revista baker hudges connexus 6 - oil & gas

8/9/2019 Revista Baker Hudges Connexus 6 - Oil & Gas

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CONNE US2013 | Volume 4 | Number 1

The Baker Hughes Magazine

Well of the FutureEquion builds ambitious,

sustainable business plan

on nontraditional relationship

A Solid BondDeploying the right

tools and technologies

to ensure well integrity

A Total SolutionSmall independents have

less overhead, expert network

with total well solution packag



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 Solutionsbased on

Executive Focus



One of the major lessons from the

initial unconventional “era” is that

to build a truly sustainable global

shale business, we must first reframe

our current approach—which relies

heavily on empirical data and afactory drilling mindset—to an

approach that is based on geologic

measurement and scientific models.

We know that no two unconventional

resource plays are the same. Even

large source rock shale deposits

have sweet spots and nonproductive

sectors. So, our desire over the last

half decade to engineer the shale with

a one-size-fits-all approach cannot

be sustained on a global basis.

As we move to commercialize

unconventional resources in places

like China, Saudi Arabia, and South

America, we’re going to be less

and less inclined to drill hundreds

of wells in one play to use the lawof averages to predict results.

Instead, we have an opportunity

to integrate prediction techniques,

such as hydraulic fracturing models,

with geomechanics, petrophysics,

and reservoir simulation to identify

commercial prospects earlier and

to derisk the entire field faster and

more effectively.

Providing our customers with a more

comprehensive view of their reservoirs

to accurately pinpoint sweet spots so

they can make the most productive

decisions is a fundamental goal of the

Baker Hughes unconventional resource

strategy. We recently enhanced that

strategy by entering a collaborative

relationship with CGG, a fullyintegrated geoscience company that

provides geological, geophysical, and

reservoir capabilities.

By employing reservoir models that

integrate log-derived, near-wellbore

geomechanical and petrophysical

properties from Baker Hughes with

calibrated seismic data from CGG,

operators can optimize well placement

and completion design earlier in the

asset life cycle for more efficient well

construction and more productive wells.

In this issue of Connexus, two articles

about total well solutions for customers

producing unconventional resources in

North America relate the importance of

reservoir intelligence.

In South Texas, Baker Hughes is

providing a total well solution to

Cheyenne Petroleum, one of numerous

smaller producers in the Eagle Ford

shale. The Baker Hughes reservoir

solutions team created a hydraulic

fracturing model using our proprietary

fracturing simulator and then

experimented with different fracturingscenarios to see which methods

produced the best results. A production

simulator then showed how each

change would affect ultimate recovery.

In the Northeast U.S., Baker Hughes

is delivering a total well solution for

Gastar Exploration Ltd. The operator

is seeing increased production after

changing its standard fracturing

design to an irregular spacing designbased on a developing technique

that uses reservoir lithology and

geomechanical stress measurements

to place the laterals.

Reframing our unconventional resource

strategies around the geosciences and

advancing these new ideas mean we

can extract hydrocarbons in the most

effective, efficient, and sustainable

way possible.

It also means that as an industry

we can build a sustainable global

unconventional resource business that

minimizes our footprint, improves

recovery, and, ultimately, delivers

energy to help transform communities.

Martin Craighead

Chairman and CEO, Baker Hughes

www.bakerhughes.com



20

04

38

04 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.

12 Marcellus Muscle

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.

16 Industry Insight

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.

20 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.

26 Big Service

Cheyenne Petroleum is finding cost savings

in almost every aspect of its Eagle Ford

shale operations with a Baker Hughes total

well solution.

31 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.

34 Smart Fields

More and more operators are introducingthe smart field value-added concept to their

business plan, which means much more than

just automating a field or completing the

wells with “intelligent” devices.

38 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 minimizerefining bottlenecks, maintain refinery

reliability, and ensure product quality.

44 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.

CONTENTS2013 | Volume 4 | Number 1

|



34

4

is published byBaker Hughes Global Marketing.Please direct all correspondenceregarding this publication

to [email protected].

www.bakerhughes.com

©2013 Baker Hughes Incorporated.All rights reserved. 38453 05/2013No part of this publication may bereproduced without the prior writtenpermission of Baker Hughes.

Editorial Team Kathy Shirley

strategic marketing manager, bran

Cherlynn “C.A.” Williams publications editor

Tae Kim senior graphic designer

Shirley Leong senior graphic designer

Lan Phamweb designer

Contributors Ann LiggioPeter Schreiber

On the Cover

The Marcellus shale is asedimentary rock formation

stretching from upstate

New York to the rolling

Appalachian Mountains of

West Virginia, shown here.

48 An App for That

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-packdeployment system for that.

54 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.

59 Trash Talk

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.

62 Good Neighbors

Baker Hughes supports the PETRONASPetroleum 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.

64 Latest Technologies

New sponge liner coring systems, electrical

submersible pump designs, and hydraulic

fracturing pump designs help solve

customer challenges.

66 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


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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.

www.bakerhughes.com



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 futureWith 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) JairoPeñuela, Jose Luis Gómez, Jae Song, Wilson Carreño,Mario Pacione, Alexander Valdivieso, Pedro García,Graeme Symons, Luis Carlos Alzate, Cesar López, andDiego 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 requiressubstantial 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 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.”

The complexity of the Wellof the Future project can bereadily appreciated by lookingat just one aspect of the wellconstruction process:

running the 11 ¾-in.casing and not getting it

to bottom as planned.

Among the questions that mightarise are:

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.

www.bakerhughes.com



A mountain of challengesThe 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 arenumerous: 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 touse 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

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.”

“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

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.”

“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

Right Team

+Analysis

+Out-of-the-box Ideas

+Innovative Engineering

+Cutting-edge Technology

+Management

Commitment and Support

=The Well of the

Future

|



FRT8 FRT8

The 17,000 ft (5182 m)

of dipped and folded

geology betweenthe drilling rig and the

producing zones beneath

the Andean foothills is

nothing short of hellish.

> While the Well of the Future project focuses primarily on reducing the time and cost to drill, making adjustments in casing design could help alleviatethe problems of hole instability and severe mud losses, while a multilateral well design could make a huge difference in improving productivity.

The Present The Future

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.”

www.bakerhughes.com



Interdisciplinary solutionsTraditional 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.”

“The only way to over-come the challenges thatwe have in the industrytoday is to work differentlyby working together.”

Carlos Vargas

vice president,Drilling and Completions, Equion

0 |



2 ndColombia’s ranking in the world as an exporter of cut flowers, after the

Netherlands, shipping more than USD 1 billion in blooms annually

500 million tons Amount of flowers Colombia exported to the U.S. for Valentine’s Day in 2013

300

km

(186 miles)Distance the national bird of Colombia, the Andean condor, can fly in one day

2.4 billionBarrels of proven oil reserves (January 2013)

944,000 Barrels per day of oil production in 2012

56 % Area of Colombia covered by natural forest

55,000Number of species of plants indigenous to Colombia

(15% of the world’s existing species)

1,870Species of birds indigenous to Colombia

(20% of the world’s total bird species)

2 ndColombia’s ranking in the world for most species of butterflies, roughly 3,000

3 rd Colombia’s ranking in the world for Spanish-speaking population

6 thFIFA world ranking as of April 2013

46 millionPopulation of Colombia, second largest

in South America after Brazil

5700 m

(18,700 ft)

Height of Pico Cristobal Colon,

Colombia’s tallest mountain peak

100

Percentage of Colombian coffee a

product must consist of to obtain alicense to use the Juan Valdez trademark

560,000Number of people employed in Colombia’s

coffee industry

Sources: Embassy of Colombia, Washington,

D.C.; www.cia.gov; World Intellectual

Property Organization

Colombia by the Numbers

www.bakerhughes.com



When a small company invests the majority of itscapital budget into one project, every spendingdecision becomes a big one.

2 |



Less than three years ago, Gastar

Exploration Ltd. found itself a long way

from its legacy assets in the deep Bossiernatural 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.

Building relationshipsEven 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.

“There’s a lot of moving parts out there.

These wells are complex and, because

we have so few employees, we rely onan 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 andcompletion 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.”

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.”

www.bakerhughes.com



D e p t h

Time

Vertical

Curve

Lateral

A u t o T r a

k C u r v e

S y s t e

m

S t e e r a b l e M o t o r

S y s t e m

Driving down costsPart 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-builduprate 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

4 |



“These wells are complex and, because we haveso few employees we rely on an excellent group ofconsultants out in the field. The coordination of all thedifferent disciplines within Baker Hughes is essential

and key to our success.”

Mike McCown vice president for Gastar’s Northeast operations

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 oninformation 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 anddiesel, 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 tubing-

conveyed 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 forBaker 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.”

www.bakerhughes.com



I N D U S

T R Y I N

S I G H T

w i t h

J. R u s s e

l l P o r t

e r

With the rise in production from unconventionalresource plays, much has been written about theU.S. becoming energy self-sufficient. What are yourthoughts 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.

Smaller independent companies have been a largepart of the production growth from unconventionalresource plays. Do you see the mix of companiesin 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

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.

Industry Insight

6 |



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 stateregulations affect the future of activity in theMarcellus 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/liquidsreserves in just three years. To what do youattribute this increase in liquids reserves? Anddoes Gastar intend to concentrate more on liquidsproduction 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,

www.bakerhughes.com



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 youpredict 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, 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 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 providerin the Marcellus. How has this improvedyour 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 inapplying reservoir studies to the unconventionalresource 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 regulationstoward a more sustainable water strategy?How can you drive down the cost of waterto 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

8 |



$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 inyour 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 natives.

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 t imely basis. In return, we have beenvery open to the Baker Hughes total well solution concept of packaging services. Over the past two years, we’ve seen our overall costs per welldecrease, and we’ve seen our EURs and our production increase.”

www.bakerhughes.com



By collaborating closely with operators anddrawing from a comprehensive portfolio ofdesign processes, cementing technologies andequipment, and R&D processes, Baker Hugheshelps minimize risks and ensure long-term

integrity for wells around the world.

Integrated technology solution aimed at

DRIVINGINNOVATIONSIN WELL INTEGRITY

0 |



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 productionin 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 wellintegrity 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, BakerHughes 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.”

www.bakerhughes.com



This review identified new development

areas for the company and a need tocombine 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 simulationAn 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.”

2 |



Cementing a solid bondOnce 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 thecasing 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 oil-

based 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 CO2 and othercorrosive 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.

www.bakerhughes.com



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 measurecement 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 withboth 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.”

4 |



> Baker Hughes trains fieldspecialists on cement unit

simulators and tests allcementing technologies beforethey 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.

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 inte rested parties in the Norwegian petroleum industry and is owned by the Norwegian petro leumindustry, represented by The Norwegian Oil

Industry Association and Federation ofNorwegian Manufacturing Industries.

www.bakerhughes.com


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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 multimillion-

dollar 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

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 managementVincent 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

8 |



“Without this arrangement,

we’d need a lot more

people. The good thing

is that we’re able to stayrelatively 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 solutionsThe 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 FordSome 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 drillingcosts 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.”

0 |



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 CO2

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.

ADVANCINGRESERVOIR

PERFORMANCE

with 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 solutionsto maximize the value of a

customer’s asset.

www.bakerhughes.com



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 legacyIn 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 third-

party 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.

2 |



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.”

www.bakerhughes.com



More and more operators areintroducing the smart field value-added concept to their business

plan, which means much morethan just automating a fieldor completing the wells with“intelligent” devices. It involvespeople, technologies, andprocesses that deal with a muchbroader scope of work across allof the activities embedded inmanaging an oil and gas asset.

FIELDS SMART

The Art ofMaking

4 |



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 anyoil 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 technologies 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 decisionsThe 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.

“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.”

“The West Kuwaitintegrated digital oilfieldconceptual study projectwas developed throughclose collaborationbetween the KOC team

and a Baker Hughes-led consortium ofcompanies. ...This is theinitial step of a journeythat will bring KOC toa world leadershipposition in digital fieldsand to a world-class

example of excellence.”

Bader Al-Matar team leader, research andtechnology subsurface, KOC

www.bakerhughes.com



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.

“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, third-

party 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 visionA 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.

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 state-

of-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

ENGINEERING

FOCUS

ASSET/FIELD

FOCUS

AssetOperations

ProductionOptimization

ReservoirManagement

OPERATIONS

FOCUS

ENGINEERING

FOCUS

ASSET/FIELD

FOCUS

P l

a n

I n terve n e

M e a s u r e

D i agn o s e

M e a s u r

e

Ac tual

S y

s t e m

I m p le m e n t

P r o

d u c e

&

C ompar e

M o d e l

S e t ti n g s

P l a

n

C a p i tal Pr o g r a m

P l a n

R e ser v o i r

F i e

l d

D e v e

l o

p m

e n t

I m pleme n t

E x e c u t

e

O p e r a t i n

g

C h a r a c t er i z a t i o n

Decision making along an asset life cycle

6 |



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

while preparing to kick off Phase 2 of this

complex, but high-value IDF project.

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, connectivi ty,

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.”

> Leonel Pirela, intelligent fields globaldirector, Gaffney, Cline & Associates

www.bakerhughes.com



After the

8 |



“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 theproduction 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 keepprofits flowing,” Bieber says.

The right refining solutionsIn 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

“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

2 |



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.”

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.

www.bakerhughes.com



DV satyaNone 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.

Faces of Innovation

4 |



DV Satya Gupta is a Baker Hughes chemicalengineer whose name appears on more than

130 patents relating mostly to technologies

for well stimulation. He’s credited with

research in everything from carbon dioxide-

compatible, 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.

The path to chemical engineeringSatya 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 biomedical-

related studies on membranes and

encapsulations. As Gupta looked at options

for advanced studies, he was offered

a medical doctor Ph.D. program at the

University of Miami in Florida but turned it

down in favor of the chemical engineering

Ph.D. program at Washington University.

“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 t ime, 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

www.bakerhughes.com



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

Gupta remembers well the day he discoveredthe 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’sheadquarters 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 solutionsTo 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, polymer-

specific enzyme breakers, premium

Among the manytechnological

achievements creditedto Gupta is a line of

scale inhibitor productsbased on the chemistryfound in diatomaceous

earth, a naturallyoccurring substance

used in everyday

cat litter.

6 |



performance aqueous fluid systems,

nonaqueous fluid systems, ultralightweight

proppants, and the Sorb line of long-

term production assurance products.

Much of the development work on

encapsulated breakers took place in theearly 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.

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 CO2. Some of these are

unique in the sense that nobody else does it.

If everybody can do it, my interest wanes.”

The next bright ideaWhether 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 nextbig technology breakthrough is just

around the corner. Or in the case of

encapsulated inhibitors—over lunch.

“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 IllinoisTool Works Inc.

www.bakerhughes.com



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 completionsthat 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, single-trip 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.

www.bakerhughes.com



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.”

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.

H o u s t o nN e w O r l e a n s

U N I T E D S T A T E SA u s t i n

Cascade and Chinook Fields in the Gulf of Mexico

Gulf of Mexico

M I C OE X

LowerTertiaryTrend

S h e l f

D e e p w

a t e r

1, 0 0 0

f t

5, 0 0 0

f t

7, 5 0 0

f t

Cascade

Chinook

> Since its introduction in2007, the MST system hasbeen successfully deployedin 40 wells in the Eastern

Hemisphere, treating morethan 180 zones.

0 |



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 deploymentPetrobras 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

“The deployment of theMST system met ourobjectives in delivering arobust completion, while

greatly reducing thecompletion time over aconventional stacked,frac-pack system.”

Scott OgierPetrobras completion engineer

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 Hughesallowed 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.”

2 |



Lower Tertiary team dedicated to deliveringgame-changing completion systems for

ultradeepwater Gulf of MexicoBaker Hughes is adopting a cross-

functional 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 engineering-

centric 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.

“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.”

In 2009, Baker Hughes Reservoir

Development Services completed a

study that characterized the Lower

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 operationsphase, 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).

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.

“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 delivera 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).

www.bakerhughes.com



ne visit to the Baker Hughes User Lab and the notionthat oil and gas companies are stodgy places wherecreativity can’t be found goes right out the window.O

www.bakerhughes.com



> Joel Tarver demonstrates theeye-tracking equipment usedby development teams tomonitor a user’s experience,including body language.

Functionality vs. usabilityWhile 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 innovationSituated 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.”

www.bakerhughes.com



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 tohelp 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 thinkpeople 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 appfor 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.”

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.”

> Test-driven development meanssoftware is rigorously testedas it’s developed, not just forreliability, but for performance,usability, and consistency.

8 |



On average, as much as 30% of thenonproductive time on a deepwaterdrilling rig is the result of debris in

the wellbore—trash that’sleft over from drillingand completion

operations. Baker Hughesmay now have the industry’s bestintegrated system for removingit, but don’t take our word for it.World Oil magazine thinks so too.

> Joe Cottrell, a fieldoperations engineer,inspects key dimensionson the XP riser brushand boot basket.

www.bakerhughes.com



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

metal, and, if the rig crew wasn’t careful, an

occasional wrench or glove.

“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.”

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 cleanThere 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

package, especially in high-pressure/high-

temperature 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.”

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

01> The X-Treme Clean XP wellcleanup system removesdebris from the wellborethat could hinder future

operations.

02> George Krieg (left) and JoeCottrell inspect the brushstrips on the XP casing brush.

01 02

0 |



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, andsome 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 differentiatorThe X-Treme Clean XP well cleanup

system consists of a modular family

of high-performance circulation tools,

brushes, magnets, scrapers, and filters.

They can be run as an integrated

one-trip wellbore cleanup system or

separately for specific operations.

“We are particularly proud of the high-

performance, 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.”

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

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 improvecirculation 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 industry takes noteThe 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 ball-

activated 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 fieldWhen 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

X-Treme Clean XP wellbore cleanup tools

and fluid services.

“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 technicalsupport 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.

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.”

www.bakerhughes.com



Partnership with Local University Helps Prepare Malaysia’s Industry Workforce

Good Neighbors

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 oi l 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

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 providinghands-on training in real-world applications, and by promoting

the development of new products and technologies.

2 |



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, swelling-

elastomer 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.

www.bakerhughes.com



from Baker Hughes

Rhino™ bifuel pumpsThe 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 diesel-

powered 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 electricalsubmersible pumpsThe 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.

4 |



“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 andunconventional 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.

FLEX series pumps deliver superior

efficiency across the wider

operating range, lowering

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 pumpsimprove reliability by providing stable

operations in these varying conditions.

SOr™ sponge liner coring systemThe 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 materialthat 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.

www.bakerhughes.com



H. John Eastman Delivers aNew Slanton Drilling

A small but very deep, dark lake lies within a mile of a residentialneighborhood in the rapidly growing town of Conroe, Texas, a half hournorth of Houston. Although today the site is tranquil, more than 75years 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,” becameinternationally 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 cableAfter 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, whichwas 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 milesSome 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

6 |



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, buta 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 wellDesperately 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-year-

old 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 weeksof drilling, and then forced thousands of

tons of water into the well at a steam-

powered 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 successThe 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.

www.bakerhughes.com



www.bakerhughes.com

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