine ﬂuid types or quantify residual oil volumes because the sponge can be easily damaged, allowing oil seepage during core extraction,” explains Carlos Rengel, product manager for Baker Hughes coring services.
“The SOr system, which includes a customized coring bit, a redesigned sponge liner, and specialized equipment to ensure optimal coring recovery, encases the core with oil-absorptive sponge material that captures the expelled oil as the core rises to the surface. The data gathered from the core and ﬂuids captured in the sponge enable operators to determine the quality, quantity, and the depth of oil in the reservoir, and the economic feasibility of recovering remaining reserves.” The molded, oil-absorptive sponge liner with protective mesh ensures a strong ﬁt between the core and the sponge so that expelled oil is absorbed rather than lost in the formation or wellbore. “This tight ﬁt also provides additional core integrity and protects it during acquisition, recovery, surface handling, and transportation to the laboratory for analysis and short-term storage,” Rengel adds. The system’s process and equipment allow operators to secure a larger volume of unaltered core for oil saturation analysis, effectively reducing total data acquisition costs and minimizing nonproductive time. The system works well in conventional and unconventional oil formations, including shale plays and mature, secondary, and tertiary ﬁelds.
FLEX series pumps deliver superior efﬁciency across the wider operating range, lowering
H. John Eastman
Delivers a New Slant on Drilling
A small but very deep, dark lake lies within a mile of a residential neighborhood in the rapidly growing town of Conroe, Texas, a half hour north of Houston. Although today the site is tranquil, more than 75 years ago it was the site of one of the worst oilﬁeld ﬁres in U.S. history. H. John Eastman, probably best known as the “father of directional drilling,” became internationally famous in 1934 for his part in mitigating the disaster using his newly developed techniques for controlled directional drilling. Today, the site of the oilﬁeld disaster, a lake about 150 ft (46 m) across and believed to be at least 600 ft (183 m) deep, is known as the Conroe Crater Lake. A Texas Historical Marker that was erected at the site in 1967 referred to Eastman not by name, but as “a driller … who killed the blowout by using directional drilling for the ﬁrst time in coastal Texas.” The marker has since disappeared.
A truck, a winch, and some cable After earning a degree from Oklahoma A&M College, Eastman began his career as a production superintendent for Magnolia Petroleum Company in Oklahoma, and later worked as a salesman for Standard Oil in California. In 1929, Eastman struck out on his own with a truck, a winch, a built-on darkroom, and 7,000 ft (2134 m) of cable, naming his new company Eastman Oil Well Survey Company. Based in Long Beach, California, he used an acid bottle as his primary drift indicator and traveled up and down the California coast to solicit survey business. With the help of Alexander Anderson, a local watch maker, Eastman built the ﬁrst multishot survey instrument and then together they invented a single-shot instrument.
Also in 1929, Eastman obtained the patent for a retrievable openhole whipstock, which was used to deﬂect the drilling assembly in a controlled direction to “kick off” a well. In addition, he used bottomhole assemblies with carefully-spaced stabilizers to make the well build, hold, or drop inclination. These instruments—the whipstock deﬂection tool and stabilized bottomhole assemblies—were the foundation for controlled directional drilling.
A ﬁre seen for 35 miles Some 1,600 miles (2575 km) away, in Conroe, Texas, pioneer oilman and philanthropist George W. Strake had been drilling since 1931 in what was then the third largest oil ﬁeld in the U.S. at 19,000 acres (7689 hectares). Strake’s Conroe discovery proved that the Cockﬁeld sand was an oil-producing formation, and opened wildcatting from Texas into Louisiana and Mississippi in an area 50 miles wide by 500 miles long (80 by 805 km). At the beginning of 1932, the Conroe ﬁeld was producing more than 65,000 barrels of oil a day. Then, in January 1933, disaster struck when a gusher came in and instantly burst into ﬂames. People as far away as Houston could see the thick, black smoke from the inferno. The ﬁre raged for months, resisting all attempts to be quelled by dynamite and thousands of tons of dirt. George Everett Failing of Enid, Oklahoma, and his crew ﬁnally succeeded in extinguishing the blaze with his technique
of mating a drilling rig to a truck and a power take-off assembly. The innovation allowed the team to rapidly drill a series of slanted relief wells, a revolutionary technique at the time, and relieve the enormous gas pressure. Failing’s crew extinguished the Conroe ﬁre, but a steadily growing crater continued to feed off sunken casing at the rate of 6,000 barrels a day. Plus, reduced pressure in the ﬁeld had dropped the production of all other wells to less than 100 barrels per day.
Harnessing a wild well Desperately wanting to protect its ﬁnancial investment as the largest producer in the ﬁeld, Humble Oil needed to act before the ﬁeld had no more lifting power and the oil pool was dissipated. It decided to bring in Eastman and his ﬁve-yearold company, which had already established a winning reputation in the new ﬁeld of directional drilling. Arriving on the site, Eastman saw that the crater had grown so large that he would need to put his relief well, Alexander H. No. 1, at least 400 ft (122 m) away and that he would need to deviate the borehole deep underground to reach the true source of the crater. A story in the May 1934 edition of Popular Science magazine described the procedure: “When the drill reached a depth of 1,960 ft [597 m], it was pulled up, and down into the hole went another instrument. Below its cutting teeth was attached a piece of pipe cut diagonally along its length, on a slant. Drillers carefully lowered it until it ﬁtted the bottom of the hole. Then the bit was set
in motion. Following the slanting surface of the beveled pipe, it was deﬂected, starting a new hole at an angle toward the runaway well.” Eastman reached his directional drilling target on Jan. 7, 1934, after nine weeks of drilling, and then forced thousands of tons of water into the well at a steampowered pressure of 1,400 psi (96.5 MPa). It took only two days to stop the ﬂow of oil into the crater. The success at the Conroe oil ﬁeld brought Eastman recognition around the world. At the age of 40, he was even lionized in the Popular Science article, which referred to his “brilliant work … [as]… a specialist in the new science of directional drilling.” The article read in part, “Slanted oil wells are the latest sensation of the oil industry. Drilled by experts who use special tools and secret methods to send the bit burrowing into the ground at strange angles. … They are being used to harness wild wells that cannot be controlled from above; to turn the bit aside when tools have become stuck in the hole and to tap subterranean pools lying beneath deep lakes or inaccessible peaks.“
Success breeds success The fame paid off in even greater success for his young company, and by 1955, Eastman Oil Well Survey had 30 branch ofﬁces around the globe. Still busy with his company in the 1940s and ‘50s, Eastman moved to Denver, Colorado, where he became a prominent citizen. He was an active member of a trail-riding and civic group called the Roundup Riders of the Rockies and became known as a breeder of ﬁne
horses, which he showed at major equestrian events in the U.S. and Canada. In 1972, Eastman’s company was acquired by Petrolane Inc. and merged with Whipstock Inc. to become Eastman Whipstock, the world’s largest directional drilling company. In 1986, the company merged with Norton Christensen, a pioneer in PDC bits, downhole motors, and coring services, to form Eastman Christensen, which was acquired by Baker Hughes in 1990. H. John Eastman died in 1995 in Long Beach at the age of 90. The company he founded is now an integral part of the Baker Hughes Drilling Services business. Once considered a risky novelty, directional drilling is now practiced by nearly every operator in the energy business worldwide.