Transforming Fireproong
in the Downstream
p. 44
Virtual Reality as a Workforce
Training Solution
p. 4
Follow The Leader: Examining How
Industry Giants Reduced Operational
Costs By Going Digital
p. 22
In Mineral Buying
Innovation Wins
p. 10
THE MAGAZINE FOR LEADERS IN AMERICAN ENERGY
May / June 2019
OilmanMagazine.com
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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
Invaluable Land Knowledge Software and AI: Sarah Skinner – page 15
Downturn by Legislation: Jason Spiess – page 18
Transitioning from an Outside Industry into the Oil Sector: Recent Graduates and
Petroleum Engineering Education: Tonae’ Hamilton – page 23
Waterless Oil Sands Extraction Process set to Improve Oil and Gas Industry Environmental Track Record: Eric Eissler – page 27
Be Aware of the Modern Day Snake Oil: Jason Spiess – page 28
Interview: Josh Robbins, CEO, Beachwood Marketing: Emmanuel Sullivan – page 30
Improving Oil and Gas Storage and Operations Through Innovation: Tonae’ Hamilton – page 36
50 Years Later: The Impact of Discovery: Mark A. Stansberry – page 43
Transforming Fireproong in the Downstream: Sarah Skinner – page 44
Guest Columns
Virtual Reality as a Workforce Training Solution: Elliot Green – page 4
IoT in The Oil and Gas Industry: Bill Ebanks and David Head – page 6
Continuous “Hands Off ” Insulation Resistance Testing of Critical Motors: Jeff Elliott – page 8
In Mineral Buying Innovation Wins: Matt Chamberlain and Ashley Gilmore – page 10
Implementing Articial Gas Lift Earlier Can Improve Declining Wells: Andrew Poerschke, Teddy Mohle and Paul Ryza – page 12
Digital Twin Technology Adds a New Dimension to Offshore Projects: Thornton Brewer – page 16
Technological Advances Cushion Oil Crisis: Amandeep Kaur – page 19
Follow The Leader: Examining How Industry Giants Reduced Operational Costs By Going Digital: Shallan Grisé – page 22
Scale Sand Production with Modular Natural Gas Power: Mike Mayers and Josh Haugan – page 26
Oil Markers: Useful Pricing Tools: Eugene M. Khartukov – page 32
There Is More than One Way to Practice Hydraulic Fracturing: Andres Ocando – page 38
DevOps Provides Digital Pipelines to Cloud Benets: Aater Suleman – page 42
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1
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Gifford Briggs
Gifford Briggs joined LOGA in 2007 working
closely with the Louisiana Legislature. After
nearly a decade serving as LOGA’s 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
ofce 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
Ofcer 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 efciently.
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.
Not many of us would have guessed the deal of the quarter that blasted
the energy headlines last month. Chevron announced that it was acquiring
Anadarko for $33 billion in cash and stock or $65 per share. The merger
places Chevron in a signicant position with a wide corridor of acreage in
the Permian. Since the blockbuster deal was announced, industry analyst
believe more M&A activity is coming. More so with companies that are
considered Permian pure-plays like Pioneer and Concho. According to oil
and gas experts, companies that primarily operate in the Permian and then
merge have the best potential to integrate their acreage position. Occidental
also bid for Anadarko at $70 per share and was caught off guard that they struck a deal with Chevron.
In the past 12 months there has also been a string of O&G software and technology acquisitions.
First off, Drillinginfo went on a buying spree purchasing a long list of established software compa-
nies to complement its existing suite of upstream products. To name a few, they purchased: Oildex,
MineralSoft, Cortex, 1Derrick, Midland Map Co and PLS. Most of the acquisitions occurred after the
private equity rm Genstar Capital completed the purchase of Drillinginfo Holdings. After Quorum
Software was acquired by private equity rm Thoma Bravo, the fullstream software provider then
acquired Coastal Flow Measurement and its subsidiary Flow-Cal, a producer of gas and liquid mea-
surement software. Oil and gas accounting solutions company Wolfpack Software acquired LandPro
Corp in March of this year. P2 Energy Solutions, another E&P software provider acquired iLand-
Man, a SaaS-based land management platform. Watereld Energy Software, a Tulsa-based oil and gas
software provider with a focus on the midstream and downstream markets, acquired NeoFirma, a
cloud-based eld operations platform that is geared toward independent oil and gas companies.
There has been a lot of M&A activity recently and it will be exciting to see in the months ahead
as segments of the industry continue to consolidate and adapt to a digital oileld with a goal of
improving operation, market share and personnel performance.
MAY — JUNE 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
Eric Freer
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com/subscribe. The contents of this
publication are copyright 2019 by Oilman
Magazine, LLC, with all rights restricted.
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is strictly prohibited.
All information in this publication is
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reliable, but the accuracy of the information
cannot be guaranteed. Oilman Magazine
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LETTER FROM THE PUBLISHER
CONTRIBUTORS — Biographies
Oilman Magazine / May-June 2019 / OilmanMagazine.com
2
Emmanuel Sullivan, Publisher, OILMAN Magazine
Oilman Magazine / May-June 2019 / OilmanMagazine.com
33
Week Ending April 26, 2019
DIGITAL DOWNHOLE DATA
Colorado: 32
Last month: 30
Last year: 28
North Dakota: 58
Last month: 60
Last year: 55
Texas: 491
Last month: 491
Last year: 513
Louisiana: 62
Last month: 65
Last year: 60
Oklahoma: 102
Last month: 108
Last year: 129
U.S. Total: 991
Last month: 1,006
Last year: 1,021
OIL RIG COUNTS
*Source: Baker Hughes
Brent Crude: $70.71
Last month: $67.51
Last year: $68.81
WTI: $65.66
Last month: $59.87
Last year: $65.49
CRUDE OIL PRICES
*Source: U.S. Energy Information Association (EIA)
Per Barrel
Colorado: 15,504,000
Last month: 15,904,000
Last year: 13,511,000
North Dakota: 42,668,000
Last month: 42,391,000
Last year: 35,902,000
Texas: 149,786,000
Last month: 151,783,000
Last year: 120,708,000
Louisiana: 3,706,000
Last month: 3,795,000
Last year: 3,778,000
Oklahoma: 17,968,000
Last month: 18,113,000
Last year: 16,434,000
U.S. Total: 367,993,000
Last month: 370,792,000
Last year: 309,831,000
CRUDE OIL PRODUCTION
*Source: U.S. Energy Information Association (EIA) – January 2019
Barrels Per Month
Colorado: 165,265
Last month: 166,118
Last year: 150,695
North Dakota: 71,834
Last month: 69,792
Last year: 55,403
Texas: 715,337
Last month: 716,176
Last year: 609,451
Louisiana: 254,571
Last month: 248,381
Last year: 210,425
Oklahoma: 261,193
Last month: 265,546
Last year: 227,286
U.S. Total: 2,950,748
Last month: 2,955,447
Last year: 2,586,405
NATURAL GAS
MARKETED PRODUCTION
*Source: U.S. Energy Information Association (EIA) – January 2019
Million Cubic Feet
Per Month
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Oilman Magazine / May-June 2019 / OilmanMagazine.com
4
Virtual Reality as a Workforce
Training Solution
By Elliot Green
Virtual Reality (VR) has been the most anticipated
upcoming technology for the past three years.
However, in these past three years it has been slow
to deliver on the large promises made. VR was
expected to revolutionize the way that industry
worked from training to day-to-day operations.
While it has taken longer than everyone expected,
that promise is now becoming a new reality for
many industries.
History
Virtual Reality burst into the mainstream lexicon in
2015. By March 28, 2016 Oculus Rift had launched
their rst headset with the HTC-Vive arriving at
developer’s front doors the following month. The
Oculus Rift and HTC-Vive were being touted
as the very next big step for the VR industry.
By October of that same year, Sony PlayStation
released their VR headset. With this, VR had
ofcially hit mainstream commerce and was now
readily available to both developers and consumers.
Computers took a performance step forward and
prices of hardware fell. Nvidia graphics cards
became hugely powerful and, with this, VR was
now everywhere. By 2017, VR was on every
trade show booth, in every marketing pitch and
presentation, and it looked like it was here to
stay. But then nothing; the technology stagnated.
Customers didn’t appear, the adoption and sales
gures of VR headsets were notoriously buried
and by early 2018 it looked like maybe we had all
just repeated the 3D TV fade, but things were
about to change.
Present
In early 2019 the tide has started to shift.
Developers had been through a period of learning
and customers had a moment to digest the
technology. A new realm of partnerships between
industry and developers is starting to form which
included exciting, valuable, useful and cost saving
solutions.
One of those solutions is in pre-construction
plant inspections. By taking the original CAD draft
drawings and putting them into a VR environment,
the plant team are, within minutes, able to be
virtually in that plant, looking for colliding pipes
and structures, adjusting valve positions, looking
for efciencies and avoiding costly redraws and
new component manufacture. This in itself is a
new frontier for the industry.
Shell has taken this approach with their Vito
platform. For the rst time in history, while the
platform is still in construction over one-thousand
miles away in Singapore, the rig is being virtually
explored by its future crews who are stationed
in Louisiana. This process is not only saving the
company time and money but ultimately the lives
of their staff as they are now better equipped to
manage their assigned rigs even before they rst
step foot onto them.
Training is a second application that has been
quick to employ the virtues of VR. The fully
immersive environment provides higher retention
rates, as high as 90 percent when re-tested after
OILMAN COLUMN
A Real user ghting a Virtual re
The view from a supply vessel during VR Rigger training Internal, intelligent Riggers provide Articial Intelligence real time
directional signals to VR Crane operators
Oilman Magazine / May-June 2019 / OilmanMagazine.com
5
S
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F
D
E
P
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N
D
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B
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I
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Y
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QUALITY THROUGH RESEARCH
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VALVE PRODUCTS
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RESEARCH LLC
OILMAN COLUMN
one month, compared to regular class teaching,
and engages a new generation providing the
training team with the ability to measure and score
everyone on the same standard. Variables such
as classroom location and experience of training
staff are no longer factors for training success.
South Louisiana Community Colleges’ Oil and
Gas teaching department recently introduced their
rst educational piece of VR specically designed
to educate the future workforce on what a typical
Permian basin rig may look like. The students
are able to explore the entire rig from mud pits
through to the crows nest in each area having to
identify the different working elements of the
noisy, dirty rig.
VR Crane training simulators are now small
enough and powerful enough to match and better
the more traditional large-scale trailer or static
systems. The VR simulators can be packed up,
moved and set up with no more space than a desk
and chair. The simulators have real world physics
applications. They include sensors for measuring
the trainee inputs and include scenarios that are
either A) too dangerous to recreate in a traditional
training or B) they are testing for situational
awareness.
All of this computer-based training is unbiased,
measurable, portable and scalable.
Future
The industry will ultimately dictate where this
technology is best utilized. But, in a period of time
where every expenditure is being assessed and
efciencies looked for, there are already discussion
about placing VR systems on offshore platforms
to provide refresher training during rotation. Com-
panies are identifying opportunities to take mobile
systems into the Permian Basin to provide multi
program centers. The centers would be capable of
acting as a VR Crane simulator in the morning and
VR Incipient Fire training in the afternoon and
VR Hazard awareness in the late afternoon. The
exibility of this technology is unmatched and the
boundaries are still being tested.
Training companies, designers, HSE, and labor
agencies are all going to have the ability to identify
costs savings, improved worker engagement and
practical applications where a VR solution would
improve their business, performance and bottom
line.
Conclusion
The future is bright - developers have overcome
the initial challenges, hardware is accessible, the
quality is excellent and the solutions being created
have a strong demand across a wide variety of
platforms. Virtual Reality is here now and is going
to be used across the industries at every level.
Elliot Green is the Founder of TANTRUM
Lab a Virtual Reality software training company
based in Lafayette, Louisiana. He has been
creating VR experiences for clients since late
2015. His team has developed a unique
approach to VR training incorporating
wherever possible real-world physical objects.
Elliot is a seasoned developer of cutting-edge
technology, having previously worked for
Nokia creating some of the very rst Aug-
mented Reality experiences as well as multiple
consumer-focused technology expos.
The VR Fire ghters view while practicing
the PASS technique
Oilman Magazine / May-June 2019 / OilmanMagazine.com
6
IoT in The Oil and Gas Industry
By Bill Ebanks and David Head
The oil and gas industry faces technical
challenges unique to its business, with hundreds
of thousands of onshore and offshore wells
distributed over wide geographic areas and
thousands of miles of pipelines requiring
continuous monitoring, periodic maintenance,
and constant connectivity to ensure safety and
optimized performance. As new, Internet-
enabled technologies emerge to help address
the operating challenges in these environments,
companies must consider carefully the emerging
risk of signicant cybersecurity breaches in order
to avoid or minimize the monetary, reputational,
and operational damage from such intrusions.
While additional computational and networking
capabilities will drastically change how businesses
operate in the future, the tradeoffs inherent in
deploying such technology must also be kept in
mind.
The connectivity of all of our myriad devices,
known as the IoT, has advanced dramatically
for corporations and households alike. Micro-
sized devices, heavily equipped with electronic
and networking components, are increasingly
becoming embedded into our working and
personal lives. While the consumer implications
are broad and increasingly visible, businesses are
also improving their processes with increased
automation and advanced analytics that take
advantage of concepts such as predictive
maintenance or near-real time monitoring of
infrastructure.
As we move from early adoption into general
acceptance, the number of IoT devices continues
to grow at an exponential rate. Only three
years ago, there were 15.41 billion IoT devices
connected worldwide; now however, according
to Statista, the 23.14 billion devices installed in
2018 will grow to more than 75 billion by 2025.
There is little debate over the benets that can
be realized by using these devices. However,
corporations often overlook critical security
considerations when deploying new, cutting-edge
technologies, and IoT devices are no exception.
The importance of considering security
implications may not always be clear in the initial
deployment of such technologies, particularly
when executives are focused on the opportunity
to reduce costs and increase their bottom line.
Growth in IoT Devices
Lacking security-related analysis, a breach on a
connected device could allow hackers to steal
data, disrupt operations, and impact production.
Seasoned adversaries will often seek entry
on an unsecured connected device in order
to expand their access to sensitive databases
and le structures in other locations. Popular
IoT device developers claim that the security
protocols that their hardware utilizes are fully
secure and, in some instances, “future proof.”
In reality, without adequate security practices
in place to support their use, these devices may
actually be easy to compromise, as demonstrated
by the SANS Institute
1
. As a result, it is likely
that many organizations have not adequately
quantied the risk resulting from their growing
reliance on IoT devices. Data breaches are in the
news far too often, and companies are suffering
major impacts to their stock value, reputation,
or operating earnings as a result. These impacts
are particularly acute in industries that require
an always-on, always-functioning infrastructure,
where any disruption can cost hundreds of
thousands, if not millions, of dollars per
incident.
In the news, we have seen examples of attacks
focused on shutting down connected devices.
TSMC (Taiwan Semiconductor Manufacturing
Company), the world’s largest manufacturer of
semiconductors, was forced to take multiple
plants ofine in order to recover from an attack.
2
Saudi Aramco, one of the world’s largest oil
companies, suffered one of the largest hacks in
history in 2012. The hack originated on a single
computer that was connected to their larger
IT infrastructure, wreaking havoc throughout
the network. As a result of the breach, Saudi
Aramco was forced to take a number of their
operations ofine and had to resort to the
manual handling of supplies, shipping and
contracts with governments and business
partners. Approximately 35,000 computers were
affected, forcing the company to give oil away
for free, in some cases, to avoid disruption in
distribution.
3
This leads to an interesting challenge in the
oil and gas industry, where companies will be
keen to harness the signicant benets that IoT
devices bring but must simultaneously work to
protect their infrastructure from the expanded
attack surface presented by the same devices.
For example, within the past few years, upstream
and downstream oil and gas companies have
seen an evolution in the technology available to
monitor and automate operations. Companies
are implementing this new technology to reduce
NPT (non-productive time) by integrating
information and operational technology to
speed up processing time, to enable predictive
maintenance, and to reduce frequency of
disruptive incidents. Additionally, to prevent/
minimize disruption, companies typically
supplement manual inspections with PLCs
(programmable logic controllers) to control
valves and satellite connections to remotely
monitor equipment – greatly improving overall
operating efciency. While the operational
benets from such initiatives are easy to
measure and report, the risks of inadequately
protecting this expanded attack surface are not
often considered fully – raising the specter of
operational disruption and loss of key assets.
Operational disruption is not the only risk posed
by insecure devices. As the energy industry
is already heavily regulated, additional nes
and repercussions are likely to be explored by
OILMAN COLUMN
Source: Statista
Oilman Magazine / May-June 2019 / OilmanMagazine.com
7
OILMAN COLUMN
regulators concerned about the systemic risk
of a vulnerable infrastructure. The NERC CIP
(North American Electric Reliability Corporation
Critical Infrastructure Protection) protocol
provides a set of requirements designed to better
secure the assets that operate North America’s
bulk electric system. The protocol also stipulates
the need for robust cyber capabilities to protect,
detect, and recover all critical systems. Similarly,
purchasing cyber insurance, while somewhat
benecial, is not a one-stop shop for mitigating
nes and prot loss resulting from a cyber
breach because residual mitigation and recovery
efforts can continue to incur costs. And how do
you quantify the potential, ongoing reputational
and brand impact of such an incident?
Now the question becomes, what can
organizations do to mitigate the risk stemming
from this growing reliance on IoT devices? As
technological capabilities evolve to more fully
automated monitoring of operating conditions
and to more advanced analytics and machine
learning capabilities, security programs must also
mature and enforce the concept of “security
by design.” That is, IoT devices supporting
communication and storage should have
appropriate security layers in place. Sensitive data
must be segmented from less secure networks,
and any transmission of data over any network
should be end-to-end encrypted. Security can’t
be locked into the rmware, future-proong
requires upgradeable measures to address
currently inconceivable new threats. Additionally,
ongoing, real-time monitoring and automated
incident alerting on IoT devices can enable
timely response to any suspected compromise.
Proper security testing, mimicking real-world
scenarios, must include assurances that IoT
devices and their supporting infrastructure
are regularly scanned for vulnerabilities and
upgraded when necessary. All these defensive
measures need to be dened and documented,
while driven by a security policy that aligns to
both business and security objectives of the
organization.
What You Need to Know
• While the use of IoT devices within industry
are growing exponentially, for all the cost
cutting and strategic benets they provide,
these devices, and their connections to the
internet, are not inherently secure.
• A breach of a connected device has the
potential for exponential damage as the
impact traverses industrial and IT systems to
which it connects.
• The solution is to plan ahead, to consider
security throughout the design, and to
monitor in real time (security-by-design and
defense-in-depth).
• New cyber laws and regulations are being
implemented on a continual basis.
Bill Ebanks
is a managing
director in
the Energy
Practice and
David Head
is a managing director in the Digital Practice
at AlixPartners, the global consulting rm.
1 – In order to demonstrate the importance of proper security
testing and design, SANS developed a series of straightforward
exercises to demonstrate the relative ease of compromising
a device leveraging the Thread protocol, a common IoT me-
dium. SANS [https://www.sans.org/reading-room/whitepa-
pers/internet/gorilla-deliver-assessing-security-googles-thread-
internet-things-iot-protocol-38070]
2 – ZDNet [https://www.zdnet.com/article/tsmc-says-vari-
ant-of-wannacry-virus-brought-down-its-plants/]
3 – CNN [https://money.cnn.com/2015/08/05/technology/
aramco-hack/index.html]
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Oilman Magazine / May-June 2019 / OilmanMagazine.com
10
In Mineral Buying Innovation Wins
By Matt Chamberlain and Ashley Gilmore
Mineral buyers want to be special.
Unfortunately, most know that aside from the
strength of their network there isn’t a lot to
differentiate one group from the next. That, of
course, doesn’t stop them from trying.
Nearly every mineral buyer has an obligatory
website offering “fast and fair offers” telling
potential sellers that they will give them more
for their minerals than the other guy. They
battle for inbound leads, focus on creating
sleeker websites, tweak keywords to perfection
and spend on geo-targeted digital advertising.
In the end, there is no denable special sauce
separating one from the next.
The more ambitious and well-funded invest
heavily in hiring the most talented negotiators
and researchers in an attempt to drum up
leads in targeted AOI (areas of interest).
Others focus on developing proprietary
software solutions. Although very intelligent
land professionals help create these, land
professionals are not developers and the
solutions are usually customized Excel
spreadsheets.
So, while mineral buyers want to be unique,
most of them act on very similar principles -
“fast, fair offers with a focus on integrity.” Are
they better negotiators and researchers? Maybe.
Does this provide a substantial advantage?
Most likely not. Do they have access to public
data that no one else does? Obviously no, most
often leads come from tax rolls, lease records,
forced pooling agreements, company reports or
other similar publicly available data.
In a market where everyone is selling
themselves the same way and using the same
data, the only way to gain a meaningful
advantage is to innovate in ways others are
not. Those who fail to adopt new technologies
and reimagine processes will tread water and
eventually fall behind. The mineral buyers that
uncover and implement solutions to quickly
and accurately process reams of mineral
ownership data will win by a landslide.
How Can a Mineral Buyer Truly Gain an
Edge?
A good option is “buying in front of the bit,”
or attempting to buy in front of operators.
E&Ps do this all the time to improve NRI (net
revenue interest), diversify their portfolio and
become more resilient to market swings. If a
mineral buyer wants to buy in front of a drill
bit they don’t own they have four options:
1. Partner with an operator and agree on
cost + fee per acre
2. Predict the future
3. Get lucky
4. Leverage inside information
Partnering is the only option proven to work
consistently enough to bank on, while the
others can be considered gambling, illegal or
both. Getting lucky is only a plan for fools and
we’ll leave inside information to the sharks.
In order to partner, a mineral buyer must rst
nd a company willing to trust them with their
sensitive information. If they do, partnering
is a safe, risk-averse bet for those who are
content with small wins and limited upside. But
the oil and gas industry, with its rich history of
wildcatters and tycoons, has never been a place
for those looking to win small. This leaves
mineral buyers with a single option - predicting
the future which, if you squint, looks very
similar to getting lucky.
Blanket Title as a Mineral Buying Strategy
Over the last decade, data companies have
started offering tools that make it possible
to predict future production with impressive
accuracy. For example, DrillingInfo gives
clients access to leasing trends and rig
movements to determine where an operator
will drill next. When this data rst became
easily accessible it gave users an edge, but
today nearly everyone uses DrillingInfo and,
as a result, everyone can make the same
predictions. When everyone uses the same data
services, custom spreadsheets, and CRMs, it
is no longer an advantage, it is the minimum
requirement to stay competitive. Predicting the
future only has value if a company is able to
execute on it before someone else. Answers
make you smart, actions get things done, but
neither hold much value without the other.
The Need For “Actionable Intelligence”
Prices can soar overnight when an operator
takes a lease, beginning a rush to gain
position. The rush forces buyers to cut
corners by sacricing speed and accuracy to
close transactions. In the end, success in this
environment relies heavily on luck and brute
force. Mineral buyers must nd a way to
accurately value a mineral owner’s assets fast
enough to take action while competition is
limited.
Running out title conventionally can cost
thousands of dollars for a single owner.
Current economics dictate that in order to
invest capital into conrming ownership
OILMAN COLUMN
Oilman Magazine / May-June 2019 / OilmanMagazine.com
11
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OILMAN COLUMN
mineral owners rst must commit to selling
by signing a LOI (letter of intent). Without a
commitment, it is cost prohibitive to prerun
title. When capital is deployed to research a
single lead, a company is essentially placing a
binary bet with limited upside.
The Agrarian Age for Mineral Buyers
The approach to date resembles a hunter/
gatherer mentality. To survive requires being
opportunistic, adaptable and expertly skilled.
The best have been able to survive and even
thrive, but even then, outdated tools and a
resource intensive approach limit the size and
stability of the opportunities. Just as early
humans transitioned from “hunter/gatherers”
to farmers in the Agrarian Age, mineral
buyers need to evolve and begin “farming”
opportunities. Systematically running blanket
title is the way to accomplish this.
Blanket title generates a list of all current
mineral owners for an AOI with pre-
conrmed interest calculations. Mineral
buyers taking this approach acquire actionable
intelligence that allows them to bypass the
step of signing an LOI. Offers can be sent out
en masse and close rates skyrocket when an
owner is approached with a deed and a check
they can sign and cash on the spot. There
are two ways to run blanket title. The rst
is reactively by waiting for a potential seller,
getting an LOI signed and then running out
all of the names and owners in the same tract,
section, or AOI, rather than just the single
signed owner. The second is to proactively run
an area of interest (AOI) to identify all owners
before having a potential seller.
Using Title Management Platforms to Win
Today, successful mineral buyers know
“where” they want to buy, the winners of the
next half decade will be the fastest to nd the
“who.” Title Management Platforms (TMP)
like Tracts, use common title to identify all
leads surrounding the initial target. Features
like automatic interest calculation eliminate
math while document interpretation libraries
store deed interpretations for repeated use.
Hungry, young, PE backed mineral buyers are
entering the space and building their processes
using a technology rst strategy. By removing
the most time-consuming steps involved
in title research they are able to run entire
sections for what it used to cost to run out
a single name. As these companies continue
to adjust, auto calculation of interest and
interpretation libraries are turning one lead
into 20 and cutting required investment into
a fraction of what they have been historically.
Leveraging TMPs is providing immediate
returns, exponentially increasing upside while
vastly reducing the opportunity for a complete
loss. Today TMPs offer a massive competitive
advantage for those early to adopt, soon they
will be a requirement just to stay competitive.
We’ve seen this story before.
Matt Chamberlain is VP of Growth at
Tracts having lead efforts in business
development, client relations and strategic
planning. He has a breadth of experience
bringing new technology and processes
to the energy sector and environmental
industries. Ashley Gilmore is CEO and
co-founder of Tracts where he applies an
extensive background in launching and
managing startup companies. Drawing on
a deep knowledge of land title law and
information technology, Gilmore pioneered
a new approach to title processing in the oil
& gas industry. Gilmore has been awarded
numerous patents for title processing
and visualization technologies.
For more
information, please visit www.tracts.co.
Oilman Magazine / May-June 2019 / OilmanMagazine.com
12
OILMAN COLUMN
Implementing Artificial Gas Lift Earlier
Can Improve Declining Wells
How an innovative approach regarding the optimum time to implement articial gas
lift has signicantly improved production as wells decline – beginning on day one
By Andrew Poerschke, Teddy Mohle and Paul Ryza
Even after the prep work is nished and product
recovery has been initiated, there is still no surere
way for oileld exploration and production
companies to condently know how much and for
how long their wells will produce recoverable oil
and natural gas. There’s a simple reason for that:
no two wells, even if they are located yards from
each other, possess the same production and life
cycle characteristics.
While this uncertainty can be frustrating for
oileld operators who must show their investors
what their capital investment is actually buying
them, it does create some opportunities. Namely,
the opportunity for oileld engineers to employ
outside-the-box thinking when identifying ways to
atten each well’s inevitable decline curve, which
will result in predictable production rates and
higher monetary returns over a longer period of
time.
Surveying the Field
A United States-based energy company operates
wells in Texas’ Permian Basin, specically Pecos
County in the Southern Delaware Basin’s Wolf-
camp A and Wolfcamp B formations. Most of the
drilling sites are horizontally fractured wells with
depths between 9,500 and 10,500 feet with FBHP
(owing bottom-hole pressures) from 5,000 to
6,000 psi. On average, each well has 50 fracking
stages and requires 2,250-2,500 pounds of sand
per foot and 60-80 barrels of water per foot.
The wells generally have strong bottom-hole
pressures, but fail to ow naturally for an extended
period of time. This means that they will require
some form of ow-optimizing articial lift earlier
in their operational window. For example, the
characteristics of Southern Delaware wells are
such that they may only ow for 90 to 120 days
before needing articial lift, while wells located
a handful of miles away may ow for more than
two years before requiring intervention.
The most effective articial lift system in this
area has been one that features an ESP (electrical
submersible pump) installed in the well. However,
this approach can be problematic for three
reasons:
• Remote areas of West Texas do not always
have access to reliable electricity.
o If power is not readily available, building
out a power grid can cost millions of dollars.
• Alternative high-volume lifts that require a
natural gas generator to convert natural gas
into electricity can be rented, but this adds
signicant cost to the bottom line of the
operator’s LOE (Lease Operating Expenses).
• Other forms of articial lift can have upfront
costs of 10 to 20 times more than a set of gas
lift valves.
For a potential solution, the producer reached
out to Apergy, a leading provider of articial
lift technologies, to help oil and gas production
companies optimize their returns safely and
efciently. The main request was a challenging
one: Draw as much oil and natural gas out of the
well as possible in the rst 90 days of operation,
while reducing LOE over the well’s production
life cycle.
Seeing is Believing
The client was not averse to using costly
alternative lifts if reaching the goal of maximized
production rates could be realized, but Apergy’s
oileld engineers knew there had to be a more
cost-effective way to attack the problem. So,
they developed a four-pronged approach to
introducing gas lift to a series of 10 Wolfcamp A
and B wells.
The trial involved introducing to the wells at four
specic points during their lifetimes a gas lift
system that featured annular gas injection:
• Option A: Well ows for 90 days before
Annular Gas Lift is installed.
• Option B: Well ows for 15-45 days before
Annular Gas Lift is installed.
• Option C: Annular Gas Lift is installed on the
rst day the well begins owing.
• Option D: Annular Gas Lift is installed on the
rst day the well begins owing, while injecting
gas in the rst few days of production.
Well No. 1 Well No. 2
Oilman Magazine / May-June 2019 / OilmanMagazine.com
13
OILMAN COLUMN
The rst two options were not a radical departure
from accepted norms. Options C and D, on the
other hand, are solutions that few production
companies will consciously choose to implement.
Let’s take a look at the performance of the 10
individual wells that were tested, one well with
Option A, the next three with Option B, three
with Option C and the nal three with Option D
(the production graphs for all wells are not shown
because of space constraints):
Well No. 1 began producing in February 2017, but
by the end of April was beginning to experience
daily production declines, though water-recovery
rates remained steady. Staying on the existing
course could mean an early death for the well, but
when Annular Gas Lift was installed at the 90-
day mark, the production curve bumped up and
remained steady, save for some small peaks and
valleys, through June 2018.
Well Nos. 2 and 3 were a similar story to Well No.
1: strong early production that tapered off before
the 90-day mark, when Annular Gas Lift was
installed, which stabilized production. Annular
N
o w
A
v A i l A b l e
: T
h e
C
r u d e
l
i f e
C
l 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
Well No. 3
Well No. 7
Well No. 5
Well No. 8
Continued on next page...
Oilman Magazine / May-June 2019 / OilmanMagazine.com
14
OILMAN COLUMN
Gas Lift valves were installed after only 15-45
days of operation. The result was a more gradual
decline in production rates over the following
months of operation. In fact, the wells’ returns
beat the engineer’s forecast by such a wide
margin that they were used as an example shown
to investors of how ROI could improve with
this well setup.
The wells using Option C were the results
the engineers were really anxious to see since
the setup – the Annular Gas Lift application
deployed from the rst day of the wells’
operation – was a departure from accepted
norms. All three wells began operating in 2018
and the results have been similar – strong
production rates from day one that have
continued with only small valleys experienced.
If there has been one standout performer, it has
been Well No. 7, which showed an absolutely
negligible decline curve over its rst three
months of operation.
The last wells had Annular Gas Lift valves
installed with injected gas within the rst
few days of owing. The return has been so
impressive, the decline curve so negligible and
the LOE so optimized that the operator has
decided to treat all future wells in the Southern
Delaware Basin in this fashion.
Several takeaways can be analyzed when
considering how these wells performed based on
the four different gas lift setups:
• Adding a velocity string during owback
reduced slugging and outproduced casing
ow.
• Switching
from Annular
Gas Lift to
Conventional
Gas Lift did
not improve
production at
2,500 b/d total
uids.
• When the
injection gas was
turned off after
the rst 90 days,
the wells loaded
up immediately.
• Production
results compared to other forms of high-
volume lift were similar and, in some cases,
surpassed due to lack of downtime, but at a
fraction of the cost.
Conclusion
In an industry like oil and gas exploration and
production that features so many well-to-well
variables that must be considered when deter-
mining the best way to produce the well, there
is simply no one-size-ts-all solution. While
many companies continue to rely on alternative
high-volume lifts – or wait to introduce articial
lift systems until the last moment before the well
loads up – forward-thinking companies are nd-
ing that there are some noteworthy alternatives
available. Based on the empirical information
noted above, one of the more successful ap-
proaches is intentionally installing an articial lift
system earlier in the well’s life, up to and includ-
ing the rst day of operation, with the results so
far speaking for themselves.
Andrew Poerschke is the Regional Operations
Manager for Apergy, Houston, TX, and can
be reached at andrew.poerschke@apergy.com,
while Teddy Mohle is a Lead Completions
Engineer and Paul Ryza a Senior Production
Engineer. Apergy (formerly Dover Articial
Lift) is a leading provider of highly engineered
technologies that help companies drill for
and produce oil and gas efciently and safely
around the world. Apergy’s products include
a full range of equipment essential to efcient
functioning throughout the life cycle of a
well – from drilling to completion to
production. For more information,
please visit www.apergyals.com.
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Oilman Magazine / May-June 2019 / OilmanMagazine.com
15
Land management is a crucial link in the upstream
management chain because the health of every
exploration and production organization depends
on it. Landmen must move quickly during lease-
acquisition phases if they want to secure the best
leases in prime exploration areas. Traditionally,
this process was slow and tedious, but because
of technological advances and AI, it no longer
has to be that way. Time is money. The work of a
traditional landman is extremely labor intensive –
physically and mentally. The amount of time and
work put into land acquisitions and everything that
goes along with it is major time and man-hours
are expensive. Just think if E&P companies could
manage their assets and streamline the processes
of the land life cycle, giving them the ability to
use technology to maximize efciency and the
advantage in an ever-evolving oil market.
P2 Energy Solutions
P2 is offering just that. They are the world’s largest
software and technology company dedicated to
the upstream oil and gas industry, with solutions
spanning the entire value chain from exploration
to decommissioning. More than 1,500 companies
use P2 products and services daily to improve
decision-making, gain clarity into complex
workow scenarios, and optimize upstream
efciency.
History of Tobin
Founded in 1928 in San Antonio, Texas, by Edgar
G. Tobin, the company began capturing and
interpreting aerial photography to create detailed
maps for the burgeoning Texas oil industry. By
1930 the company had already mapped over 3,000
miles of pipelines and numerous elds including
projects in Mexico and Venezuela.
Tobin quickly established itself as the industry
leader in spatial information management in the
United States and has set signicant milestones
ever since. Acquired by P2 Energy Solutions in
2004, Tobin was and remains a trusted source for
mapping and geo-spatial data services for oil and
gas producers.
With Tobin’s dedicated specialists, who have over
850 years of combined experience and a history
of pinpoint accuracy, Tobin gives their customers
the condence to make decisions that impact their
company’s success. Fast, quality data delivery and
user-friendly design lets oil and gas producers see
well, lease, and land activity with complete clarity.
“Tobin has established a solid foundation of trust
over 90 years and as part of P2 we continue to
build the future with our customers,” said J. Scott
Lockhart, CEO of P2 Energy Solutions. “We are
bringing new insights through machine learning,
visualization, advanced analytics, and value-added
solutions to meet the needs of the industry for
the next century and beyond. We are just getting
started.”
Tobin Data Layers
Through Tobin Data, companies can obtain well,
lease and land activity quickly and with pinpoint
accuracy. Tobin data covers several layers.
The Survey layer offers the most comprehensive,
continuous survey coverage in the industry,
covering 1.4 billion acres, 65,000 townships and
300,000 original Texas abstracts. Within the survey
layer, there are two types of grids.
The Jeffersonian Land Grid is used in 30 states
across the U.S., including states in the Rocky
Mountain region – home to many of today’s
hottest shale plays like the Bakken and Niobrara.
The Texas Land Survey Grid being the most
accurate base available due to Tobin. It ensures
that every line is veried digitally and visually. No
matter where the work is taking place, every line of
the map is remarkably accurate and aligned.
The Ownership layer allows companies to see
who owns the surface rights for each particular
parcel of land, giving them the detail needed to
position their lease outlines and manage property
assets. This eliminates the need to go to the
courthouse to obtain any of this information.
More than 200 counties are tracked, including 180
counties throughout Texas, Louisiana, Mississippi,
New Mexico, Pennsylvania and Ohio. It also
provides ownership data in 42 Oklahoma counties,
two Utah counties and two New York counties.
The Polygons calculate totals, volume, acreage and
distance geographically with Tobin Data sets.
The Lease layer enables companies to see
where competitors are leasing across the U.S.
before leases expire. The interactive data shows
critical insight into the mineral lease landscape
enabling better business decisions. This ensures
that companies can compete condently in the
hottest shale plays. Information can be obtained
on 750,000 leases in more than 250 counties across
the U.S. with coverage being constantly expanded
by the day. Lease activity points are published on a
nightly basis. All of the data is collected in person
from the courthouse daily so companies can
have condence that they are receiving the most
accurate and current data available.
The Well layer provides all the access companies
need on oil and gas permits, completions, and
plugs. It uses purpose-built accuracy software
and a multitude of data sources, including
high-resolution imagery, to hand-verify each well
location. The well locations are digitized using
a variety of sources by their expert geospatial
mapping specialists. Locations are veried and
adjusted using an array of mapping platforms,
such as satellite imagery, digital ortho-rectied
aerial imagery, GPS coordinates, well plats, line-
calls from survey or public land grid systems and
USGS topographic quads. Each well is digitized
to specic criteria and hierarchies, and specialist
then determine which digitizing platform best suits
locating and mapping the well. Each location is
supplemented by including a number of critical
well attributes, such as well operator, lease, and
product.
There are several risks associated with using free or
low-cost location data.
• Changing plans at the last minute for a well pad
because your map data is off. Or worse: placing
a well pad in the wrong spot.
• Learning that the neighboring wells are closer or
further than you expected.
• Being forced to terminate a well on somebody
else’s property.
• Drilling or starting production even though
neighboring wells are not producing.
• Not drilling a new well when neighboring wells
are producing.
In addition to the information itself, one of the
major benets Tobin offers is the way in which
it’s delivered. Through their single le delivery, the
data can be obtained within hours, instead of days.
There is no stitching, joining or relating required.
Employees can also monitor specic areas of
interest and if anything changes, they would
receive an email informing them of the change.
This gives them the ability to constantly monitor
and stay on top of anything that occurs, without
having to always spend time checking on the status.
P2 is raising the bar with their land management
software and AI. They are progressing quickly and
efciently while making positive growth changes.
They are impacting one of the most critical parts
of exploration and production, if not the most
critical part – the land. Without the land and
the plethora of information that surrounds the
acquisition of it, there are no oil wells being built
and no wells being built, means no oil is being
produced. Land knowledge is absolutely vital to
the success of this industry. What they are doing is
a game-changer and hopefully they don’t intend to
stop any time soon.
Invaluable Land Knowledge
Software and AI
By Sarah Skinner
OILMAN COLUMN
Oilman Magazine / May-June 2019 / OilmanMagazine.com
16
OILMAN COLUMN
Digital Twin Technology Adds a New
Dimension to Offshore Projects
By Thornton Brewer
Offshore makes a comeback. Bloomberg
reports that investors expect offshore
investment in 2019 to increase for the rst
time in ve years.
The greater offshore investment has also
led to higher demand for digital technology,
in large part to gain greater transparency of
workow processes and data. The digital twin
creates a virtual replica of the offshore eld,
allowing for smarter, more collaborative and
efcient eld planning and operations.
For many new projects, companies look to
implement digital eld twins from day one
to enable smarter business decisions from
planning through development. Oil and gas
operators and service providers already use
digital software to plan and build new elds
digitally in the cloud, see tremendous potential
to introduce new, more transparent digital
workow processes into their operations.
Global Collaborative Environment
Digital twin enables true workow
collaboration and information transparency
in offshore development. The digitized eld
data moves teams away from a traditionally
siloed work environment with a variety of
owned, non-integrated tools, applications and
data to a global collaborative environment.
Operators can now collaborate cross-
departmentally within the enterprise, as well
as with outside contractors as everyone works
from the same real-time data. Greater visibility
and collaboration leads to better business
decisions and greater safety procedures
with reduced stafng
requirements. Digital twin
technology uses Open Web
technology to access and
view the data at any point
no matter where you sit in
the world.
Additionally, big data signicantly transforms
the bidding process for oil and gas engineering
rms. Historically, the basic bidding process
captured brainstormed ideas from engineers
on ip charts and in PowerPoint and then
converted them into visuals via Visio,
Corel Draw and MS Paint. An outsourced
engineering house would then transform them
into Computer Aided Design, or CAD, les.
This legacy engineering design process limited
the EPC rms’ ability to meet tight design
schedules and implement late changes quickly.
Emerging technologies
are proving they
can generate
many more eld
concepts in a much
shorter time while
helping to eliminate
inaccurate options.
By uploading data to
the cloud, digital twin
technologies are able to
visualize subsea elds
and run computations
from a single
source of data. For
instance, McDermott
uses FutureOn®’s
FieldAP™ – a
FieldTwin™ platform
application to respond
far more rapidly and
efciently to new project
opportunities as well as
develop multiple concept proposals – in just
20 percent of the time it took to develop a
response in the past. The tool accelerates
project timelines by up to 80 percent during
the early concept and FEED (Front-End
Engineering Design) phases.
Data Transparency
The data transparency via visualization enables
teams to see more about their assets from
every vantage point and every point in time
via real-time 3D digital simulations. This
allows engineers to explore more ideas, more
rapidly, in collaboration
with colleagues all
around the world.
Through the power
of data visualization,
engineers examine
multiple possibilities
in minutes rather than
days, weeks or months required in years past.
This speed results in 30 percent reduction in
pre-feed eld design and signicantly more
successful bids for EPC rms.
Data Integration and Cost-effectiveness
Internal resistance to technology happens
because engineers fear the emerging tools will
not integrate into legacy systems. These new
technologies, however, are being designed
with integration in mind. Through an API,
these digital technologies are bringing expert
engineering systems data directly into a single
platform so engineers don’t have to close out
of one system to open a ow simulation in
another software.
Companies may budget cost-effective digital
platforms as an operational expense rather
than CAPEX (capital expenditure) with a
return seen immediately, i.e., $45,000 in cost
savings associated with outsourced drafters.
Traditional digitalization approaches can
involve signicant upfront CAPEX. IoT
devices, SMART sensors and robotic tools
require costly new equipment investments,
employee training and retrotting of existing
systems. The return on investment is difcult
to assess.
As offshore investment increases, companies
must adapt to gain competitive advantage
initially – and to remain competitive as digital
adoption rapidly progresses. Digital twin
technology can play a big part in moving the
industry forward for greater collaboration,
smarter eld development and enhanced
operations, all while reducing costs to retrieve
the oil more quickly.
Thornton Brewer is the digital experience
and marketing lead at FutureOn, a 2019
OTC Spotlight on New Technology®
Award recipient. For more on how we help
maximize the value of new elds, please
visit www.futureon.com.
FutureOn®’s FieldAP™ and FieldTwin™ create new elds digitally in
the cloud. FutureOn is the only digital solution provider to receive
the 2019 OTC Spotlight on New Technology® Award.
Digital twin generates a
virtual eld in the cloud to
offer greater transparency.
www.energyexposition.com
Oilman Magazine / May-June 2019 / OilmanMagazine.com
18
Downturn by Legislation
By Jason Spiess
On April 16 of this year, Governor Jared Polis
signed Senate Bill 181 into law after what many
consider one of the most controversial pieces
of legislation in oil and gas history, as it met
opposition from almost every Republican in the
state of Colorado and the energy industry.
The law took effect immediately, and changes the
Colorado Oil & Gas Conservation Commission’s
mission to prioritize health and safety over
industry development which at the time of
deadline, the COGCC had not implemented nal
changes.
Destenie McMillen, third generation senior
landman, is seeing the impact happen already, even
before the new regulations are set in stone.
“That bill was passed very quick,” McMillen
said. “I along with thousands of landmen, eld
workers, roughnecks, we all went and testied to
the Senate to really explain there has not been an
economic study to show what happens when say
60 percent of a county loses oil and gas revenues.”
McMillen continued citing ripples of impact
- local businesses, local governments, state
governments, county employees, just to name a
few. This is before she started citing the formation
of committees, school budgets and other local
government pontications.
A study commissioned by the Colorado Oil
& Gas Association (COGA) says the industry
contributes $1 billion in tax revenue annually
and employs 89,000 people in the state. Another
study estimated that if the new regulations were
to shut down half of new oil and gas production,
the state would lose 120,000 jobs and $8 billion
in tax revenue by 2030. The law also gives local
governments more say to regulate the industry
themselves.
A joint statement released by COGA and the
Colorado Petroleum Council after the bill passed
the General Assembly, said, “While a few critical
amendments were added that begin to address
some of industry’s concerns and provide a
degree of certainty to our member companies,
our industry remains rmly opposed to this
bill because it threatens one of the pillars of
Colorado’s economy.”
McMillen validated the energy organizations’
concerns, as she is heavily involved with industry
events and is hearing the same story from county
to county. And it is causing enough anxiety in
companies to take action.
“It’s kind of been a little bit of a runaround I
guess for a lack of better term,” McMillen said.
“Everyone is very nervous. I know of a company
that left the Western Slope two weeks ago. They
just packed up and moved their operations to
Oklahoma.”
This new environmental safety narrative and
legislation is even bleeding into energy-rich
Wyoming.
“The most provocative thing for me was the
district court judge who basically put a halt on
something like 500,000 acres worth of Federal
leases claiming that the environmental impact
study has not been done to his satisfaction,”
McMillen said.
McMillen said this is a quick switch in positioning
as she cannot recall a time in modern Wyoming
history where the court stopped a “bought and
paid for” mineral lease rather than validate them.
“That’s a little alarming to me,” McMillen said.
McMillen’s concern is well warranted. Back in
Colorado, Governor Polis is beating the war
drums against energy louder every day.
“In all of the Senate Bill 181 it was about the
environment, health and safety and regulation,”
McMillen said. “Then last week he made an
interesting comment that no one had said before.
He called it the War on Oil and Gas.”
This comment comes at an interesting time.
America has reached a point where we can use
words like “energy independence”, exporting
oil and are building more pipelines to ow more
energy. While the world is talking about the
booming Permian Basin and Bakken, companies
are experiencing quick impacts from the new law.
“The third-party consultants and businesses will
be the rst ones to go. It is the same as when a
downturn happens,” McMillen said. “Only this
downturn in Colorado is caused by legislation
because the rest of the country is booming to the
tune, we have oil exports.”
McMillen continued to explain how a regular oil
price downturn you have to adjust and see the
signs as the industry trickles downward. She said
in Colorado it is totally different because it is like
“someone just dropped a hammer.”
“It’s a sad thing when you see how the counties,
state and federal governments were working
together for this common goal and now with the
stroke of a pen it completely changes everything,”
McMillen said. “This was a huge accomplishment
for our country, but some people do not see it that
way.”
And right now, those people are in power in
Colorado. And they have the ear of a federal judge
in Wyoming.
Joe Dancy, Associate director, Maguire oil and gas
institute, Southern Methodist University, believes
the new red tape introduced to the industry will be
bad for the oil and gas business.
“The risk of additional controls on oil and gas
development will certainly lessen the value of the
minerals as well as any oil and gas leases that are
granted,” Dancy said. “Additional costs, delays
in development, and possibly lease expirations
all have to be factored into the oil and gas
transaction. This is not good for mineral owners,
companies, or the state.”
William Prentice, CEO, Meridian Energy Group,
has felt the pinch of regulations and legislation
too. After an unexpected two years of regulatory
legal battles only to have their science and
engineering validated in numerous times by the
state health departments and even the federal
Environmental Protection Agency.
OILMAN COLUMN
Top Women in Energy Award Ceremony Women’s Energy Network - Colorado Chapter
Founding Board
Women’s Energy Network -
Colorado Chapter Board 2018
Destenie McMillen and Colorado House of Representative
Polly Lawrence at an energy industry meeting
Oilman Magazine / May-June 2019 / OilmanMagazine.com
19
OILMAN COLUMN
“It’s been very frustrating because we expect
people to look at us and see people who are
trying to do the right thing, which we are.”
Prentice said. “We don’t think we get credit for
that enough.”
Prentice has always invited transparency and
hasn’t faulted anyone for asking the question,
however, after multiple victories and validations,
the oversight organizations should take notice.
“The latest set of court challenges, and I get
lectured all the time for not commenting on
legal stuff, well just reading through this recent
appeal there are factual statements in there that
are simply not true,” Prentice said. “They have
proven to be untrue for the last several iterations.
It’s like people do not give us credit or learn
anything from the previous proceedings.”
And unfortunately for the industry, as long
as the elected ofcials can be controlled by
fear-mongering health and safety iconoclasts,
unnecessary revenue hemorrhaging may be the
“new normal” for parts of the industry as the
“war on oil” begins and states can now create
quick downturns by legislation.
Marked by intensied volatility due to
continuous sharp oil price uctuations, the oil
market experienced its longest and deepest
slump in 2014-2016. However, following the oil
production cut deal, the prices recovered for a
brief time and reached an all-time high in 2019.
The oil production cut deal between OPEC and
allies, including Russia, coming to an end in June
2019 and the uncertainty about oil prices has
spiked multi-fold. Achieving stability in the oil
market is imperative; it does not come without
challenges.
Many practitioners, academicians, and
policymakers conducted scalable studies
to examine the underlying economic and
geopolitical factors of oil price dynamics. The
critical determinants of the cyclical behavior of
oil markets are supply and demand, global real
money stocks, inventories, activities of nancial
investors in the oil futures market, developments
in nancial markets, geopolitical crisis, and
interest rates.
The resilience of the oil-rich economies to the
oil crisis varied with the economic fundamentals.
Countries that have a more scal policy, higher
foreign currency liquidity buffers, diversied
export base, exible exchange rate regime
respond better to oil shocks and have lowered
exposure to oil price uctuations.
Apart from these factors, technological
advances emerged not less signicant than
the economic fundamentals impacting the
response to oil shocks. Shale oil technology, a
combo of hydraulic fracturing and horizontal
drilling technology coupled with large-scale
viable commercial exploitation in crucial basins,
such as the Permian and Appalachian, have
propelled the overall unrivaled crude oil and
LNG production in the United States to over
11 million barrels (bbls) per day and over 100
billion cubic feet per day, respectively.
Using advanced exploration and extraction, the
shale industry achieves higher efciency gains
and are capable of break even at low crude
prices. The recent bids of Chevron and
Occidental to acquire Anadarko are driven by
the potential of Shale to yield higher prots
even at a lower price of crude oil. Such a
phenomenon involving a giant corporation
acquiring small companies using advanced
technologies also generates signicant M&A
deal opportunities in the upstream sector,
and there can be a surge in transformative
acquisitions in 2019. Moreover, shale oil has
an enormous potential to drive a signicant
increase in supply over the next decade owing
to rapidly declining costs of extraction and
potential for discovering new elds. Companies
relying on more modern technologies such as
microwave fracking, drilling pads coupled with
Automatic Robotic Drilling can drive down costs
of a barrel produced and boost prot margins
amid an oil crisis.
In addition to new oil and gas production
technology, blockchain technology also has
tremendous potential to mitigate the adverse
effect of price uctuations. Blockchain, the
foundation of cryptocurrency Bitcoin, is a ledger
capability providing an indispensable solution to
trade and settlement inefciencies and reduce
the risk of fraud while enabling full end to end
visibility in that business network.
Blockchain has several use cases in the oil and
gas industry, and many companies have viewed
this as an opportunity to transform the business
and navigate the complex landscape. Blockchain
users including Chevron, BP, Equinor, Reliance
an Indian oil and gas company, Total a French
oil and gas company joined together to establish
the Vakt, a digital transaction platform backed by
JP Morgan’s quorum.
The oil and gas supply chain is byzantine as
it includes participants from different global
locations and under complex regulations. As
multiple suppliers participate in such a complex
chain, various linkages in the supply chain
become sources of origination and escalation of
risks rendering most of the business transactions
inefcient, costly and vulnerable to errors.
The benet of this technology is unparalleled
as it mitigates the risks and drives high business
protability by reducing cash conversion cycle,
overhead and a number of cost intermediaries.
Using smart contracts, digital certications and
digital compliance the blockchain technology
brings about expeditious transactions in a trusted
mode.
These technological advances enabling low costs
of production and drilling, as well as expeditious
transactions with minimal errors and enhanced
transparency will facilitate the companies to
overcome any future oil price shocks, while
maintaining high-prot margins and reducing
the downward pressure on the economy.
Amandeep Kaur works
as a Financial Accounting
professional at Scanoleum
an oil and gas startup
company focused on Oil
and Gas trading, Drilling
Services and Marketing Oil and Gas
equipment. She dedicates a signicant time in
monitoring Oil and Gas markets, identifying
opportunities as well as managing risks and
compliance. She has a keen interest in writing
about Oil Markets, M&A activities in the Oil
Industry, and Advanced Technologies to help
oil and gas businesses. She has an MBA in
Finance and Marketing from the University
of Delaware.
Technological Advances Cushion Oil Crisis
By Amandeep Kaur
Photo courtesy of everythingpossible – www.123RF.com
Oilman Magazine / May-June 2019 / OilmanMagazine.com
20
Oil and Gas Measurement Automation
is Key in Optimizing Production
By Duane Harris
With commodity prices in ux, the industry seeks
to adopt new strategies to increase efciency and
optimize existing assets. Producers are looking for
new technologies to enhance their organizational
agility and, ultimately, improve recovery rates in
the high-decline rate wells.
As the industry is putting the latest technology
to work, measurement departments have found
themselves directly in the center of the digital
transformations that are sweeping the industry.
They are supporting more agile and digitized
organizations. That means the ability to provide
instant access to up-to-date measurement
information throughout the organization is
required to stay competitive, all while maintaining
one source of truth.
Sophisticated measurement automation
applications have been a critical enabler
of the digitalization and business process
transformations that production operations have
put into practice. The wide variability in well and
pad production necessitates accurate and timely
measurement data as well as the ability to monitor
and optimize production.
How can measurement departments more
effectively use the information on ow rates and
well performance to balance their systems and
optimize production?
Measurement Automation
As measurement processes have become more
complicated, automation has become a key
focus in the oil and gas industry. Understaffed
measurement teams are looking for software
solutions that help them work more effectively,
utilizing automation to synthesize the vast domain
expertise and complexities into manageable
workows.
Automation allows new measurement
professionals to tackle the system balance process,
which has become much more complicated
with the numerous mergers, acquisitions, and
divestitures over the years. Both the organic and
aforementioned inorganic methods of company
growth have led to diversied operations, where
the measurement departments must track
multiple uids such as natural gas, NGL (natural
gas liquids), and heavier hydrocarbons.
These systems will often have a variety of
meters, ranging from the traditional orice,
positive displacement, and turbine types to
newer technologies including cone, Coriolis,
and ultrasonic. Installed on top of those meters
is a broad assortment of correctors, gas ow
computers, and liquids ow computers.
An operation that tracks multiple uids must
consolidate all the information from the different
technologies, verify the accuracy, apply required
uid quality samples, and then recalculate as
needed. Only when those steps are complete can
the measurement department attempt a system-
wide inventory balance.
Automated system balancing is a powerful tool
that can highlight anomalies in the database
rapidly as well as in the oil and gas system.
Unaccounted-for losses are exposed and
pinpointed through techniques such as system
segmentation, and issues are brought to light, for
example, equipment failures, leaks, and deviations
from standard operating procedures.
Recent changes to the API Manual of MPMS
(Manual of Petroleum Measurement Standards)
include the introduction of three-dimensional,
physical properties tables and a completely
updated 2nd Edition to Chapter 21.1, Flow
Measurement Using Electronic Metering
Systems—Electronic Gas Measurement. A
modern measurement application ensures all
functionality stays current with all applicable
standards.
FEATURE
With FLOWCAL Enterprise measurement software, the user can view a multitude of ow data information. The Volume
Editor allows the user to view hourly, daily, batch and monthly ow data as well as characteristic and analysis data.
Photo courtesy of Quorum Software
Oilman Magazine / May-June 2019 / OilmanMagazine.com
21
FEATURE
Measurement automation applications also
provide editing, reporting, and data export
capabilities that ensure compliance with audits,
industry regulations, and standard operating
procedures. Data validations and system
balancing ag data anomalies, account for
missing data, expose sources of unaccounted-
for inventory, and maximize the integrity of the
measurement information.
Furthermore, the measurement applications
integrate measurement ofce operations with
eld technician tasks and allow everyone to
work from a common database and reports.
The integration signicantly reduces potential
sources of error and increases efciency across
all departments.
Data Integrity
Data validation is critical for today’s oil and gas
companies to reduce their risk prole and ensure
accuracy in reporting to both stakeholders and
external authorities. This is possible because
measurement automation applications employ
sophisticated data validation capabilities. The
result is an overall improvement to measurement
information integrity that not only meets industry
and regulatory audit requirements but directly
impacts the bottom line.
A data validation process ags potential
anomalies and brings them to the attention of
the measurement staff. Numerous checks and
balances are applied to owing parameters, meter
characteristics, quality information, and rolled-up
historical averages and totals.
For a measurement analyst, this can save
signicant time that would otherwise be spent
sorting through large amounts of data to locate
problems long after they occur. Instead, the
system ags the issues and analysts can work to
solve them immediately.
Information that fails a validation test creates
an exception in the measurement system, which
are reviewed by the measurement staff, typically
daily. Through this review, the team identies and
resolves most issues on the same day.
Issues are tracked throughout the year to
determine if equipment needs to be upgraded or
replaced or if a new design is needed to resolve
an ongoing problem. Before closing each month,
all exceptions are either resolved or agged as
process-pending.
Conclusion
It is necessary to understand ow rates and
individual well performance to optimize
production, enhance production economics, and
improve recovery rates in unconventional wells.
The increase in variability and complexity in
well and pad productions are driving companies
towards automated systems and more accurate
data for better operational monitoring and
optimization.
Modern measurement automation software
encompasses the vast expertise that only the
most accomplished professionals held. The
applications process the considerable amount
of data that is provided by measurement
equipment at remote well sites and presents it
to management in an effective manner. Also,
users benet from improvements to compliance,
enhanced production, increased asset efciency,
and lower operating costs.
Duane Harris, an experienced
energy sector professional,
has more than thirty
years’ experience in gas
measurement technology with
a focus on data integrity and
corporate measurement procedures. He gained
much of his experience as a Measurement
Manager for a major pipeline company.
There, he was responsible for overseeing all
measurement functions, ensuring data integrity
from the eld to the corporate ofce.
The Rollup Viewer shows accumulated hourly, daily and monthly period totals for meters and locations such as production
well sites.
The NGL Balance Viewer allows analysis of NGL balances. It has several options for data viewing including the daily and monthly time frames shown here.
Oilman Magazine / May-June 2019 / OilmanMagazine.com
22
Last year’s tumultuous oil prices saw WTI
and Brent both start the year at over $60 for
the rst time since 2014, the benchmark year
for pre-crash
prices. Hopes
of a true price
rebound began
to grow as both
commodities
hit four-
year highs
several times
throughout
2018. For
an online
archive of how
intense the
hype became,
simply search
“will oil prices reach $100 again.” The result
is pages upon pages of industry and nance
headlines examining the possibility of $100
barrels — the overwhelming majority of which
were published in 2018. While the consensus
was split, optimists were about to learn a lesson
in false hope. WTI and Brent closed the year
well below $60 per barrel, prompting the U.S.
Energy Information Administration (EIA)
to reduce both its 2018 and 2019 forecasts in
early December. To add insult to injury early
this year, 2019 forecasts were further reduced,
along with 2020 forecasted prices. If additional
evidence was necessary to illustrate that low
prices are the “new normal” for the O&G
industry, Q1 of 2019 provided a solid case.
How the Biggest E&P Projects Safeguard
Prots
Logically, cost discipline has been the dominant
business strategy of O&G producers since
2014. Any hope of realizing prot in the face
of dwindling revenues required signicant
reductions in what was already one of the
biggest upstream cost risks: operational costs.
The upstream companies that were able to
weather the
latest price crash
found ways
to trim the fat
and implement
lean operating
principles.
However, this
was not the
case for the
biggest ventures
in oil and gas
extraction:
offshore rigs.
Whether it was a
response to the
2008 crash or simply the capitalist pursuit of
prot, stakeholders in these mammoth projects
had already identied, rened and implemented
new ways to reduce operational costs.
How did they manage? By embracing the
next step in the evolution of industrialization:
digitization.
It was mid-2014 when McKinsey & Company
published a whitepaper titled “Digitizing Oil
and Gas Production.” Using North Sea offshore
rigs as benchmarks, they observed that while
production efciency had dropped in the
past decade, the performance gap between
industry leaders and all others had nearly
doubled between 2010 and 2012. Looking
for what sparked the differentiation, analysts
examined the role of technology. Production
was considered “digitally-capable” at this point,
with any average offshore rig using upwards of
40,000 sensors to collect massive amounts of
complex data. So how did the leaders manage
to pull away from the pack?
By successfully
integrating all that data.
The E&P companies that were able to use
data effectively increased production efciency
by ten percent and saw $220 million to $260
million dollar increases to their bottom line.
And remember, this shift occurred
before
the 2014 crash in oil prices. The advantages
gained through production efciency became
exponentially more valuable in the face
of shrinking revenues as global oil prices
plummeted.
What Does “Successful Integration of
Data” Mean?
Data can be used in a lot of ways, from
reducing unplanned rig downtime by
informing predictive maintenance schedules,
to enabling the complete automation of
complex, unconventional drilling maneuvers.
In fact, automation (the conversion of manual
processes to automatic ones) is presently the
ultimate means of utilizing data to increase
efciency. Where the Industrial Revolution
was marked by the use of iron to enable
mechanization, the digital revolution of the 21st
century requires vast amounts of data to enable
the next step in our tech evolution: automation.
Five years ago, when McKinsey & Company
identied automation as a “clear competitive
imperative” for the O&G industry, prices were
over $100 per barrel and the case for large
capital investment in new tech was a hard sell.
However, in the new normal of sub-sixty dollar
barrels, the urgency of automation is clear.
Avoid a Cart-Before-The-Horse Scenario:
Automation Is Data-Driven
As previously mentioned, automation requires
data - and lots of it. Operations such as rigs
and reneries are rife with data-capturing
Follow The Leader: Examining How
Industry Giants Reduced Operational
Costs By Going Digital
By Shallan Grisé
O&G producers and service companies don’t
need to reinvent the wheel in order to reduce
operational costs. The most capital-intensive
projects in the industry have proven digitization
as a model for reducing operational costs. In this
article, we take a look at what analysts learned
from the industry’s digital pioneers before
examining how to scale the same principles to
reduce costs and safeguard prot margins in the
face of unpredictable market prices.
OILMAN COLUMN
Oilman Magazine / May-June 2019 / OilmanMagazine.com
23
opportunities: every sensor, gauge and meter
can go from simply displaying information
to storing it. However, indiscriminate data
collection is unmanageable and will certainly not
lead to production efciencies. Before the rigs
examined by McKinsey & Company increased
prots by $200 million through intelligent data
integrations, stakeholders began with a vision
for how the information would be used. This
way, only digital outputs that furthered the end
goal were selected for collection.
Scaling Down: The Path to Automation for
On-Shore Producers and Service Companies
Various automations are available to O&G
production and service companies without
the need for data collection or other R&D.
These ready-made solutions reduce operational
costs for some common standard processes
such as executing a slide or scheduling tool
maintenance. If you can purchase the tech,
you are able to reduce operational costs. These
products are good for your bottom line but they
do not result in a true competitive advantage.
Pulling away from the pack and creating the
signicant production gap achieved by the
leaders in our case study requires vision,
creativity and asking the right questions. Where
are the opportunities in your operations? Where
is data not being captured? Or, which processes
fail to leverage captured data? These kinds of
questions produced a proven digital model
that also performs at smaller scales. Careful
examination of your processes will also lead to
a well-informed digital roadmap for reducing
operation costs. Consider what can be learned
from the timing of the industry leaders in the
McKinsey & Company whitepaper as well.
Rather than reacting to market changes, these
innovators made proactive capital investments
before the need was even apparent.
There’s another advantage to following in the
footsteps of giants — you don’t need an in-
house team of programmers to create bespoke
software tools. Thanks to third party specialists,
every step of digitization — from the overall
vision to eld execution — is guided by experts.
The management of eld crews is one of
the biggest opportunities to capture data and
improve processes through automation. Even
as the digital revolution permeates all other
aspects of E&P, eld operations remain heavily
dependent on paper, leading to revenue leakage
and high operational costs. The disconnect
between the eld and the leadership team
results in information lags and errors, making
effective cost management impossible.
At Aimsio, we’re familiar with the challenges
you face when it comes to managing remote
eld operations. We also happen to be
specialists in creating digital solutions for
O&G producers and service companies. To
see how our platform makes real-time cost
management possible by capturing data in
the eld, head over to www.aimsio.com.
OILMAN COLUMN
Continued on next page...
Switching from one major to another while
in college can be a difcult decision and
process. However, switching from a more
simple industry to a complex industry,
like the oil and gas industry can prove to
be even more difcult. The oil and gas
industry, once known for its traditionalism
and alignment to few demographics, has
quickly been evolving and appealing more to
a variety of demographics, including recent
graduates. With technology, big data, and
analytics playing a larger role in the industry,
more individuals have been inclined to start
career paths pertaining to oil and gas, such
as petroleum engineering. Two individuals,
Siddhartha “Sid” Sen and Alan Alexeyev
have both launched successful careers in the
oil and gas industry and currently mentor
graduate students looking for ways to enter
and transition into the oil and gas industry,
as they once did. Both Sen and Alexeyev
provided their perspectives on what the
journey is like entering the oil and gas
industry, what graduate students can expect
to face upon entering the industry and how,
with a rise of diverse individuals entering the
oil sector, the industry is about to experience
signicant change.
When Sen was asked what inspired him to
start a career in the oil and gas industry,
he responded “The oil and gas industry is
a global platform which brings together
people from various educational backgrounds
and skill sets to solve problems related to
the overall energy mix for the world and it
touches many aspects of our day to day lives.
It was this fact that led me to start a career in
the oil and gas industry.” Sen, originally from
Mumbai, India, came to Houston, Texas, to
pursue his MBA at Rice University. One of
the reasons he selected Rice University for
his MBA was its proximity to the oil and gas
industry and the fact that it was based in the
capital of the energy world.
As for Alexeyev, he began his career in the
oil and gas industry by attending the SPE
(Society of Petroleum Engineer) events and
conferences and talking to people and friends
about the industry and the profession. “I
liked it a lot – the way people worked, the
importance of the profession, exibility
and opportunities it can offer. I somehow
felt connected to the industry and people in
it and wanted to be a part of it too. Plus, I
always had a general technical education, so
I thought I could do engineering as well,”
Alexeyev explained. Alexeyev originally
majored in Mathematics, but decided
to pursue a second bachelor’s degree in
petroleum engineering at the University of
Wyoming. He obtained a master’s degree in
Petroleum Engineering from the University
of North Dakota.
With both individuals having established
their own careers in the oil and gas industry,
Transitioning from an Outside Industry
into the Oil Sector: Recent Graduates
and Petroleum Engineering Education
By Tonae’ Hamilton
Oilman Magazine / May-June 2019 / OilmanMagazine.com
24
OILMAN COLUMN
they
now mentor and lecture graduate
students looking to enter the industry, as
they once did. When asked about the biggest
challenges that students may face when
trying to break into the oil and gas industry,
Sen explained that the foremost challenge
they [students] face is having clarity on what
they want to do. “There are innumerable
avenues to pursue and having a fairly good
understanding should help students in the
long run. I always advise students to spend
time talking to people from the industry
and understand their job roles,” Sen further
explained. He also stated that having an idea
of what you want to do will provide you
the opportunity to develop a plan and work
towards it. As for another challenge that
students face, Sen shared that in his mind,
the second challenge is meeting the right
people.
Extending on the conversation of students
breaking into the oil and gas industry,
Alexeyev was asked if he believed the
industry had taken initiatives to smoothly
transition young professionals into the
oil sector. He expressed how the industry
could provide more engineer-related jobs
for students. “Even if internships are scarce,
they could host weeklong job-shadow
events, where students could observe what
it takes to work either in the ofce or on
a eld location even for a brief period of
time,” Alexeyev expressed. He stated that
such events would boost the understanding
of petroleum engineering classes and the
industry by a lot. “Maybe have some sort
of weeklong boot camps set up on drilling
rigs or in the ofce, make that part of the
curriculum. I foresee that would be the
next big step the industry can take to help
the younger generation. This in turn will
produce better quality students just because
they will understand it much better upon
graduating,” Alexeyev further explained.
Alexeyev was also asked if and why it is
important for more young adults to be in
the oil and gas industry. “Yes, it is important
and SPE is at the front of all of this,” stated
Alexeyev. “There are local and university
chapters everywhere that organize the
learning and volunteering and social events,
as well as sister organizations that are also
closely related to oil, like the AADE, AAPG,
AGU, ARMA, SEG, etc. It’s really all part of
one big oil-related industry and points out
how different disciplines can work together
and help each other,” Alexeyev further
explained. He described how during those
organizations’ events, young people and
students are exposed to those who have been
in the industry longer and thus, can learn
from them. “They can see the expectations
of the industry and how they can t in. It’s
great for networking, great to see what new
technology and trends other companies are
doing. There’s just so much interesting stuff
out there,” Alexeyev expressed.
Continuing the conversation on graduate
students and young professionals entering
the oil sector, Sen was asked whether he
believed the incoming of graduate students
and individuals from other industries into the
oil and gas industry would have an effect. He
was additionally asked if an inux of diverse
demographics would be advantageous
to the industry? Sen answered, “I am a
rm believer that a diverse demographic
community will be benecial to each and
every one in the industry. I also believe that
diversity already exists within this global
industry.” He further explained how the
oil and gas industry is in the process of
implementing effective ways to harness data
and information for operational efciencies.
“The incoming batch of graduate students
will bring valuable skill sets to achieve this
and thus should be capable of impacting the
future of the industry. Diversity will help
bring varied thought processes, views and
expertise together, which will be benecial to
the oil and gas industry,” Sen expressed.
On the topic of transition, Alexeyev was
asked whether he believed an individual’s
transition from another industry to the oil
and gas industry would provide difculty or
opportunity, such as a diverse perspective.
He responded, “The oil industry has many
people working with different but related
STEM (science, technology, engineering, and
math) programs. I think nowadays we’ll be
seeing more computer scientists/engineers
working in our industry too, because of
the shift to digitization, data analytics, and
automation.” He expressed how he would
advise that the petroleum engineering
curriculum add a few data analytics and
computer programming courses as a
requirement to reect the current industry
changes.
Continuing the conversation on industry
transition, Sen was asked what advice he
gives to individuals looking to transition into
the oil industry from graduate programs or
other industries. He stated “My advice to
anyone trying to transition into the oil and
gas industry would be to try and identify
the challenges that the industry is facing
currently. Then, develop skills which would
help address or work on these challenges.”
“The oil and gas industry is looking to better
harness the data that is available and use
it to increase efciencies, and anyone with
the skills to enable or achieve it will be in
demand,” Sen further explained.
When asked what advice he gives to students
who initially express interest in the oil and
gas industry, Alexeyev stated that for those
interested in an oil and gas career, “I’d say
denitely choose a major in STEM, whether
it is a general engineering (civil/mechanical/
chemical) or science (math/CS/physics)
major, just to have exibility in case you end
up not pursuing oil so you can still apply
yourself in other industries.” He expressed
how students could take introductory
petroleum classes which could serve as
electives. “That way, they [the students]
wouldn’t lose time and classes in case they
decided not to pursue it; it’s all about being
exible,” explained Alexeyev.
Photo courtesy of khunaspix – www.123RF.com
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Oilman Magazine / May-June 2019 / OilmanMagazine.com
26
OILMAN COLUMN
Scale Sand Production with
Modular Natural Gas Power
By Mike Mayers and Josh Haugan
To continue to reduce costs, frac sand companies
and oil companies have started to build their
own frac sand mines in the Permian Basin,
located mostly in the western part of Texas and
in the southeastern part of New Mexico. While
the quality of these in-basin frac sand mines
is slightly lower than Wisconsin White Sand,
operators cut millions from their capital budgets
by supplying their own frac sand closer to their
production sites in West Texas.
This trend marks a signicant shift in the
sand mines industry, as in-basin frac sand now
accounts for a majority of the market, which has
started rail shipments out of the Permian Basin
and dissipated frac sand shortages.
However, access to power grids remains limited.
It can take a utility company anywhere from 12
to 24 months to set up the infrastructure re-
quired to power a frac sand mine; however, after
investing $100 million in a new mine, suppliers
cannot afford to hold production until power
becomes available from the utility company.
Modular natural gas generators bridge the power
gap, enabling mines to start production and enter
the market before the installation of permanent
utilities. Rental power companies and owners
and contractors’ electrical engineers work closely
to develop a sophisticated, cost-effective and
environment-conscious power plan for each
mine that delivers the following benets:
Low-cost Natural Gas
Mine operators seeking alternatives to diesel nd
natural gas to be an attractive option. Natural
gas cost 40 to 45 percent less than diesel and
since they need to supply their sand dryers with
natural gas the use of natural gas generators is a
no brainer.
However, the costs associated with natural gas
generation, installation and operations, as well
as the required maintenance of these complex
installations, prove far less than the cost to hold
production until permanent power is available,
which can take years. In fact, multiple Permian
sand mine developers are already using 83
megawatts of natural gas power in a market
previously dominated by diesel.
Reduce Environmental Footprint
Over the years, many local governments and
authorities have raised concerns about the long-
term continuous use of diesel generation because
of NOx pollutants. Tighter regulation means
sand mine developers are expected to explore
alternative options to minimize energy waste,
reduce greenhouse gas emissions and improve
air quality.
Mine operators nd natural gas to be a good
option for environmental reasons because natural
gas emits roughly 30 percent less carbon dioxide
than diesel fuel according to U.S. Energy Infor-
mation Administration. With the emergence of
lean-burn engine technology, natural gas power
generators also meet the U.S. Environmental
Protection Agency’s emissions regulations.
One Size Does Not Fit All
Projects vary greatly and so must power
congurations to achieve each unique site’s needs
and required redundancy levels. Thanks to a
well-engineered power solution, the sand mine’s
power capacity can ramp up or down, or the
diesel can be swapped out for natural gas should
it become available later.
Also, gas-powered generation can install a
redundancy of N+1 to achieve 100 percent
uptime should a generator fail or to allow a
generator to be serviced every 30 days for
maintenance, as required. A sand mine operator
certainly doesn’t want to shut down or reduce
production due to routine maintenance on a
generator.
Grounding
Inadequate grounding and ground testing leaves
personnel and equipment at risk and doesn’t
meet Mine Safety and Health Administration
requirements. The process of accurately
measuring ground resistance is essential to verify
proper grounding and ensure the protection
of people and equipment. Proper grounding in
highly resistive soil such as sand is much more
difcult than in other materials like dirt or clay.
Certication of correct grounding in large power
grids such as these usually calls for a different
method of testing.
Remote Monitoring
Given the off-grid locations of most mines, it
is essential to have a remote monitoring system
in place to monitor and verify the operation of
the power system. Remote monitoring alerts
engineers immediately of an issue and allows
for swift and focused decision-making before a
costly problem or worse, downtime can occur.
Such an incident can cost a mine up to $15,000
an hour. The 24/7 monitoring of the installa-
tion, operations and required maintenance of
these complex power systems enable operators
to devote a larger share of capital to other mine
projects.
Natural gas provides cost-effective, sustainable,
exible and dependable power for frac sand
mines waiting on permanent power. Mines can
start up to almost a year ahead of schedule
thanks to modular natural gas power, potentially
generating $100 million of revenue in 11 months
for the operator.
Mike Mayers is a business development
manager specializing in the frac sand industry
for Aggreko, based in Houston, Texas, and
Josh Haugan is a business development
manager also based in Houston. Call Aggreko
at 1-800-AGGREKO (1-800-244-7356) or
visit www.aggreko.com whenever you need
help.
New frac sand mines speed to market with natural gas-powered generators
Oilman Magazine / May-June 2019 / OilmanMagazine.com
27
In fracking, there is the initial
capital investment, however,
to keep production at a constant
output, capital expenditures are
needed every year for DCET
(drilling, completions, equipment
and tie-ins). This reduces the
net prot, as the payout term
is always present.
Photo courtesy of 汤 石 宏 – www.123RF.com
David Sealock, CEO of Petroteq Energy
spoke with OILMAN’s editor, Eric Eissler, at
length about the company’s innovative oil sands
extraction technique which is environmentally
friendly because it does not use water in the
extraction process.
Crunching the Numbers
When you think about the costs of buying
capital equipment, there are high associated
costs with it that makes many executives
reconsider purchasing new equipment until
it has been fully depreciated and used—in
most cases—well beyond their intended life.
However, according to Sealock, “The capital
cost to construct PQEs proprietary CORT
(clean oil recovery technology) is the lowest in
the oil sands mining sector at approximately
$10,000 per owing barrel.” He continued,
“Conventional oil sands mining extraction
capital costs are four and ve times this
amount per owing barrel. The reason for this
is that our CORT does not use water in the
process.” Whereas, the
conventional oil sands
mining operations spend
a massive amount of
capital on water handling
and treatment, however,
it does not alleviate the
environmental issue of
the tailing ponds that are
created by this process.
Drilling down further
into the costs aspect,
Sealock pointed out that
Petroteq’s process is much more favorable than
fracking cost on both levels: capital costs and
operations costs. In terms of capital costs, “our
facilities are ‘build once and produce for multi-
decades’. For example, our 1000-barrel-per-
day facility in Vernal, Utah has the resources
available to produce for over 4 decades.” This
is a one-time investment on capital equipment,
with a massive ROI over a multi-decade term.
Regarding operations costs, based on
economies of scale of the daily production will
be constant at $25-barrel-of-liquid-equivalent
when we are producing more than 4,000 barrels
of oil per day. Sealock further explains the
multi-decade advantage, “as our operations are
multi-decade, we can keep our costs
constant as our operations stay the
same. With fracking, in my view, there
is uncertainty if a constant cost base
can be achieved, as there are more
elements that are needed – access to
water, fracking sand, etc. I think that
the industry will see more variability
in fracking that our oil sands mining
process provides.”
Furthermore, while Petroteq cannot
control oil commodity pricing, the
company is focusing on what it can
control and that is operations costs. As
Petroteq heads into the 2nd half of
2019, the company will look at hedge
options for production as needed
through forward market sales.
The First Operational Facility
The rst CORT facility has been up and
running in Vernal, Utah.
With the success of the
pilot plant and the current
production at Vernal,
Utah, Petroteq had the
engineering data and the
continuous operations
experience to apply for an
additional 3,000- barrels-
of-oil-per-day expansion.
Sealock highlights its
production numbers
by saying that “this will
increase our production
to 4,000-barrels-of-oil-per-day and as we
expect State approval in the very near term,
we hope to have this 3,000 barrels of oil per
day expansion built and commissioned by Q1
2020 and in full operations by Q2 2020. This
expansion will be the building block on how
we will expand our production operations on
our other assets as well as local and global
potential licensing and or joint ventures we are
in discussions with.”
Growing Interest and Expanding
Blockchain Technology
General interest in the CORT system has been
on an upward tread. This is due, in part, to the
fact that there is an operational CORT facility.
Technology has and will always be the catalyst
that increases production at lower cost and in
a much more environmentally favorable way.
Petroteq’s CORT is this type of technology and
it will change the way that oil sands mining is
assessed in the future. Not only does Petroteq’s
CORT reduce costs for oil sands extraction,
both on a capital expenditure and operations
costs basis, the key to the process is that it uses
much less energy than many other methods of
harvesting oil sands hydrocarbons. “Because it
uses no water and has virtually no GHG emis-
sions, our CORT has environmentally efcient
environmental goals and is very synergistic for
the industry,” Sealock summed up.
Petroteq’s Blockchain
While Petroteq has been using aspects of the
PB (Petrobloq Blockchain) operations in our
capital expenditures, the focus on Petrobloq
Blockchain has been managed by Marcus
Laun, our Business Development director. The
development of PB has been more centric
to our work with vendors, our work with the
State and in the future, with potential business
partners. Since it launched around this time last
year, there have not been too many updates
as to its progress. It can be assured that the
blockchain development has been kept under
wraps in order to keep competitors from
gaining any inside information as to what the
company is developing.
Waterless Oil Sands Extraction Process
set to Improve Oil and Gas Industry
Environmental Track Record
By Eric Eissler
OILMAN COLUMN
Oilman Magazine / May-June 2019 / OilmanMagazine.com
28
OILMAN COLUMN
Be Aware of the Modern Day Snake Oil
By Jason Spiess
The founder and CEO of BMA Biotech,
Mark Bullock is no stranger to the oil and
gas industry. Both Bullock’s step-father and
father-in-law have both worked in the industry
for over 40-years. So, it is little wonder how a
small-town boy from the United Kingdom is
now living in Sugar Land, Texas and providing
highly effective products and sustainable
services to the O&G industry.
“BMA Biotech is a family owned company,
with long and established ties in the oil and gas
industry,” Bullock said.
To aid Bullock in the development of his
rst range of oileld chemicals, he built up
a team of scientists and petroleum engineers
who all had considerable experience within
the industry. This would ensure that not
only were BMA Biotech’s oileld chemicals
highly-effective in their application, but also,
it would make sure that the products were
sustainable and reduced risks to health, safety,
and the environment while being 100 percent
biodegradable within 75-days.
Bullock said within a few short weeks of
the release of their newly developed oileld
chemicals in early 2017, their professional
network and new clients within the industry
begun to voice concerns regarding a number of
oil spill cleanup products used in the industry,
which was akin to snake oil.
“Our clients continually chose BMA Biotech
to undertake eld assessments and the
implementation and execution of treatment
plans, as all of our eld personnel have
extensive site evaluation and both soil and
water remediation treatment experience, in the
continental United States, United Kingdom,
Europe, and certain regions in the Mid-East,”
Bullock said. “I know it is different in every
state and country, but in Texas it is called the
Responsible Party. Basically the company that
causes the spill, for lack of better words, is the
one legally on the hook for the clean-up.”
Bullock listed off a few PT Barnum-esque
claims he was aware of, which ranged from
turning crude oil into non-harmful sand to
other spurious claims which were scientically
impossible.
“Look at what they are telling you about their
products and actually just Google it,” Bullock
said. “You’ll nd more than enough academic
research out there to prove or disprove their
theory.”
To ensure that BMA Biotech was able to
develop a more effective range of spill
remediation products, they added new
members to their research and development
team which had over 40-years of experience in
oileld remediation sector.
By early 2018, BMA Biotech had released their
rst ex-situ soil wash chemical and in-situ/ex-
situ microbial based spill remediation products.
Bullock said, their bioremediation product
differs from conventional products as they
don’t use bulking agents – such a vitamins and
their bioremediation product contains a wider
spectrum of microorganisms than any other
microbial based remediation product.
“We developed a microbial remediation
product and we proved our formulation by
adding more microorganisms than any other
product on the planet,” Bullock said. “Which is
far more sustainable and effective.”
He then went on to say how their ex-situ
chemical treatment differs is that it can be
separated from oil/petrochemicals and then re-
used. In addition, the oil/petrochemicals can be
recovered and sold as a commercial commodity.
“We pride ourselves on setting the standards,
for others to follow. We only resort to ‘dig and
haul’ as a very last resort, or if state agencies
prefer this method of oileld contamination
cleanup. We stand behind all of our
remediation products, and only deploy the most
effective types of treatment methods. We do
not mis-sell our products, nor do we make false
or inammatory claims about our services and
capabilities of our products,” Bullock said.
Initially, it seemed that the PT Barnum-esque
companies were being countered by BMA
Biotech’s new remediation products, to some
degree. But Bullock knew he had to step up to
the next level when a company basically told
him to assist them in a clean up mess from one
of the snake oil companies operating in the
oileld.
“We have over 40-years of hands-on
experience in providing Phase I and Phase
II environmental site assessments and
delivering effective soil and water remediation
programs to a diverse range of oil and gas
companies around the world,” Bullock said.
“We believe our oileld environmental services
are world-class and provide a true ‘cradle to
grave’ approach to the cleanup and successful
remediation of oileld contamination.”
Micrograph showing how SWS encapsulates crude oil petrochemicals
E&P wastewater - produced water
Micrograph comparing conventional microbial product spore count to BMA 400
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Oilman Magazine / May-June 2019 / OilmanMagazine.com
30
OILMAN COLUMN
Interview: Josh Robbins, CEO,
Beachwood Marketing
By Emmanuel Sullivan
Emmanuel Sullivan: When did you start
Beachwood Marketing and what is the
business pain point you solve?
Josh Robbins: It was a side
hustle from 2010 until 2014,
then I “ofcially” opened
the doors of Beachwood.
Beachwood is celebrating
our ve-year anniversary
this July.
Beachwood started because I accidently
uncovered a deal during my nine to ve gig;
discovering that an oil company was going to sell
all of their assets. I left the oil company and made
a call to a good friend (who happened to operate
in the same area) and told him the information.
Two months later, we were having beers
celebrating the acquisition of those assets.
I had no idea that there was an opportunity like
this. When I asked that Oilman how he would
have normally gone about buying additional wells,
he said he would check in once a year with that
operator over breakfast, but that there wasn’t a
real outlet for people to purchase wells outside of
the online auction houses. Beachwood is actively
solving a signicant pain point in today’s oil and
gas industry: transacting – actually buying wells
off-market in this pricing environment.
ES: What services does Beachwood
Marketing provide for the oil and gas
industry?
JR: Beachwood is a contract business
development service that uncovers oil and gas
deals by calling oil and gas operators (over 4,000
calls monthly).
ES: How has the oil and gas property buy/
sell activity been the past year?
JR: The last ve years in the oil and gas industry
have been lled with ups and downs. It wasn’t
until the summer of 2018 that the acquisitions
and divestiture segment nally recovered.
Everyone was excited to see $70 oil, then the
market crashed again in October of 2018, sending
the industry back to square one: full recovery
mode in the last quarter. Since the start of 2019,
and especially in Q2, the A & D market has really
picked up; the Chevron acquisition of Anadarko
helping to encourage the market movement.
ES: What technology platforms do you rely
on to conduct business?
JR: The primary technology platform that I use
is LinkedIn; I’ve been an active user since 2012
and I push my team to utilize its reach. This year
LinkedIn has grown into a personal branding
platform, and I’m now a Micro-Inuencer for
the oil and gas industry. I’m actively building a
network of followers that are interested in my
travel, sales, oil and gas and traditional networking
opportunities.
ES: Do you have any changes planned for the
services you offer?
JR: Beachwood doesn’t have any changes planned
for our services; we will continue to track down
off-market deals for the foreseeable future.
ES: Do you see growth in the oil and gas
segment you serve?
JR: The oil and gas market we serve is actively
looking for assets to purchase and any additional
assets we can uncover, expands their reach. I
think there is an enormous growth opportunity
for buy side deal sourcing.
ES: What is a typical day for you like?
JR: As a business owner, I’m not sure there is
such a thing as a “typical day.” Normally I’m up
around 5:30 am, whether here in Oklahoma City
(where the Beachwood ofce is located) or on the
road (I travel about 43 weeks a year).
In the ofce by 6:30 am, I enjoy the quietness
of the ofce. I always start with a cup of coffee
and mapping out the calls for the day. Any
meetings in Oklahoma City are done at Stella
Nova; the best coffee in all of Oklahoma City –
because #coffeeisforclosers.
That hashtag is always on my
LinkedIn posts, which has
helped to grow my Inuencer
base. The rest of the day is
lled with calls. I’m on the
phone at the ofce, cell and in
the conference room. On any
given day, I probably make or receive 120 phone
calls – but I’m in the Outbound Call business!
I’m not a fan of formal, sit down meetings. We
meet Monday’s and Friday’s and the rst day
of the month. Other than that, we accomplish
what we need via email or phone. The Monday
/ Friday meetings are always to celebrate the
victories. There is an epidemic in our culture
about eighth-place trophies. I am a big proponent
of encouragement and celebrating the small wins.
It’s not an eighth-place trophy, it’s a high ve
and a pizza slice. It’s taking an interest in your
team and knowing when they hit the small goals.
Because if you hit 12 small goals – one every
month – you are denitely hitting your year goal!
The workday usually continues late, as I try
to dene the tasks for the following day and
to plan travel if needed. I look at owning my
own company as being on the clock non-stop.
My Grandfather owned his own business for
many, many years, and it was his advice I asked
for prior to starting Beachwood. He asked me
one question: Are you okay with working every
second of your life? Gramp said that even when
you turn the lights off and lock the door to go
home, your business is in every thought. On the
elevator, in your car, in your dreams. And if I
can handle that, then I’m an entrepreneur and I
should open my business.
On the road I’m constantly checking in on the
family – using SnapChat and Instagram to send
the kids messages and get jokes/pictures back
from them. It’s 2019. Your kids are using social,
so communicate like they communicate! We share
music. I know what books they are into. They ask
for food recommendations for places they are
at with friends. I honestly think that social has
me more connected to my kids than I could ever
hope to be without it. Taking off from work I
usually check LinkedIn and Soundcloud for new
music to listen to for all the road trips. It’s mostly
inspirational, instrumental music and podcasts.
ES: How is your service different from
competitors?
JR: Our competitors are sell-side auction
houses that broker deals.
At Beachwood we don’t
broker. We don’t have land,
legal, geo or engineering,
we have salespeople that
can nd deals that aren’t
on the market. We are buy-
side deal nders, which is
considerably different from
our competitors.
ES: What methods do you use to market your
business?
JR: Beachwood’s core business model uses
outbound marketing; primarily through targeted
outbound phone calls. “We take inbound calls,
make outbound calls, send emails, LinkedIn mes-
sages and pull leads from our website trafc”.
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Oilman Magazine / May-June 2019 / OilmanMagazine.com
32
Oil Markers: Useful Pricing Tools
By Eugene M. Khartukov
Benchmark crude (oil marker) is the petroleum
that serves as a pricing reference for other
types of oil and oil-based securities. The
benchmark makes it easier for traders,
investors, analysts, and others to determine
the prices of multitudes of grades of crude oil
varieties and blends. Using benchmarks makes
referencing types of oil easier for sellers and
buyers.
There is always a spread between WTI, Brent
and other blends due to the relative volatility
(high API gravity is more valuable), sweetness/
sourness (low sulfur is more valuable) and
transportation cost – the price that controls
world oil market price.
Brent blend
is a light (38.06° API), sweet crude
(0.37% sulfur by weight). Some 15 U.K. elds
in the Brent-Ninian area in the northern North
Sea contribute to the blend, although very
little production comes from the once-prolic
Brent eld, after which the stream was named.
The Brent blend is transported to the Sullom
Voe terminal via pipelines. This terminal,
representing an
inlet between North
Mainland and
Northmavine on
Scotland’s Shetland
Islands, is operated
by Enquest, which
acquired a three
percent stake and
the operatorship of
the terminal from
BP in 2017. Despite
the declining physical volumes associated
with the Brent blend (a peak of 1.3 mln b/d
in 1985, less than 0.5 mln b/d in 2000, 75.5
kb/d in 2018 and forecast 58.1 kb/d in 2020),
its importance as a nancial oil benchmark is
increasing (though seriously questioned now).
Therefore, between 2002 and 2015 a series
of changes were made to Dated Brent in an
effort to maintain its liquidity and status – by
increasing the available volume (some crudes
were added and its delivery window was
repeatedly widened).
Generally speaking, three major markers used
in pricing of crude oil across the globe are
WTI (Western Texas Intermediate) for the
American markets, Brent for the European/
West African Markets and Dubai or OD
(Oman/Dubai) crude oil grades used for
Persian Gulf and the Asian markets.
Crude oil benchmarks are reference points
for the various types of oil that are available
in the market.
Also known as oil
markers, crude oil
benchmarks were
rst introduced in
the 1980s, with the
aim of establishing
a standard for
the world’s most
actively-traded
product. At
present, there
are dozens of
different oil
benchmarks,
with each one
representing
crude oil from
a particular part
of the globe.
However, the price of most of them are
pegged to one of the following three primary
benchmarks: Brent, WTI or OD. Roughly two-
thirds of all crude contracts around the world
reference Brent
Blend, making it the
most widely used
marker of all.
Other well-known
oil markers include
the OPEC Reference
Basket used by
OPEC, Tapis Crude
which is traded in
Singapore, Bonny
Light used in
Nigeria, Urals oil used in Russia and Mexico’s
Isthmus as well as Canada’s Western Canadian
Select (WCS) and Edmonton Par crude.
WTI
, known also as Texas Light Sweet crude,
is referred to as the oil extracted from oil elds
and wells in the U.S. and is landlocked. The
crude is transported via pipelines and hence
one of the drawbacks as it is fairly expensive
to distribute and sell to other parts of the
globe. This crude is light and ‘very sweet’
(API gravity 39.6°, sulfur content 0.4-0.5 %
by weight). WTI is pumped to Cushing hub
in Oklahoma and is a benchmark for crude
mainly in the United States.
Historically, price differences between Brent
and other index crudes have been based on
physical differences in crude oil specications
OILMAN COLUMN
The Geographical Range of WTI and Brent
Brent is the reference price for roughly 66% of all globally traded
oil, while WTI is the dominant price marker in the United States.
Dubai crude – which is mainly delivered to Asian countries – is the
main reference for oil traded in Middle Eastern markets.
Sources: Intercontinental Exchange (ICE), Investopedia,
Money Morning Staff Research
Chart 2. Global Coverage of the Main Oil Markers / Source: Peak Oil
Oilman Magazine / May-June 2019 / OilmanMagazine.com
33
OILMAN COLUMN
and short-term variations in supply and
demand. Prior to September 2010, there
existed a typical price difference per barrel
of between ±3 USD/bbl compared to WTI
and OPEC Basket; however, since the autumn
of 2010 Brent has been priced much higher
than WTI, reaching a difference of more than
$11/b a barrel by the end of February 2011
(WTI: 104 USD/bbl). In February 2011 the
divergence reached $16/b during a supply glut,
record stockpiles, at Cushing, Oklahoma before
peaking at above $23/b in August 2012. It has
since (September 2012) decreased signicantly
to around $18/b after renery maintenance
settled down and supply issues eased. In 2018,
on the average, this price premium in relation
to WTI stood at over US$6.1/b
(Chart 1)
.
Dubai/Oman
refers to the crude oil produced
in Middle Eastern countries and is lower grade
than Brent or WTI. It has high sulfur content
and is procured in Dubai, Oman and Abu
Dhabi. This is the benchmark for the Persian
Gulf production and is mainly sent to Asia
(Chart 2)
.
Tapis Crude: It is the benchmark for light
sweet Malaysian crude. The sulfur content is
as low as 0.03% and the API gravity is around
45.5. Although this oil marker is not as widely
traded as WTI, it is used as a benchmark in
Asia.
Bonny Light: It is a benchmark for high grade
Nigerian crude, with an API of around 36.
Due to its very low sulfur content, it corrodes
the renery
infrastructure
minimally.
Isthmus: This
is the crude
oil benchmark
for light crude
produced in
Mexico. The
sulfur content is
around 1.45%
and the API
gravity is 33.74º.
The OPEC
Reference Basket
(ORB)
, also
referred to as the
OPEC Basket,
was initially
introduced at the
start of 1987 and
was originally
the pricing
data formed by
collecting seven
crude oils from the OPEC nations (except
Mexico). These included, on an arithmetic
basis, the spot prices of Saudi Arabia’s Arab
Light, Algeria’s Saharan Blend, Indonesia’s
Minas, Nigeria’s Bonny Light, Venezuela’s
Tia Juana Light, Dubai’s Fateh and Mexico’s
Isthmus. This information was used by
OPEC to monitor the global conditions of
the oil market. Since June 16, 2005 (decided
by the 136th OPEC Conference), the OPEC
Reference Basket of Crudes (ORB) was the
production-weighted average of 14 (since
June 2018) it composed of the following 15
crudes: Saharan Blend
(Algeria)
, Girassol
(Angola)
, Djeno
(Republic of Congo)
, Oriente
(Ecuador)
, Zaro
(Equatorial Guinea)
, Rabi
Light
(Gabon)
, Iran Heavy
(Islamic Republic
of Iran)
, Basra Light
(Iraq)
, Kuwait Export
(Kuwait)
, Es Sider
(Libya)
, Bonny Light
(Nigeria)
, Qatar Marine
(Qatar)
, Arab Light
(Saudi Arabia)
, Murban
(UAE)
and Merey
(Venezuela)
. As of June 2005, ORB’s API
gravity was 32.7° and its sulfur content –
1.77% by weight.
In 2007-2018 the following changes have
happened to composition of ORB:
• As of January 2007: The basket price
includes the Angolan crude “Girassol”
• As of 19 October 2007: it includes the
Ecuadorean crude “Oriente”
• As of January 2009: excludes the Indonesian
crude “Minas”
• As of January 2009: the Venezuelan crude
“BCF-17” was replaced by the crude
“Merey”
• As of January 2016: the basket includes the
Indonesian crude “Minas”
• As of July 2016: it includes the Gabonese
crude “Rabi Light”
Chart 1. Monthly Dynamics of WTI and European Brent Spot Prices in 2018, in US$/ bbl
Source: Eugene M. Khartukov
Chart 3. Annual Dynamics of ORB Price in 1994-2018, in US$/b
Source: Eugene M. Khartukov
Continued on next page...
Oilman Magazine / May-June 2019 / OilmanMagazine.com
34
• As of January 2017: excludes the
Indonesian crude “Minas”
• As of June 2017: includes the Equatorial
Guinean crude “Zaro”
• And as of June 2018: includes the
Congolese crude “Djeno”
In 1994-2018 annual average price of ORB
has increased 4.5-fold: from $15.53 per barrel
on the average of 1994 up to $69.78/b in
2018
(Chart 3)
. At the very end of 2018 ORB
average price stood at $51.55/b and was
growing.
Edmonton Par
and
Western Canadian Select
(WCS)
are benchmarks crude oils for the
Canadian market. Both Edmonton Par and
West Texas Intermediate are high-quality
low-sulfur crude oils with API gravity of
around 40°. In particular, Par crude, delivered
at Edmonton, Alberta, has 40.02° API gravity
and 0.3% sulfur. In contrast, WCS, blended
at a storage terminal in Hardisty, Alberta, is a
heavy and sour crude oil with an API gravity
of 20.5 to 21.5° (925 to 935 kg/m³) and sulfur
content of 3.0 to 3.5% by weight.
Western Canadian Select (WCS) trades at a
considerable discount to WTI (up to US$30/b
at the end of 2017). But the gap started to
widen in 2018 as U.S. renery capacity was
rising
(Chart 4)
.
For Edmonton Light, the discount jumped to
U.S. $7.32 per barrel in January, after averaging
U.S. $3.93 in Q4 2017, and this discount was
expected to narrow to around US$3.50 by
2019.
The
Canadian Crude Index
(CCI)
serves as a benchmark for oil
produced in Canada. It allows in-
vestors to track the price, risk and
volatility of the Canadian commodity.
The CCI provides a xed price
reference for Canadian crude oil and
provides an accessible and transparent
index to serve as a benchmark to
build investable products upon, and
could ultimately increase its demand
to global markets. The CCI was
launched by Auspice Capital Advisors
in 2014 and can be used to identify
opportunities to speculate outright
on the price of Canadian crude oil or
in conjunction with WTI to put on a
spread trade which could represent
the differential between the two.
Currently, Canadian oil trades at a
discount to WTI. The landlocked
location and transportation constraints
of crude oil in Western Canadian
provinces contribute to this discount.
Also, until 1986,
Arab Light
(or
shortly AL) price (32. 8° API (0, 8602
г/см3; OPEC sources insist on 34° API;
sulfur content – 1. 97 %) was a leading oil
marker and a technical reference, to which all
OPEC’s other oil prices were linked. In early
1986 Saudi Arabia adopted net-back pricing
and AL price was replaced as the world oil
czar by Brent blend spot prices
(Chart 5)
.
Furthermore, until 2009 Indonesia’s
Minas
crude (also referred to as Sumatran Light) and
comes from the island of Sumatra. Its API
gravity is approximately 35° and the specic
gravity is 0.8498; sulfur content of only
0.08%) was an oil marker for up to 1 million
b/d of Indonesian, Vietnamese and Sudanese
crude, a legacy from an era when Minas, which
began commercial production in the 1950s,
was the largest oileld in Southeast Asia.
However, its output, once above 400,000 b/d,
has fallen by mid-2008 below 200,000 b/d
(and, perhaps, as low as 150,000 b/d due to
the ageing eld’s natural decline) and less than
50 kb/d of Minas oil was available for exports.
Malaysian
Tapis
crude with an API gravity of
42.7° and with only about 0.04% sulfur is also
under the question as a Pacic/Asia oil marker
OILMAN COLUMN
Chart 4. Daily Movements of WCS, Maya and WTI Spot Prices in 2013-2018, in US$/bbl
Source: Bloomberg
Chart 5. API Density and Sulfur Contents of Some Crude Oils / Source: Energy and Capital
Oilman Magazine / May-June 2019 / OilmanMagazine.com
35
OILMAN COLUMN
as its production currently naturally declines
(from a maximum of 360,000 b/d to around
280,000 b/d now). While it is not traded on a
market like Brent or WTI, still it is often used
as an oil marker for Asia and Australia. Tapis
oil has previously lled the role of regional
light sweet benchmark, powering the APPI
index system that was widely used in In-
donesia, Australia and Vietnam.
The price of Tapis in Singapore is often
considerably higher than the price of
benchmark crude oils such as Brent or WTI.
This is because its greater aromaticity (i.e.,
higher °API) allows for greater production
of higher-value products, such as petrol
(gasoline), than from Brent or WTI. Its high
price is also due to the purity of the blend.
Because it contains less sulfur, it requires less
renery processing than sourer crude oils such
as Brent crude and WTI.
Alaskan North Slope
(ANS)
crude blend
(a relatively high
viscous – 23.9cSt
@50°F –- and quite
heavy – 29.6° API)
is also considered as
a Pacic oil marker
but its production
(over 2,000 kb/d
in the second half
of the 1980s) is
falling (down to
below 500 kb/d in
2020, according to
forecasts).
Urals
blend, which
is a mixture of
crudes produced
in Volga-Urals and
Western Siberia with
its sulphur content of 1.3-1.8% and specic
gravity at 20°C – 850.1-870.0 kg/m3 and at
60°F – 853.7-873.5 kg/m3 (≈ 30.5-34.5°API)
pretends to become a global oil marker,
although the bulk of this crude is known
to be sold within term contracts with a few
European buyers. Urals trade has been fanfare-
ously launched in Moscow on SPIMEX
commodity exchange in late November 2016
as a long-awaited genuine benchmark crude.
But, with the known inertia and limitations,
it is actually a forcebly introduced local and
invalid oil marker, which is unlikely to become
most widely (globally) used in any foreseeable
future. Interesting to note that 2006 already
saw the rst attempt to create a tradeble
futures contract for the Russian export crude
– under the name of REBCO (Russian Export
Blend Crude Oil), which started to be traded
on the NYMEX. However, the contract did
not gain popularity among oil traders (number
of trades was extremely limited) and was
eliminated in 2012.
Also,
ESPO
blend, which is sold from
Kozmino terminal in the Russian Far East
and has, according to Platt’s, sulfur content of
0.54% and gravity of 34.7°API, may become
a Pacic oil marker in the future but it is not
traded yet on any commodity exchange that
provides the needed liquidity and the price’s
transperancy.
In response to accusations that Brent price
was manipulated by some oil traders (Platt’s
was ready and eager to take a killing legal
action against those who publicly disseminated
such accusations). The leading oil-price agency
has developed an InterContinental Exchange
(ICE) introduced in early July 2015. The
so-called
BFOE Index
, which is the volume-
weighted average price of trading in the
21-day Brent Blend and Forties
(UK)
, Oseberg
and Ekosk
(Norway)
(and since 2018 also
Norway’s Troll crude) ‘cash’ or forward market
in the relevant delivery month as reported and
conrmed by industry media and is an average
of second month cargo trades in the 21-day
BFOE market plus or minus a straight average
of the spread trades between the rst and
second months.
In the same vein, Argus Media launched in
May 2009 and publishes daily now
Argus
Sour Crude Index
(or shortly
ASCI
), which
is based on sour oil production in U.S. Gulf
of Mexico (offshore Lousiana), and is a
useful pricing tool used by buyers, sellers
and traders of imported crude oil for use in
long-term contracts and has been adopted as
the benchmark price for sales of crude oil by
Saudi Aramco (in 2009), Kuwait (in 2009) and
Iraq (in 2010).
Contracts based upon ASCI are listed on the
world’s two largest oil exchanges, the New
York Mercantile Exchange (NYMEX) and the
Intercontinental Exchange (ICE).
Oil markers’ price dynamics are well correlated
but not to a full extent – reecting oil balances
of their own markets
(Chart 6).
Talking about the prerequisites (preconditions)
of oil markers, it would be useful to look at
the table, showing the compliance with them
of Brent and Urals oil blends
(Table 1).
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.
Table 1. Compliance with the Main Prerequisites of an Oil Marker for Brent and Urals Blends
Source: ICIS complied from Liz Bossley, 2018
Oilman Magazine / May-June 2019 / OilmanMagazine.com
36
OILMAN COLUMN
Improving Oil and Gas Storage and
Operations Through Innovation
By Tonae’ Hamilton
The topic of oil conservation, protection,
and storage has become a prevalent area
of interest in the oil and gas industry. With
more companies looking for ways to store oil
properly and safely and avoid the ever-present
risk of tank explosions, the demand for oil and
gas technology and solutions has increased.
As such, oil and gas software companies
have been on the forefront of this demand,
developing new ways to help clients store
gas, improve their operations, and save on
expenses associated with poor storage and
protection. Abshier Energy, a woman-led
oileld and lightning protection company,
provides innovative software and equipment
to companies looking to improve the safety
of their operations and efciently protect
their biggest assets. Through their innovative
solutions and diverse range of equipment,
Abshier is striving to not only improve the
state of oil and gas companies, but also the
state of the industry and the environment.
Susan Snyder, President of Abshier Energy,
shared her thoughts on how innovative
thinking and solutions can go a long way in a
traditional industry that is ready for change.
Speaking on Abshier’s mission and goals for
the oil and gas industry, Snyder stated how
they want to change the conversation from
cost-driven justication of safety-related
installations and focus the conversation
on the application, quality control, and
quality assurance of the installations that
limit the risk of an unplanned discharge of
static or lightning on or at a hydrocarbon
generating site. She further explained that an
unplanned discharge could create catastrophic
environmental issues or loss of human life and
thus, safety is the primary goal.
Snyder shared how Abshier’s technology
and solutions so far have helped improve
the operations of oil and gas companies.
She explained that through their reliability-
focused installations and industry-consensus
standards, they consistently challenge the
market. Snyder explained the key differences
that make Abshier and their products stand
out from other oil and gas competitors saying,
“We strive to be unique, quality centric and
not focused on the dollar, but focused on the
customer and our employee’s needs.”
Being the president of a diverse, women-
owned company, Snyder reected on the
difculties she faced marketing Abshier’s oil
and gas solutions and equipment in a generally
traditional industry. She expressed “we’ve
generally faced the same issues that other
[minority] companies face, although it is a little
disappointing to see that companies don’t take
full advantage of diverse spending.”
When asked what technologies or solutions
Abshier is currently working on, Snyder
explained that they are currently taking steps
to educate customers on the application, use,
and employment of their unique protection
systems.
In regards to oil protection and spill
prevention, Snyder gave her perspective on
the oil storage tank explosion that occurred
in the Houston area. Asked what the oil and
gas industry can do to minimize such risks,
she expressed the importance of having
procedures in place. “Documenting what
you do, how you do it and qualifying those
who interact with hazardous substances and
processes are a must,” stated Snyder.
In addition, Snyder described the type of
solutions Abshier provides to clients to
prevent such oil tank explosions. She stated
that they provide static grounding, equipment
grounding, system bonding as well as full
testing to make sure that the installations are
safe to operate and suitable for long term
operation. “Maintenance is also a key factor
that has to be added for an overall effective
safety program,” Snyder further explained.
Snyder was asked about future innovations
and developments she’d like to see created in
the future within the company itself or the
industry overall. “Abshier Energy would like
to see an industry evolution where justication
of costs are squarely focused on safety and
reliability from day to day operations of oil
facilities,” Snyder shared. Per their own future
goals, she stated how they would like to lead
the industry to understand the impacts that
static/lightning protection can have to the
long-term survivability of oil and gas related
process systems/equipment. “We understand
life cycle costs of oil and gas related
equipment and can help justify the longevity
of these systems/components with a qualied
maintenance plan/program,” Snyder further
explained.
Snyder expressed how there must be a
mentality shift about how we install, operate
and maintain our equipment and systems.
“Equipment costs are increasing signicantly
by the day, disasters aren’t cheap, bad PR is not
good, and qualied manpower is not getting
cheaper. Planning, documenting, and qualifying
is a must,” stated Snyder.
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Oilman Magazine / May-June 2019 / OilmanMagazine.com
38
There Is More than One Way to
Practice Hydraulic Fracturing
By Andres Ocando
Hydraulic fracturing is a highly practiced branch
of the production discipline that is commonly
used in sands with low permeability. Sometimes
it is used for sand control operations and, in
other cases, to increase production when it goes
down.
The functional principle of fracturing consists
on using uid at a higher pressure than the
breaking strength of the rock, and later lling
this opening with proppant material (the one
that sustains the fracture) to avoid its closure.
The simplicity of the process does not reect the
difculties that could appear in the way, because
when talking about rocks, we also talk about a
natural material that is not homogenous.
The rst recorded fracturing was carried out
in Kansas, in 1947. After the positive results
were obtained, it became the perfect option
to increase production quickly. Over time,
improvements in the fracturing process began
to appear, so did larger pumps, deeper depths
reached, the fracturing uid ceases to be only
water and the proppant stops being only sand.
In addition to this, the fracture plans are
coordinated by specialists with the creation of
software that predicts the possible behavior of
the rock. In turn, with the introduction of more
technologies and professionals, the costs to
fracture reach gures from $800,000, in simple
cases, and $3,000,000 in more complicated cases
with multiple stages.
In spite of all this effort, it becomes impossible
to completely correct the fractures, since
currently there isn’t any mathematical complete
software that can iterate the necessary times
to predict the behavior of the rock before the
pressure.
However, there is more than one way to practice
hydraulic fracturing. As a case study, here is
an analysis for fracture optimization using
geomechanics as spearhead. It takes place in
west Venezuela, specically in an important eld
that carries oil with 24 API° quality. The target
deposit has petrophysical characteristics that do
not allow the natural ow of crude oil.
Its porosity is near 15 percent but with a
permeability of approximately 8 cps, which
makes it a perfect candidate for fracturing.
Despite having more than 30 wells fractured in
the past, you cannot nd one whose fracture
lasts more than 1 month open.
In addition to the aforementioned conditions,
this particular reservoir has a geological feature
known as migration, a process in which the
target sand rises. In this case the migrated sands
are eocenic, being originally in the past to depths
between 12,000 ft to 15,000 ft; and they’re today
at 4,000 ft, maintaining part of its characteristics
as hardness, resistance, among others.
Using the
Marcelo
Frydman
methodol-
ogy, the
progress
goes in the
acquisition
of data
where a
post-mor-
tem
analysis of
fractures previously practiced was constructed,
detailing what type of uid, proppant and pres-
sure were used.
With this information it was possible to know
that the uid commonly used was water and
the proppant was sand, due to the age of the
fractures.
From the structural model and analysis of
drilling events, it was possible to identify
important quantities of events that were
repeated when drilling. It was also detailed how
the formations were arranged layer by layer,
understanding the migration effect suffered by
the deposit.
With the stratigraphic mechanics, thin sections
were practiced, which is the microscopic
analysis made directly to the core extracted
from key wells in the deposit, noting the grain
arrangement, the size of grains, and how the
formation was supported, resulting in supported
grain.
It can be
inferred
from the
size and
type of
grain what
type of
proppant
should be
used. With
an average
size of 15 microns, it makes reference to a ne
sand type, therefore the proppant size should be
close to 15 microns to avoid plugging in the pore
throats built with fracturing.
For the overburden pressure analysis, we
used the available petrophysical records. In
the following image (Chart 1) you notice how
the reading of the density record (left) has a
signicant change in behavior when entering
the target area Eocene, due to the migration
phenomenon mentioned above.
With the result of the OBG (overburden
gradient), the impact of the sands formation
OILMAN COLUMN
Flowchart to build an oil geomechanical model (Marcelo Frydman)
Fine sections. Source: Ocando, Osorio 2015.
Oilman Magazine / May-June 2019 / OilmanMagazine.com
39
OILMAN COLUMN
migration is noted because the density is greater,
so there is an overload pressure much higher
than expected at this depth.
For the pore pressure analysis, different available
records were used together with the operational
events that they demarcate when the pore
pressure infers, such as gas inux or circulation
losses. In addition to pressure tests, these were
used to calibrate the pore pressure in the target
area, which allows predicting the pressure
needed to reach the formation rupture in case of
fracturing.
Above (Chart 2), you can see the compaction
train calculated with the available sonic registers
(left), and the nal result of the pore pressure.
Since there was a signicant number of well
cores in the deposit area, geomechanical
tests were carried out in the rock mechanics
laboratory Miguel Castillejo at the Central
University of Venezuela, with the support of Dr.
Castillejo.
To the different samples already cut, analyses
were carried out as the following:
Brazilian test: This is practiced to know the
resistance to stress the rock has, an important
value at the time of hydraulic fracturing, since it
allows to know how the rock will behave after
breaking.
Unconned Compressive Strength (UCS):
The exercise of submitting the core to a
charge without connement in order to
know the resistance to the axial pressure the
rock has, by contributing the values of the
Poisson coefcient. This helped to know if
the anomalous
overload pressure
where the target
formation
exposed was
affected. The
result was
negative, since
being an Eocene
rock, the Poisson
coefcient
obtained was 0.33.
Triaxial tests
(TRX): This
test is practiced
to simulate
the reservoir
pressure. The
sample is conned
and receives
both vertical
and horizontal
pressure to
obtain the value
of the Young’s
coefcient. In
this case, it was
used in an axial pressure close to the overburden
to which the rock is subjected in the subsoil;
which progressively increased the horizontal
pressure to simulate the reservoir pressure and,
subsequently, the amount of pressure necessary
to propagate a hydraulic fracturing of the rock
and the Young coefcient 0.63 x10 (6) psi.
These results allow us to know what type of
rock it is. The logic indicates that, since it is
a rock belonging to the Eocene, it must be
consolidated; but the results showed that it isn’t.
Since there is an unconsolidated rock, fracturing
processes change drastically. Another non-
standardized test was carried out and, when
rubbing the rock with the ngers in the broken
sectors after the tests, an easy detachment of
Chart 1: Density log vs OBG. Source: Ocando, Osorio (2015).
Brazilian Test. Source: Ocando, Osorio (2015). UCS Test. Source: Ocando, Osorio (2015). TRX Test. Source: Ocando, Osorio (2015).
Chart 2 Compactation train vs preassure. Source: Ocando, Osorio (2015).
Continued on next page...
Oilman Magazine / May-June 2019 / OilmanMagazine.com
40
OILMAN COLUMN
the grains was observed, which points at a
low cohesion of the rock. This answers why,
despite being Eoceanic, it is an unconsolidated
rock.
In the following steps the geomechanical
model is concluded, obtaining the effort
directions that allow to choose in which
direction fracturing should be practiced. The
theory orders that it fracture in the maximum
direction. The value of the minimum effort
(Sh) was also obtained, and the value of the
maximum (SH) was estimated, and with the
failure analysis using the Mohr Coulomb
theory it was shown that the rock has a low
cohesion.
With the results obtained at the end of the
geomechanical model, it can be seen how
several questions around the fracturing were
answered.
In reference to the deposit geological
conditions, it is noted that, in spite of
migrating the formation and changing depth, it
kept its main characteristics. The key formation
efforts obey a normal regime, so the best way
to practice the fracture is in a vertical well.
To select the fracture uid, it is necessary
to take into account the formation low
cohesion, since a very invasive uid can
cause sandblasting
after fracturing. This
sandblasting process
was observed in the
post-mortem analysis
that took place in the
beginning.
A foam uid of low
density stands out as
the best option, in
addition to a proppant
with high resistance as
a ceramic type, because
the formation has a
signicant overload
effort added to the
minimum effort. The aim
is to avoid a Crushing
effect (the pulverization of the proppant due
to pressure conditions).
With all of this it is possible to demonstrate
that, although fracture simulators do not work
properly in this case due to the abnormal
conditions that this deposit presented, other
disciplines such as geomechanics can provide
a safer way for successful fracturing, and thus
take care of the investment that the oil and
gas industry undertakes in this method of
stimulation.
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.
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Classication of the type of rock according to the Young’s Model and Poisson’s Ratio.
Source: Geomecánica aplicada a la Industria Petrolera (2013).
Result of Mohr circle. Source: Ocando, Osorio (2015).
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Oilman Magazine / May-June 2019 / OilmanMagazine.com
42
DevOps Provides Digital Pipelines
to Cloud Benefits
By Aater Suleman
According to the World Economic Forum, digital
transformation could unlock approximately $1.6
trillion of value for the Oil and Gas industry, its
customers and society. This value is derived from
greater productivity, better system efciency,
savings from reduced resource usage, and fewer
spills and emissions. Yet, the journey to these
digital transformation benets begins with a
proverbial rst step which can be elusive for
large oil and gas enterprises who have vast legacy
technologies and complicated organizational
structures to navigate.
DevOps has emerged as a key process
improvement that combines cultural philosophies,
practices, and technologies that can help oil
and gas companies address a spectrum of
business initiatives by delivering services at a
higher velocity. By innovating faster, oil and
gas companies can more quickly achieve digital
transformation benets, whether it be sending
drilling platform IoT data to the cloud for
predictive maintenance or creating new services
to meet evolving customer expectations.
Cloud technologies coupled with DevOps
practices continue to dominate priorities for
operators across the oil and gas sectors as
they recognize their role in facilitating digital
transformation to provide competitive and
economic advantages. IDC Energy Insights
predicts that by 2020, 25 percent of large oil
and gas companies will have implemented a
platform to develop, analyze, model, and simulate
best practices in a cognitive-based continuous
learning environment. Cloud-enabled technology,
alignment between an organizations’ IT and
business leaders, and DevOps practices are key
enablers to transform IT service delivery.
Let’s explore a few industry examples of how
using DevOps to enable the cloud journey has
helped organizations achieve enterprise agility, as
well as ve tips to build a roadmap to success.
Reduce Time to Market
Deeper data insights that can expedite resource
exploration, drilling and production can be gained
from cloud-enabled machine learning. Big data
tools coupled with the cloud’s elastic resources
and DevOps automation can speed processes
– like reservoir simulations – to reduce time-to-
decision and reach production faster.
For example, Fugro, which collects and provides
highly specialized interpretation of oceanic
geological data, is able to keep skilled staff
onshore using an IoT platform model. Referred
to as OARS, its cloud-based project provides
faster interpretation of data and decisions. In
addition, new environments which previously
took weeks to build, now launch in a matter of
hours, providing better access to information
across global regions.
Lower Costs Through Automation
The automation of IT operations and
development practices help reduce costs by
optimizing processes and greatly decreasing
the potential for costly human error. With
customized delivery pipelines, companies like
Halliburton have been able to streamline complex
workows, allowing it to obtain increasingly
reliable real-time data to steer drilling operations,
accelerate digital transformation and enable rapid
entry into new markets. Operational workows
can be optimized across the value stream – from
pipeline monitoring to gaining a 360-degree view
of the customer that allows you to better engage
with them at the pump. Automation can help oil
and gas companies prosper despite constantly
changing market conditions. Take GE Oil & Gas,
for example. The service provider moved 350 of
its applications to Amazon’s cloud offering, AWS,
over the course of two and a half years, which
resulted in 52 percent reduction in IT costs. This
savings, coupled with greater agility and speed
to market, enables the company to compete
even better in an industry experiencing immense
market challenges.
Obtain Security and Compliance
Securing business-critical data while meeting
compliance objectives set forth by NIST, ISO
and others is foundational for every company, but
especially for brokers and trading information
organizations. For companies like OTC Global
Holdings, balancing security with agility through
cloud automation and security best practices
enables these types of rms to remove errors,
lower costs, increase speed, and better drive
compliance.
Getting Started with Cloud-Based DevOps
By combining DevOps processes and cloud
technology, oil and gas companies can innovate
faster, and more quickly achieve digital
transformation benets. Here are ve quick tips
on where and how to start:
Tip One: Begin with a pilot project. It’ll allow
you to begin in a contained environment, testing
change in a limited way. Find a small, impactful
project that can be completed in eight to 12
weeks and will deliver measurable business
impact.
OILMAN COLUMN
Photo courtesy of Busakorn Pongparnit – www.123RF.com
Oilman Magazine / May-June 2019 / OilmanMagazine.com
43
Fifty years ago, in 1969, natural gas was found
in tremendous commercial volumes at the
GHK Company #1 Green well, completed at
a depth of 24,147 feet in the Anadarko Basin.
This is approximately a mile southeast of Elk
City, Oklahoma, my hometown. In those fty
years, thanks to the beginning of exploration
in the Anadarko Basin, natural gas has become
a much needed fuel for power generation and
transportation. The total depth was 24,454
feet. GHK began drilling the well in 1967.
As described in the book entitled
The Grand
Energy Transition,
“the #1 Green broke
virtually every technological record of its
time. It was by far the highest-pressure well
ever drilled in the world, the second deepest.
Cameron Iron Works specially built the largest
and highest-pressured gas wellhead ever
constructed to contain the highest pressured
gas well in the world (15,130 pounds per
square inch at the surface). Because we
had encountered such a high world record
pressure, there was no pressure gauge in
the world to measure it. Luckily, one of our
partner companies, Amerada, had a research
and development facility in Tulsa that worked
with high pressure gas. It constructed the
rst-ever 20,000-psi gauge” – “The #1 Green
well became the rst well to establish the
prolic gas-producing capability of the Deep
Anadarko Basin, thereby opening the province
to billions of dollars of subsequent deep gas
development.”
Six years later, 1975, after the #1 Green well
discovery, I rst recognized what a strong
force OPEC was while working for then U.S.
Senator Dewey F. Bartlett. Senator Bartlett
had asked several of his staff members
including myself to review remarks he was
going to make in Norway before OPEC
ofcials. Only a year before, the energy
industry had been deeply impacted by the
1973-74 oil embargo. It was obvious that the
energy industry and our nation’s petroleum
security would be dealing with major issues
during my lifetime.
Because of my interest in energy
development, two years later, in 1977, I
began working as a petroleum landman in
the Anadarko Basin, purchasing oil and gas
leases in locations where some of the deepest
natural gas wells were drilled. Natural gas and
all forms of energy was necessary then and
will denitely be necessary in the future.
A strong natural gas industry means more
jobs, and a more secure economy. It is
extremely important that the U.S. be in a
strong position of securing energy reserves
within its own boundaries.
National Energy Talk (NET) - National
Energy Talk, an Energy Advocate Initiative,
was launched July 31
st
, 2017 in Elk City,
Oklahoma and meetings have been held in
Tulsa, Edmond and Oklahoma City along with
presentations in Houston, Denver and other
cities. In 2019, NET will continue its efforts
as a platform engaging a national energy
dialogue. Go to Facebook: National Energy
Talk to support/learn more about NET.
50 Years Later: The Impact of Discovery
By Mark A. Stansberry
Mark A. Stansberry
OILMAN COLUMN
Tip Two: Identify people within the
organization who will form your CoE (Center of
Excellence). Experience tells us they are people
who work effectively with ambiguity, have a
bias toward action, are technically skilled, and
embrace mitigated risk-taking. The team should
be DevOps advocates, cross-functional, and
empowered to capture best practices from the
pilot project.
Tip Three: Following a successful pilot project,
you can begin the process of scaling DevOps.
Conduct a thorough portfolio assessment;
DevOps efforts should focus on applications that
contribute to revenue and should be invested in
and therefore migrated to the cloud.
Tip Four: With several migration options
- lift and shift, replatform and refactor - it’s
important to understand the pros and cons of
each approach per application. Analyze cost in
terms of development resources and business
interruptions that may be required from a
signicant rewrite.
Tip Five: Establish automation with technology
pipelines that allow for easy repeatability. Your
DevOps platform should feature technologies
and processes for continuous testing and delivery,
a landing zone, and security.
DevOps is equal parts people, process and
technology. With a CoE in place to help train
teams, a solid cloud-based DevOps platform, and
automation to streamline processes and ensure
they are followed, oil and gas enterprises have a
roadmap to digital transformation success with
DevOps.
For example, TechnipFMC, a renewable energy
leader, assessed that it had two parallel goals: It
wanted to use an AWS cloud migration strategy
as an opportunity to overhaul its business
systems and in the process, the company wanted
to build standardization. Moreover, TechnipFMC
aimed to increase developer agility, grow global
access for its workers and decrease capital
expenses. Based on its application portfolio TCO
analysis, a lift-and-shift migration approach was
pursued. With 80 percent of its applications now
dened by a small number of templates, the
company has standardized its software builds,
ensuring security best practices are followed by
default. The enterprise has increased its time
to innovation, speed to market and operational
efciencies.
With continued market volatility, and growth in
competition to meet evolving customer expecta-
tions with new services, the time to fuel growth
through enhanced productivity and efciency has
never been more at hand. While the oil and gas
industry has traditionally focused on operational
efciency, digital transformation offers the ability
to more closely tie data inputs, and business intel-
ligence, allowing the industry to further enhance
efciency, making smarter decisions, faster.
Aater Suleman is CEO and
co-founder of Flux7, an
IT consultancy providing
DevOps consulting,
cloud architecture, and
migration services. For more
information, please visit www.ux7.com.
Oilman Magazine / May-June 2019 / OilmanMagazine.com
44
OILMAN COLUMN
Transforming Fireproofing
in the Downstream
By Sarah Skinner
In the event of a hydrocarbon plant re,
unprotected structural steel will only
last a few minutes before it collapses.
Whether it is a pipe rack or vessels,
heat could lead to the catastrophic
collapse of the structure, making it
crucial to protect it. Various reproong
systems have been utilized over many
years to protect these steel structures.
Surprisingly, there are currently no laws
making it mandatory that petrochemical
companies reproof their steel, but for
the most part, they all do it for practical
purposes. Because it just makes sense to
protect your assets.
Alfred Miller Contracting (AMC),
headquartered in Lake Charles, Louisiana
has been in business over 70 years and they
reproof more steel than anyone in North
America. At their yard, they boast a highly
efcient, climate-controlled reproong shop
featuring two, 6,000 square-foot, moving
buildings—rather than move the steelwork,
they move the process over the steel. Their
Toyota-esque Lean Production System
enables
them to process over 1,000 tons worth of steel
at any given time and continue working in any
conditions.
The idea of the moving buildings was born in
2006 with the Motiva project. At the time, it
was the rst mega-project and the largest in the
gulf coast region. AMC had to gure out a way
to supply that volume of reproong because
it had never been done before in such a tight
schedule. They followed the lean manufacturing
principles modeled after Toyota, which provides
the best quality, lowest cost and shortest lead
time through the elimination of waste. They
have several patents relating to reproong
including a patented, UL certied corner bead
which increases accuracy and productivity at the
same time.
There are three different ways to reproof steel
and the one used depends on the preference of
the client and the requirements of the project.
There are concrete, light-weight cementitious
and epoxy intumescent applications.
• Concrete: 2-inches thick, heavy, no UL
certication.
• Lightweight Cementitious: ~1-inch thick,
lighter weight, less durable, economical.
• Epoxy Intumescent: ~3/8-inch thick, reacts
with heat to create a foam, which protects
steel from heat source, durable but expensive.
As previously stated, there are no standards
and/or regulations on reproong making it
mandatory that certain guidelines are put in place
and followed to avoid potentially hazardous
and expensive mistakes. There is a network of
people that are passionate about maintaining
the integrity of reproong standards and
in 2016 they formed an organization called
PFPNet. PFPNet is a non-prot, subscription-
funded body that was established to increase
understanding and raise competency across
the whole hydrocarbon passive re protection
industry. They do this by bringing in industry
experts to consolidate their experiences to
determine the best practice for application
methods and the appropriate resources to use.
Simon Thurlbeck, one of the Founders of
PFPNet and now Director, explains, “Having
worked in the eld of re and explosion risk
management in major hazard facilities for many
years, it was obvious that those involved with
hydrocarbon PFP needed a collective technical
organization to identify and capture good
practice, and produce guidance and training that
the whole industry could endorse. The idea was
born from a realization that the industry was
asking the same questions that have always been
asked, and often making the same mistakes, and
that this experience was being lost as people
moved on or retired, In setting up PFPNet we
wanted to rectify this situation, and have industry
identify the issues and provide the expertise that
we could then capture through work programs
voted for by the Members.”
Bob Pool, AMC’s Executive Vice-President is
on the steering committee for PFPNet and was
recently elected to the board of directors for the
National Fireproong Contracting Association.
Because of Bob’s experience and associations
within the industry, AMC has a resident
reproong expert on hand and available to
them at all times.
“Fireproong is a permanent part of the
structure and you only get one chance to do
it right, so we’ve invented and tested several
innovative systems which all help improve the
accuracy and efciency of the reproong.
The consequences of getting it wrong are
extremely high, so you want to make sure it is
applied by applicators who understand the right
reproong system for the situation and know
how to do it correctly,” says Pool.
The reproong effectiveness is tested at UL
(Underwriters Laboratories) in Northbrook, Illi-
nois. In a protected facility, reproong products
with different thicknesses are applied to mimic
what is applied to the structural steel on real
world projects. They run re tests to establish
the exact time before structural failure occurs.
This provides the industry a realistic expectation
of protection that they can offer their clients.
AMC is a company that never rests and
sees itself as a solutions provider. By no
means will you ever catch their president,
Philip Miller, letting the grass grow under
his feet. Whether it’s precast buildings, pipe
racks or reproong, Miller believes that
there is always a way to make something
more efcient and more cost effective. The
innovation truly never stops and Alfred
Miller Contracting is revolutionizing, not
just the re proong industry, but the entire
petrochemical industry as a whole.
Left: AMC Fireproong Yard / Right: Heater Legs – Photos courtesy of Alfred Miller Contracting
ALFREDMILLER.COM
THINK PRODUCTIVITY
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Born and bred in the Downstream Oil
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Our automation, technology, and lean
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