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Oilman Magazine Nov/Dec 2019

The State of Water 2019: How to Sustain
the Oil and Gas Industry’s Lifeblood
p. 34
A Closer Look at Remote
Operations Centers
p. 6
The Case for AI in Planning
and Forecasting
p. 20
Machine as a Service will be
the Star of Industry 4.0
p. 14
THE MAGAZINE FOR LEADERS IN AMERICAN ENERGY
November / December 2019
OilmanMagazine.com
UNCONVENTIONAL
OIL & GAS RECOVERY
Oilman Magazine / November-December 2019 / OilmanMagazine.com
1
IN THIS ISSUE
Feature
Progressive Strides in Unconventional Oil and Gas Recovery
By Sarah Skinner - pages 22–24
In Every Issue
Letter from the Publisher – page 2
OILMAN Contributors – page 2
OILMAN Online // Retweets // Social Stream – page 3
Downhole Data – page 3
OILMAN Columns
Boone’s Impact and Vision!: Mark A. Stansberry – page 9
Automation and Economy: Driving Principles of the Modern Oil and Gas Industry: Eric R. Eissler – page 16
Pipeline Technology: Data’s Role in Midstream Pipeline Segmentation: Tonae’ Hamilton – page 28
From Gemini Corporation to Gemini Fabrication: Recovery after Receivership: Tonae’ Hamilton – page 36
Most Common Oil and Gas Cybersecurity Threats: Emmanuel Sullivan – page 45
Pipelines as Critical Infrastructure: Jason Spiess – page 46
Guest Columns
Driving Offshore Growth with Satellite Communications: Morten Hansen – page 4
A Closer Look at Remote Operations Centers: John Evans and Matthew Routh – page 6
Drilling for IoT Data Insight: Michael Skurla – page 6
Four Steps to Advanced Data Science in the Oil and Gas Industry: Stuart Robertson, Nilesh Dayal,
Franco Ciulla and Amar Gujral – page 10
Five Essential Mobile Device Management Features for Oil and Gas Personnel: Anson Shiong – page 12
Machine as a Service Will Be the Star of Industry 4.0: Petteri Vainikka – page 14
What Safety Measures Should You Take for Lone Workers: John Carvalho – page 17
The Case for AI in Planning and Forecasting – page 18
Revolutionary Evaporation System Cuts Costs To $.006 Per Barrel And Protects Environment
From Particulate Contamination: Robert Ballantyne – page 20
The Plaza Group Dening and Embracing the Core Values: Lillian Espinoza-Gala – page 25
Conductor Supported Platforms: Demystifying the Industry’s Best Kept Secret: Rob Gill – page 26
Coarse Filtration: The “First Line of Defense” In Protecting Oil and Gas Processes: Del Williams – page 29
Virtual Reality is Not Just a Game, but Training: Andres Ocando – page 30
The State of Water 2019: How to Sustain the Oil and Gas Industry’s Lifeblood: Blythe Lyons,
John Tintera and Kylie Wright – page 32
Whose Milkshake is Whose?: Pennsylvania Supreme Court Considers Whether the Rule of Capture Applies
to Hydraulic Fracturing: Tony Guerino and Liz Klingensmith – page 34
Robotic Process Automation: Four Key Considerations for Oil & Gas: By Steven Bradford and Kent Landrum – page 38
Why bbl? Energy Units in the USA and Other Countries: Eugene M. Khartukov – page 40
Oilman Magazine / November-December 2019 / OilmanMagazine.com
2
Gifford Briggs
Gifford Briggs joined LOGA in 2007 working
closely with the Louisiana Legislature. After
nearly a decade serving as LOGAs Vice-
President, Gifford was named President in
2018. Briggs rst joined LOGA (formerly
LIOGA) in 1994 while attending college at
LSU. He served as the Membership Coordinator and helped
organize many rsts for LOGA, including the rst annual
meeting, Gulf Coast Prospect & Shale Expo, and board
meetings. He later moved to Atlanta to pursue a career in
restaurant management. He returned to LOGA in 2007.
Mark A. Stansberry
Mark A. Stansberry, Chairman of The
GTD Group, is an award-winning: author,
columnist, lm and music producer, radio
talk show host and 2009 Western Oklahoma
Hall of Fame inductee. Stansberry has written
ve energy-related books. He has been
active in the oil and gas industry for over 41 years having
served as CEO/President of Moore-Stansberry, Inc., and
The Oklahoma Royalty Company. He is currently serving
as Chairman of the Board of Regents of the Regional
University System of Oklahoma, Chairman Emeritus of the
Gaylord-(Boone) Pickens Museum/Oklahoma Hall of Fame
Board of Directors, Lifetime Trustee of Oklahoma Christian
University, and Board Emeritus of the Oklahoma Governor’s
International Team. He has served on several private and
public boards. He is currently Advisory Board Chairman of
IngenuitE, Inc. and Advisor of Skyline Ink.
Thomas G. Ciarlone, Jr.
Tom is a litigation partner in the Houston
ofce of Kane Russell Coleman Logan PC,
where he serves as the head of the rm’s
energy practice group. Tom is also the host of
a weekly podcast on legal news and develop-
ments in the oil-and-gas industry, available at
www.energylawroundup.com, and a video series on effective
legal writing, available at www.theartofthebrief.com.
Jason Spiess
Jason Spiess is an award winning journalist, talk
show host, publisher and executive producer.
Spiess has worked in both the radio and print
industry for over 20 years. All but three years of
his professional experience, Spiess was involved
in the overall operations of the business as a
principal partner. Spiess is a North Dakota native, Fargo North
Alumni and graduate of North Dakota State University. Spiess
moved to the oil patch in 2012 living and operating a food truck
in the parking lot of Macís Hardware. In addition to running a
food truck, Spiess hosted a daily energy lifestyle radio show from
the Rolling Stove food truck. The show was one-of-a-kind in the
Bakken oil elds with diverse guest ranging from U.S. Senator
Mike Enzi (WY) to the traveling roadside merchant selling ags
to the local high school football coach talking about this week’s
big game.
Joshua Robbins
Josh Robbins is currently the Chief Executive
Ofcer of Beachwood Marketing. He has
consulted and provided solutions for several
industries, however the majority of his consulting
solutions have been in manufacturing, energy
and oil and gas. Mr. Robbins has over 15 years
of excellent project leadership in business development and
is experienced in all aspects of oil and gas acquisitions and
divestitures. He has extensive business relationships with a
demonstrated ability to conduct executive level negotiations. He
has developed sustainable solutions, successfully marketing oil
and natural gas properties cost effectively and efciently.
Steve Burnett
Steve Burnett has been working in the oil
industry since the age of 16. He started out
working construction on a pipeline crew and
after retirement, nishes his career as a Pipeline
Safety Compliance Inspector. He has a degree in
art and watched oil and art collide in his career
to form the “Crude Oil Calendars.” He also taught in the same
two elds and believes that while technology has advanced, the
valuable people at the core of the industry and the attributes they
encompass, remain the same.
The oil and gas industry is experiencing signs of a slowdown with
reduced drilling rigs, E&P nancial distress, reduced headcount and
a pull back from investors. Industry experts agree that this is part of
a normal cycle in the course of oil and gas business. However, the
overall theme is that business activity in the industry will slow down
in Q4 and as we head into 2020.
Let’s unpack some of this gloom. From a recent Baker Hughes rig
report, the U.S. rig count fell for 7 weeks in a row from 898 down
to 855 as of this writing. A handful of exploration and production
companies led for chapter 11 bankruptcies during Q3. Some notable independent E&P
companies ling bankruptcy include Sanchez, Halcon and Alta Mesa. It has been reported that a
few could lead to liquidation and not recapitalization with creditors. The U.S. unemployment rate
fell to 3.5 percent in September and employers continued to add jobs. Although, in the oil and
gas sector, the industry shed about 5,000 jobs in Texas alone over the past three months. Finally,
numerous reports indicate that investors are nervous about investing more into shale properties
and would rather see operators control capital expenditures, produce more product and increase
cash ow.
There are positive signs out there. Overall the Permian Basin is doing well, in fact New Mexico
added ve drilling rigs in October. Much needed pipelines to drive product to market have
come online and several are due to start next year. There are also several LNG terminals in
development and renery expansions in the Gulf Coast region.
NOVEMBER DECEMBER 2019
PUBLISHER
Emmanuel Sullivan
MANAGING EDITOR
Sarah Skinner
ASSOCIATE EDITOR
Tonae’ Hamilton
FEATURES EDITOR
Eric Eissler
GRAPHIC DESIGNER
Kim Fischer
CONTRIBUTING EDITORS
Gifford Briggs
Steve Burnett
Thomas Ciarlone, Jr.
Joshua Robbins
Jason Spiess
Mark Stansberry
SALES
Diana George
To subscribe to Oilman Magazine, please
visit our website, www.oilmanmagazine.
com/subscribe. The contents of this
publication are copyright 2019 by Oilman
Magazine, LLC, with all rights restricted.
Any reproduction or use of content without
written consent of Oilman Magazine, LLC
is strictly prohibited.
All information in this publication is
gathered from sources considered to be
reliable, but the accuracy of the information
cannot be guaranteed. Oilman Magazine
reserves the right to edit all contributed
articles. Editorial content does not
necessarily reflect the opinions of the
publisher. Any advice given in editorial
content or advertisements should be
considered information only.
CHANGE OF ADDRESS
Please send address change to
Oilman Magazine
P.O. Box 771872
Houston, TX 77215
(800) 562-2340
Original cover photo by
Alexey Zaytsev – www.123RF.com
LETTER FROM THE PUBLISHER
CONTRIBUTORS — Biographies
Emmanuel Sullivan, Publisher, OILMAN Magazine
Oilman Magazine / November-December 2019 / OilmanMagazine.com
3
Week Ending November 1, 2019
DIGITAL DOWNHOLE DATA
Gulf of Mexico: 21
Last month: 22
Last year: 18
New Mexico: 108
Last month: 113
Last year: 102
Texas: 416
Last month: 414
Last year: 533
Louisiana: 56
Last month: 55
Last year: 62
Oklahoma: 51
Last month: 63
Last year: 144
U.S. Total: 822
Last month: 855
Last year: 1,067
OIL RIG COUNTS
*Source: Baker Hughes
Brent Crude: $60.39
Last month: $60.06
Last year: $71.25
WTI: $55.60
Last month: $53.60
Last year: $63.67
CRUDE OIL PRICES
*Source: U.S. Energy Information Association (EIA)
Per Barrel
Gulf of Mexico: 62,187,000
Last month: 47,641,000
Last year: 60,602,000
New Mexico: 29,019,000
Last month: 27,680,000
Last year: 22,052,000
Texas: 158,756,000
Last month: 155,719,000
Last year: 140,226,000
Louisiana: 3,844,000
Last month: 3,369,000
Last year: 4,083,000
Oklahoma: 17,438,000
Last month: 17,397,000
Last year: 17,431,000
U.S. Total: 383,317,000
Last month: 364,736,000
Last year: 352,176,000
CRUDE OIL PRODUCTION
*Source: U.S. Energy Information Association (EIA) – August 2019
Barrels Per Month
Gulf of Mexico: 85,774
Last month: 65,360
Last year: 94,309
New Mexico: 160,117
Last month: 150,181
Last year: 132,412
Texas: 777,658
Last month: 763,333
Last year: 669,265
Louisiana: 279,278
Last month: 269,052
Last year: 229,816
Oklahoma: 265,828
Last month: 269,170
Last year: 259,041
U.S. Total: 3,115,678
Last month: 3,040,996
Last year: 2,814,741
NATURAL GAS
MARKETED PRODUCTION
*Source: U.S. Energy Information Association (EIA) – August 2019
Million Cubic Feet
Per Month
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Oilman Magazine / November-December 2019 / OilmanMagazine.com
4
OILMAN COLUMN
Driving Offshore Growth with Satellite
Communications
By Morten Hansen
Digitalization in the offshore market has begun
to ramp up, with new technologies poised to
deliver substantial costs savings and improved
protability to the industry. However, these
technologies depend on the existence of robust
and reliable connectivity – a challenge for many
offshore operators, particularly as they venture
into deeper waters that are frequently out of
range of traditional terrestrial networks.
Today, satellite communications are supporting
rig and platform owners in powering an
increasingly diverse range of applications while
providing value and critical support to offshore
businesses. High-quality, low-latency connectivity
to offshore sites is enabling digital technologies
such as real-time recording of eld data, digital-
twin, remote operations, which are all accelerated
by the improved communications providing a
major impact on operational efciencies and
crew safety.
The Connectivity Revolution
Until recently, the offshore industry was limited to
the use of GEO (Geostationary) satellites for the
transmission of data to rigs and platforms at sea
that were beyond the reach of bre or microwave
networks. While GEO provides reliable and
consistent connectivity, new digital applications
leverage underlying technologies such as analytics,
mobility and the cloud – technologies that rely on
latency that is lower than GEO is able to provide.
The availability of the O3b MEO (Medium Earth
Orbit) system in 2014 was a game-changer for
the offshore industry. This constellation operates
at a lower orbit than GEO systems, providing
latencies of up to 150 milliseconds for a round
trip data transfer, compared to almost 600
milliseconds per round trip for GEO.
The high throughput capacity and low latency
of the O3b system opens the door to a range
of digital capabilities that would not have been
possible earlier, including applications such as
real-time transfer of eld data, virtual modeling
of offshore assets and wireless sensor monitoring
for better reservoir management, as well as IT
services such as desktop virtualization, remote
server access and cloud-based storage, with the
end result being improved production and lower
operating costs.
MEO-level latency and throughput enable an
improved experience for crew wishing to remain
entertained during their downtime and connected
to family and friends while offshore – a key factor
in the industry’s efforts to recruit and retain top
talent.
Being the only satellite operator to offer both
GEO and MEO high throughput capacity, SES
combines the O3b MEO system with its wide-
beam and high-throughput GEO assets to create
an even more compelling value proposition for
offshore operators, delivering network resiliency
that is particularly critical for deep-water sites
dependent on reliable connectivity.
Building the Path Forward
That high level of connectivity will become
even more critical for the offshore industry as
it adopts IoT and cloud. Sophisticated sensor
technologies mean the OT (Operational Technol-
ogy) realm is becoming increasingly connected,
feeding critical data into onshore IT systems that
previously operated as isolated business func-
tions, while cloud computing platforms allow
companies to more efciently and cost-effectively
process and analyze that data. The cloud also
enables the cost-effective extension of onshore
IT systems such as human resources, training
and logistics to offshore sites, paving the way for
safer and more efcient operations.
Cloud-optimized connectivity will be a critical
part of that transformation, including strategic
partnerships with leading cloud service
providers. For example, SES has established
these relationships, bringing the capabilities of
the major cloud platforms such as IBM Direct
and Microsoft Azure ExpressRoute to offshore
sites. Cloud services can be provisioned over
dedicated MEO or GEO links, or a combination
of the two, delivering a tailored service with the
latency, availability and coverage that is specic
to the enterprise and application requirements,
all backed by solid SLAs. The rollout of SES’s
next-generation MEO constellation, O3b
mPOWER, in 2021 will further strengthen the
ability of offshore providers to capitalize on
cloud services by delivering multi-gigabit, low-
latency connectivity ideal for high-throughput
applications and “bursty” cloud workloads.
Looking Ahead
Protability and business continuity in the oil
and gas sector will be inextricably linked to its
adaptability and the tools that make it possible.
High-speed, reliable and scalable connectivity
solutions are crucial to enable the right set of
applications that can fully digitalize operations.
The next generation of satellite technology
is essential to support the industry and open
opportunities for its expansion and growth, while
reducing complexity and risk. The demand for
real-time data is growing, and it is critical that the
offshore industry continues to keep pace, using
the surging amounts of information to the best
advantage for their individual operations.
Morten Hansen is
responsible for the energy
segment market management
of SES Networks, a provider
of global managed data
services. He holds extensive
experience in the remote communications
and information technology services
industries. He is currently leading the strategy,
development, and positioning of products,
services and solutions into the energy market
vertical, including onshore/offshore oil and
gas, resources/mining and related customer
applications.
SES is the only satellite operator to offer both
GEO and MEO high throughput capacity.
Photo courtesy of Arianespace
O3b mPOWER will further strengthen the ability of
offshore providers to capitalize on cloud services by
delivering multi-gigabit, low-latency connectivity.
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Oilman Magazine / November-December 2019 / OilmanMagazine.com
6
OILMAN COLUMN
A Closer Look at Remote Operations Centers
By John Evans and Matthew Routh
Operators go to great lengths to accurately
position wells and avoid well collisions as they
continue to search for ways to manage oileld
drilling operations effectively to maximize
performance and production, while also lowering
costs. As a result of these trends, operators and
oileld service providers (such as Gyrodata) have
introduced new drilling technologies and services
into the market that help make drilling opera-
tions more efcient. ROC (Remote Operations
Centers) in particular have become employed on
a more regular basis. These centers enable opera-
tors to apply continuous improvements in real
time to address a wide range of problems so they
can optimize drilling operations.
ROCs are multidisciplinary collaboration centers
that strive to strike a balance between having
the right people, technology and processes in
place to monitor wells in real-time from off-site
locations to maximize operational potential and
better ensure service quality. Before ROCs were
introduced into the industry, operators faced
numerous challenges when drilling in crowded
oilelds or in remote areas that had wellbore
stability and service reliability issues.
Over the past ten years, ROCs have transformed
dramatically, as their capabilities have expanded
thanks to live data feeds, powerful data analytics,
and increased computing capabilities. Drilling
and well planning engineers are able to provide
new solutions to issues that come with multi-well
pad drilling by optimizing drilling performance
and avoiding wellbore collisions through real-
time correspondence with the rigs. ROCs have
made de-manning onsite MWD (Measurement
While Drilling) services and remote monitoring
of operations possible, which has greatly reduced
the overall safety liability on a rig location. This
also allows subject matter experts to extend their
knowledge and skills across several rigs for bet-
ter performance and utilization. Streaming live
data into analytical software solutions increases
drilling efciencies by providing optimization
specialists the capabilities to make recommenda-
tions and adjust drilling parameters in real-time.
What Remote Operations Centers Entail
At ROCs, drilling engineers monitor and try
to determine what is occurring during drilling
operations to ensure well plans are appropriately
followed, risks are mitigated and challenges are
effectively handled.
The centers can achieve the following:
Reduce the likelihood of events that cause
non-productive time
Reduce costs by improving operational
efciency
Help operators gain a better understanding
of complex well sites
Utilize advancements in technology to obtain
3D visualization and improved models
Prevent wellbore collisions
Increase the effectiveness of drilling
operations
ROCs include data management, eld
communication as well as remote visualization
services. They basically serve as an extension
of a well site. Experts at the centers analyze
real-time data streams of parameters that are
measured both on surface and downhole when
drilling.
ROCs also provide KPI (Key Performance
Indicator) solutions for visualizing, benchmark-
ing and reporting. This allows operators to gain
deep insights into their operations so they can
do a better job of dening lost time and reduce
nonproductive time. Experts at ROCs are well
positioned to utilize advanced analytics and
customizable alerts to help operators predict and
prevent problematic events from occurring. With
real-time predictive road maps that the centers
offer, operators are able to optimize perfor-
mance, correlating live and historical data that
can help determine local best practices.
How Remote Operating Centers are
Contributing to the Drilling Industry’s
Transformation
Over recent years, the industry and technology
has evolved, as oil and gas companies have been
at the forefront of digital operations. ROCs are
proof of the trending digital transformation that
the industry is currently facing. Drilling processes
have become more modernized with a broader
variety of analytics being tracked and monitored.
Dynamic, real-time alerts allow operators to
make important decisions regarding their opera-
tions so they can avoid being unprepared for
challenges. This is helping to lower overall well
costs and shorten the number of drilling days.
Modern technology and equipment has given
the industry the ability to remote into equipment
and gain a better understanding of operations.
ROCs help operators escalate different issues
and communicate more effectively. These centers
are also driving more standardization in the
industry so operators can really measure their
performance. They allow operators to see how
they are performing against best practices and
indeed, local best practices.
ROCs have also helped push drilling
performance to the next level. Now the industry
is having more asset, eld and data management
in place. Data is also coming in from multiple
sources, including surface equipment, downhole
drilling equipment, manual reports as well as
asset management software. This helps drive
effective all-encompassing operations -thus
helping operators understand and execute best
practices to improve operating performance.
As new technologies continue to evolve, so do
technicians’ skill sets. Field engineers are being
utilized in remote centers – not just technicians
and mechanics out in the eld. Field engineers
have been required to learn about drilling
automation, coding, and programming. This has
changed the role of the technician. As a result,
oileld service companies that have ROCs have
been required to have training programs that
truly support the changing dynamics of the
industry. Technicians and eld engineers have
been required to become more competent and
develop new areas of expertise.
By leveraging the strengths of experts, ROCs
have caused the drilling industry to more
effectively reach oilelds’ true potential by
improving operational efciency and lowering
costs. This valuable service is saving the industry
millions while also promoting safer and more
effective drilling operations. Overall, integrated
operations at the centers is causing signicant
improvements in reserve recovery.
About Gyrodata’s Guide Center
When you rst step into Gyrodata’s ROC, the
Guide Center, you feel like you have entered a
smaller version of a NASA control room. Wall-
to-wall screens (with data displayed in a clean
An operator drilled a 9,015-foot lateral in one run by
adopting a total system approach utilizing Gyrodata’s
RSS, mud motor and MWD.
Oilman Magazine / November-December 2019 / OilmanMagazine.com
7
OILMAN COLUMN
and sharp way) gives the center a futuristic vibe.
In a shared ofce space, drilling engineers are
busy at several work stations where they carefully
evaluate data and drilling performance so they
can develop effective strategies and procedures
that will help make drilling processes more ef-
cient. Real-time models (which are vital tools for
planning a well) are constantly updated with data
from wells. At the 24/7 center (which opened in
2018), multi-disciplinary teams deliver real-time
monitoring services and support for well plan-
ning, well engineering and optimization services.
The Well Planning Operational Technical
Support group applies their expertise regarding
various types of well geometry and elds to
optimize solutions for wellbore/pad design and
well permitting. The company’s anti-collision
and real-time monitoring services provide clients
with the safest recommended path to avoid
offset wells or other potential hazards. Engineers
specically leverage their expertise in tool error
modeling to aid operators in reducing the ellipses
of uncertainty. This allows operators to safely
navigate through highly populated pads or elds
without having collisions.
Gyrodata survey management experts at the
Guide Center also utilize software solutions that
improve MWD accuracy by providing BHA
(Bottom Hole Assemble) magnetic corrections
and survey analysis, which also ensures accurate
wellbore placement.
Well engineering consultancy services help
protect drilling operations. They involve torque
and drag modeling, hydraulics modeling, critical
speed as well as BHA analysis. The center
also offers real-time optimization. Experts at
Gyrodata dene pace-setter wells with optimized
BHAs and drilling parameters for each section of
the well that serve as a roadmap for directional
drillers to follow.
Experts at the Guide Center are involved in data
acquisition, modeling, performance optimization
as well as local best practice validation. Their
workows involve managing a massive amount
of data, scenario modeling, eld target planning
as well as risk analysis. All of these factors help
them determine what exactly is going on with
a well, which also helps operators make vital
decisions regarding their drilling operations.
The Guide Center also serves as a data center,
where experts store information on how wells
perform for future reference and KPI analysis.
The data allows experts to analyze operational
parameters to identify trends, which in turn
allows them to determine techniques that
enhance drilling performance.
At the center, experts also examine groups
of customer specic wells that are in a close
proximity of each other to determine if they are
illustrating similar characteristics. Experts strive
to expand on the successes of the pacesetter
wells and focus on the limitations of the slower,
more challenging ones. This data helps them with
future planning and drilling. Previous knowledge
allows experts to create an effective road map for
operators.
Case Study
A major operator planned to drill a Wolf Camp,
A well in the Permian Basin. Experts from
Gyrodata obtained customer offset data from the
Permian Basin and reviewed it for the planned
work. Based on the expert’s historical data of
conventionally drilled wells in this formation,
they were able to apply the knowledge to select
the proper conguration for motor assisted
RSS (Rotary Steerable System) and MWD tool
selection. A directional drilling team applied the
derived road maps and parameter recommenda-
tions when drilling the entire well.
Because of what was learned from the study of
the historical data that lead to proper congura-
tions, the customer was able to successfully drill
a 9,015-foot lateral in one run with the GyroDrill
Motor assisted WellGuide RSS in 43.84 drilling
hours at an average rate of penetration of 205.8
feet/hour. Due to these measures, the operator
saved about 9 days of rig time and almost half a
million dollars in drilling costs.
Conclusion
Overall, ROCs offer modelling and drilling
performance analysis, which helps improve the
safety and quality of both ongoing and future
operations. They also offer an opportunity for
improved decision-making in the context of
real-time asset management. The centers are
improving drilling times signicantly for peak
performance while also reducing non-productive
time. They have a circular loop of obtaining and
reviewing data and utilizing it to aid effective
decision making so operators can run protable
and efcient drilling operations.
John Evans has over 30
years of experience in the
oil and gas industry. He
is the Gyrodata Product
Line Manager for rotary
steerable system (RSS) and
measurement-while-drilling (MWD) services.
John manages the technology portfolio and
operations technical support (OTS) plus
the remote operations Guide Center that
provides well planning, well engineering and
drilling optimization. Johns primary areas of
expertise include RSS, drill bits and drilling
technologies, MWD, logging-while-drilling, as
well as drilling engineering and optimization.
Matthew Routh has been
involved in the oil industry
for almost 24 years. He has
spent the last 7 years with
Gyrodata, with his most
recent role being the Guide
Center manager. Matthew graduated with
a mechanical engineering degree from the
University of Louisiana and has been involved
in several aspects of the oil industry, including
surveying, directional drilling, well planning,
well engineering, and drilling optimization.
Remote Operations CenterGuide Center - Matt Routh Working
Oilman Magazine / November-December 2019 / OilmanMagazine.com
8
OILMAN COLUMN
Drilling for IoT Data Insight
By Michael Skurla
Digital technologies have been a critical factor in
the oil and gas industry’s transformation. Beyond
transforming the industry, the integration of
“smart” technologies now has the potential
to create additional cost-savings from existing
capacity. McKinsey research conrms how
effective use of digital technologies can “reduce
capital expenditures by up to 20 percent” while
reducing operating costs “in upstream by 3 to
5 percent and by about half that in downstream.
While integrating modern technologies isn’t
a new phenomenon in the oil and gas sector,
the advent of advanced sensing devices, and
analytics from IoT and cloud services, offer
signicantly more data-driven, predictive
maintenance possibilities. Recent research by
the Swedish analyst rm Berg Insight predicted
that the installed base of wireless IoT devices
in the global oil and gas industry – at a CAGR
(Compound Annual Growth Rate) of 6.8 percent
– will reach 1.9 million units by 2023. The report
sites remote monitoring of tanks and industrial
equipment in the midstream and downstream
as the most common applications for wireless
solutions in the oil and gas industry.
With millions of physical devices connected
to the Internet - from sensors, to equipment,
to vehicles – collecting and sharing data across
the devices, the avalanche of generated data
from these devices must be captured. And the
data must be transformed into comprehensible
analytics to enable cost-effective preemptive
operations and equipment maintenance to drive
down operations cost, while increasing efciency.
With distributed mission-critical facility
operations across regions and continents, the
oil and gas operators and executives must have
holistic, real-time access and views across all
their operations to prevent unforeseen risks.
Tapping into digital technologies for advanced
IoT analytics can not only contain operational
costs, but allow for poised, data-driven business
decisions.
As the McKinsey study underscores, assuring the
most consistent up-time alone can reduce costs
by up to 27 percent while also increasing energy
efciency by as much as 10 percent.
Crude IoT Data into Rened “Smart”
Business Decisions
With IoT devices well integrated into all aspects
of the oil and gas industry operations – from
renery to pipeline monitoring to worker safety
to offshore rigging – operators have full access
and holistic views into their operations and
across all sites. For instance, sensors installed
on oil tanks can help monitor and expedite
maintenance issues before there are irreversible
problems with the tank. Likewise, sensors
on ber optic cables can help map out oil
exploration drilling sites to increase outputs
without wasting time drilling in dry areas.
But keep in mind that billions of data points
generated from these IoT devices are similar to
crude oil – they are crude data. Only when the
crude data is rened by collecting, organizing
and delivering actionable analytics can they
be valuable business intelligence tools. Only
then can operators tap into the rened data
to determine where operational tasks can be
improved – from nding exact drilling sites,
to increased productivity to ensured employee
safety and more.
Facilities and sector operators can easily use
interoperable IoT tools to empower existing
advanced technologies and systems. They don’t
need to overhaul their existing systems and sub-
systems for new IoT connectivity.
Drilling into IoT Platforms Benets
Edge IoT Platforms deployed at each site can
seamlessly integrate into existing production
and systems – without major congurations.
There’s no need to bridge custom, development,
programming, and proprietary technology. Its
seamless integration into all existing systems
quickly expedites data mining capabilities from
all operations sites across regions and continents.
Operators can start collecting data from sensing
systems to access a full portfolio of analytics
of the data that can be rened for scalable
deployment on and offshore.
With much of the oil and gas industry work
conducted in far-to-reach spots, the IoT
platforms can offer full visibility into hard-to-
reach and monitor areas. Resolving connectivity
issues – from tankers in middle of the ocean,
to workers at far-reaching oil rigs to pipelines in
the desert – allows operators to quickly detect
problems or maintenance needs. Operators can
swiftly mediate alerts and ag repairs before
anything percolates into a major risk or disaster.
The IoT platforms can expedite provisions of
appliances across various regions and distributed
sites by collecting and organizing all data. The
data can then be stored securely in a single,
comprehensive, private data collection repository
– and be easily accessible in the cloud. Once
stored, the collected and organized data can be
easily mined for analytics, UX tools and facility
management applications using either existing
in-house tooling, or through other cloud-based
tooling available from a multitude of micro-
service analytics and visualization providers.
The rened value of the data is gained with
clear, actionable analytics that can help propel
best business decision making. With real-time
views of all the IoT devices connected across all
the operational sites, oil and gas operators and
executives can gain unprecedented access to:
Gather real-time data and analytics from
Oilman Magazine / November-December 2019 / OilmanMagazine.com
9
OILMAN COLUMN
inaccessible sites – from offshore rigs
to tankers – maintaining full control of
operations and maintenance
Expedite monitoring of renery and pipeline
systems – without having “boots on the
ground” or “under the ground/oceans”
Quickly resolve problems with preemptive
measures – such as shut down or delay
work to repair malfunctioning equipment
or leaking pipes, etc. - before they erupt
into major safety risks, PR nightmares and
irreversible nancial damage
Unify separate monitoring systems, regardless
of sub-systems, to gain sustainability and
efciency by reducing costly service/repair
calls
Tap advanced analytics to help reduce
costs with predictive maintenance which
the McKinsey report sites can decrease
maintenance costs by up to 13 percent –
not to mention gaining increased energy
efciency
IoT data for improved customer service and
customer relations and marketing strategy
– by determining price-points that appeal
to customers, or efcient supply chain
management to improve “location planning
and route optimization” as sited in the
McKinsey report
Today’s IT-centric IoT ecosystem eliminates
the legacy challenges of lack of visibility and
access to valuable data from distributed sites.
Now multi-site, distributed enterprises can
quickly obtain collective monitoring without any
disruptions to the efciency of their existing
subsystems.
Managing a portfolio of IoT connected,
distributed mission-critical facilities with an IoT
platform enables data mining for actionable
analytics. Easily scalable across hundreds and
thousands of distributed portfolio locations,
the platform enables oil and gas operators to
harness rened data to establish solid data-
driven business decision advantages.
More critically, the oil and gas industry can
alleviate its top three risks – economic, political
and environmental – by utilizing the valuable
rened actionable analytics. Failing to harness
these advantages is a risk no enterprise can
afford to take in today’s volatile business world.
Michael C. Skurla is Director
of Product Strategy for
BitBox USA, which offers
a single, simple and secure
IoT platform solution
for enterprises to collect,
organize and deliver distributed data sets from
critical infrastructure with a simple-to-deploy
Edge appliance with secure cloud access.
Twenty-ve years ago, Boone Pickens sent me
a letter describing his passion for natural gas
and America’s energy future. I share with you a
portion of the letter, dated October 7, 1994:
“There is a lot of focus these days – as there
should be – on the tremendous costs facing
business and local governments as a result of
the 1990 Clean Air Act.
Many of the proposed solutions are so
ridiculous or technologically far-fetched
that they deservedly short shrift in the
environmental debate.
It seems a great public service can be done by
advocating realistic pollution alternatives and
when it comes to transportation, that solution
is natural gas and natural gas vehicles.
Natural gas is the cleanest fossil fuel in the
world, burning 80-90 percent cleaner than
gasoline at two-thirds the cost. Natural gas is
a superior fuel, with an octane rating of 130
compared to 90 or so for gasoline. It’s also an
abundant, domestic fuel that can cut federal
trade decit in half and help reclaim many
of the half-million U.S. oil and gas industry
jobs lost in the past 10 years. If 20 percent
of America’s 200 million vehicles operated
on natural gas rather than foreign oil/gasoline,
we could cut foreign crude oil imports by
50 percent.
There are other environmental benets of
natural gas besides dramatic reduction in
tailpipe emissions. It seems that the case for
natural gas is pretty clear.
The rst time my wife Nancy and I met Boone
was in Western Oklahoma at a reception.
Boone’s energy vision was shared then and
was infectious. Throughout the years, I would
follow his many initiatives including natural
gas vehicles, higher education support, tness
initiatives, his energy plan and the list goes on.
In my 2012 book,
America Needs America’s
Energy,
I quoted Boone: “We are now spending
half a trillion dollars on foreign oil, importing
62 percent of the oil we use, and we haven’t
had the leadership in DC to do anything
about it. We’ve got to move to other sources
of energy. But we’ve gotten way behind, and
will continue to pay the ddler. It’s not a good
future.” In the last seven years, Boone was
able to see a great deal of his vision of energy
independence come to fruition.
I not only followed Boone and his many
initiatives, but I took on several of his
challenges including support of natural gas, his
energy vision and higher education support...
Boone was instrumental in supporting a
documentary lm, released in 2012, of which I
was one of the producers. He not only helped
nancially support, but was interviewed in the
lm. He shared his views on natural gas and his
strong belief in America.
As I stated in my book, “Future generations
are depending on us to keep the American
dream alive.” Boone’s challenges are still at
the forefront: having passion for an effective
energy policy/plan, supporting higher
education, looking into the future with great
courage and with great vision. He could see a
better future for generations ahead. It is up to
all of us to make the difference!
Boone’s Impact and Vision!
By Mark A. Stansberry
Mark A. Stansberry
Oilman Magazine / November-December 2019 / OilmanMagazine.com
10
OILMAN COLUMNOILMAN COLUMN
Four Steps to Advanced Data Science
in the Oil and Gas Industry
By Stuart Robertson, Nilesh Dayal, Franco Ciulla and Amar Gujral
When it comes to advanced data science –
including machine learning and AI – there’s a
perception that energy is lagging behind other
industries, like retail or technology. While un-
derstandable, especially given the sheer visibility
of AI solutions like online recommendations or
ride-sharing apps, it’s also a bit unfair.
While “fail fast and fail often” is a common
mantra in the tech industry, the amount of data
and AI experimentation that energy companies
can pursue is restricted: In energy AI needs to
be deployed into highly sophisticated systems
with multiple variables at play, so trial and error
is risky.
Also, many activities within oil and gas happen
relatively infrequently, such as developing a
well or eld, so obtaining data at the required
scale – crucial for a number of algorithms, such
as deep learning – can be difcult. At the same
time, available data is often highly commercially
valuable, so there’s great incentive not to share it.
Therefore, the number of opportunities in which
AI can be applied in oil and gas may be more
limited than in other industries. However, when
AI is applied to the appropriate areas, the impact
can be considerable, even game-changing.
Oil and gas players understand the potential
of advanced data science, and the level of
investments in digital technologies reects this.
Since 2011, over $1 billion in seed and venture
funding has been raised by oil and gas startups.
In 2018, more than 35 percent of this funding
has been allocated to software, analytics and AI
products. Between 2011 and 2018, over 700 U.S.
oil and gas software patents were granted.
Frequently operating at the cutting edge of
science and engineering, the oil and gas industry
stands to benet considerably from data-driven
analytics. But to do so, there are four key areas
to optimize: good problem formulation, data
readiness, expertise availability and organizational
enablement.
Addressing the Right Problem
Not all problems can – or should – be addressed
using advanced analytical techniques. In general,
AI-driven solutions are appropriate for two
broad classes of problems: 1) complex business
decisions that hinge on predictions inferred from
data patterns and 2) automation of processes
with complex but discernible underlying patterns.
For example, GE determined that it could
improve the effectiveness of its equipment
maintenance by applying predictive algorithms
to heat loss data. By handling anomalies pro-
actively, operators can avoid unplanned, costly
downtime. However, there are certain critical
components that may not contain sensors and
cannot be monitored easily by service engineers.
In response, GE developed a heat-monitoring
smartphone app that uses an iPhone equipped
with a thermal camera to provide noninvasive
monitoring. Thermal images can then be classi-
ed as normal or irregular based on engineers’
domain knowledge, providing a labeled dataset.
This informs an image recognition algorithm,
derived through machine learning, which then
identies when equipment needs repairs.
Gathering the Right Data
AI and machine learning algorithms almost
always require signicant amounts of data,
especially since both training and testing datasets
are needed to effectively test a model. The data
must be of sufcient quality, granularity and
representative of what’s being modeled.
BP was seeking to reduce fugitive emissions
(emissions resulting from leaks or gases that
are unintentionally released during industrial
activities) that were signicant in many of its
mature elds. While engineers believed that
machine learning could be effective in reducing
fugitive emissions, they still needed to obtain the
data to develop and test appropriate models. But
outtting all their wells with sensors to gather
this data would be costly and hard to justify.
BP came up with an inexpensive way to gather
data and test their hypothesis by xing Android
phones to a selection of beam pumps and then
combining the data gathered with historical
maintenance logs and weather recordings. This
allowed them to test the algorithmic approach
and prove the business case.
Following this successful pilot, permanent
sensors were installed that were able to yield
large amounts of data on equipment telemetry
and well conditions. Armed with new data, the
algorithm now provides recommendations to
engineers, allowing them to make the necessary
changes at each of the wells to minimize fugitive
emissions.
Assembling the Right Expertise
Of course, effective application of AI requires
more analytics expertise to ensure the right tools
and technology are being implemented. But that’s
rarely enough. For the complex problems faced
by the oil and gas industry, other capabilities are
also critical to effectively close the gap between
technical skills and commercial understanding.
To optimize its energy portfolio, Exelon wanted
to accurately dispatch excess power generated
by its wind turbines, but it needed a ve-minute
forecasting capability to predict when wind
speed would change suddenly. The company was
looking for an OEM-agnostic data aggregation
and analytics solution, but didnt have all the
required capabilities and didn’t want the risk and
cost of in-house development.
So, Exelon decided to partner with GE’s
Renewables Data Science Team. Exelon provided
the team with access to a year’s worth of turbine
data to use in building and training machine
learning models for wind ramp prediction.
GE used its Predix industrial IoT software within
Exelons IT infrastructure for a purely software-
Photo courtesy of everythingpossible – www.123RF.com
Oilman Magazine / November-December 2019 / OilmanMagazine.com
11
OILMAN COLUMNOILMAN COLUMN
based machine learning solution. The result
was an increase in annual energy production of
around three percent, and reduction in operating
costs of 25 percent. The real-time forecasting
model was also applied to longer-term forecasts,
resulting in improved overall accuracy.
Ensuring the Right Organizational
Conguration
A receptive organization is key to scaling up AI
solutions. Senior leadership needs to be willing
to step up and take ownership of the process,
and facilitate overall organizational buy-in
to maximize use of the new technologies by
personal across all levels.
Rio Tinto sought to combine its in-house mining
and analytics expertise with the specialties of
various partner companies (including Komatsu,
Caterpillar and Amazon) to develop automation
solutions for use in drilling, extraction and ore
transportation.
To do this, Rio Tinto both leveraged specic
partner strengths and focused on designing
supportive organizational structures. It created a
dedicated data science unit within a centralized
innovation function to foster the spread of ideas
across business units
Rio Tinto succeeded in embedding cutting-edge
automation as a central part of operations. Since
2014, it has been growing its use of automated
haulage system trucks, which now make up about
20 percent of the eet. The trucks lowered costs
by 15 percent, and automated drills improved
productivity by 10 percent.
It’s a daunting prospect to start an advanced
analytics and machine learning initiative,
especially in an industry as complex as oil and
gas. Often, it makes most sense to think in
terms of manageable short-term efforts (such
as focusing on one or two problems of high
value to the business, running pilots rst, making
the most efcient use of data and partnering
when possible) that can be broadened into more
ambitious longer-term initiatives (like building
in-house capabilities, focusing on innovations
with tangible and immediate benets, providing
stakeholder incentives and incorporating data
analytics into core business activities).
One thing’s clear: Advanced data science
applications have a place in the oil and gas
industry, and the potential to yield tangible
benets is considerable. Innovation has always
been at the core of the oil and gas industry – and
many companies are already nding creative ways
to implement data science solutions.
Stuart Robertson is a Senior Manager in
L.E.K. Consulting’s London ofce, and leads
L.E.K.s Disruptive Analytics initiative. He has
extensive experience across both public and
private sectors, and has provided strategy and
transaction support to clients in numerous
industries.
Nilesh Dayal is a Managing Director and
Partner in L.E.K. Consulting’s Houston ofce,
and is head of the rm’s Oil & Gas practice.
He has more than 20 years of experience
advising clients on growth strategies related to
acquisitions, new business ventures, corporate
restructuring, supply chain management,
protability and operations improvement, and
more.
Franco Ciulla is a Principal in L.E.K.
Consulting’s Houston ofce. He has 25 years
of experience working in the oil and gas
industry in technical, operational, commercial
and strategic roles, with a focus on upstream
activities and oileld supply chain strategies.
Amar Gujral is a Senior Manager in L.E.K.
Consulting’s Houston ofce. He is focused on
growth and commercial strategy, M&A, and
due diligence in the energy sector.
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Oilman Magazine / November-December 2019 / OilmanMagazine.com
12
Five Essential Mobile Device Management
Features for Oil and Gas Personnel
By Anson Shiong
Challenges abound in the oil and gas industry:
from navigating unpredictable – and often
treacherous – weather conditions to maintaining
production levels and ensuring the safety and
security of staff and equipment across a range
of locations. It’s clear to see the role mission-
critical communications technology plays in the
smooth operation, safety and efciency of both
headquartered and remote worksites.
This importance is reected in the rapid
development of communications technologies.
The two-way radios and daily reports of the late
1980s have evolved into the Wi-Fi connectivity,
personal smartphone use and real-time data
transfer capabilities of today, and the benets
of such are clear – with the new technologies
allowing for remote, unmanned, and subsea
developments.
Needless to say, the oil and gas industry has
been transformed by improved communications
systems, and one such system ushering in the
next stage of communications technology and
efciency is mobile device management, or
MDM.
At a base level, MDM allows companies to
manage, control, and create security policies
on company-deployed mobile devices. But the
capabilities of MDM go much further than this;
with some solutions offering features benecial
to the oil and gas industry, like bulk, two-way le
transfer capabilities, remote control for unmanned
devices and grouping capabilities.
However, not all MDM solutions are created
equal. For oil and gas companies looking to invest
in MDM technology, the following ve features
should be considered:
Two-Way Bulk File Transfer Capabilities
One of the biggest communication challenges
in having a remote and varied workforce is the
transfer of large les and amounts of data.
Manually sending les and data, one-by-one via
email channels is time-consuming and frustrating
for personnel, and many companies can do
without incurring the cost of sending technicians
to remote worksites to install important updates.
With this in mind, the need for simple and reliable
two-way data transfer channels is obvious.
As such, companies should seek an MDM
solution with two-way, bulk le transfer
capabilities that enable staff at remote facilities
to transfer large les through a secure TLS, or
similar, encrypted channel.
Application Management
Services
Oil and gas industry-specic
applications have emerged
since the popularity boom of
smartphones, and it’s clear to
see why: they simplify certain
processes within each sector
of the oil and gas industry
while providing easy access to
information. As such, another
essential function to look
for in an MDM solution is
an Application Management
Services suite, also referred to
as an AMS suite.
An AMS suite enables
companies to create their own ‘app store,
where company-developed, process-specic
applications can be customized, branded and
remotely deployed to company devices, without
any interaction with the end-user. Companies can
also take advantage of the force install feature
which makes sure critical security updates are
installed on all devices, leaving no room for
potential exposure to security threats. They can
also use the staged rollout feature which enables
updates on only a certain percentage of devices
so that if there are any system-breaking bugs only
a portion of devices will be affected.
Remote Control for Unmanned Devices
With the rapid evolution of technology, many
processes that previously required human
interaction have been automated, such as daily
reports. However, this presents several challenges
for companies, with the maintenance of these
devices and installation of important updates
often requiring an IT technician to be on-site.
Considering the remote nature of many worksites,
this can be a costly exercise.
The right MDM solution will enable oil and gas
companies to remotely control their unmanned
devices, allowing managers to perform
maintenance and deploy important updates
through an admin console.
Device Management
With any remote device, sometimes things
will inevitably go wrong, and due to the varied
worksite locations in the oil and gas industry.
Using an MDM solution allows companies
to monitor all devices from the dashboard,
giving them a bird’s eye view of all deployment
operations. On the dashboard, you can see the
current home screen status of each device by
taking a screenshot and can see detailed device
information such as device name, network status,
battery status, CPU usage and which group the
device belongs to. The dashboard also shows the
location of the device which makes it easier to
track when moving from one place to another.
Grouping Capabilities
There is a range of employee functions within
each stream or sector, so it makes sense that
not all employees will need the same tools,
applications, information or updates. To
streamline the dissemination of information
to certain functions or groups, the right MDM
solution should offer grouping capabilities.
These capabilities enable companies to dene
devices by user and function. For example: If a
company has engineer-specic information, they
can group all engineer devices, and target their
le distribution to that group, ensuring personnel
only get the resources they need to do their job
well.
With the implementation of any new technology,
companies need to assess their own unique needs
and determine which solution is the right t. But,
following the above suggestions should empower
oil and gas companies to embrace MDM
technology and reap the benets of simplied
processes, streamlined communication, and
increased control and security.
Anson Shiong is CEO of Sand Studio, the
developer of mobile device management
(MDM) solution for Android devices,
AirDroid Business.
OILMAN COLUMN
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SUBSCRIBE TODAY!
Global cloud service revenues exceeded $175
billion in 2018, and Gartner expects them
to grow beyond $278 billion by 2021. SaaS
(Software as a service) has been the star in that
success story. It contributed more than $72
billion to 2018 global cloud service revenues,
and SaaS is projected to grow nearly 18 percent
this year to reach $85.1 billion.
Now there’s a new star on the horizon: MaaS
(Machine as a Service).
MaaS is the New SaaS
What cloud computing did to the software
industry in the 2010s, digital twins and articial
intelligence platforms are doing to heavy-asset
industries today. Although nascent, MaaS is
poised to become the star of Industry 4.0.
MaaS in the EPC and OEM (Original Equip-
ment Manufacturer) arenas is the equivalent
to SaaS in the software product business. It
implies a shift in the commercial structure of
the relationship, moving risk, prot margin and
capital expense from the customer – the equip-
ment operator – to the supplier.
The MaaS model gives suppliers an incentive to
keep machinery running rather than having it
break down, which benets the customers. In
addition, service businesses benet suppliers
because they are less cyclical and less vulnerable
to global nancial turmoil.
MaaS is Here Today, Providing Great Value
Pioneering MaaS examples by progressive
industry leaders are already bearing fruit, and
prospective fast-followers are watching closely.
For example, Caterpillar Inc. is working to
steady its boom-and-bust business cycle by
adding monitoring services to its parts and
repairs business. As Caterpillar CFO Andrew
Boneld explained, “Parts and services are
the area where we can actually reduce some
of the cyclicality.” The company had 700,000
machines connected to its cloud services in
the summer of 2018.
Caterpillar hopes to double its parts and
services revenues from 2016 to 2026,
which would bring them to $28 billion. The
company already has provided its dealers
with access to such digital tools as the Cat’s
Service Information System Parts Inventory
Optimization Tool and its Remote Flash and
Remote Troubleshoot, which provide dealer
technicians with live machine diagnostics to
remotely identify problems.
Rolls-Royce employs the TotalCare business
model for its wide-body aircraft aero engines.
Under that program, Rolls-Royce is responsible
for ensuring its engines perform to customer
requirements. More than half (52 percent) of
the company’s civil aerospace business revenue
came from services in 2017.
International engineering and services company
Kone also has embraced the MaaS model. A
third of the company’s group total revenues
now come from its maintenance business,
which also services non-Kone equipment in its
People Flow business.
Aker BP and Framo also have partnered on a
MaaS effort. The largest independent oil and
gas operator in Europe, Aker BP wanted to
create an autonomous platform that’s smart
enough to make decisions that optimize
production. So, it offered pumping company
Framo access to its live pump data for the rst
time. And Framo agreed to actively support
Aker BP in its operation and maintenance of
the pump system. This MaaS relationship has
resulted in a 30 percent reduction in mainte-
nance, 70 percent reduction in shutdowns, and
40 percent increased pump availability.
A McKinsey analysis across 30 industries indi-
cated the average earnings before interest and
taxes margin for aftermarket services was 25
percent. It’s just 10 percent for new equipment.
This Model is Poised to Change Oil and Gas
It’s difcult to predict what the oil and gas sec-
tor will look like in the next ve to 10 years. But
it seems clear that digitalization will cause some
players in this industry to rise and others to fall.
MaaS is coming of age as machine learning
matures as a discipline, making its disruptive
force twice as potent. Now asset-intensive
industries like oil and gas can use advanced data
platforms and advanced APIs to share data with
their suppliers to take advantage of MaaS.
Digital frontrunners in the oil and gas supply
chain and other machine operating industries
are examining closely what happened with
SaaS disruption and preparing to leverage the
MaaS model in a similar way. That is stimulating
discussion and steering digital strategies in
industrial board rooms around the world.
Petteri Vainikka is vice president of product
marketing at Cognite - www.cognite.com.
Machine as a Service Will Be the
Star of Industry 4.0
Why MaaS Is Shining Brightly, Positioned as the New Software as a Service
By Petteri Vainikka
Oilman Magazine / November-December 2019 / OilmanMagazine.com
14
OILMAN COLUMN
Photo courtesy of wrightstudio – www.123RF.com
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Oilman Magazine / November-December 2019 / OilmanMagazine.com
16
Automation and Economy:
Driving Principles of the Modern
Oil and Gas Industry
By Eric R. Eissler
OILMAN Magazine
had a chance to catch up
with Bill Coskey CEO of ENGlobal, a speciality
engineering services company that focuses on
oil and gas automation solutions, subsea control
systems and construction and engineering;
essentially, their lines of business cover all
three streams of the oil and gas industry:
downstream, midstream and upstream.
ENGlobal experienced some difcult times after
Bill entered retirement between 2010 and 2012.
One of the biggest changes that occurred dur-
ing Bill’s retirement period is that the industry
suffered two precipitous drops in commodity
prices and activity during the last 10 years.
Downturn and Comeback
Bill came back to take back the helm of his
company to steer it in a better direction. He
reiterated, “I returned to run ENGlobal mainly
out of concern for our people and to preserve
their jobs, and to a lesser extent, out of a great
sense of pride for
the Company I had
founded.
The company downturn
was due, in part, to
having suffered with
the implementation
of “larger company”
structure, policies and
practices. Despite the
good intentions of
this shift in size and
management, the large-
company management
changes with an added
extra overhead structure
did not produce any
signicant additional
revenue or prot. “I
also believe that the lack
cash forecasting during that time, together with
difculties we encountered with a new banking
relationship, sent us into a downward spiral and
liquidity squeeze that we eventually recovered
from,” he said. ENGlobal was able to get out of
their hard nancial position by selling off three
of their operations to pay off debt and put
some cash in the bank. This was the rst thing
they did in 2012. While a critical move to save
the business, the large sell off left ENGlobal
in a position where they became short staffed
to support the “large scale”
operations the rm ventured
into years back.
Modular-built Factories
ENGlobal’s automation
integration facility,
80,000 square-feet, is
located in Houston.
The company engineers,
designs and integrates
systems for clients’
individual requirements
that incorporates all of
the instrumentation and
electrical power functions
of an energy related facility.
The modular packaged
systems include electric
power houses, control buildings, and
on-line process analytical systems and
enclosures.
Bill describes the way
the modular units are
produced by saying
that “We have two
“factories.” One is a
10 acre mechanical
fabrication/shop
facility in Henderson,
Texas which per-
forms structural/
pipe fabrication
and welding.” He
continues, “the type of
modular systems we
produce in Henderson
will take from two
weeks to three months
to produce depending
on the complexity.
All the modules we
produce are transported to the job site over the
road and are thus ‘truckable.’” A typical module
produced by the company is 10-12 feet wide
by 40-50 feet long, made up of structural steel,
piping, vessels and other types of equipment.
Automation Key to Growth and Expansion
It has been said many times before, and it will
be said many times after, but automation is key
to the success and growth of many companies
in the modern era of information technology.
Automation provides better efciency and
improved safety. Furthermore, all facilities can
be monitored and controlled at a single location
by use of electronic control systems.
Bill went on to further illustrate the above with
an example from his company, “Facilities which
in the past were ‘manned’ are now remotely
operated. Data and alarms generated from the
local operation are continuously analyzed which
leads to greatly improved safety. The operating
data can also be used to optimize each process,
which leads to a more efcient and economical
operations.” Following these practices leads to
a signicant increase in prot and production.
Bill went on to state that going forward, “Our
mission is to more than double our revenue over
three years while keeping overhead at a constant
level. We have put the pieces of this puzzle
together and are excited about the early results
from our new strategy.”
Digital oilelds have grown in number, which,
in turn has led to an increase in investments
and productivity. Automation has proved
to be a cost saving investment for the oil
and gas industry, because it used to improve
many of the processes in the industry. In
conjunction with big data, the investment and
implementation in the oil and gas industry
has grown substantially. ENGlobal is looking
to capitalize on this opportunity to take the
company higher.
OILMAN COLUMN
Analytical Modular Building – Photo courtesy of ENGlobal
When I left the company, spending within
the energy industry was depressed and still
negatively impacted by the “great recession”
of late 2008 and early 2009. By the time I
returned, the market for our services had
slowly recovered, and this recovery lasted
until late 2014.
Unfortunately, during this recovery, our
company was mainly focused on managing
through nancial difculties and raising cash
to solve liquidity issues and thus we did not
benet to a large degree from the recovery
during the rst two plus years. Then after we
had solved some internal issues of our own
making, our industry went into the cyclical
downturn of late 2014 through 2016.
Oilman Magazine / November-December 2019 / OilmanMagazine.com
17
OILMAN COLUMN
What Safety Measures Should You
Take for Lone Workers
By John Carvalho
You hear about lone worker accidents all the
time. “Lone Worker” is not just remote oileld
or pipeline workers in the wilderness. According
to Wikipedia, a lone worker can be “an employee
who performs an activity that is carried out in
isolation from other workers without close or
direct supervision. Such staff may be exposed to
risk because there is no one to assist them and
so a risk assessment may be required...” That
denition covers many activities within the oil
industry and others.
Up in our neck of the woods in New England,
we had a few lone worker incidents that grabbed
signicant coverage. One involved a worker
who was severely injured after falling into a
large lathe at a Glastonbury, CT manufacturer
DAC Technologies. The 58-year-old man was
extricated and airlifted to Hartford Hospital by
Life Star helicopter.
Another involved a National Grid worker who
fell out of the bucket he was working in and
struck wires as he fell approximately 35 feet to
the ground.
Given these types of incidents, lone workers are
now often supported by cloud-based automated
monitoring systems and specialized monitoring
call centers - often referred to as an ARC
(Alarm Receiving Center) in the UK, or EDC
(Emergency Dispatch Center) in the U.S. In fact,
Man Down/Lone Worker detection devices have
become standard, if not a requirement, for most
work sites in the oil and other industries.
Given the gravity of this investment—cost
and what is at stake, literally people’s lives –
companies need to do their homework when
purchasing a man down/lone worker detection
device or devices.
Sure, your budget will play a large factor in
the system you purchase. Yet to make the
best investment for your dollar and provide
optimal safety for your workers, you want your
man down/lone worker devices to contain the
following features:
Man-down (no-motion) detection – If
a worker is down and not moving, optimal
response time is key. In addition to having this
feature, you want a system where you can adjust
the alarm time. Many systems will come pre-set
to 90 seconds. Different projects and clients
can have different safety requirements and you
will want a system where you can adjust the no
motion setting.
Panic alarm – As the name implies, a worker
may not always be able to verbally communicate
distress. A device with a panic alarm provides an
extra communication tool to alert the command
center of a problem.
Live cloud-hosted web software for
conguration and emergency response
management – With today’s technology,
software and rmware updates occur on a
regular basis. By having your lone worker/man
down system hosted in the cloud, you ensure
that updates to the system occur immediately
and in real-time.
Live gas detection compliance dashboard –
This feature eliminates manual data collection,
review and reporting. But most importantly it
provides a real time view on conditions.
24/7 live monitoring Safety Operations
Center – A few providers of lone worker/man
down systems will offer 24/7 live monitoring.
This is in addition to your own staff keeping a
watchful eye and ear on your lone workers. This
second set of eyes and ears provides an extra
layer of safety.
Push messaging with the live monitoring
team – Another imperative for lone workers to
be able to communicate by receiving a text for
example to “evacuate” or “check-in.
False detection – This feature enables a
lone worker to cancel a pending alert before
it is communicated to the command center
dashboard. A quick “shake” or resuming
movement returns the work-alone device to
normal operation.
Automated-prescheduled, wireless rmware
updates and device conguration changes
Whether your service is on the cloud or not,
you want to ensure your device and rmware
are current 100 percent of the time. Automated
prescheduled /Pre - Approved updates should
be included with any system you purchase.
Customizable system – Most lone worker/
man down systems come with pre-set
congurations. For many operations, the
standard settings will sufce. Yet there are
many benets to purchasing a system that is
customizable. For example, should you do
government contracts. Many of those might
require a system that has shorter no-motion
detection (e.g., 60 seconds detection rather than
90 seconds). Think of your lone worker/man
down system like an iPhone. You purchase your
phone and then in another year a new phone
comes out with a few additional features. If you
want the additional features, you must buy the
new phone. Lone worker/man down devices
come in customizable formats so that instead of
buying an entirely new system, you can simply
add onto your existing one.
Extended warranties – Your typical lone
worker/man down devices will come with a two-
year warranty. That’s standard. If you have an
opportunity to purchase an extended warranty,
you should do so. The length of the extended
warranties will vary. Our organization offers a
ve-year warranty. That will typically cover the
lifetime of the devices. Extended warranties are
an even better idea if the system you purchase is
customizable.
Man Down/Lone Worker detection systems
vary in price. For a smaller organization
requiring ve devices, you can expect to spend in
the neighborhood starting at $6,000.
You cant place a value on human life.
Unfortunately, price does play a role in the type
of system you might purchase. By doing your
homework, you can nd a system that offers
optimal protection for your workers, liability
protection, and value for your business.
John V. Carvalho, III is
the president of Apollo
Safety, Inc. Veteran-owned,
Apollo Safety specializes in
gas detection products and
services for portable and
stationary systems. For information, please
visit www.ApolloSafety.com or call 800-813-
5408.
Oilman Magazine / November-December 2019 / OilmanMagazine.com
18
OILMAN COLUMN
The Case for AI in Planning
and Forecasting
By Jack Kokko
Obtaining robust market
intelligence for a complete view of
the oil and gas industry across the
supply chain comes with its fair
share of challenges. The rise of
web search engines made access
to publicly available information
easier for companies to tap into
disparate competitive resources that
were hard to access previously. For
modern researchers and analysts,
the burden now rests on distilling
disparate public and proprietary
resources to identify consensus and
track long-term impact of emerging
trends.
One of the biggest benets of
AI is the ability to distill large
amounts of information quickly and
efciently, giving researchers a new
way to streamline insight discovery
and focus on more strategic
initiatives. NLP (Natural Language
Processing), an AI technique that
focuses on the understanding of
human language, works to add a
contextual layer, with the ability to
distinguish nuances and tonality in
differentiated verbiage – uniting
different sources that share similar
themes under a shared context or
sentiment, regardless of variations
in terminology.
Understanding Macro Trends
Developing a full understanding
of the long-term impact of
current macroeconomic trends
is a balancing act of collecting
information en masse, while
maintaining a razor-sharp edge
on the most important insights
to inform strategy. Complexity
deepens when the market landscape
takes the global stage, with different
entities using different verbiage to
discuss similar themes. How are
different stakeholders responding?
What is the tonality of companies
that face potential impact? What
is the consensus of Wall Street
analysts, and how does it vary from
other global perspectives?
For example, in September 2019,
an unexpected drone attack on
Saudi Aramco facilities raised a
urry of questions on the impact
on the price and supply of crude
oil. According to AlphaSense data,
contextual mentions of “global oil
production” spiked throughout the
week of the attack across a range
of document types – especially
within broker research, news and
company presentations.
Dissection of these different
content sets together in real-time
can lead to a greater understanding
of both the short-term and long-
term implications of the event as
a whole.
First, let’s look at regulatory data,
which is notoriously difcult to
mine when searching through
agency repositories. Further
investigation immediately reveals
a highly relevant EIA regulatory
report released on September 23
detailing an immediate production
drop at Saudi Aramco facilities to
2 million b/d in wake of the attack
– down from estimates of 6.7-9.9
million b/d of crude oil production
in August.
A later report led by the EIA
at the start of October forecasts
lower crude oil prices through the
duration of Q4 and into 2020,
despite tighter global balances in
wake of short-term loss of supply,
stating; “The tighter balances are
largely the result of unprecedented
short-lived loss of global supply
following the September 14 attacks
on crude oil production and
processing infrastructure in Saudi
Arabia.
The report also states that supply
will outpace demand into Q4,
posing questions over inventory.
Understanding and tracking these
larger regulatory forecasts can be
useful when assessing your own
planning and forecasting in light of
shifting oil prices and demand.
Analyzing broker research alongside
other content resources can help
afrm strategy in alignment with
forecasts from the Street. Broker
research is also especially valuable
when extracting data tables to build
out your own reporting. According
to AlphaSense trends data, more
than 400 broker reports discussing
global oil production were released
within the two weeks following the
attack, with a spike on September
18. Of those reports, 217 of them
mentioned Saudi Arabia. Sorting
and ltering these reports by
relevance, broker tag, and report
type can give you a more robust,
qualitative view of the issue.
Drilling in deeper, analysts can
Photo courtesy of nicoelnino – www.123RF.com
Oilman Magazine / November-December 2019 / OilmanMagazine.com
19
OILMAN COLUMN
leverage sentiment analysis to
immediately understand how other
market leaders are discussing
industry issues to help afrm their
own consensus. Sentiment analysis
leverages deep learning AI models
to identify tonality of language.
When those AI models are applied
to company documents like
earnings transcripts, analysts can
quickly identify how companies
are discussing specic trends
and how that language may have
changed over time.
When looking at all earnings
transcript mentions of “global oil
production” through 2019 (63 at
the time of the study) we found
that overall sentiment skewed
negative (38 percent overall
positive, 62 percent negative).
Total SA explicitly addressed
the Saudi Aramco attack at their
Investor’s Day conference on
September 30, saying: “It’s also a
shock for the oil markets because
obviously, it increased somewhat
the risk premium in the oil
price, and it might also force the
market to reconsider what are the
acceptable levels of inventories
and spare capacities in the world.”
This is an interesting insight from
Total SA, and could also be worth
noting when considering planning
and forecasting for changes in
demand and inventory in the event
of short-term shifts in global
supply.
Using AI for Planning and
Forecasting in Oil and Gas
The future of AI within the
Oil and Gas space is promising,
with companies already investing
heavily in AI to improve
processes, increase production,
and reduce waste (research shows
oil and gas investment in AI is
projected to reach $4.1 Billion by
2025). When it comes to corporate
planning and forecasting, AI
tools can help elevate market
intelligence by consolidating and
streamlining insight discovery, and
adding greater contextual depth
for a more complete picture of the
market landscape and the potential
short and long-term impact of
macroeconomic trends.
The ability to forecast effectively,
while still remaining nimble is
strengthened by those nuggets of
information that can provide the
greatest condence in afrming
or dissuading hypotheses in both
near-term and long-term scenario
planning. An information edge is
also obtained when these insights
are discovered early, allowing for
room to quickly and condently
execute ahead of competitors,
identify opportunities, improve
processes, or preemptively
safeguard against unfavorable
market conditions to mitigate
impact on the bottom line.
Jack Kokko is
the CEO and
founder of
AlphaSense, a
groundbreak-
ing AI-based
market intelligence search en-
gine. His mission is to leverage
AI to help businesses acquire
information more efciently,
and make better decisions
more quickly and condently.
AlphaSense is currently used
by over a thousand investment
management rms and corpo-
rations across all industries, and
has won numerous industry
awards, including “Best Analyt-
ics Product” and “Best Mobile
Solution.” Jack holds an MBA
with a major in nance from
the Wharton School of the
University of Pennsylvania. He
also holds a master’s degree in
electrical engineering from the
University of Oulu, Finland and
a bachelor’s degree in nance
from the Helsinki School of
Economics.
Oilman Magazine / November-December 2019 / OilmanMagazine.com
20
OILMAN COLUMN
Revolutionary Evaporation System Cuts
Costs To $.006 Per Barrel And Protects
Environment From Particulate
Contamination
By Robert Ballantyne
Disposing of industrial wastewater
is a problem in many industries.
Wastewater is so named because it
typically contains a high concentra-
tion of contaminants including
chemicals and particulate matter
that are beyond the capabilities of
municipal sewage systems. Mining
endeavors including all types of
fossil fuel recovery are particularly
awash in wastewater.
Oil and gas operations may produce
5 to 10 times more water than oil,
meaning millions of barrels per day
have to go somewhere.
Some water can be lightly treated
then reused for well completions
and recovery methods. Some can be
injected deep into the earth, but this
is costly and has been scientically
linked to earthquakes in some areas
of Texas, Oklahoma and elsewhere.
Evaporation of wastewater has
been another viable option for
decades, but older methods had
their own environmental issues.
Most evaporation units were simply
sprinklers or snowmakers that used
great force to stream water out
over a holding pond. The two main
problems with this method was,
rst, that the large pumps required
were power hogs, requiring 40 HP
motors and costing 20 cents per
barrel.
The other issue has been that,
once the water evaporates or when
the droplet sizes shrink below 75
microns, the particulate matter—
whose toxicity made the water a
problem in the rst place—was
launched into the surrounding
atmosphere as dry aerosol, where
it could travel for miles before
precipitating out. It has not been
uncommon to see evaporation
ponds where airborne salts have
killed nearby trees, rusted out
barbed-wire fences and caused
other problems miles away.
The most common pollutants
include salts like sodium chloride,
sodium sulfate and calcium chloride.
It is clear that the contamination
that keeps industrial waste out of
the city sewer system also prevents
the water from being evaporated
completely, in order to keep those
contaminants from being released
into the air. But evaporation does
greatly reduce the volume of water
to be injected or otherwise disposed
of. Herein lies the system’s scal
benets.
Regarding injection of this denser
water, one might ask if injecting
that into an SWD would cause
problems in the formation. RWI’s
research shows that water with TDS
levels at 160,000 ppm can indeed be
injected without harming the for-
mation into which the water goes.
Most produced water in the
Permian Basin, for example,
tests at 6,000-10,000 ppm. So,
concentrating it by approximately
No w Av A i l A b l e : T h e C r u d e l i f e Cl o T h i N g
w w w
.
s h i r T s i C l e
.
C o m
/
T h e C r u d e l i f e
2.0 units float on the surface of the evaporation pond, allowing concentrated
droplets to fall back into the water.
Oilman Magazine / November-December 2019 / OilmanMagazine.com
21
OILMAN COLUMN
ten times through the evaporation process cuts
the amount of water injected by 90 percent. This
is another layer of cost savings.
Time for a Change
The arrival of new EPA air quality rules—
specically Rule 40 CFR 51-300 in 2018—has
put older methods in danger of nes or worse.
And increasing emphasis on reducing costs
and increasing protability has caused mining
operations in particular to examine every
procedure for possible cost savings.
In 2017 Colorado-based Resource West,
Inc. (RWI) began testing 2.0 series enhanced
evaporators, a system designed completely from
the ground up with the goal of satisfying both
the economic and environmental requirements
of the industry.
RWI spent two and a half years researching and
testing 2.0 at their ve acre test site in western
Colorado. The system they released to the
public proved to be 116 percent more effective
at evaporating water, using approximately 88
percent less power while keeping droplet size
above 100 microns, which allows them to fall
back into the pond for disposal.
Instead of 20 cents per barrel, RWI 2.0 evapo-
rates water for approximately .006 cents per
barrel.
Efciency Boost
Snowmaker-based units use strong air force and
pumped large amounts of water into the air. This
method requires bulky 40 HP pumps which not
only require high levels of power, the ow they
create allows water particles to collide, greatly
reducing the evaporation rate and, therefore, the
efciency of the process. When particles collide,
some tend to break up into smaller pieces, known
as daughter particles, which oat for miles and
are the main source of airborne dry aerosol
contamination.
For RWI 2.0 the droplets are injected in the
middle of the ow, which greatly reduces
collisions. This creates a more efcient process
and helps keep particles above 100 microns by
eliminating daughter particles (see photo above).
Instead of pumps, 2.0 uses fans requiring only
5HP each, reducing power consumption by 35
HP per unit.
The 2.0 units oat on the surface of the pond,
allowing the concentrated drops to fall back into
the water.
In the Field
RWI installed its rst 2.0 commercial units in
Hobbs, NM, in retention pond holding super-
saturated drill cutting water. Because of the
regions hot climate, the water held an abnormally
dense 230,000 ppm of TDS. The purpose of
this test was to prove the unit’s ability to control
the drift of salts—a critical requirement in a
pond adjacent to a U.S. government uranium
enrichment area.
The unit passed the test successfully.
In an ongoing installation that is now starting
its third year, a mining operation in the state
of Washington installed 15 Landshark 2.0
evaporators. Power draw for these 15 units totals
56 KWH, powering 75 HP compared to the 450
KWh required for previous units using a total of
40 HP each.
The 15 Landshark 2.0 units evaporate an
average of just under 7.2 million gallons per
month, compared to the 2 million gallons being
evaporated by the previous system. And after
more than two years with these systems in place,
there has been no buildup of salts in the area
near the evaporation pond.
Uses in the Field
RWI 2.0 can be used either by large producers
who own and manage their own produced water
systems or by SWD companies looking to reduce
their costs and the amount of water they inject
downhole.
The need for alternatives to SWD is
unprecedented, as the Groundwater Protection
Council predicts that, by 2028, produced water
in the Permian Basin alone may total more
than 6 billion barrels per year, an increase of
approximately 50 percent from 2019 numbers.
Reuse by 2028 is projected to be less than 2
billion barrels per year—leaving 4 billion barrels
to be injected, if these numbers play out as
predicted.
If producers or SWD operators could reduce
this amount by 90 percent through evaporation
that would leave less than 1 billion barrels to be
injected.
Agencies such as the Texas Railroad Commission
and the U.S. Geological Survey have linked SWD
operations to earthquakes, as per the following
quote from the USGS website: “The injection of
wastewater and salt water into the subsurface can
cause earthquakes that are large enough to be felt
and may cause damage.
Safe evaporation systems such as RWI’s Series 2.0
units could be instrumental in reducing the risk
of human-induced earthquakes in the Permian
and other producing basins across the U.S.
The combination of uncertain economic times
and public pressure on the industry to improve
its environmental footprint, the oileld is
increasingly looking to innovation for solutions.
This could be an important step in that direction.
Robert Ballantyne served in the United
States Marine Corps. An electrical engineer,
his ongoing education has concentrated on
molecular and atomic spectroscopy. His
science research focuses on environmental
monitoring, mitigation, and remediation
systems design, with an emphasis on waste
stream reduction. His current role as
Director of Research and Development for
RWI Evaporation allows him to pursue raw
scientic research into ways to fundamentally
change environmental mitigation markets and
methods.
Injecting droplets into the middle of the water flow reduces droplet collisions, making a more
efficient flow and keeping particles from escaping into the ambient air.
Oilman Magazine / November-December 2019 / OilmanMagazine.com
22
FEATURE
Progressive Strides in Unconventional
Oil and Gas Recovery
By Sarah Skinner
When talking about advances in oil and gas tech-
nology, we would be remiss if we didn’t discuss
unconventional methods of oil and natural gas
recovery and the ways in which they could benet
the U.S. economy. There are always the tried and
true methods – foolproof and with little-to-no
risk. With these standard approaches, there have
been and continue to be advances that make them
more efcient and cost-effective. But it makes
you wonder, what else is out there? What other
innovations are there that could potentially revo-
lutionize the oil and gas industry and the recovery
of these vital resources? Companies, universities,
researchers, government agencies, etc. would all
benet from the exploration of alternate meth-
ods. The problem with unconventional methods
is that it’s a risky operation to research them and
without proven success, it is hard to nd backing.
The U.S. DOE (Department of Energy) has
recognized the extreme benets associated with
this kind of research and they have generously
chosen to invest approximately $30 million
dollars to boost unconventional oil and natural
gas recovery. In January 2018, they announced
the selection of six projects, selected under the
Ofce of Fossil Energy’s “Advanced Technology
Solutions for Unconventional Oil and Gas
Development” to receive the federal funding.
The eld projects that were chosen are currently
producing less than 50,000 barrels per day using
unconventional plays. According to the DOE
press release dated January 3, 2018, “The newly
selected projects will help us master oil and gas
development in these types of rising shale, along
with bolster DOE efforts to strengthen America’s
energy dominance, protect air and water
quality, position the nation as a global leader
in UOG (unconventional oil and natural gas)
resource development technologies, and ensure
the maximum value of the nation’s resource
endowment is realized.
The DOE took careful measures in selecting the
six recipients of this award. Without further ado,
they are as follows:
1. C-Crete Technologies, LLC – Hexagonal
Boron Nitride Reinforced Multifunctional
Well Cement for Extreme Conditions
2. The Institute of Gas Technology – Hydraulic
Fracture Test Site II (HFTS2)
3. Texas A&M Engineering Experiment Station
– Eagle Ford Shale Laboratory: A eld Study
A Closer Look at Remote Operations Centers  Machine as a Service will be the Star of Industry 4.0  The Case for AI in Plan...
Oilman Magazine / November-December 2019 / OilmanMagazine.com
24
FEATURE
tight gas sand reservoirs. By using the newly-
developed and comprehensive monitoring
solutions, unprecedented and comprehensive
high-quality eld data will improve scientic
knowledge of not only the hydraulic fracturing
process, but re-fracturing, and subsequent huff
and puff gas injection as an EOR method.
The Trustees of the Colorado School
of Mines (Golden, CO) & Oceanit
Laboratories, Inc. (Honolulu, HI)
Colorado School of Mines (CSM) and
Oceanit Laboratories are developing a novel
‘hydrate-phobic’ coating for deepwater well
environments that will improve safety, cost, and
component life during operations. The ability
to mitigate gas hydrate blockages in owlines
is critical to ensure the safe and economic
operation of deepwater facilities, to extend the
life of the eld, and to minimize product loss.
Prevention of hydrate blockages will mean
operating in a safer and more cost-effective
environment, as current mitigation costs can
exceed $1M per mile of pipeline.
A coating capable of repelling deposition
and preventing hydrate build-up - that can be
applied in-situ to existing owline facilities
- would represent a breakthrough over
the current state-of-the-art, mitigating the
severe production, environmental, and safety
issues that this deposition can cause during
operations, including catastrophic blowouts and
sustained leaks. CSM and Oceanit are further
testing this novel coating against the adhesion
and deposition of waxes and asphaltenes to
investigate the broader capabilities of the
coating under eld conditions, where these
solids will accumulate to cause restricted
ow problems in the owlines. This research
represents a novel, cost-effective solution to
unresolved ow assurance challenges that
would ultimately lead to major fundamental
breakthroughs in gas hydrate and related solids
engineering.
“Novel, nanocomposite-based surface
treatment technologies, such as the ones
being developed by Oceanit can have a
profound impact on the efciency, safety and
therefore environmental impact of production
operations. In bringing this technology to the
market, Oceanit is proud to partner with CSM,
who brings decades of expertise in hydrates
and ow assurance testing to the effort. The
funding support from U.S. DOE National
Energy Technology Laboratory made this
partnership and maturation of the technology
possibly. We are excited to advance a eld-
deployable solution to a very long-standing
challenge faced by the industry today.” – Dr.
Vinod Veedu, Oceanit Laboratories, Director
of Strategic Initiatives
“Gas hydrate plugs in owlines present a major
economic and safety concern to the oil and gas
industry during subsea production. The ability
to prevent hydrate deposition is using coatings
is especially critical to mitigating pipeline
blockage and ensuring safe and efcient
production. “– Dr. Carolyn Koh, Colorado
School of Mines, Director, Center for Hydrate
Research
University of Louisiana at Lafayette
(Lafayette, LA)
Tuscaloosa Marine Shale Laboratory (TMSL)
is an excellent example of collaborative effort
between the federal government (DOE, Las
Alamos National Lab), several academic
institutions (University of Louisiana at
Lafayette as the lead, University of Missouri
Science and Technology, University of
Oklahoma, and University of Southern
Mississippi) and private sector (Goodrich,
ExxonMobil, Signal, and Helis) to support
energy production and development projects.
The goal of TMSL project is to bring all
stakeholders together in a synergistic approach
to unlock signicant estimated unproved
hydrocarbon resources of Tuscaloosa Marine
Shale, as a major challenging shale play, in
economic and environmental-friendly manner.
TMSL is a multidisciplinary team of more
than 30 faculty and research assistants with
background in petroleum engineering, geology,
geophysics, and socio-economics studying the
key issues in reservoir quality and completion
quality of TMS.
The University of Louisiana, Lafayette is home
to a TMS virtual laboratory with a signicant
amount of whole cores, slabbed cores, cuttings,
and data for TMS wells. The team recently
published the results on the mineralogy and
geochemistry of 11 TMS wells at “Marine and
Petroleum Geology” journal: “Heterogeneity
of the Mineralogy and Organic Content of
the Tuscaloosa Marine Shale, Marine and
Petroleum Geology. Vol. 109, Pages 717-731”
The virtual laboratory will conduct testing
and analysis of various properties of rock and
formation uids from the TMS to determine
sources of the wellbore instability issues,
improve formation evaluation, the role of
geologic discontinuities on fracture growth and
shale creep. University of Louisiana – Lafayette
also plans to investigate the application of
stable CO2 foam and super-hydrophobic
proppants for improved reservoir stimulation,
as well as to better understand the nature of
water/hydrocarbon/CO2 ow in a clay and
organic-rich formation.
The TMS has been estimated to contain 7
billion barrels of recoverable light, sweet crude
oil, while its current total average production
is only about 3,000 barrels of oil per day. Over
the years, operators have been unsuccessful in
the TMS play, in part due to its clay-rich nature
which makes it sensitive to water. Improved
understanding of the TMS, along with public
scientic assessment of new approaches for
developing the play, will expand and accelerate
industry efforts to cultivate this resource with
minimal environmental impact.
Virginia Polytechnic Institute and State
University (Blacksburg, VA)
The Central Appalachian region is host to an
abundance of hydrocarbon resources including
coalbed methane, shale, and other unconven-
tional reservoirs. Many of these plays are verti-
cally stacked such that a single well or group of
wells in close proximity can produce simultane-
ously from multiple reservoirs. Because many
of these reservoirs produce less than 50,000
BOE (Barrels of Oil Equivalent) per day and
can thus be classied as ESUPs (Emerging
Stacked Unconventional Plays). The project is
designed to improve characterization of the
multiple emerging unconventional pay zones
that exist in the established Nora Gas Field
through the drilling and coring of a vertical
stratigraphic test well up to 15,000 feet deep.
This project will evaluate and quantify the
benets of novel completion strategies for
lateral wells in the unconventional Lower
Huron Shale. A major research objective of
the project is to characterize the geology and
potential deep pay zones for Cambrian-age
formations in Central Appalachia. A second
major research objective is to evaluate and
quantify the potential benets of novel well-
completion strategies in the emerging (and
technologically accessible) Lower Huron Shale.
The benet of this research will reduce surface
footprint, infrastructure requirements and
development costs by combining best practices,
state of the art technology and effective
outreach to carefully develop these resources.
Conclusion
The motive behind the unconventional
methods research consists primarily of three
objectives:
1. Improving understanding of the process
involved in resource development
2. Advancing technologies and engineering
practices to ensure these resources
are developed efciently with minimal
environmental impact and risk
3. Increasing the supply of U.S. oil and natural
gas resources to enhance national energy
dominance and security
The oil and gas industry is advancing by
leaps and bounds, to be progressive, the
unconventional must be explored. The DOE
assisting in these efforts is displaying their
commitment to the industry and the U.S.
economy as a whole. It will be interesting to
follow these projects and see where the end
result leads.
Oilman Magazine / November-December 2019 / OilmanMagazine.com
25
OILMAN COLUMN
The Plaza Group Defining and Embracing
the Core Values
By Lillian Espinoza-Gala
It is not unusual for a Houston Petrochemical mar-
keter to celebrate 25 years in business. But a look at
the history of the company, and the extraordinary
decisions made by a 33-year old chemical engineer-
ing executive, Randy Velarde, in 1994, is to see some
important lessons for all corporate leadership in
the 21
st
Century. Velarde began his executive level
career after graduating from University of New
Mexico with a B.S. in Chemical Engineering in
1981. Velarde’s corporate climb began with Shell Oil
Chemicals followed by an even better management
job with Texaco Chemicals ten years later.
After 15 years climbing the corporate ladder with
Shell and Texaco, Velarde learned that Texaco
would be selling its Chemical Division to Hunts-
man. Feeling stied by the bureaucracy involved in
working for two major operators, Velarde proposed
to Texaco’s corporate management that he take over
the marketing and distribution of the by-products
not included in the Huntsman sale. In 1994, he
became the exclusive distributor of the aromat-
ics that are not a valued fuel by the major reners.
Velarde found customers, such as 3M and Sherwin
Williams and Pzer Pharmaceuticals, that could use
the acetone, benzene, and butane in everything from
nail polish remover to paint thinner and medicinal
compounding.
In those nal days of completing the legal docu-
ments to create the new company, he struggled
to come up with a name. Velarde is the son of a
former long-time government worker and a stay-
at-home mother, who had a passion for genealogy,
and had traced ancestors on both sides of the
family to Spain. Since his company would be a
global petrochemical marketer, the Spanish term
“Plaza”— the square where merchandise is bought
and sold — came to mind. Thus the name, The
Plaza Group. Within two years, Velarde bought out
his initial investors and partners and remains the
only shareholder.
The rst 15 years of The Plaza Group saw
increased revenues and new customers and suppliers
annually. However, as the U.S. and other countries
recovered from the Great Recession of 2008, The
Plaza Group experienced a plateau. While other
companies borrowed money to breathe new life
into their businesses, Velarde decided to pause and
examine the organization. He instructed his board
of directors and management team to read and
study the book
Built to Last: Successful Habits
of Visionary Companies
by Jim Collins and Jerry
Porras. Velarde and his team then went on a two-
day retreat to brainstorm the fundamental building
blocks that created the foundation of The Plaza
Group. Velarde recalls the retreat as the event that
would forever set the compass and future direction
of The Plaza Group.
“This was hard work writing as a group the
ingredients in our recipe that had led to 15 years
of success and extraordinary growth. We had to
dene the organizational DNA – those fundamental
building blocks that enabled our entrepreneurial
success. We had to do a lot of soul searching,
brainstorming, and wordsmithing to nail down how
many core principles we would adopt and dene
how each one would be embraced and honored
throughout the entire organization. If you choose
too many core values, the organization simply
cannot embrace and enforce all of them.” Realizing
the world is dynamic and successful businesses must
be nimble enough to adopt quickly to unexpected
changes, Velarde says it would be important to select
values that would serve in up and down markets.
Five core values were adopted. “It’s one of those
moments when you realize what things you want
to live by — knowing at some point mistakes will
be made. We are all human and prone to make mis-
takes, but you want everyone in your organization to
understand what the corporate DNA is. It is not just
a plaque that you put on the wall.”
The Plaza Group adopted ve core values:
1. To be honest and forthcoming
2. To treat people with respect, courtesy, and
professionalism
3. To provide exceptional service to customers and
suppliers
4. To be opportunistic
5. To be nancially responsible
Velarde says the ten years following this break-
through season became a process of leading by
example. Every employee from top management
to those on the front line had to embrace each of
these ve core values in both their professional
and personal lives. Velarde says in our litigious
U.S. corporate world one sign the organization has
succeeded in adopting the ve core values is the
fact The Plaza Group has never had to deal with a
lawsuit.
Velarde likes to recount an example when a
Plaza Group employee discovered a supplier had
undercharged by $100,000. In business transactions
that amount to millions each year, some companies
might have let this mistake pass, but it was brought
to the attention of the supplier and corrected.
This proved to be a trust building experience in
the relationship between The Plaza Group and the
supplier AND with The Plaza Group employees.
Everyone witnessed the true meaning of core value
number one — being honest and forthcoming.
Velarde says feedback is critical in order to take the
pulse of the entire organization. He created a Core
Value Team that meets with him every 60 to 75
days to share with him both positive and negative
feedback. Velarde wants to know where mistakes are
made and feels that it is important to know if they
are simply human error or a violation. He believes
it is important to be compassionate when mistakes
are made, but it is critical to spot a trend when
standard operating procedures begin wandering
from the ve core values. Velarde says, “If you spot
a negative trend, it is critical to nip it in the bud in
order to prevent bad seeds from growing within the
organization.”
Within last three years, The Plaza Group has
acquired Dallas-based Conchemicals and the
Woodland-based Truth Fuels. Being a minority-
owned business has given The Plaza Group a great
advantage with the Truth Fuel Group, which pro-
vides fuel for small generators to cities and special
events, as often cities or non-prots or NOGs want
to do business with a minority-owned company.
Velarde’s two sons have joined The Plaza Group
within the last ve years and brought forward the
principles for work-life balance. Velarde says he
realizes that may be one of the shortcomings of
his generation and that this younger generation
helps balance the organization in attracting young
professionals and allows him to focus on mentoring
the next generation.
As 2020 approaches, Velarde says he is excited about
new challenges in nding solutions for climate
change and creating a healthier environment in the
petrochemical industry for the benet of everyone
on the planet. As someone who loves to sh, he is
passionate about helping foster good stewardship
of land and water resources.
Listening to Velarde share his extraordinary journey
from a Shell/Texaco corporate executive leader
to striking out to build a niche business proves
that, while Velarde began his career as an ordinary
chemical engineer, he adopted an extraordinary
vision for his organization and has prepared The
Plaza Group to be uniquely positioned for the next
season of the 21
st
Century.
Randy Velarde and sons: Vincent and Garrett – Photos courtesy of The Plaza Group
Oilman Magazine / November-December 2019 / OilmanMagazine.com
26
OILMAN COLUMN
Conductor Supported Platforms:
Demystifying the Industrys Best Kept Secret
By Rob Gill
For the eld development engineer striving to
deliver the most cost-effective concept design
for a shallow water development, there are
a variety of possible routes to take. Maybe a
subsea tieback would provide the most protable
solution, or perhaps a jacket supported wellhead
platform? Maybe separate offshore processing is
worth considering?
One option that is all too often overlooked
though, and that can substantially reduce the
capital cost of a development, is the conductor
supported platform (CSP). Frequently this boils
down to a simple lack of familiarity. Other
times, some persistent misconceptions lead eld
development planners to quickly write-off a CSP
as a viable option.
In fact, a CSP can be an extremely cost-
effective option - one that can accelerate time to
production and which is suitable for a far wider
range of conditions than commonly assumed.
In some marginal cases, a CSP could even be
the difference between a viable and non-viable
project. So, perhaps it’s time to demystify the
sector’s best kept secret?
The Power of CSPs
Firstly, what is a conductor-supported platform?
Simply put, it’s a more exible and cost-effective
alternative to a traditional jacketed structure. A
CSP provides all the dry tree functionality of a
jacket supported platform, with the difference
being that the well conductors themselves are
used as the structural and foundation support for
the topsides.
So why are they worth considering?
The use of a CSP can drastically reduce
installation costs. Modular design means it is
possible to fully install a CSP using a jack-up
drilling rig, rather than having to rely on a
heavy-lift crane barge, which will inevitably be
accompanied by notoriously high mobilization
costs. It is highly likely that a jack-up will already
be onsite to drill the wells themselves, so it makes
sense to simply keep the rig for slightly longer
to install the structure too. Assuming a daily
cost of $150,000 per day, an extra week with the
rig would cost around $1 million. Contrast that
with a traditional jacketed supported platform,
which would require a heavy-lift crane barge
for installation. In many parts of the world, the
mobilization costs alone for a crane barge could
run into tens of millions of dollars, meaning
that seven or eight gure savings from this point
alone quickly become achievable.
Because it also uses the conductors for support,
a CSP is a much lighter structure, requiring less
steel and representing a lower material cost than
a comparable jacket supported platform. Though
the conductors themselves may need to be over
specied in comparison, it is important to bear
in mind that a budget price quotation for a CSP
will include the conductor cost. By contrast, the
cost of the conductors will generally be excluded
from a budget price quote for a comparable
jacket supported platform and will instead be
hidden within the drilling cost estimate.
The simpler design of a CSP also enables a more
exible approach to fabrication. With an almost
modular design, it is not necessary to fabricate
one single huge structure in a large fabrication
yard. Instead, the job can be split between
smaller fabrication yards, with more competitive
pricing. This can also be a great benet for
projects with strict local content rules, offering
the exibility to designate some sections to local
yards, which may not always have the ability or
experience to fabricate large structures.
Finally, CSPs also offer exibility with regards
to early production and helping to realize
project returns faster. It is possible to install the
conductors and subsea support structure and
then begin drilling right away, without waiting for
the topside to be installed. If the topside is not
expected for another couple of months, this can
signicantly accelerate time to production and
the critical path to reaching rst oil or gas.
Myth Busting CSPs
So with a lower capital cost and so many other
advantages, why don’t CSPs feature more
prominently as an option for shallow water eld
developments? Perhaps, they’re dismissed due to
Oilman Magazine / November-December 2019 / OilmanMagazine.com
27
OILMAN COLUMN
some persistent misconceptions that surround
conductor-supported designs and the types of
developments they would be suited to?
Myth 1: CSPs are only suitable for shallow,
benign ocean conditions
It’s true that CSPs are not a deep-water
technology – they are suitable for water depths
of up to 100m and excel in depths up to 65m.
It is also true that many of the CSPs deployed
today are in locations with relatively mild met
ocean conditions, such as the Gulf of Thailand,
West Africa and the Middle East.
It doesnt follow however, that CSPs are only
suitable for the most easy-going met ocean
conditions. There is an idea that: “yes, CSPs
may be great for the Gulf of Thailand, but they
wouldn’t stand up to the kind of storms you see
in more challenging environments.”
Actually, CSPs are capable of withstanding the
most extreme storm or seismic events. The
governing design criteria for a CSP structure is
generally its fatigue life, with the design focus
being on the structural stress caused by constant
wave action. If a CSP has been designed
properly for fatigue, then it will always be able to
withstand the most severe conditions.
Myth 2: Boat collision regulations preclude
CSPs
Rules vary from location to location, but many
take a blanket approach of taking perceived best
practice from one scenario and applying it across
the board.
For example, BS EN ISO 19902 structural design
standards require that platforms be designed with
reasonably foreseeable collision events in mind.
A specic energy impact value is not stated,
but 14MJ has traditionally been accepted. This
represents a signicant event, with a 5000-tonne
vessel drifting at a speed of 2 m/s (4 knots), in a
sea-state with wave heights of 4m.
How likely however is that scenario in most
instances? For a CSP installation, a typical supply
vessel might be only 100 tonnes, and is more
likely to be approaching at 0.5 m/s than 2 m/s.
The key is to focus on “reasonably foreseeable
collision events,” and take a risk and evidence-
based approach to deciding what they are, rather
than relying on blunt received wisdom.
Sharing the Secret
CSPs are well-known to too few eld
development planning engineers, and well-
understood by even fewer. In a sense, they
are the industry’s best kept secret. Engineers
looking for a dry tree solution for a shallow
water development should nd CSPs, such as
Aquaterra Energy’s Sea Swift platform, to be a
viable and attractive option. CSPs are capable
of reducing capital expenditure, accelerating
time to rst production and even helping with
sometimes-tricky local content rules.
Perhaps it’s time the secret got out?
As a member of Aquaterra
Energy’s Management
Board, Rob is responsible
for growing the company’s
platforms and offshore
structures business. Before
joining Aquaterra Energy, Rob has held
positions within Granherne, Petrofac and
Worley where he was responsible for the
early stage development of major projects
within the upstream oil and petrochemicals
businesses. This has included the conceptual
and early phase engineering design of
new upstream developments as well as the
initiation of new products and services and
several innovative nancing schemes.
Oilman Magazine / November-December 2019 / OilmanMagazine.com
28
OILMAN COLUMN
Pipeline Technology: Datas Role in
Midstream Pipeline Segmentation
By Tonae’ Hamilton
In recent years, the role of technology has
become more signicant in midstream and
downstream operations. With the increased use
of technology in the oil and gas industry, oil
producers and service providers have been able
to improve the efciency of their operations and
maximize prots. Now with data and automation
on the rise, the midstream market is bound to
undergo a major transformation.
A large number of oil and gas processing
facilities are demanding more data collection and
automation programming be put in place as a
way to maximize output, reduce plant downtime,
and increase their ROI. By increasing the use of
data and analytics in midstream operations, oil
and gas companies have the ability to observe
and determine the efciency of their pipelines,
solve problems and improve processes, and plan
more strategically to improve their business.
As a result, many oil and gas operators and
oil and gas solution companies are partnering
with or acquiring pipeline data and analytics
companies to enhance operations or better their
services. Rapidly growing provider of energy
data analytics and advisory services, LawIQ,
is one of the companies that has taken the
initiative to acquire leading liquids pipeline rate
and tariff data company, Lens On Washington.
As expressed by Craig Heilman, LawIQ’s Chief
Operating Ofcer, the purpose of the acquisition
is to expand their widely used natural gas and
liqueed natural gas analytics platform, and
extend their customer base into the oil pipeline
and exploration and production market.
With the oil and gas industry experiencing an
increased demand to improve and ramp up
production, operators need feasible ways of
obtaining and utilizing data to respond to such
demand. Thus the assistance of oil and gas data
and solution companies is crucial. Aware of the
competitiveness within the oil and gas transporta-
tion market, LawIQ acquired the LawIQ Liquids
Database (formerly Lens On Washington) to
extend and build on their data and analytics
covering oil and other liquids products’ pipelines
and improve access to valuable insights buried in
tariffs and other lings. “Our customers need to
know the details of origin and destination points
and rates, so that they can position themselves
effectively and protably,” stated Heilman. Their
database, which has over 30 years of data, was
meticulously aggregated and structured into an
indispensable resource for customers.
In addition, the ability to monitor pipelines in
midstream operations has become a crucial
need for oil and
gas operators. By
monitoring pipelines,
operators can determine
the effectiveness of
their pipelines (i.e.,
which segments of
the pipeline are useful,
pipeline errors),
predict outcomes
and prevent future
risks, and plan better
business practices. In
addition to combining
data, technology, and
expertise for customers to better anticipate events
impacting their growth, LawIQ is one of the
companies aiding operators in acquiring pipeline
and infrastructure data to improve business
operations, with their acquisition of Lens on
Washington. “Our analytics platforms, research
content, and advisory services help customers
model and assess their risks and opportunities
and serve as a foundation for teams across their
enterprises to better understand regulatory, and
market dynamics from origination to ongoing
operations,” Heilman expressed.
Although operational efciency is a key reason
for the increased need for data, another
signicant factor for operators seeking the use
of data and analytics is revenue. LawIQ focuses
on how data and technology can be used on the
commercial side of the business for companies
that own or develop energy infrastructure.
“In our case, we leverage technology to help
customers predicting regulatory timelines and
costs that drive ROI and optimal infrastructure
capacity” stated Heilman. With the use of data
and analytics, operators would also have the
ability to predict project and production costs
and therefore, gain the advantage of thoughtfully
planning out budgets and creating methods to
reduce such costs.
Though many operators expect to maximize ROI
with the utilization of data and analytics to en-
hance production, there are still issues that need
to be addressed concerning production and pipe-
line capacity. As Heilman explained, “Growth in
production will never match takeaway. There is
always a period of falling prices followed by an
increase when pipeline capacity comes online,
then another drop with additional capacity.
Supply and demand imbalances and periods
of price volatility and instability are persistent
across basins.” With a lack of infrastructure to
get more of the production to market, basins will
be left congested and supply and demand could
be impacted, along with revenue and cost of
operations.
Nevertheless, the oil and gas industry can still
expect to see a rise in data and analytics with
many operators investing in the solutions of data
companies to improve pipeline operations and
segmentation and discover potential business
opportunities. “Teams use our platforms to
baseline assumptions and data sets, benchmark
projects, and identify commercial opportunities,
Heilman shared. In addition, the oil and gas solu-
tion and software sub-industry has also become
a competitive market, with an increased number
of solutions companies seeking to improve the
business practices and strategies of oil and gas
facilities and the operations of the oil and gas
industry overall through data and software. “We
will always be looking for ways to grow our offer-
ing of analytics platforms, research content, and
advisory services,” stated Heilman.
Data and analytics and pipeline technology
overall has been in popular demand for the oil
and gas industry in recent years. With many oil
and gas operators in North America looking
to monitor the efciency of their pipelines,
improve midstream operations, and expand
their prot and company growth, oil and gas
data and solution providers are being invested
in to help achieve such goals. Ultimately, as the
industry undergoes a signicant technological
transformation on the domestic front, such
transformation is expected to happen on a global
level. Heilman expressed that LawIQ would
welcome the opportunity to work with global
companies. “As we continue to grow our exports,
we expect to assist companies outside of North
America that have opportunities and exposure
to North American infrastructure capacity and
performance,” stated Heilman.
Photo courtesy of Iurii Kovalenko – www.123RF.com
Oilman Magazine / November-December 2019 / OilmanMagazine.com
29
OILMAN COLUMN
Coarse Filtration: The “First Line of Defense”
In Protecting Oil and Gas Processes
Multi-element, automatic self-cleaning strainers optimize upstream and
downstream production, while minimizing maintenance and downtime
By Del Williams
For the oil and gas industry, coarse ltration
of various uids is critical to ensure reliable
production, extend the life of a wide variety of
upstream and downstream equipment, and increase
the intervals between backwashing or necessary
maintenance.
Upstream, production wells often use coarse
ltration (from 30-100 microns) to remove
sand, solids, or debris during secondary phase
waterooding, where clean ltered water is
introduced into a rock layer through injection wells
to push residual oil to operating wells.
Deep water rigs may prelter seawater to remove
solids before further ltration for uses ranging
from enhanced oil recovery, to heat exchangers, to
producing potable water.
Upstream, when oil is produced, liquid separation
is used to separate produced water from the
oil. Coarse ltration may be needed during the
produced water treatment.
In downstream applications coarse ltration may
be 125-3200 microns. Reneries often prelter raw
water from lakes, rivers, and aquifers to remove
organic, aquatic, and other solids, which allows
fresh water to be used as process and cooling water.
In cooling towers, ltration can improve cooling
efciency while reducing fouling and plugging.
In process equipment, the removal of suspended
scale and debris from heat exchangers and cooling
systems can prevent the clogging of equipment and
nozzles.
“Without adequate coarse ltering of process
uids, oil and gas systems can be susceptible to
expensive damage from large particulates,” says
Glenn Mountain, General Manager at R.P. Adams,
a Buffalo, NY-based manufacturer of industrial
ltration equipment. “Raw or produced water that
is not adequately pre-ltered can cause excessive
fouling, leading to decreased production as well
as costly, premature replacement and unscheduled
production downtime.”
Fortunately, a growing number of oil and gas indus-
try professionals are ensuring more reliable produc-
tion with superior water or process uid quality by
using low maintenance, multi-element, automatic
self-cleaning strainers. This approach provides a
more effective rst line of defense against equip-
ment damage and downtime.
Optimizing Process Reliability and Production
Historically, the oil and gas industry has utilized
certain types of sand or media lters, centrifugal
separators, and basket type strainers for coarse
ltration. However, in many cases these have a
number of shortcomings, including susceptibility
to fouling and damage, which can require frequent
cleaning, maintenance, and early replacement.
“Whether for upstream or downstream processes,
the industry wants to keep production going 24/7,
says Mountain. “So, the goal is to avoid equipment
damage, process interruption, and having to pay
maintenance technicians to open up lters for
cleaning when they get dirty.”
In response, many oil and gas industry professionals
now rely on multi-element, automatic self-cleaning
strainers like those from R. P. Adams. The company
rst introduced and patented the technology in the
1960s, and has over 10,000 installations worldwide
today.
This design provides an alternative to sand and
media lters, centrifugal separators, and basket type
strainers. Unlike those designs, the multi-element,
automatic self-cleaning strainers can provide
continuous removal of suspended solids. When
utilized as the “rst line of defense” for oil and gas
water or uid ltration, the strainers can reliably
lter out sand, silt, and other suspended solids as
small as 30-100 microns in size.
A signicant feature of the multi-element design
is in the engineering of the backwash mechanism,
which enhances reliability. With many traditional
strainers, the backwash mechanism comes into
direct contact with the straining media. This can
be problematic, as large, suspended solids often
encountered with raw or produced water can
become lodged between the straining media and
the backwash assembly. The result is straining
media damage and/or rupture that can compromise
ltration and even other downstream equipment,
hindering production. Instead, the multi-element
design utilizes a tube sheet to separate the straining
media from the backwash mechanism. This
prevents the backwash mechanism from coming
into contact with the media and damaging the
elements.
Oil and gas industry operators often also need to
consider how to best reduce membrane fouling and
required maintenance. Traditional strainers, howev-
er, due to limitations in straining
area can become clogged quickly.
When that occurs, cleaning,
media replacement or backwash-
ing is necessary, which adversely
affects productivity as well as
maintenance costs. In this regard,
the multi-element design provides
three to four times the surface
area of traditional strainers and
pre-lters. This translates directly
into less frequent backwashing so
less water goes to waste, less power is consumed,
and less maintenance is required.
While traditional media found in large basket
designs can lead to collapse and failure under
differential pressures as low as 35 PSID, the smaller
diameter of the media used in the multi-tube
strainers also enables the strainer to safely handle
differential pressures in excess of 150 PSIG. This
protects production even under higher differential
pressures in the eld, which could otherwise result
in signicant downtime.
As an additional protective measure, the strainers
also include a shear key, which sacrices itself in the
presence of excessively large debris. So, if large de-
bris were to cause mechanical problems within the
strainer, the shear key breaks, protecting the unit’s
rotating assembly, motor, and gearbox by halting the
drive shaft rotation. Filtration continues, but opera-
tors notice an increase in differential pressure as the
backwash cycle is interrupted, and can take action to
clear the obstruction and replace the shear key.
For oil and gas environments exposed to highly
corrosive elements like seawater or salt spray,
upgrade options to materials such as super duplex
and duplex stainless steels, titanium, Monel, Inconel,
and Hastelloy can also provide further resistance to
corrosion and corrosion-related damage.
When considering technology for oil and gas course
ltration systems, automatic multi-element, self-
cleaning lters are an increasingly popular choice
and a reliable, cost effective solution.
Del Williams is a technical
writer based in Torrance,
California. He writes about
health, business, technology,
and educational issues, and has
an M.A. in English from C.S.U.
Dominguez Hills.
Oilman Magazine / November-December 2019 / OilmanMagazine.com
30
OILMAN COLUMN
Virtual Reality is Not Just a Game,
but Training
By Andres Ocando
With the passage of time, it is increasingly
difcult to get trained personnel for the oil
industry. The experience as a crane operator,
drilling rig, welder, drilling oor engineer
among others, will only be achieved with time,
and practical knowledge is only acquired with
practice.
Worldwide companies use millions of dollars
for the training of personnel in these areas,
and they still have the risk of some problem
when using the equipment they were trained
for. This is why it can be highly difcult to nd
experienced professionals in practical operations
such as equipment management in the oil
industry.
Faced with this need, the virtual reality industry
offers a solution to the oileld. By bringing
together design professionals, architects,
mechanical engineers, petroleum engineers and
(as a key piece) engineers of the disciplines
related to the computational area, such as
computer, systems and virtual design engineers.
With the aforementioned ingredients, we expect
as a result a functional response to the need for
practical staff training, and it has not been fully
achieved, but there has been a growing process.
Every time, more companies are venturing
with these types of tasks and more and more
operations are simulated for learning every day.
When this type of service is hired, specialists in
the area to be trained are mixed together with
the virtual reality technology, which emulates
the operating controls of the drill (if this is the
type of operation to be learned), then every
training provides practical and theoretical
knowledge by specialists. This undoubtedly
translates into less preparation hours and better
results regarding staff learning.
The investment when training staff with this
type of tool represents a greater amount than
the one that’s usually put in professional training
with specialists in the area, but the risk of losses
due to errors of non-experienced professionals
is even greater.
What is This Learning Based On?
With replicas of the original controls to operate
drills or cranes in some cases during teaching,
the difculties that the operator can face could
be modied, from environmental conditions
to the occurrence of blowouts or accidents. It
implies going further.
By understanding that there are different types
of learning, experienced professionals are used
in the training areas, together with the virtual
reality simulator. In this way kinesthetic, visual,
auditory and reading learning are covered all at
the same time.
Nowadays, there is a signicant amount of
companies that are dedicated to this training
modality, but some dare to innovate a bit
further.
The Optimax MLA Simulator created by
Castillo Max, a Venezuelan company, is a virtual
reality system that allows the training of Marine
Cargo Arms operators. With the use of this
simulator, the transition from theory to practice
in the handling of Load Arms by operators is
facilitated.
This mechanism gets to simulate different
environmental conditions as well as different
operating protocols, operational emergencies or
extraordinary situations; and most important,
the arm control scheme, as it includes original
handlers of this type of equipment to recreate
an experience as close to reality as possible.
The position of marine cargo arms operator
is a dangerous work and calls for a high
responsibility, not only the component’s
integrity is put in danger, but also human lives,
like the diver in the bottom of the sea.
On the other hand, we have the Luminous
Company from the United Kingdom, which
uses laser technology to copy scenarios, that
is, with the structures scanning, you can create
an exact copy of the location so the public
can learn from the processes in the same place
where they will be working.
Despite not having controls schemes that are
normally used in the oil and gas industry, this
system allows the personnel training in the most
important eld: safety. Using a 3D scenario
with virtual reality in real time, it shows workers
the structures to be occupied in their day-to-
day labor, with the use of casual examples
such as putting out the re, picking up tools
on the oor or a check list to achieve the basic
instruments of protection.
Luminous offers to companies the ability
to train people with real structures, either
offshore or on land by changing environmental
conditions or by varying the possible problems
that the worker may face.
Unigine is the Russian company pioneer in the
use of virtual reality for personnel training,
although it moves a little away from the drilling
oors, it focuses on one of the sectors with the
most exposure to danger the industry has: the
reneries.
In the past, accidents registered in reneries
were due to lack or neglect of maintenance
tasks. This is why Unigine has an Interactive
Maintenance Training program that uses
detailed virtual scenarios in which the apprentice
can do several things, from moving into the
premises to doing maintenance work to a power
box, in order to start a process cooling pump,
Optimax MLA Simulator – Photo courtesy of CastilloMax Oil and Gas
Oilman Magazine / November-December 2019 / OilmanMagazine.com
31
OILMAN COLUMN
and thus avoiding an accident in the future.
In the reneries arduous search for qualied
and attentive personnel, Unigine shows great
progress, despite not having extreme emergency
situations, as could happen in some cases, it
gets very close to what is necessary for the
development of common activities in a rening
plant operator’s day.
Q-bit Technologies, located in Palo Alto,
CA, represents one of the most important
presences in VR training for the oil industry,
because it covers areas such as lifting, on
land and offshore drilling, renery, and the
implementation of virtual classrooms.
They use the internet to provide theoretical
training in virtual classrooms, and practice
sessions in real time from anywhere in the
world.
And We Wonder, Why Virtual Classrooms?
Well, in this line you have the duality of sharing
classrooms with other people from other
countries with rich experiences. At the same
time, you can carry out drilling practices with
people worldwide, who occupy different roles
on the drilling oor or in reneries, depending
on the chosen type of training. In this way,
they could not only save time, but also money,
since only the VR equipment and an internet
connection are needed.
Among the qualities of Q-bit are:
Industrial Machinery and Procedures VR
training
Risk and Safety VR Training
Oil and Gas, Drilling and Renery
Simulators, Oil & Gas VR Training
Hospital and Emergency Care Procedures
VR Training
Soft Skill and Management VR Training
Collaborative VR Workshops and Virtual
Reality Classrooms
Collaborative VR Training Environments
Virtual Reality Collaborative Training
Simulations
After analyzing the different advances in VR
technology for the oil industry, it shows that
there is a long way to go. Although the demand
is high, what the oil and gas industry looks for
every day is highly trained personnel, which can
be reliable for different practical activities such
as drill, cranes and marine arms manipulation,
or renery processes to name a few.
The pending subject of this training modality
would focus on the actual equipment controls
and on being able to simulate experienced
situations in order to prepare their staff, not
only to face the ideal scenario, but also the most
difcult tasks, such as a pressure increase during
drilling, as an example.
It is expected that one day VR simulators can
train a diver and a sub-marine arm operator
in real time, by using the North Sea waters as
a scenario, among other activities. Apparently,
that day is nearer that we think.
Therefore, it is not an easy task for VR
engineers joined with the oil and gas specialists,
but in terms of security, the sum invested in
training and safety is usually not restricted in
the oil companies. For this reason, the VR
appears as an option with more and more
importance.
Andres Ocando is a petro-
leum engineer who gradu-
ated from Santiago Mariño
University in Venezuela.
His geomechanical-oriented
thesis received an honorable
academic mention. He currently has 4 years
of experience working as a geomechanical
and reservoir engineer at PDVSA.
Unigine VR Refinery Model – Photo courtesy of Unigine Qbit VR Drilling Platform Training Situations and Qbit VR Training – Photos courtesy of Qbit Technologies
Luminous 3D Laser Scan – Photos courtesy of Luminous
Oilman Magazine / November-December 2019 / OilmanMagazine.com
32
OILMAN COLUMN
The State of Water 2019: How to Sustain
the Oil and Gas Industrys Lifeblood
By Blythe Lyons, John Tintera and Kylie Wright
Led by unconventional play development, the
U.S. is closer than ever to energy independence.
Texas plays a leading role in the current U.S.
oil and gas boom. Yet Texas has a two-fold
challenge born of this success: The state must
source huge amounts of water for fracturing
operations, often in arid, drought-prone areas.
At the same time, it must manage billions of
gallons of produced water from these onshore
unconventional operations.
To maintain its oil and gas production
capabilities, Texas must continue to make its
signature strides in management of produced
water and expand recycling and reuse
opportunities. To this end, the Texas Alliance
of Energy Producers (the Alliance) and the
IPAA (Independent Petroleum Association of
America) teamed up to publish the white paper:
“Sustainable Produced Water Policy, Regulatory
Framework, and Management in the Texas Oil
and Gas Industry: 2019 and Beyond.
The paper is a sequel to one we wrote in July
2014, “Sustainable Water Management in
the Texas Oil and Gas Industry,” which was
published by the Atlantic Council. The following
factors drove our decision to update that paper:
Data points to exponential increases in the
amount of produced water that the industry
will generate over the next ve years. In the
Permian Basin alone, produced water output
will reach a level of 8.5 billion barrels of
water by 2024. (See Table)
Table: Produced Water Projections
to 2024 for the Permian Basin
Year MMbbl/year
2019 7,090
2020 7,400
2021 7,670
2022 7,990
2023 8,240
2024 8,510
Source: B3 Insight, 2019
Texas has done many things right –
including legislative and regulatory actions
– to encourage safe and economic produced
water reuse and recycling options. However,
more remains to be done at both the state
and federal levels.
Produced water recycle and reuse is likely to
increase as the midstream water management
industry continues to mature, demand for
fracturing water grows, freshwater and
trucking costs increase, treatment costs
decline, and injection capacity is constrained.
Current and emerging treatment
technologies can support cost-effective
recycle and reuse in the oil and gas industry.
However, no silver bullet technology exists
that would replace the need to maintain
disposal capacity. We report on factors that
impact the costs of and availability to access
saltwater disposal wells going forward.
Published on September 16, the white paper
outlines 10 recommendations to encourage the
economical and sustainable recycling and reuse
of produced water. We hope this can serve as
a model for other states. The report centers
around three guiding principles related to state
and federal policy and regulation:
1. Texas must maintain leadership and control
over produced water management;
2. Texas must continue to update its laws,
regulations, and practices; and
3. The federal government must update its
rules and continue discussions with its state
partners.
Here are the 10 specic recommendations:
Maintain State Leadership and Control Over
Produced Water Management:
1. Preserve the RCRA (Resource
Conservation and Recovery Act)
exemption: The RCRA exemption gives
Texas primary jurisdiction over produced
water. The existing RCRA regulatory
framework is the keystone for nearly all oil
eld waste management practices – and
essential for expanding produced water
management options. It is imperative that
Texas preserve the RCRA exemption.
2. Delegate NPDES (National Pollutant
Discharge Elimination System)
authority to Texas: Texas recently passed
legislation that will lead to the consolidation
of state authority for discharge permitting.
The new law directs the TCEQ (Texas
Commission on Environmental Quality) to
seek delegation from the EPA for oil and
gas wastewater discharge. Achieving this
NPDES delegation – target timeline is 2021
– would simplify permitting and expand
reuse options for produced water in Texas.
3. Maintain Texas jurisdiction over
pipelines: Texas regulates produced water
pipelines via a comprehensive framework as
well as state eld employees who regularly
Source: Tintera, J., Lyons, B.J., Wright, K.A. 2019. Sustainable Produced Water Policy, Regulatory Framework, and
Management in the Texas Oil and Natural Gas Industry: 2019 and Beyond. Texas Alliance of Energy Producers and IPAA.
10 Policy Recommendations for the Sustainable Use of Produced Water
Oilman Magazine / November-December 2019 / OilmanMagazine.com
33
OILMAN COLUMN
inspect produced water operations and
maintenance activities. The state currently
has an all-time high of lled inspector
positions with 69 pipeline safety inspectors
and 170 oil and gas inspectors. Any
federal usurpation of state oversight by
agencies such as the PHMSA (Pipeline and
Hazardous Material Safety Administration)
would burden the recycling industry and add
little value.
Continue to Update State Laws, Regulations
and Practices:
4. Increase interstate and association
policy coordination: Texas government
and industry ofcials should participate
in nongovernmental organizations with
broad representation across the states to
share best practices and other information.
The eventual goal would be to standardize
policy across the U.S. as much as realistically
possible given the differences in local
geographic conditions and state regulations.
This can be accomplished through the
auspices of the IOGCC (Interstate Oil and
Gas Compact Commission), which gathers
ofcials from across the country to meet
regularly and discuss policy and issues. Other
organizations such as the national GWPC
(Groundwater Protection Council) should
be supported as a vehicle for producing
valuable research. In June 2019, the GWPC
published a produced water report that will
advance the conversation on hydrocarbon
extraction management, regulations, and
overall energy security.
5. Revise produced water statutes and
regulations: The oileld regulatory
framework in Texas is well funded by the
state legislature, has modern and updated
regulations, and is competently administered
by accountable state regulators. Yet the
midstream recycling industry is rapidly
evolving. As scientic knowledge expands,
technology progresses, and new facts are
uncovered, Texas regulators must draft rules
that keep pace with these advancements.
The state has made strides here in the past
several years. For instance, some recycling
is now PBR (Permitted by Rule), a concept
that has encouraged produced water recycle
and reuse. On May 16, 2019, the U.S. House
Subcommittee on Energy and Mineral
Resources invited California, Ohio, South
Dakota, and Texas to testify on hydraulic
fracturing and state regulation of produced
water. Alliance President John Tintera
gave testimony that clearly demonstrated
Texas’ impressive and effective regulatory
framework, which is a model that could help
other states address regulatory concerns.
6. Prepare a roadmap for benecial reuse
outside the oil and gas industry: The
industry should continue to advance the
state of the art, hone its operations, and
follow sound produced water management
practices in the oileld. Meanwhile, the
government can encourage uses outside the
oilelds by creating a roadmap of how to
update regulations, sponsor research, and
issue permits for pilot studies. Scientic
research must be supported through a solid,
repeatable funding mechanism.
7. Develop incentive mechanisms: In the
recent Texas legislative session, legislators
voted against several bills that would
have provided tax relief or tax credits for
documented produced water recycling
activities. For example, one bill that failed
specied tax credits for desalters, including
those handling produced water. These
incentives would lower produced water
treatment costs, facilitate higher recycle
rates, and eventually lead to benecial reuse
of produced water. Legislators expressed
interest in an interim study of incentives
and economic impacts, which they should
pursue and learn from for the next legislative
session in 2021.
8. Collect and provide public access to
better produced water data: Standardized,
statewide produced water data is needed
to track water volumes and production
activity. This information would also
help communicate the value of produced
water and the opportunities recycling
represents. Texas should determine the
best mechanisms to collect and publish this
data in a way that is not onerous or costly
to the industry. The industry itself should
standardize produced water terminology,
reporting, and disclosure.
Federal Government Agencies Must Update
Rules and Work with State Partners:
9. Update or eliminate 98th Meridian
policy: The 98th Meridian is an arbitrary
geographic marker the EPA uses to separate
discharge permitting under NPDES rules.
The meridian bisects Texas into land
roughly east or west of Dallas. Under
the current federal regulatory scheme,
onshore discharges east of 98th Meridian
are typically not authorized. For onshore
discharges west of 98th Meridian whose
“produced water has a use in agriculture
or wildlife propagation,” benecial use
permit applications may be considered. The
EPA must eliminate or modify this federal
regulatory contrivance. It is not reective
of the current technological advances in
recycling or the need for site specic permit
conditions independent of broad national
controls.
10. Institutionalize Texas and federal agency
cooperation: Some states have been
working with the EPA on memorandums
of understanding, white papers, and other
endeavors involving produced water. In May
2019, the EPA issued its own draft “Study
of Oil and Gas Extraction Wastewater
Management,” which will be nalized by
year end. These efforts are laudable, and
Texas should pursue similar opportunities to
collaborate with the EPA and DOE.
Texas has created an environment where
produced water is no longer just a waste; it can
be a valuable resource. As the nations oil and
gas leader, the state must vigorously defend its
legislative and regulatory framework against
federal oversight and evolve them as needed
to promote the recycle and reuse of produced
water. It’s time for the next generation of
innovation, with careful consideration of these
10 recommendations.
John Tintera is the past President of the
Texas Alliance of Energy Producers. He is
the former Executive Director of the Texas
Railroad Commission and is a regulatory
expert and licensed geologist (Texas #325)
with a thorough knowledge of virtually all
facets of upstream oil and gas exploration,
production and transportation, including
conventional and unconventional reservoirs.
Blythe Lyons serves as a consultant to the
Texas Alliance of Energy Producers, and was
formerly a Senior Fellow with the Atlantic
Council’s Energy and Environment Program.
Kylie Wright is a Senior Environmental
Specialist with GAI Consultants, Inc., and is
a former geologic consultant with the Texas
Alliance of Energy Producers..
Photo courtesy of Ronald Loveday – www.123RF.com
Oilman Magazine / November-December 2019 / OilmanMagazine.com
34
OILMAN COLUMN
The Rule of Capture has been a foundational
concept of oil and gas prospecting for 150
years. The Rule of Capture exists to provide an
afrmative defense to drillers when they tap into
oil and gas pockets that cross property lines.
As ctional oilman Daniel Plainview so aptly
described it in the lm
There Will Be Blood,
“Underground, there’s no way to know whose
milkshake is whose.
But does the venerable Rule of Capture apply
to ssures and proppants crossing property
lines during hydraulic fracturing? And if not,
where does that leave production companies
accused of subsurface trespass? In 2008, the
Texas Supreme Court in
Coastal v. Garza
held
that the Rule of Capture shielded Coastal from
liability for trespass claims arising from hydraulic
fracturing operations. But an appeals court in
Pennsylvania has found just the opposite—that
the Rule of Capture defense does not apply to
hydraulic fracturing activities. Both Texas and
Pennsylvania are two of the leading natural gas-
producing states in the country and divergent
opinions on the application of the Rule of
Capture to hydraulic fracturing activities is
particularly noteworthy.
The Pennsylvania Supreme Court agreed to
consider the issue and heard oral arguments in
September 2019. Their ultimate decision could
have far-reaching and long-term repercussions
on the entire industry.
Fracing Company Loses in Pennsylvania
Court; Appeals to State Supreme Court
In
Adam Briggs et al. v. Southwestern Energy
Production Co.,
a Pennsylvania family claims
that a fracking operation next to their property
unlawfully crossed over into their 11-acre lot to
tap into gas pockets.
A three-judge panel in Pennsylvania Superior
Court sided with the plaintiffs in 2018, nding
that the Rule of Capture does not apply to
fracking operations. The ruling overturned a
2015 decision by a lower court, which dismissed
the lawsuit on Rule of Capture grounds.
At issue is the very technology used in fracking.
Traditional oil and gas development taps into
pockets of natural resources. But fracking
involves the injection of proppants, or
pressurized uids, into solid rock formations
in order to release natural gas and hydrocarbon
liquids trapped within. The plaintiffs compared
this process to a drill bit digging into their
property. The court ruled that this procedure
is invasive to the point of being substantively
different from traditional well drilling and, thus,
not protected by the Rule of Capture.
“In light of the distinctions between hydraulic
fracturing and conventional gas drilling, we
conclude that the rule of capture does not
preclude liability for trespass due to hydraulic
fracturing,” the Pennsylvania Superior Court
wrote in its decision.
In its lings to the state’s Supreme Court,
Southwestern Energy Production argued that if
the Superior Court’s ruling is allowed to stand, it
would create mass confusion among oil and gas
producers and open up virtually every fracking
operation to subsurface trespass claims.
“Settled expectations would be upended if this
court were to limit [“the Rule of Capture’s”]
application in this case,” the defendants wrote in
a brief to the Pennsylvania Supreme Court.
Texas Supreme Court Says Rule of Capture
is a Valid Defense to Trespass Claims
The Pennsylvania Superior Court’s decision
is contrary to the 2008 ruling of the Texas
Supreme Court in
Coastal Oil & Gas Corp. v.
Garza Energy Trust, et al.
In Coastal, the dispute arose between two
energy companies. The plaintiffs claimed that
Coastal’s fracking operations in Hidalgo County,
Texas drained gas from a reservoir underneath
the plaintiffs’ nearby tract.
The court’s majority did not rule on the
question of whether or not such activity could
be considered trespassing. But they did say that
in order to be actionable, trespass must cause
injury and due to the Rule of Capture, there
Whose Milkshake is Whose?:
Pennsylvania Supreme Court Considers
Whether the Rule of Capture Applies
to Hydraulic Fracturing
By Tony Guerino and Liz Klingensmith
Photo courtesy of Vladimir Endovitskiy – www.123RF.com
Oilman Magazine / November-December 2019 / OilmanMagazine.com
35
OILMAN COLUMN
could be no nding of injury.
The majority wrote that the owner of mineral
rights has “title to the oil and gas produced from
a lawful well bottomed on the property, even if
the oil and gas owed to the well from beneath
another owner’s tract.” In other words, the Rule
of Capture protected Coastal from trespass
claims.
The Texas Supreme Court rejected arguments
from the plaintiffs that fracking is an “unnatural”
activity, pointing out that all drilling for oil and
gas is a human-directed, and thus unnatural,
activity.
The Court also outlined several points in
favor of keeping the Rule of Capture in place,
including for fracking operations. They noted
that property owners have other business and
legal remedies available to protect their interests,
including simply drilling their own wells to
capture the gas on their property.
In his concurrence, Justice Don Willett noted
the importance of the oil and gas industry to the
Texas economy, and wrote that overturning the
Rule of Capture for fracking would leave much
of the state’s valuable natural resources untapped
and unusable.
“The Court today averts an improvident decision
that, in terms of its real-world impact, would
have been a legal dry hole, juris-imprudence
that turned booms into busts and torrents into
trickles. Scarcity exists, but above-ground supply
obstacles also exist, and this Court shouldn’t be
one of them,” he wrote.
However, the Texas decision was not unanimous.
Dissenting justices wrote that the Rule of
Capture only applies to legal oil and gas
production methods. Just as the plaintiffs in both
Texas and Pennsylvania have done, the dissenters
on the court likened fracking across property
lines to an oil drill that unlawfully crosses
property lines.
“Both involve a lease operator’s intentional
actions which result in inserting foreign materials
without permission into a second lease, draining
materials by means of the foreign materials, and
‘capturing’ the minerals on the rst lease,” the
dissenting justices wrote.
What’s Next for Fracking Industry, Rule of
Capture?
Without a doubt, all eyes are on Pennsylvania
and that state Supreme Court’s consideration
of
Briggs v. Southwestern Energy.
Interested
parties are weighing in on both sides, with
energy companies asking the Supreme Court
to overturn the Superior Court decision and
property rights advocacy groups urging the
Justices to uphold it.
If the Supreme Court sides with the plaintiffs,
the effects on Pennsylvania’s natural gas industry
could be chilling. The Rule of Capture acts as
an afrmative defense to trespass claims. The
Briggs
decision obliterates that defense, and
anyone in the unconventional natural gas and
liquids business would have to think long and
hard before undertaking any fracking operations
in the Keystone State, which is home to the gas-
rich Marcellus Shale.
Observers also correctly wonder what a
plaintiffs’ verdict in
Briggs
would mean
nationally. At least in the short term, it likely
would mean a great deal of state-to-state
variation in how the Rule of Capture is applied.
Company ofcials would need to be aware of
any particular state’s approach if they intend to
conduct fracking operations in that state.
For example, West Virginia’s Supreme Court
of Appeals issued a ruling in June 2019
(EQT
Production Co. v. Crowder et al.)
that horizontal
drills that cross property lines underground, even
if not producing from that strata, constitute
subsurface trespass, and that gas companies
cannot drill such wells without the permission of
the neighboring property owner. Even though
distinguishable from alleged trespass arising
from ssures and proppants resulting from
hydraulic fracturing, the Court took a broad
perspective when it wrote, “This court will not
imply a right to use a surface estate to conduct
drilling or mining operations under neighboring
lands.” Those operations arguably include the
effects of hydraulic fracturing.
With fracking operations taking place across
the country, it seems likely that more and more
state courts will be forced to reconsider the age-
old Rule of Capture for a modern-day energy
industry.
Tony Guerino and Liz Klingensmith are
energy and environmental litigators serving
the oil and gas industry. They are Partners in
Womble Bond Dickinson’s Houston ofce.
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Oilman Magazine / November-December 2019 / OilmanMagazine.com
36
OILMAN COLUMN
From Gemini Corporation to Gemini
Fabrication: Recovery after Receivership
By Tonae’ Hamilton
Any corporation can succumb to nancial
hardship, bankruptcy, or receivership at any
given time, no matter the industry.
Unfortunately, Gemini Corporation, a 30-year
professional services rm that provided multi-
disciplined engineering, eld, and environmental
services for energy and industrial facilities is one
of the corporations that went into receivership
last year in April. With the company staggering
in growth and prot for its last several quarters
and underperforming in its third quarter back
in 2017, it underwent restructuring. The ofcial
release announced that the restructuring would
include “changes to the executive leadership
team and signicant reductions in personnel
resulting in a $6 million annual reduction in
overhead costs.
With the announcement of restructuring, the
operational staff at the time experienced a lot
of uncertainty. “In uncertain times, it is very
difcult to stay focused on the task at hand,
stated Andy Farrow, President of Gemini
Fabrication, the company that developed out
of Gemini Corporation. As a result, Gemini
Corporation saw the departure of executive
leaders including Peter Sametz, president and
CEO, and Roger Harripersad, vice president of
Human Resources.
FTI Consulting Canada Inc. was appointed the
receiver and manager of all of Gemini’s current
and future assets. With the restructuring and
receivership order, Gemini Corporation was
almost completely wiped out, along with all the
jobs attached to it. That is, until the team of
the Ponoka Plant worked together to salvage
what they could of Gemini. “It was an outside
party that ultimately acquired the Gemini assets,
hired the operational teams and created Gemini
Fabrication Ltd., but it was the team in Ponoka
that really pulled together to try and keep
things going during the receivership,” Farrow
explained.
Thanks to the efforts of the Ponoka team,
along with the outside support they received,
they were able to save the fabrication entity
of Gemini and 150 jobs, and make Gemini
Fabrication succeed in the same facility where
things almost fell apart. Today, the Gemini name
has transitioned to “Gemini Fabrication,” which
still remains on the 56-acre facility.
Although Gemini Fabrication does not retain
executives or board members once associated
with parent company Gemini Corporation, it
has made efforts to retain some of the same
values as its predecessor company. “We have
tried to uphold some of [Gemini Corp’s] values
that were very good, such as their commitment
to safety. Gemini, through its history has always
made safety a priority which continues today as
a pillar of the business,” expressed Farrow.
Although the companies share a few similari-
ties in values, Gemini Fabrication is far from
the image of its predecessor company. Farrow
explained that Gemini Fabrication is a much
more focused organization with a goal to be rec-
ognized as the #1 fabricator in Western Canada
within ve years. “We are a lean organization
that doesnt have extra layers of management,
which also allows the people doing the work to
be more engaged in what they are doing. We are
focused on being an industry leader in terms
of Safety, Quality, Price and Delivery,” Farrow
further explained.
With a complex history, dedicated team, and
plan for continued success, Gemini Fabrication
has shown that anything is possible, with
it currently being recognized as one of the
largest employers in the Ponoka AB area. The
company celebrated their one-year anniversary
on October 1st and is on its way to being
the #1 fabricator in Western Canada. Farrow
offered his advice to companies currently
undergoing the same or similar events as
Gemini Fabrications predecessor company once
did before succumbing to receivership. “Staying
ahead of the down cycle is critical because you
can’t save money after you have spent it. You
need to stay focused on what you are best at
and where you can add the most value. Time
is a limited resource and if you’re focused on
chasing something you’re less capable of doing,
you’ll miss the opportunity to focus on the
things you do well,” Farrow expressed.
Andy Farrow, President, Gemini Fabrication – Photos courtesy of Gemini Fabrication
800-208-7918 nyb.com
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Oilman Magazine / November-December 2019 / OilmanMagazine.com
38
OILMAN COLUMN
Robotic Process Automation: Four Key
Considerations for Oil & Gas
By Steven Bradford and Kent Landrum
Many energy companies have embarked on
signicant digital transformation projects utiliz-
ing emerging technologies such as big data, cloud,
mobile, APIs (Application Program Interfaces),
natural language processing, machine learning and
RPA (Robotic Process Automation) to reduce costs
and streamline operations. In a recent discussion
with an organization contemplating a major RPA
initiative in the commercial and logistics area, the
possibility of investing some time up front on
process improvement, along with RPA implementa-
tion, was raised.
A Case for Process Improvement
The response from the client was basically, “No,
why do I need to spend time optimizing or
reworking processes anymore when I can just
automate them?” The query appeared simple on
its surface, but it calls into question the role that
process improvement methods ranging from TQM,
to ISO 9000, to Lean and Six Sigma plays in a world
lled with software bots and AI workers (especially
outside of manufacturing). It challenges the notion
that master data management and governance are
foundational for technology-enabled operational
excellence and questions the value proposition of
simplication in the form of reduced customization
and application portfolio rationalization.
The reality is that it’s not quite so black and white
but, rather, lies somewhere along a continuum
for most companies contemplating how best to
leverage automation. Below are four key reasons
to consider combining process improvement/
optimization with any major RPA initiative:
1. Lower Technology Implementation Costs
Implementation cost almost always represents one
of the highest initial hurdles to any information
technology initiative. Adding a process optimiza-
tion lens to RPA projects can serve to reduce
implementation cost in a number of different
ways. Perhaps most obviously, automating fewer
and simpler processes will require less IT resource
effort. Time spent up front to clarify process
owners, actors, steps/tasks, hand-offs, informa-
tion inputs and outputs, etc. will pay dividends by
simplifying requirements gathering. Standardizing
and simplifying processes will reduce the amount
of complex exception logic that must be congured
or developed. Removing unnecessary or unrelated
steps in the process may also present opportuni-
ties to reduce the number of integration points
between systems, which can be a signicant cost
driver. These benets continue to accrue through-
out the implementation project lifecycle as the more
focused process scope streamlines development/
training of the bots, compresses testing complexity
and effort and reduces delivery risk by eliminating
many unknowns. Finally, many RPA solutions are
licensed in a manner that increases cost based on
the number of bots or processes being managed,
so rationalizing the number of actors and process
steps may provide some relief both at project kick-
off, as well as in steady-state operations.
2. Reduced Ongoing Maintenance & Support
Costs
The introduction of virtually any new technology
such as RPA into an organization has the poten-
tial to increase IT operating cost by consuming
infrastructure resources either on premises or in the
cloud be it CPU, memory, storage, bandwidth or
otherwise. On the other hand, many of the benets
of including a process improvement component
in an RPA project compound over time long after
the initial system implementation. Calling out
these savings opportunities can help establish the
benets case necessary to secure project approval
and ensure that funding can be made available for
other value-generating investments across the IT
portfolio. In many instances, the time savings on
the business side alone are insufcient to justify the
investment; however, identifying and articulating
recurring IT cost reductions can help substantiate
the business case. Fewer, simpler processes will
result in a smaller sustainment burden for business
subject matter experts and IT support staff given
a lower number of processing errors that require
troubleshooting. These savings multiply when the
cost of shadow IT within the business necessary
to compensate for poor data quality resulting from
ineffective processes is taken into consideration.
Patches, upgrades, extensions and enhancements
to the underlying systems utilized by the automated
processes will be less costly as a result of more
straightforward integration and more compact
regression testing requirements.
3. Enhanced Reliability & Resiliency
Recent business continuity events such as Hurricane
Harvey or the Shamoon cybersecurity attack expe-
rienced by energy companies have highlighted the
importance of an organization’s ability to operate
and meet commitments to key stakeholders even
in the face of signicantly impaired IT capability.
Process automation certainly has the potential to
compensate for many of the mistakes of the past
by powering through unnecessarily arduous tasks
in a very cost-effective manner. However, energy
companies should carefully consider how they will
continue to operate if the RPA platform and/or
related systems were rendered unavailable. During
a business continuity incident business teams will
need to fall back on manual transaction processing
and during such episodes the benet of optimized
and well documented processes will be highly vis-
ible. Ensuring that the most critical processes are
simple, well understood, documented and built to
operate effectively in a business continuity context
will be of increasing importance in the future.
4. Greater Enterprise Value Creation
The focus of most RPA initiatives in the past has
been on taking cost out of the organization by
automating repetitive steps performed by employ-
ees in transaction processing. However, adding a
process improvement component from the outset
can help identify opportunities to eliminate unnec-
essary processes altogether, streamline those that
remain and create value in new and differentiated
ways. While automation can simplify what oil and
gas companies do today some of the most power-
ful prospects for its application lie in the ability to
offer incremental value-added services to customers
that cannot be provided in a cost-effective manner
today. Leveraging a company’s past investment in
skillsets such as BPR/BPM, TQM, ISO 9000, Lean,
Six Sigma, etc. and partnering with outside experts
can help identify and unlock these opportunities
to make the most from a technology investment in
process automation.
Conclusion
RPA offers signicant opportunity as a central
component in any oil and gas company’s digital
transformation strategy. The ability to capitalize
on the base investment to maximize return by
controlling costs, increasing resiliency and delivering
new value-creating capabilities can be signicantly
enhanced by putting early emphasis on process us-
ing time-tested methodologies and proven business
insight. Project sponsors and managers of automa-
tion initiatives should carefully consider building
these elements into their projects from the outset.
Steven Bradford is a Managing
Director with Opportune’s
Process & Technology prac-
tice. He has over 23 years of
leadership experience in busi-
ness transformation, systems/
technology implementation, business process
and controls improvement.
Kent Landrum is a Director,
Process & Technology at
Opportune LLP. He has more
than 18 years of diversied
information technology
experience with an emphasis
on solution delivery for the energy industry.
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Oilman Magazine / November-December 2019 / OilmanMagazine.com
40
OILMAN COLUMN
History tells that in the past
Standard Oil company – for the
sake of distinguishing – painted
barrels that were used to carry
crude oil in blue color (while those
for kerosene – in red). Therefore,
the rst letter “b” stands for
“blue.” But this is a non-grounded
myth as “blue” was carried by
the barrel many years well before
Standard Oil was created at all. A
more realistic look at the fact that
the Vikings used wooden barrels
to store salted herrings, which, as
you know, shine blue.
Actually, Richard III, King of
England from 1483 until 1485,
had dened the wine puncheon
as a cask holding 84 gallons and a
wine tierce as holding 42 gallons.
By 1700 custom had made the 42
gallon watertight tierce a standard
container for shipping eel, salmon,
herring, molasses, wine, whale oil
and many other commodities in
the English colonies. After the
American Revolution in 1776,
American merchants continued to
use the same size barrels.
Oil companies that are listed
on American stock exchanges
typically report their production
in terms of volume and use the
units of bbl, Mbbl (one thousand
barrels), or MMbbl (one million
barrels) and occasionally for widest
comprehensive statistics the Gbbl
(or sometimes Gbl) denoting
a billion. There is a conict
concerning the units for oil barrels.
For all other physical quantities,
according to the International
System of Units, the uppercase
letter “M” means “mega-” (“one
million”), for example: Mm (one
million metres, megameters), MHz
(one million hertz, or megahertz),
MW (one million watts, or
megawatt), MeV (one million
electronvolt, or megaelectronvolt).
But due to tradition, the Mbbl
acronym is used in the USA today
meaning “one thousand bbl,” as
a heritage of the roman number
“M” meaning “one thousand.” On
the other hand, there are efforts
to avoid this ambiguity, and most
of the barrel dealers today prefer
to use bbl, instead of Mbbl, mbbl,
MMbbl or mmbbl.
Outside the United States, volumes
of oil are usually reported in
cubic metres (m3) instead of oil
barrels. Cubic meter is the basic
volume unit in the International
System. In Canada, oil companies
measure oil in cubic metres, but
convert to barrels on export, since
most of Canada’s oil production
is exported to the USA. The
nominal conversion factor is 1
cubic meter = 6.2898 oil barrels,
but conversion is generally done
by custody transfer meters on
the border, since the volumes are
specied at different temperatures,
and the exact conversion factor
depends on both density and
temperature. Canadian companies
operate internally and report to
Canadian governments in cubic
metres, but often convert to U.S.
barrels for the benet of American
investors and oil marketers. They
generally quote prices in Canadian
dollars per cubic meter to other
Canadian companies, but use
U.S. dollars per barrel in nancial
reports and press statements,
making it appear to the outside
world that they operate in barrels.
Companies on the European stock
exchanges report the mass of oil
in metric tonnes. Since different
varieties of petroleum have
different densities, however, there
is not a single conversion between
mass and volume. For example,
one tonne of heavy distillates
might occupy a volume of 256
U.S. gallons (6.1 bbl). In contrast,
one tonne of crude oil might
occupy 272 gallons (6.5 bbl), and
one tonne of gasoline will require
333 gallons (7.9 bbl). Overall, the
conversion is usually between 6
and 8 bbl per tonne.
The measurement of an “oil
barrel” originated in the early
Pennsylvania oil elds. The Drake
Well, the rst oil well in the U.S.
was drilled in Pennsylvania in
1859, and an oil boom followed
in the 1860s. When oil production
began, there was no standard
container for oil, so oil and
petroleum products were stored
and transported in barrels of
different shapes and sizes. Some
of these barrels would originally
have been used for other products,
such as beer, sh, molasses or
turpentine. Both the 42-U.S. gallon
(159 l) barrels (based on the old
English wine measure), the tierce
(159 liters) and the 40-U.S. gallon
(151.4 l) whiskey barrels were used.
Also, 45-U.S. gallon (170 l) barrels
were in common use. The 40
gallon whiskey barrel was the most
common size used by early oil
producers, since they were readily
available at the time.
In August 1866, at the height of
the oil boom in northwestern
Pennsylvania, a handful of
American independent oil
producers met in Titusville. One
of the issues that were discussed at
this meeting was the coordination
of standard containers for oil
supplies to consumers. As a result,
a 42 gallon volume was agreed as a
standard oil barrel.
Already by the year 1700, everyday
practice in Pennsylvania and
accumulated experience led to the
fact that the sealed wooden barrel
of 42 gallons became the de facto
standard container for transporting
sh, molasses, soap, wine, oil,
whale oil and other goods.
Barrels with a capacity of 42
gallons when lling them with oil
had just such a weight that one
healthy person could handle. One
person could not cope with larger
barrels, and the use of smaller
barrels was not so economically
Why bbl? Energy Units in the USA
and Other Countries
By Eugene M. Khartukov
Oilman Magazine / November-December 2019 / OilmanMagazine.com
41
OILMAN COLUMN
advantageous. In addition, 20
barrels with a capacity of 42
gallons were ideally placed on
typical, at that time, barges and
railway platforms.
Thus, choosing a 42 gallon barrel
as an industry standard was a
logical and natural step for early oil
producers. In 1872, the American
Petroleum Association ofcially
approved a 42 gallon barrel as a
standard.
Currently, oil, of course, is no
longer transported in any barrels.
It is transported by tankers and
oil pipelines. But the oil barrel as
a unit of measure remained in the
practice of world oil trade.
Then why is the abbreviation
“bbl” used to refer to a barrel?
Why are there two letters “b”
in the barrel designation (bbl),
although the English word barrel
has only one “b?”
Popular rumor says that such an
abbreviation owes its origin to the
phrase blue barrel. The fact is that
in the early practice of Standard
Oil, it was to paint its oil barrels
in blue. The blue barrel was a kind
of guarantee that its volume is 42
gallons.
But upon careful reading, you may
notice the use of the abbreviation
“bbl” in Sally Brig Ship Cargo
Declaration dated September 11,
1764.
There are other hypotheses about
the origin of the abbreviation
“bbl.” For example, some believe
that bbl was used to indicate the
plural. That is, one barrel is 1 bl,
two barrels is 2 bbl, etc. Others
believe that the abbreviation
“bbl” was used to mean the word
“barrel” so as not to confuse it
with the word “bale.” That is, 1 bl
is one bale, and 1 bbl is one barrel.
In general, the truth is somewhere
nearby. But what is a real truth
there, it is no longer to nd out.
However, as it was mentioned
above, the “viking” hypothesis
seems the most realistic.
Around 1866, early oil producers
in Pennsylvania came to the
conclusion that shipping oil in
a variety of different containers
was causing buyer distrust. They
decided they needed a standard
unit of measure to convince
buyers that they were getting
a fair volume for their money,
and settled on the standard wine
tierce, which was two gallons
larger than the standard whisky
barrel. The Weekly Register, an
Oil City
, Pennsylvania newspaper,
stated on August 31, 1866 that
“the oil producers have issued the
following circular:”
Whereas, it is conceded by all
producers of crude petroleum on
Oil Creek that the present system
of selling crude oil by the barrel,
without regard to the size, is
injurious to the oil trade, alike to
the buyer and seller, as buyers, with
an ordinary sized barrel cannot
compete with those with large
ones. We, therefore, mutually agree
and bind ourselves that from this
date we will sell no crude by the
barrel or package, but by the gallon
only. An allowance of two gallons
will be made on the gauge of each
and every 40 gallons in favor of
the buyer.
And by that means King Richard
III’s English wine tierce became
the American standard oil barrel.
By 1872, the standard oil barrel
was rmly established as 42-U.S.
gallons. The 42 gallon standard oil
barrel was ofcially adopted by the
Petroleum Producers Association
in 1872 and by the U.S. Geological
Survey and the U.S. Bureau of
Mines in 1882.
In modern times, many different
types of oil, chemicals, and other
products are transported in steel
drums. In the United States,
these commonly have a capacity
of 55-U.S. gallons (208 l) and
are referred to as such. They are
called 210-litre or 200 kg drums
outside the United States. In the
United Kingdom and its former
dependencies, a 44-imperial-gallon
(200 l) drum is used, even though
all those countries now ofcially
use the metric system and the
drums are lled to 200 liters.
Thus, the 42-U.S. gallon oil barrel
is a unit of measure, and is no
longer a physical container used
to transport crude oil, as most
petroleum is moved in pipelines or
oil tankers. In the United States,
the 42-U.S. gallon size of barrel
as a unit of measure is largely
conned to the oil industry, while
different sizes of barrel are used in
other industries.
The abbreviations “Mbbl”
and “MMbbl” refer to one
thousand and one million barrels
respectively. These are derived
from the Latin “mille,” meaning
“thousand.” This is different from
the SI convention where “M”
stands for the Greek “mega,”
meaning “million.” Outside of
the oil industry, the unit Mbbl
(megabarrel) can sometimes
stand for one million barrels.
Some sources assert that “bbl”
originated as a symbol for “blue
barrels” delivered by Standard Oil
in its early days. However, while
Ida Tarbell’s 1904 Standard Oil
history acknowledged that the
abbreviation “bbl” had been in use
well before the 1859 birth of the
U.S. petroleum industry.
Oil wells recover not just oil
from the ground, but also natural
gas and water. The term BLPD
(Barrels of Liquids per Day) refers
to the total volume of liquid that is
recovered. Similarly, barrels of oil
equivalent or BOE is a value that
accounts for both oil and natural
gas while ignoring any water that is
recovered.
Other terms are used when
discussing only oil. These terms
can refer to either the production
of crude oil at an oil well, the
conversion of crude oil to other
products at an oil renery, or the
overall consumption of oil by a
region or country. One common
term is barrels per day (BPD,
BOPD, bbl/d, bpd, bd, or b/d),
where 1 BPD is equivalent to
0.0292 gallons per minute. One
BPD also becomes 49.8 tonnes per
year. At an oil renery, production
is sometimes reported as barrels
per calendar day (b/cd or bcd),
which is total production in a year
divided by the days in that year.
Likewise, barrels per stream day
(BSD or BPSD) is the quantity of
oil product produced by a single
rening unit during continuous
operation for 24 hours.
Continued on next page...
Oilman Magazine / November-December 2019 / OilmanMagazine.com
42
OILMAN COLUMN
When used to denote a volume,
1 bbl is exactly equivalent to
42-U.S. gallons and is easily
converted to any other unit of
volume. A volume of 1 bbl is
exactly equivalent to a volume of
158.987294928 liters.
In the oil industry, following
the denition of the American
Petroleum Institute, a standard
barrel of oil is often taken to
mean the amount of oil that at a
standard pressure (14.696 psi) and
temperature (60°F) would occupy
a volume of exactly 1 bbl. This
standard barrel of oil will occupy
a different volume at different
pressures and temperatures. A
standard barrel in this context
is thus not simply a measure of
volume, but of volume under
specic conditions. The task of
converting this standard barrel of
oil to a standard cubic meter of oil
is complicated by the fact that the
standard cubic meter is dened by
the American Petroleum Institute
to mean the amount of oil that at
101.325 kPa and 15°C occupies
1 cubic meter. The fact that the
conditions are not exactly the same
means that an exact conversion
is impossible unless the exact
expansion coefcient of the crude
is known, and this will vary from
one crude oil to another.
Thus, for a light oil with an API
gravity of 35, warming the oil
from 15°C to 60°F (which is 15.56
°C) might increase its volume by
about 0.047 percent. Conversely,
a heavy oil with an API gravity of
20 might only increase in volume
by 0.039 percent. If physically
measuring, the density at a new
temperature is not possible, and
then tables of empirical data can
be used to accurately predict the
change in density. In turn, this
allows maximum accuracy when
converting between standard bbl
and standard m3.
International commodity
exchanges will often set an
arbitrary conversion factor
for benchmark crude oils for
nancial accounting purposes.
For instance, the conversion
factor set by the NYMEX (New
York Mercantile Exchange) for
WCS (Western Canadian Select)
crude oil traded at Hardisty,
Alberta, Canada is 6.29287 U.S.
barrels per cubic meter, despite
the fact that crude oil cannot
be measured to that degree of
accuracy. Regulatory authorities in
producing countries set standards
for measurement accuracy of
produced hydrocarbons, where
such measurements affect taxes or
royalties to the government. In the
United Kingdom, for instance, the
measurement accuracy required is
±0.25 percent.
A barrel can technically be used
to specify any volume. Since the
actual nature of the uids being
measured varies along the stream,
sometimes
qualiers
are used to
clarify what is being specied. In
the oileld, it is often important
to differentiate between rates of
production of uids, which may
be a mix of oil and water, and rates
of production of the oil itself. If a
well is producing 10 mbd of uids
with a 20 percent water cut, then
the well would also be said to be
producing 8,000 barrels of oil a
day (bod).
In other circumstances, it can
be important to include gas in
production and consumption
gures. Normally, gas amount is
measured in standard cubic feet or
cubic metres for volume (as well as
in kg or Btu, which don’t depend
on pressure or temperature). But
when necessary, such volume is
converted to a volume of oil of
equivalent enthalpy of combustion.
Production and consumption using
this analogue is stated in boed
(barrels of oil equivalent per day).
In the case of water-injection wells,
in the United States it is common
to refer to the injectivity rate in
bwd (barrels of water per day).
In Canada, it is measured in cubic
metres per day (m3/d). In general,
water injection rates will be stated
in the same units as oil production
rates, since the usual objective is to
replace the volume of oil produced
with a similar volume of water to
maintain reservoir pressure.
Thus, a 42 gallon barrel, which
accommodates 158.987294928
liters, became a standard unit for
measuring oil in the States in 1866.
A boe or BOE (barrel of oil
equivalent) – is often used in the
USA for energy comparisons and
combinations. This is a unit of
energy based on the approximate
energy released by burning one
barrel (42-U.S. gallons or 158.9873
litres) of crude oil. The BOE is
used by oil and gas companies
in their nancial statements as a
way of combining oil and natural
gas reserves and production into
a single measure, although this
energy equivalence does not take
into account the lower nancial
value of energy in the form of gas.
The U.S. IRS denes
higher
heating
value (HHV) of the boe as equal to
5.8 million BTU (5.8×106 BTU
59°F
equals 6.1178632×109 J, about
6.1 GJ or about 1.7 MWh.) The
value is necessarily approximate
as various grades of oil and gas
have slightly different heating
values. If one considers the lower
heating value instead of the higher
heating value, the value for one
boe would be approximately 5.4
GJ. Typically, 5,800 cubic feet of
natural gas or 58 CCF (100 cubic
feet) are equivalent to one boe. The
(1) Per m3 and bcm. (2) Kcal15/kg
Table 2 – Gross Caloric Values of Various Fuels in Australia, in Kcal-IT per kg (or cm) and in petajoules per mln tonnes (or bcm)
(1) Per dm3.
Table 1 – Average Energy Contents of Various Russian Fuels (Incl. in Relation to the Reference Fuel)
Oilman Magazine / November-December 2019 / OilmanMagazine.com
43
OILMAN COLUMN
USGS gives a gure of 6,000 cubic
feet (170 cubic meters) of typical
natural gas.
Over the northern border, in Can-
ada, Europe and Russia ofcially
uses the IEA (International Energy
Agency) as well as in the PRC a
similar but larger energy unit is
used for these purposes and energy
balances – the toe or TOE (ton of
oil equivalent). In particular, toe is
used by the Canadian ministry of
energy – NEB (National Energy
Board) – and Canadian leading
energy companies. NCV of this
energy unit is dened as 41.868
gigajoules (GJ) or 10 gigacalories
(Gcal). Net caloric value (NCV) is
dened, by convention, as follows:
1 toe = 11.63 megawatt-hours
(MWh);
1 toe = 41.868 gigajoules (GJ);
1 toe = 10 gigacalories (Gcal)
– using the international steam
table calorie (calIT) and not the
thermochemical calorie (calth);
1 toe = 39,683,207.2 British
thermal units (BTU);
1 toe = 1.42857143 tonnes of
coal equivalent (tce).
At the same time, in Russia and
the FSU other countries, the
tce is widely used for energy
comparisons. This energy unit is
usually called tonne of standard
reference fuel (trf), net caloric
value of which is dened as 29.3
GJ or 7,000 kcal. In this case it
equals 0.7 toe and is assumingly
referred to energy contents of
various fuels in the following way
(Table 1):
In its turn, in Australian energy
industry PJ (petajoules) are very
popular and 1 PJ equals 1015
joules. In detail:
1 PJ = 947,817,077,749.15 BTU
1 PJ = 2.3890295761862E+14
calories 15°C (cal15)
1 PJ = 2.3900573613767E+14
calories [thermochemical]
(calth)
1 PJ = 947,816.08955725
dekatherms (dath)
1 PJ ≈ 277.77777777778
gigawatt hours (GWh)
1 PJ = 23,884.58966275 tonnes
of oil equivalent (TOE)
Here, in Australia, PJs are used
even in the gas industry (Table 2).
Also, in Australian energy industry,
quite popular is coe (crude oil
equivalent), which is sometimes
understood as a synonym of oil
equivalent. But in Australia this has
a special meaning and its GCV is
ofcially dened as 10,250 Kcal15/
kg or 18,500 btu/ft3.
As prices, production,
consumption and trade of natural
gas (including LNG) worldwide
are often presented in
MMBtu
and
dekatherms
, 1 MMBtu =
1,055,055,852.62 Joules and 1 dth
= 10 therms or 1,000,000 British
thermal units (MMBtu) or ≈ 1.055
GJ ≈ 1,000 cubic feet (cf) or one
Mcf (of natural gas measured at
standard conditions, since one
cubic foot of dry natural gas has
a high heating value (HHV) of
approximately 1,000 Btu).
To measure and present large and
very large amounts of energy
Quads
and
Q
units are used in the
States. In particular, Quad is used
by the U.S. Department of Energy
in discussing world and national
energy budgets and is equal to 10
15
(quadrillion) BTU, or 1.055 × 10
18
joules (1.055 exajoules or EJ) in
SI units, which is an approximate
equivalent of the following:
8,007,000,000 gallons (US) of
gasoline
293,071,000,000 kilowatt-hours
(kWh)
293.07 terawatt-hours (TWh)
33.434 gigawatt-years (GWy)
36,000,000 tonnes of coal
970,434,000,000 cubic feet of
natural gas
5,996,000,000 UK gallons of
diesel oil
25,200,000 tonnes of crude oil
(the USA)
252,000,000 tonnes of
trinitrotoluene (TNT) or ve
times the energy of the Tsar
Bomba nuclear test
energy of 15,750 nuclear
explosions, each of which
was in theory produced by the
A-bomb thrown on Hirosima
on August 6, 1945
13.3 tonnes of uranium-235
In its turn, the Q energy unit is
equal to 10
18
(quintillion, trillion)
BTU or 1.0E+18 BTU.
Just to feel this better by putting
the Quad and Q units into a frame
of actual reference, we say that
in 2019 inland consumption of
petroleum and other HC liquids
is projected in the U.S. Energy
Information Administration of
the Energy Department (EIA
USDoE)’s Reference Scenario
of its
Annual Energy Outlook
(January 2019) at over 38 Quads
while global primary energy
consumption is forecast by the
EIA to grow by 2040 up to 0.82 Q
from some 0.52 Q in 2010.
It is noteworthy that each of
the above energy units is used
at certain national measurement
conditions which are called
Figure 1 – Oil and Gas Volumes under the U.S. and Russian Current STP, in %%
Continued on next page...
Oilman Magazine / November-December 2019 / OilmanMagazine.com
44
OILMAN COLUMN
the standard temperature and
pressure (or, shortly, STP). This
is very important to know since
national STPs vary noticeably
country-by-country. It is well
known that, if all other things
being equal (or in Latin
“ceteris
paribus”
), the volume is directly
proportional to temperature and
inversely proportional to pressure,
which are applied to it. Or, in
other words, under constant
temperature and pressure,
the relationship between the
volume of gas and the number
of moles is direct. This law is
known as Avogadro’s Principle
or Avogadro’s hypothesis. This
hypothesis was rst published
by Amedeo Carlo Avogadro
(1776–1856), an Italian scientist,
in the year 1811.
Just for those who prefer a
mathematical language, we refer
to Avogadro’s original and simple
modied equations:
V ÷ n = k, which means that
the volume amount fraction will
always be the same value if the
pressure and temperature remain
constant.
Let V
1
and n
1
be a volume
amount pair of data at the
commencement of our research.
If the amount is transformed to a
different value called n2, then the
volume will b altered to V
2
.
As we are aware that V
1
÷ n
1
= k
and we are acquainted with: V
2
÷
n
2
= k
Meanwhile as k = k, we can
determine that V
1
÷ n
1
= V
2
÷ n
2
.
This equation of V
1
÷ n
1
= V
2
÷
n
2
will be very useful in cracking
Avogadro’s Law problems. Here is
the Law articulated in fractional
form:
And if we emphasize that the
temperature should be presented
in kelvins (and Celsius degrees)
and the pressure – in Pascals
(how all the units are accepted in
modern chemistry and physics,
as well as in the SI, where 0 K =
–273.15°C and 1 Pa = 1 Newton/
m2 = 0.00014503773 Psi), then
the needed equation looks as
follows:
Vx = Vo × (273.15 + Tn) ÷ Po x
Pn, where
Vx – a new, sought-for volume,
Vo – an original volume in the
same units,
Tn – a new temperature in Celsius
degrees,
Po – an original pressure,
Pn – a new pressure in the same
units.
Although the Avogadro’s Law
relates to an
ideal gas
(an abstract,
theoretical gas composed of
many randomly moving point
particles whose only interactions
are perfectly elastic collision), the
above equation is actually good
(universal) for any gaseous or
liquid hydrocarbons.
The USA currently uses STP
correspond to 60°F (288.706
K, 15.556°C) and 14.696 psia
(1 atm, 1.01325 bar, also named
“1 Standard Atmosphere”). At
these conditions, the volume of
1 mole of a gas equals 23.6442
liters while 1 cubic foot of a gas
does not equal 28.3168 liters
(under any similar measurements)
but 28.8719 liters (in line with
the denition of the STP, used
by the International Gas Union
(IGU) (15°C and 760 mmHg).
The above mentioned set of
volume measurements, known as
U.S. STP, is ofcially used by the
national oil and gas and energy
business (and, rst of all, by
the API, DoE, PRMS, SPE and
USGS).
In Canada, Europe, Australia,
and Latin America, for example,
the STP conditions used by the
ISO (International Organization
for Standardization) (that are
15°C and 101.325 kPa) have been
adopted, as a rule, and are used
as the base values for dening the
standard cubic meter.
In its turn, in Russia, 20°C and
760 mmHg, corresponding, in
particular, to the U.S. NIST’s NTP
and EPAs STP, are ofcially used
for volume measurements. As the
matter of fact, this is almost the
biggest difference in temperatures
used at present in the oil and gas
industry worldwide (20°C and
60°F)
2
. At the Russian conditions,
1 U.S. cubic foot of a gas does
not equal 28.3168 liters but nearly
28.7527 liters or contains almost
1.54 percent more gas, while
U.S. oil 42 gallon barrel is not
equal to 158.987295 liters but
accommodates over 161.4345
liters of oil (again by nearly 1.54
percent more) (Figure 1).
Surely, not a big deal, of course.
But, if taken in absolute physical
terms, with gas production
standing now in Russia at some
730 bcm a year and that of crude
oil and mixed/leased condensate
at over 560 mta, this is more than
what was actually produced last
year in Vietnam (9.6 bcma or 0.93
bcfd) or Peru (6.4 mta or 154
kb/d) (Table 3).
2
To be exact, an even larger difference
should be attributed to volumes (of natural
gas) exported by Russia to the EU (almost
1.74 percent).
Eugene
Khartukov is
a Professor at
Moscow State
University for
International
Relations
(MGIMO), Head of Center
for Petroleum Business Studies
(CPBS) and World Energy
Analyses & Forecasting Group
(GAPMER) and Vice President
(for the FSU) of Geneva-based
Petro-Logistics S.A. Khartukov
has authored and co authored
over 320 articles, brochures
and books on petroleum and
energy economics, politics,
management, and oil and gas in
the FSU, Russia’s Far East, the
Caspians, Europe, the OPEC,
ME and Africa. Participated
as a speaker and/or a session
chairman in more than 170
international energy, oil and
gas and economic fora.
Table 3 – Production of HCs in Russia: Effects of Different Oil & Gas Measurements
Oilman Magazine / November-December 2019 / OilmanMagazine.com
45
OILMAN COLUMN
Most Common Oil and Gas
Cybersecurity Threats
By Emmanuel Sullivan
We are currently in the middle of a
technological revolution, and the signs are all
around us. Go ahead and name any tech buzz
word such as the Internet of Things, Big Data,
or Articial Intelligence, and it will denitely be
related to so many industries out there. Here,
however, we’re not going to talk about the new
opportunities, but we’ll be warning you about
emerging threats.
Integration and automatization have
exposed many industries to new threats and
vulnerabilities, and the oil and gas industry is
no exception. It has never been more important
to protect critical infrastructures due to the
increase in cybersecurity threats in the oil and
gas industry.
According to research conducted by ABI, the
oil and gas industry has been gearing up against
cyber threats by taking some preventative
measures. The report illustrates how a
cumulative $1.87 billion has been spent against
cybersecurity threats in the oil and gas industry.
Even though this is the case, most of the
players in the industry still lack awareness and
can easily fall victim to dangerous cyber-attacks.
What Could Possibly Happen?
The possible consequences of a cyber-attack
highly depend on the cybercriminal’s aims.
An example can be state-backed hackers or
competitors that are interested in attaining or
revealing important information held by the
victim companies. Sabotage, on the other hand,
is a whole new problem and is usually the aim
of hacktivists – such as the case of #OpPetrol
operation back in 2013.
The Possible Risks of a Successful Attack
Some of the risks that can be faced by victims
of a successful cyber-attack can include the
following:
1. Plant shutdowns
2. Equipment damages
3. Interruption of utilities
4. Shutdowns of production cycles
5. Inappropriate or inconsistent product
qualities
6. Undetected spills
7. Violations of safety measures which could
result in injuries or even death
Hackers Can Break Into Operational
Technology (OT) Networks
A computer worm called Stuxnet has been
known to target PLCs or the industry’s
programmable logic controllers along with
SCADA systems. This was a wake-up call for
so many industries other than the oil and gas
industry because the worm had been designed
in this way.
The general idea of cyber-attacks of this nature
is quite simple. Applications in enterprises such
as Enterprise Resource Planning systems or
even Business Intelligence systems are usually
connected with a large number of devices in
plants. This is done with the help of some
integration technologies that are used to
transfer data across platforms such are smart
devices. If these connections are not secured,
such as the connections between OT and IT
environments, then reneries are most denitely
vulnerable to cyber-attacks.
Oil Market Fraud
Imagine if a cybercriminal uploaded malicious
software into a system which has the ability
to change stock information for oil and gas
companies. An example can be the case where
malware had the ability to fake certain types of
data and make quantities appear much larger
than they really are.
Once this occurs, the victim company will easily
run out of production resources and hence fail
to satisfy its respective obligations. As a result,
the malware would have wreaked havoc and
caused the company to experience huge losses
while driving the oil price much higher.
Plant Destruction
In the production units of oil and gas
companies, tank gauging systems and tank
information management systems are
connected. Some of these are equipped
with functionalities that allow them to send
individual commands to PLCs, which in turn
are placed to control the lling of tanks.
When cybercriminals make their way to
this information, nothing can prevent them
from changing its critical values. How is this
dangerous? Well, a cybercriminal could easily
engineer an oil explosion by simply increasing
the maximum lling limits of individual oil
tanks.
In a similar manner, there are numerous
processes in reneries and oil separation units
that can be open to potential attacks via their
burner management systems. These systems are
not only meant to send information, but they
are also designed in a manner to be managed
remotely via special intermediate systems and
business applications. Vulnerabilities in these
remote operations can easily be compromised
leading to the worst-case scenario of a plant
explosion by simply turning off the purge
functionalities.
Equipment Sabotage
Remote plant equipment is usually at risk of
data manipulations as well. This can be in terms
of pressure or temperature measurements and
hackers could easily implant false forms of
data which show breakdowns have occurred
in remote facilities. This would then lead the
victim renery to waste their nancial resources
and time in false investigations.
The takeaway from all of the above may sound
banal, but it is the ugly truth. The newest
technological features and booming usage of
the Internet of Things have simplied our lives
quite a lot, but have also brought ahead some
new risks. Now, it’s not only a question of
the vulnerabilities of the people who use the
Internet of Things or even electric skateboards.
Every critical infrastructure that is connected
to these technologies should take the threat
seriously.
It is now time for oil and gas companies to
realize that there are no gaps between OT and
IT systems and that there are certain business
applications that exchange critical information
with devices. Due to this, these companies
should seriously consider cybersecurity and
setting strong lines of defense against possible
attacks.
Oilman Magazine / November-December 2019 / OilmanMagazine.com
46
OILMAN COLUMN
Pipelines as Critical Infrastructure
By Jason Spiess
The state of California currently experienced
a reality check in energy accountability and
aging infrastructure. While the majority of the
attention is on the spike in gas prices, black
outs and stress on the grid in California, Wesley
Cate of Eco-Energy believes the national
conversation should shift to the issue of aging
pipelines.
The most recent “Infrastructure Report Card”
published by The ASCE (American Society
of Civil Engineers) gave the United States an
overall grade of D+. According to Cate, most
of the natural gas pipelines are over 40 years old
and are in need of updates sooner rather than
later, especially since natural gas plays a large
role in energy, manufacturing and providing an
overall quality of life.
“Natural gas in 2018 we were at 35 percent of
your overall power demand. That’s massive.
Coal was at 27 percent and nuclear was at 19
percent,” Cate said. “When we look at critical
infrastructure and electricity, so if our natural
gas pipelines are 35 percent of our overall
power portfolio, I think that is critical.”
Cate recently spoke to the members of the
Southern States Energy Board about natural gas
supply, infrastructure and demand. A key point
of the discussion was if SSEB members want
industrials like Pzer, P&G, Toyota, GM and
many others in their states, then states should
be encouraging and not opposing natural gas
infrastructure.
“Pipelines create lasting jobs, which creates
lasting tax revenue,” Cate said. “There are
over 8,000 miles of proposed projects in these
members states, imagine the amount of jobs
and economic stimulus this would create.
Economic prosperity follows pipelines.”
Cate is quick to point out that economics and
the opportunity demand natural gas gets all
the attention, but there are other factors as
important.
“Natural supply has always been the focus from
a conversational standpoint. Everyone wants
to talk about the growth and that is great, and
I don’t want to shift away from that, however,
there are other elements to consider,” Cate
said. “When we look at critical infrastructure
there are three components to that discussion -
supply, infrastructure and demand.”
According to WhatIs.com, “critical infrastruc-
ture” is the body of systems, networks and
assets that are so essential that their continued
operation is required to ensure the security of
a given nation, its economy, and the public’s
health and/or safety.
While there are many interpretations and special
interests usurping this law, Cate believes the
conversation shifted to include multiple layers,
creating a complex critical need to understand.
“I think it is important to shift that narrative
over to the demand side because that is where
I believe we can start to label this as a critical
infrastructure component,” Cate said. “When
we look at where pipelines are going and what
they are providing for us as a society, really the
societal shift has already happened.
Cate added this shift needs to be understood
and acted upon before more issues like what
happened to California’s grid. Blackouts and
power rationing is only part of the story, protes-
tors and policy are inuencing when and how
the nations critical infrastructure is updated.
Protests of critical infrastructure projects –
even those actions that are deemed peaceful
and nonviolent – involve not only trespassing
on private property, but often can put the
trespassers, workers, and environment at risk.
Each arrest and incident are another play in
the protestors play book, which was put into
collective play at Standing Rock in North
Dakota.
The Standing Rock protest in the Bakken oil
elds garnered national attention due to the
narrative of the protest. Many argue that the
state ushered industry right into the protestor’s
true agenda of capturing the narrative of energy
and the environment.
Consider this. Wounded veterans and
Hollywood stood with Standing Rock
protestors. They brought in the bright lights and
big city sex appeal while pulling on the heart
strings of virtually everyone with those who
were injured while ghting for our freedoms.
The state responded by ring rubber bullets at
them and dousing them with a re hose in sub-
zero temperatures.
That’s cold. And the pipeline protestors
warmed up to the attention and shift in national
narrative.
Standing Rock is ranked number two on the
FBI’s hate crimes. Now pretty much every
protest is using the Standing Rock model. That’s
an incredible shift and reality.
However, the Standing Rock protest is a prime
example of the damage that can be caused
during these “peaceful” actions. The protest
lasted from August 2016 until February 2017
and resulted in a $33 million cost to taxpayers,
more than 700 arrests, 1,400 charges and
over 1,000s of tons of waste and several
hundred abandoned vehicles that created an
environmental issue for their water supplies.
The protestors actually created a reality of an
environmental threat in the exact specic area
they were trying to protect - the water supply.
Furthermore, the glorication of martyrism
and Instagram moments fan the ames of cash
supporting the protestors as a career more than
a cause. Roughly 92 percent of the arrests at
Standing Rock involved people from out of state.
Pipelines are obviously of national interest.
The nation’s natural gas and oil industry plays
a critical role in fueling America with reliable
and affordable energy. In fact some counties
are testing the “eminent domain” argument to
update their pipelines or nish projects.
“Our industry needs to shift from the supply
side as the focal point and shift towards the
demand based narrative. This shift will naturally
spotlight the needs in critical infrastructure,
Cate said. From a tax standpoint, to a
manufacturing standpoint. Without pipeline
infrastructure we don’t have a stock market.
The bottom line is that damage to our aging
critical infrastructure risks interrupting
necessary services across the United States.
Pipelines are critical.
According to Cate, most of the natural gas
pipelines are over 40 years old and are in need
of updates sooner rather than later.
Some counties are testing the eminent domain
argument to update their pipelines or finish projects.
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