Young Professionals in the Oil and
Gas industry: Interview with Kim
Salinas, Bank Engineer, ING
p. 80
Estimating Installation
Costs for Automatic
Tank Gauges
p. 4
Implementing the Right Strategies
to Immediately Boost Operator
Cash Flow
p. 60
Deepwater Manages
Pandemic on Land and
at Sea
p. 30
September / October 2020
See page 105
Upstream to Midstream ERP in ONE Platform
W Energy Software (formerly Watereld Energy) offers the only unied oil & gas ERP software platform
built on the cloud. With W Energy Software as a partner, upstream and midstream companies stay
lean and agile with the modern technology they need to adapt to market changes.
Discover the Future of Energy Software
Oilman Magazine / September-October 2020 /
One Hundred Years In The Permian: Rebecca Ponton .................................................................................................................................................................................52-55
OILWOMAN – A New Aera For President and CEO Christina Sistrunk: Rebecca Ponton
In Every Issue
Letter from the Publisher ...........................................................................................................................................................................................................................................2
OILMAN Contributors
OILMAN Online // Retweets // Social Stream
Downhole Data
........................................................................................................................................................................................................................................................... 3
OILMAN Columns
Oilman Cartoon: Steve Burnett ...............................................................................................................................................................................................................................31
Natural Gas: Beyond the Pandemic: Mark
A. Stansberry....................................................................................................................................................................................43
Improving Operations Through Technology: How Sigma Drilling Technologies is Revamping Industry Drilling Practices: Tonae’ Hamilton
Interview: Spencer Albright, President, MineralWare: Eric R. Eissler
Low-Code Software Development to Propel Oil and Gas Tech Higher: Eric R. Eissler
Pipelines: A Vital Piece of the Puzzle in the Oil and Gas Stream: Emmanuel Sullivan
Digital Twins Flourish in Upstream Sector: Eric R. Eissler
Wearable Safety Technology in Combustible Gas Detection: Sarah Skinner
Living the Crude Life: Jason Spiess
Guest Columns
Estimating Installation Costs for Automatic Tank Gauges: Lee Aiken ..............................................................................................................................................................4
AI’s Critical Role in The Digital Transformation Journey: Patrick O’Brien
Amphibious, All-Terrain and Airborne Drones Enhance Efciency in Execution of Essential Services: Barry Alexander
API Foundation for Renery Safety Regulations: Andres Ocando
Buyer Beware: Consent-to-Assign Provisions in the Oil Patch: Christopher Hogan
Choosing the Right MWD Telemetry System Reduces Well Delivery Costs: Shadi Mussa
Considerations Before Implementing AI in the Oil and Gas Industry: Patrick O’Brien and Ian Campbell
Decarbonizing Oil and Gas Using AI: George Hackford
Building Your Sustainable AI Strategy and Implementation: Ian Campbell ....................................................................................................................................................28
Deepwater Manages Pandemic on Land and at Sea: Nick Vaccaro ...................................................................................................................................................................30
Patented Chemical Mixing Tool Improves Results While Slashing Chemical Spending: Paul Tarmann
Using 3D Digital Twins to support Mergers and Acquisitions Due Diligence for Industrial Assets and Facilities: Brent Stanley
Drilling Tools Most Used and Techniques to Exploit Formation Conditions: Raul Palencia
3D Printing Readiness: How to Get Setup for Success: Fabian Alefeld
Financial Reporting Impairment Considerations for Oil and Gas Companies in the Low-Price Environment: Matt Federle
Four Fundamentals to Improve Safe Production in Lean Times: Eric Michrowski and Josh Williams
Future Forward Operations: Putting Innovation at the Top of the Offshore Agenda: James Larnder
GTL Technology for Flare Mitigation is Critical to Tackling Scope 3 Emissions: Holly Havel
How COVID-19 is Forcing Oil and Gas to Rethink Workforce Management: Richard Marshall
Implementing the Right Strategies to Immediately Boost Operator Cash Flow: Kevin Decker and Steve Haglund
Leveraging Technology to Crush Costs and Concerns: Elizabeth Gerbel
Satellite Connectivity is Key for Driving Offshore Efciency, Now More Than Ever: Simon Gatty Saunt
How Safety Has Become a Priority for the Oil Sector: Henry Berry
Young Professionals in the Oil and Gas Industry: Interview with Kim Salinas, Bank Engineer, ING: Alan Alexeyev
The Challenge of Hurricane Preparedness During a Global Pandemic: Jim MacDonnell, Matt Grossman and Clark Sackschewsky
Tax Considerations for Oil and Gas in a Low Price Environment: Rob Myatt
Third-Party Compliance Management Trends in Midstream Operations: Louis Krannich and Whitney Vandiver
AR is Driving Business Continuity, Flexibility and Resilience in the Oil and Gas Industry: Kelly Malone
What are the Most Relevant New Technologies for the Upstream Sector? Andres Ocando
Why AI Will be a Game Changer for the Global Oil and Gas Sector: Craig Hayman
Lightning Strikes in the Permian: Christopher J. Riojas
OILWOMAN – Greater Gender Diversity – A Rare Positive Change to Emerge From the COVID-19 Crisis? Kerrine
Kafwembe Byran .................................... 114
OILWOMAN – In the Hot Seat: Solar’s Abby Hopper: Rebecca Ponton
OILWOMAN – Breast Cancer Awareness Special – Thinking Outside the Bow: Denise Porretto
.......................................................................................................... 119
Upstream to Midstream ERP in ONE Platform
W Energy Software (formerly Watereld Energy) offers the only unied oil & gas ERP software platform
built on the cloud. With W Energy Software as a partner, upstream and midstream companies stay
lean and agile with the modern technology they need to adapt to market changes.
Discover the Future of Energy Software
Oilman Magazine / September-October 2020 /
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-
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.
Joshua Robbins
Josh Robbins is currently the Chief
Executive Ofcer of Beachwood
Marketing. He has consulted and
provided solutions for several industries,
however the majority of his consulting
solutions have been in manufacturing, energy and oil
and gas. Mr. Robbins has over 15 years of excellent
project leadership in business development and is
experienced in all aspects of oil and gas acquisitions
and divestitures. He has extensive business
relationships with a demonstrated ability to conduct
executive level negotiations. He has developed
sustainable solutions, successfully marketing oil and
natural gas properties cost effectively and efciently.
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, 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.
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 upon retirement, nished 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. With a humorist for a father, he also
learned that a dose of comedy makes everything better.
The major inuences on his cartooning style were the
Ace Reid Cowpokes cartoons, the Dirk West sports
cartoons and V.T. Hamlins Alley Oop comic.
Emmanuel Sullivan
Rebecca Ponton
Sarah Skinner
Eric R. Eissler
Tonae’ Hamilton
Kim Fischer
Steve Burnett
Joshua Robbins
Jason Spiess
Mark Stansberry
Eric Freer
Diana George
To subscribe to Oilman Magazine, please
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publication are copyright 2020 by Oilman
Magazine, LLC, with all rights restricted.
Any reproduction or use of content without
written consent of Oilman Magazine, LLC
is strictly prohibited.
All information in this publication is
gathered from sources considered to be
reliable, but the accuracy of the information
cannot be guaranteed. Oilman Magazine
reserves the right to edit all contributed
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Please send address change to
Oilman Magazine
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Cover photo courtesy of
Jasmin Pawlowicz –
Inside back cover courtesy of Dan Dunn – 416-931-3643
CONTRIBUTORS — Biographies
Emmanuel Sullivan, Publisher, OILMAN Magazine
We’re all searching for the
news in the good news/bad news equation right now and
it can be hard to nd at rst glance. While remaining realistic and pragmatic, at
we also want to be optimistic and, if we know one thing about the energy industry, it’s that
the people who make up the industry know how to adapt, innovate and adjust to its cyclical
nature (and even something as unforeseen as COVID-19). Case in point: as employees had
to respond with agility to working remotely (and, for some, the added responsibility of
homeschooling), thanks to digitization and advanced technologies, many companies had their
employees connected virtually within a matter of days without interrupting business.
Let’s get the bad news out of the way rst. Like many industries experiencing cutbacks as result of the pandemic,
the oil and gas market is no different. Just since our last issue was published in July, there has been a wave of bank-
ruptcies in the industry, the majority of which are companies that do business in the upstream segment. According
to the law rm Haynes and Boone, $55.1 billion in debt has been brought to U.S. bankruptcy courts with a total of
225 lings in the E&P market since the beginning of the year. The second quarter had the most bankruptcies since
2016. The largest oileld service company ling for bankruptcy so far this year is Diamond Offshore Drilling with
$11.8 billion in debt followed by Chesapeake Energy, a shale producer, that led with more than $9 billion in debt.
Since March, the oil and gas industry has laid off 99,000 employees: 59,000 in Texas, 9,700 in Louisiana and
8,800 in Oklahoma. In addition, Colorado, New Mexico, California and Pennsylvania lost about 4,000 jobs each.
The Bureau of Labor Statistics data indicates 44,500 jobs have been cut from oileld service companies, 23,000
from drilling and extraction, and 16,000 from pipeline companies. Major companies, such as BP, Halliburton,
Schlumberger, Baker Hughes, BJ Services and Weatherford, have eliminated employees from their payrolls.
The clean energy sector also lost 27,000 jobs since May.
A gloomy 2020 indeed; however, the paycheck protection program has helped businesses, large and small, get
through the early stages of the pandemic. There has been ongoing support locally to help struggling businesses
and individuals with business loans, grants, rental assistance and extended unemployment benets. Besides the
$300 per week supplemental unemployment benet President Trump authorized, Congress is discussing additional
aid to businesses and working on another round of stimulus payments.
Let’s end on a brighter note and continue to look for the good news in our industry. In this issue of
we’ve published a sneak peek to
OILWOMAN Magazine.
The new and exciting publication will print with
on the ip side. In
, we’ll prole women in a variety of roles that span the entire oil
and gas industry and discuss topics in renewable energy, diversity, equity and inclusion (DEI) and workforce
training. Be sure to take a look at the sneak preview and we hope you’ll be as excited as we are about the premier
issue in November.
Oilman Magazine / September-October 2020 /
Week Ending August 28, 2020
Gulf of Mexico: 13
Last month: 12
Last year: 26
New Mexico: 46
Last month: 49
Last year: 108
Texas: 107
Last month: 104
Last year: 449
Louisiana: 34
Last month: 29
Last year: 60
Oklahoma: 11
Last month: 11
Last year: 80
U.S. Total: 250
Last month: 251
Last year: 904
*Source: Baker Hughes
Brent Crude: $45.81
Last month: $43.13
Last year: $61.04
WTI: $42.93
Last month: $40.10
Last year: $55.07
*Source: U.S. Energy Information Association (EIA)
Per Barrel
Gulf of Mexico: 49,989,000
Last month: 57,376,000
Last year: 59,331,000
New Mexico: 27,439,000
Last month: 31,592,000
Last year: 27,639,000
Texas: 136,245,000
Last month: 154,760,000
Last year: 154,747,000
Louisiana: 2,350,000
Last month: 3,010,000
Last year: 3,910,000
Oklahoma: 11,257,000
Last month: 14,859,000
Last year: 18,820,000
U.S. Total: 310,045,000
Last month: 359,698,000
Last year: 377,059,000
*Source: U.S. Energy Information Association (EIA) – May 2020
Barrels Per Month
Gulf of Mexico: 76,976
Last month: 84,199
Last year: 84,924
New Mexico: 149,055
Last month: 157,831
Last year: 149,781
Texas: 720,156
Last month: 758,261
Last year: 743,888
Louisiana: 273,181
Last month: 262,307
Last year: 248,802
Oklahoma: 216,975
Last month: 235,580
Last year: 269,586
U.S. Total: 2,925,001
Last month: 2,990,647
Last year: 3,003,926
*Source: U.S. Energy Information Association (EIA) – May 2020
Million Cubic Feet
Per Month
Connect with OILMAN anytime at and on social media
Stay updated between issues with weekly reports
delivered online at
Oilman Magazine / September-October 2020 /
Determining which automatic tank
gauge works for a specic application is
more complex than simply comparing
product prices or performance speci-
cations. There are numerous factors
associated with installing a gauge that
can inate costs and cause an operator
to exceed budget. These factors can lead
to expenses that overshadow the cost of
the level transmitter itself.
The most signicant of these factors
includes the need for tank modica-
tions, cabling and conduit, and auxiliary
equipment. Operators specifying a spe-
cic level transmitter should work with
manufacturers to determine the estimat-
ed installed costs of the main automatic
tank gauge technologies. Only then can
they choose the technology that meets
their needs within their budget.
What Options are Available?
First, operators need to understand
their options. There are three promi-
nent level measurement technologies
used in aboveground storage tanks in
the upstream oil and gas market. They
are Magnetostrictive, guided wave radar
(GWR), and ultrasonic based technolo-
gies. Each technology offers specic
benets that meet the needs of different
customer applications.
Each utilizes different technologies to
measure liquid levels. A GWR level
transmitter determines the liquid level
in the tank by taking a time of ight
measurement by sending a microwave
signal and waiting for the return reec-
tion from the liquid. The GWR has a
rod or exible cable that goes inside the
tank and provides a guide on which the
microwave signals can travel. An ultra-
sonic level transmitter is similar to GWR
as it is a time of ight measurement,
but it does not have a guide to direct the
waves and it uses sound waves instead
of microwaves to determine the level
measurement. Both technologies
need to be calibrated to the tank
based on its size and product.
Magnetostrictive level transmitters use
the time-based Magnetostrictive position
sensing principle. Within the sensing
element, a sonic strain pulse is induced
in a specially designed waveguide by the
momentary interaction of two magnetic
elds. One eld is generated by a per-
manent magnet sealed inside of a oat
while the other eld is generated from
an “interrogation” current pulse ap-
plied along the waveguide. The resulting
strain pulse travels at ultrasonic speed
along the waveguide and is detected at
the head of the sensing element. The
position of the magnet is determined by
accurately measuring the elapsed time
between the application of the inter-
rogation pulse and the arrival of the
resulting strain pulse. Magnetostrictive
level transmitters are built to order and
do not need to be calibrated in order to
function in the tank.
Are Tank Modications Necessary?
One of the rst considerations engi-
neers and site managers need to make
when estimating installation costs is
how much existing tanks will have to be
modied. Most were not fabricated to
accommodate the various gauges and
other equipment required. While some
tanks require no modication, others
can require considerable alterations. The
two factors that need to be considered
are costs for new tank openings and the
cost for stilling wells. These can vary
signicantly depending on the technol-
ogy used and the preexisting nature of
the tank.
Every additional opening cut into the
tank increases the modication costs.
Multiple openings are needed when a
single gauge does not provide all of the
necessary process variable measure-
ments. Most tanks are looking for a mea-
surement of product level, interface level
and temperature to control the process.
GWR and Ultrasonic level transmitters
are only able to provide a level measure-
ment and require separate devices to
provide temperature. Magnetostrictive
level transmitters provide a denite
advantage in these applications because
they incorporate a 5-IN-1 design, which
allows for the measurement of product
level, interface level and temperature to
be measured from a single tank opening,
but also gives volume measurement and
an HI Level Switch as featured in the
Estimating Installation Costs
for Automatic Tank Gauges
By Lee Aiken
Photo courtesy of iStock
Oilman Magazine / September-October 2020 /
Photo courtesy of MTS Sensors
LevelLimit by MTS Sensors. The ability
to provide automatic tank gauging and
overll protection from a single opening
helps increase safety while minimizing
The second factor is the need for stilling
wells. Depending on the details of the
application, some level technologies
can be installed without the need for a
stilling well, allowing for lower installed
costs. If available, all three level tech-
nologies should be installed in a slotted
stilling well for the most accurate level
measurement. In addition, stilling wells
are typically required to allow the addi-
tional interface and temperature mea-
surement instrumentation to perform
correctly. This need is best determined
by the manufacturer, who can easily tell
you if a stilling well is required. For most
applications, the Magnetostrictive level
transmitter does not require a stilling
well and helps minimize cost.
How Do Cabling and Conduit
Affect Price?
Cabling and conduit needs differ sig-
nicantly based on the level technology
used and are not included in the stan-
dard cost of automatic tank gauges. To
determine the costs of the cable, simply
access the installation manual for the
manufacturer’s cable specication. Some
level transmitters require separate power
and communication cables or specialty
cables. A slight change in cable require-
ments can cause a signicant change in
Wiring topology also affects the
overall cost. Analog outputs require
direct connection between the level
transmitter and the host system, while
bus networks wiring allows sharing
cabling and reduces the amount of
cable needed. Some level technologies
require individual power cables but will
share the communication cable. All of
these options should be evaluated based
on their cost as it relates to the level
technology chosen.
The MTS LP-Series offers Modbus
RTU output over a RS485 network. The
cable can be shared with power and
communication lines and have a bus
topology to minimize the overall length
of the cable run. The cable requirements
are standard communication cable. All
of this helps the LP-Series maintain an
attractive installed cost.
What Auxiliary Equipment is
The costs of auxiliary equipment can
be determined through a site survey
and an ofcial quote from the manufac-
turer. Far too many site managers and
engineers overlook this step only to nd
themselves with hefty costs related to
auxiliary equipment later. A site survey
will reduce the likelihood of surprises.
Examples of auxiliary equipment are
heaters for cold weather applications,
protocol converters for proprietary
protocols, specialty tools for service or
installation, and licensed software.
The Magnetostrictive LP-Series from
MTS does not need any auxiliary
equipment to perform. The installed
base covers the spectrum from warm
tropical climates in Colombia to cold
climates on the North Slope of Alaska.
The LP-Series also features industry
standard protocols of HART® and
Modbus RTU that can connect directly
to most controls systems. MTS provides
free software for troubleshooting and
commissioning is included in each
shipment. There are no hidden costs for
the LP-Series.
Making an Informed Decision
Installing an automatic tank gauge
system can be more complex than it
rst seems. All factors, including tank
modications, cabling and auxiliary
equipment must be considered in order
to remain in budget. In most situations
that require installing on existing tanks,
Magnetostrictive level transmitters have
the lowest installed cost over GWR
and ultrasonic. The main difference
is the 5-IN-1 measurement capability
of the LevelLimit by MTS to measure
the product level, interface level,
temperature, volume, and a HI Level
switch from a single tank opening.
Operators who work closely with the
manufacturer to understand what they
need and how technologies differ will
be better informed and able to make
a decision that lowers costs without
sacricing the performance they need.
Lee Aiken is the Global Market Seg-
ment Leader, Liquid Level for MTS
Sensors and an active member of API
committees for Ch. 3.1b and Ch. 18.2.
With over 12 years of experience with
automatic tank gauging, he has been
published in several magazines, hosted
webinars, and taught at ISHM. Aiken
has a Master’s of Business Admin-
istration (MBA) and a bachelor’s in
electrical engineering from North
Carolina State University.
Oilman Magazine / September-October 2020 /
By taking advantage of reduced inac-
curacies and improved productivity
thanks to AI, the oil and gas industry
can enjoy faster data analysis and more
informed business decisions.
Beginning in the early 2000s, the term
“digital transformation” became a
buzzword in the oil and gas industry.
Nearly every major energy company
set its sights on creating a “Digital
Oileld” that would capture vast
amounts of data and allow for better
logistics, analytics and modeling. Other
industries managed to accomplish this
by utilizing a new wave of available
computing power, storage and the use
of articial intelligence (AI). Why has
the oil and gas industry lagged, com-
paratively speaking? Why cant major oil
and gas companies manage their inven-
tory with the speed and precision of
the likes of Amazon or Google? What
keeps them from creating the ideal
“Digital Oileld”?
AI Challenges in an Asset Heavy
First, consider the expansive scope and
scale of oil and gas assets that are cur-
rently operating in the U.S. According
to Ralph E. Davis Associates, there are
469,616 active oil wells, 131 operating
reneries, 1320 active terminals and,
in 2019, there were 224,045 miles of
active oil pipelines. Given that a single
oil well can produce one terabyte of
data per day, the amount and depth of
data generated at every step of the sup-
ply chain is immense. However, Cisco
estimates that oil and gas companies
currently use only about two percent of
the data that they generate due to a lack
of transfer capability, storage capacity
and computing power.
Unfortunately, it’s much more difcult
to track a massive volume of crude
traveling through a pipeline than it is to
simply scan a radio-frequency identi-
cation (RFID) on a boxed package
along its route from a warehouse to
your front door. Therefore, compar-
ing logistics involved in the oil and gas
industry to a company like Amazon is a
bit like comparing motorcycle repair to
xing a bicycle. Although the technol-
ogy energy companies need to track,
optimize and schedule logistics exists,
implementing such a sophisticated
system can be difcult, especially when
dealing with a number of problems
derived from poor data.
Where is AI Already Being Applied
Given the myriad of benets, one
would think the adoption rate of AI in
the oil and gas industry would be high;
however, the reality is that the degree
of industry-wide acceptance is just
scratching the surface. Effective imple-
mentations of AI can be seen primarily
in the upstream sector. In the Permian
Basin, for example, technicians histori-
cally spent much of their time driving
from one remote oil well to the next
checking systems and collecting data,
then driving back to the central ofce
at the end of the day and uploading it.
To reduce this inefciency, ExxonMo-
bil’s subsidiary XTO Energy partnered
with Microsoft’s Azure AI platform
to transform its daily operations by
creating an AI cloud infrastructure that
continuously monitors and uploads
data. This not only enables technicians
to focus on wells that may require more
evaluation and maintenance, but it also
allows for more accurate well analytics
and future enhancement modeling by
eliminating data silos.
How Can AI Benet My Company?
Sometimes the hardest part of
implementing an AI platform is
determining where it could add value
to the organization. Below are just a
few examples of AI platforms that
can enable oil and gas companies to
operate with more agility, efciency
and accuracy than ever before.
Amazon Fulllment Centers – Source: FREIGHTOSU.S. Crude & Petroleum Product Terminals – Source: EIA
AI’s Critical Role in The Digital
Transformation Journey
By Patrick O’Brien
Oilman Magazine / September-October 2020 /
Continued on next page...
XTO and Microsoft Azure IoT Solution – Source: Microsoft
Exploration and produc-
tion companies are using AI
to analyze historical equipment data
and create predictive failure analytics
models, maximizing asset utilization
and allowing operators to schedule
maintenance and x equipment
before it fails.
Pipelines use AI for remote moni-
toring of pipeline conditions, en-
abling a safer work environment for
inspectors, and alert systems when a
sensor may need to be replaced or a
spill is detected.
Reneries are able to collect,
analyze and model data from over
150,000 sensors equipped in a
facility and display it in the best
format for a specic end-user.
This allows plant operators to
spend less time performing safety
walks and vibration checks while
improving safety in the workplace.
Yield optimization machine
learning software can also improve
production accuracy and reduce time
spent performing lab tests.
Energy trading risk management
capabilities can be further enhanced
by the utilization of AI. With AI’s
ability to rapidly process large datas-
ets, coupled with its pattern recogni-
tion ability, trading surveillance pro-
cesses can better isolate anomalous
trading activity which may require
further analysis or investigation by
compliance teams.
AI platforms no longer require soft-
ware companies to develop customized
packages that exactly t the needs of a
user to allow for effective, fast imple-
mentation. Utilizing a low-code AI
platform, users can drag and drop
components to create tools at about
10 to 20 percent of the cost and time.
Overcoming AI Hurdles
Although oil and gas companies face
unique challenges, there are a few
things they can do to implement an ef-
fective AI platform and execute a suc-
cessful digital transformation strategy.
Oilman Magazine / September-October 2020 /
As discussed in an article written by
Rob Roberts, the foundation of any
AI platform implementation strategy
is an effective Master Data Strategy
(“MDS”). Major energy companies
have operations all over the world. As
groups form based on products, loca-
tions and functions, data silos lled
with information can be locked away.
Data silos can also lead to duplica-
tions, different classications of the
same data, and other issues stemming
from a data compilation phase of an
enterprise-wide software. An MDS
eliminates silos and then integrates
and cleanses data for AI use.
The Future Impact of AI
AI platforms require rigorous
planning, building, software selection,
appropriate assembly of personnel,
and implementation – all of which
need to be conducted in an organized
manner to be effective. Rushing
through any one of these phases will
inevitably lead to failures and cause
the entire project to lose momentum.
We at Opportune stand ready to
assist oil and gas companies every
step of the way during their digital
transformation journey.
The savings generated by AI’s analyti-
cal models have forced companies to
focus on how they can use AI plat-
forms to be more efcient, effective
and get a leg up on their competi-
tion. Sometimes, all it takes is for one
organization to push its limits in order
to prove its effectiveness and dra-
matically shift the best practices of an
entire industry.
The next installment of this mini-se-
ries will focus on some considerations
that allow the implementation process
of an AI platform to be as easy and
effective as possible.
This is the rst installment of a three-
part series discussing AI’s potential
and critical role in oil and gas, how
a company can prepare for an AI
platform, and important steps to
executing a sound AI implementation.
Patrick O’Brien is an
intern with Opportune
LLP’s Process & Tech-
nology group. Cur-
rently attending Texas
A&M University, O’Brien is concur-
rently pursuing an undergraduate
degree in chemical engineering and
an MS in nance.
Source: GTM Research
Get the Oil & Gas news and data you need
in a magazine you’ll be
to read.
To subscribe, complete a quick form online:
Questions? Call or email anytime. • (800) 562-2340 Ex. 5
MFG_ADS_Oilman_FullPage_01.20.pdf 1 1/10/20 12:59 PM
Oilman Magazine / September-October 2020 /
Although awareness of the safety
solutions offered by unmanned aerial
systems (UAS) – aka drones – has
recently spiked across the healthcare
community due to the coronavirus cri-
sis, perhaps one of the fastest growing
uses of this burgeoning and advanced
technology is within the oil and gas
industry. Not only can drones be used
for asset inspection and repair at large
scale energy facility sites, but now a
new breed of bots is able to monitor
work-in-progress in all environments
and across natural elements by travers-
ing land and swimming in the water!
The advent of spherical, amphibious
and all-terrain drones is creating a
powerful complement to their airborne
counterparts to achieve better business
practices, streamline solutions, increase
safety and elevate protability across
the entire energy eld.
But the key to conducting successful
missions is in the cloud! Program-
ming any type of drone hardware with
customized capabilities enables it to
collect, analyze, store, model and share
data in real time, giving oil and gas
engineers the ability to transform bots
and UAVs into powerful, autonomous,
AI-infused entities for complicated mis-
sions in surveillance, security, detection
and repair.
Besides a variety of aerial drones with
highly specialized vertical takeoff and
landing (VTOL) functions, spheri-
cal drones offer total environmental
protection and ultimate precision to the
profession by traversing all types of ter-
rains, including paved roads, dirt paths,
sand dunes, snowy elds, sloped moun-
tains and ocean surfaces. These radi-
cal bots can range from six and a half
inches to seven feet in diameter and
move uidly in a forward and backward
motion, as well as make 360-degree
turns, reaching maximum speeds of 12
mph on land and three mph in water.
Each one contains interchangeable
sensors, such as video cameras, ther-
mal, infrared, microphones GPS and
audio for continuous content gathering,
transmission of data and constant com-
munication for command and control
(C2). What’s more, they can operate up
to 25 hours on a single charge.
Further, through cloud-based
connectivity, land and sea drones can be
paired to communicate with their ying
counterparts for a strong and seamless
unmanned system (US) that works
together in solving crucial oil and gas
infrastructure challenges in a way that is
more efcient, cost-effective and safer
than traditional methods.
Here’s how:
Reduce Costs – A UAV can be used to
automate complex tasks and therefore
reduce labor costs. Instead of incur-
ring thousands of dollars in helicopter
operational costs for most aerial mis-
sions (inspection of a are-stack, for
instance), UAVs can be used for a frac-
tion of the cost, while providing better
accuracy through the use of multiple
sensors on the same platforms.
Increase Safety – In areas that have
been exposed to contamination by
an oil spill, a natural gas explosion or
that are potential security threats, an
Amphibious, All-Terrain and Airborne
Drones Enhance Efficiency in Execution
of Essential Services
By Barry Alexander
Photo courtesy of Dan Grytsku –
Oilman Magazine / September-October 2020 /
Drones are a cost-effective and highly efcient solution to a variety of industries, including military,
security and surveillance, industrial, construction, farming and forestry.
Aquiline Drones are subjected to rigorous and intense precision indoor training prior to being
released on a eld mission.
enterprise drone solution can enable
organizations to explore these areas
and even deliver supplies without
exposing employees to dangerous risks.
Increase Production – Keeping oil
reneries and rigs operational ensures
the smooth ow of product to cus-
Clearly, the latest advancements in
sensing and imaging technology
are enabling drones to be deployed
in a wide range of settings across
the oil and gas industry to perform
inspections as well as predictive
maintenance of critical infrastructure.
Specic applications, include:
Pipelines – Drones have become the
most affordable means to inspect the
thousands of miles of pipelines trans-
porting oil and gas around the world.
These infrastructures must constantly
be monitored to reduce the potential
for undetected leaks, which may cause
life-threatening res and explosions.
Drones can be equipped with opti-
cal sensors to inspect equipment for
potential pipeline leaks and impending
points of failure, infrared sensors to
examine equipment and pipelines for
heat signature anomalies, as well as
normalized difference vegetative index
(NDVI) sensors to evaluate plant life
color differentials next to pipelines,
which may also cause possible leaks.
Power Plant Facilities – Commercial
drones provide high-resolution, optical
inspections of gas power plants and
oil reneries and alerts of potential
breaches and pending points of failure.
The technology can also check efcacy,
transmission lines and surfaces.
Autonomous drones loaded with
infrared sensors and computing on the
edge can monitor such facilities using
ISR functions.
Emergencies – Distribution of single
drones or entire drone swarms that
include ground-based, amphibious
and aerial combinations can safely
assess a land or aquatic situation after
a disaster, like an oil spill, or conagra-
tion by utilizing photoelectric sensors
that offer a rst-person view of heat
signatures to evaluate re risk vectors
using normalized difference vegetative
index (NDVI) sensors. In addition,
drones can be used to measure and
quantify oil spills with the ability to
assess where the oil is spreading, how
quickly it is moving in the water, and
the specic areas it has reached. This
real-time information can determine
where to send response vessels and
recovers time previously spent on the
process of damage detection.
Transportation – Drones assist
in natural gas tunnel and oil well
evaluations, as well as the delivery of
goods and supplies to key engineers
and personnel across the entire
distribution chain whether they are on
land or the ocean.
Water Systems – Inspecting
offshore oil platforms is much
more complicated than those on
Continued on next page...
Oilman Magazine / September-October 2020 /
the mainland and puts workers at a
higher risk. Lengthy shutdowns can
damage efciency and operations
can be forced to go ofine. Using
drones can help minimize these
complications as they can transmit
real-time information to the operator
on the rig, while ying within meters
of the offshore platform. HD video
and still imagery can be provided from
all angles – vital information that can
be used to assess and plan necessary
work in advance. Autonomous
drones supplied with high resolution
optical and infrared sensors can also
be disseminated to monitor external
boundary and internal surfaces
of offshore oil facilities using ISR
Gas Emissions Monitoring – Oil
and gas companies are constantly
looking to reduce methane from
operations to mitigate climate change
and global warming. To achieve these
objectives, drones with highly sensitive
optical sensors can help monitor gas
emissions over large critical sites and
difcult to reach areas like hydrauli-
cally fractured gas wells and make sur-
veying, identifying and correcting leaks
a simple task. Drones help reduce the
cost of carrying out such inspections
and allow safe 3D mapping of drill
sites, gas pipelines, landlls and other
municipal operations.
Drones, whether aerial, land-
based or aquatic, provide essential
services to the entire energy industry
through their virtual monitoring
and surveillance, inspection and
maintenance, methane management,
emergency response and material
handling functions. The total results
and benet for all oil and gas
companies that use comprehensive
and enterprise drone solutions
are exhaustive. Reducing costs,
maximizing return on investment
(ROI) and creating new business value
in a safe, responsible and eco-friendly
manner are the business justication
for a well-dened enterprise UAV
solution in the oil and gas industry!
Aquiline Drones offers best-in-class drone hardware and sensor packages for a variety of
commercial missions.
Command and control (C2) training includes Flight Control Software that guides drones from take-
off to landing, noties pilots of any potential obstacles and ensures safe, close formation ights.
Barry Alexander is a veteran airline pilot, who recognized
the need for an aviation-inspired and real-time proprietary
operating system (RTOS) to take commercial drone
functionality to the next level and thus created Aquiline
Drones (AD), the rst U.S.-based, comprehensive drone
solutions company, comprised of highly experienced aviators, software
engineers and IT gurus. With a customer-centric model, U.S.-based
manufacturing, U.S. supply chain, and world-class MRO services, the
company offers innovative ways to use drones in commercial activities.
Since 1947 we have been dedicated to delivering innovative
coatings, linings, and fireproofing products. We are driven to
provide the best solutions, service, and quality to our customers.
Oilman Magazine / September-October 2020 /
Reneries are petrochemical industrial
plants where substances derived from
crude oil and gas are obtained. Within
their walls, transformation and ren-
ing processes occur to obtain products
such as gasoline, diesel, asphalt, kero-
sene, liqueed gas, oils and fuel. To talk
about reneries is to discuss movement
Today, rened hydrocarbons are the
most vital source of movement in the
world, despite their competitor: electric
cars. In 2018, the number of electric
cars per 1,000 people in China was 1.6
and in the United States that number
was 3.4 people per 1,000 people. This
means that the world will depend on
rening processes for much longer.
If we count the things produced in a
renery, we notice that all derivatives
have a signicant degree of volatility.
Add to this the acidic and toxic ele-
ments used to carry out these puri-
cation and rening processes and we
conclude that it is work that involves
constant high risk because the slightest
mistake can lead to tragedy.
Beyond a solution including the use of
protective equipment such as appropri-
ate clothing, special nitrile gloves or
insulator, articial respiration masks or
suits to prevent environmental toxic-
ity in controlled sectors, the best safety
practices for the rening industry are
based on the implementation of these
resources as a small part of the entire
system. The best way to avoid accidents
is if they do not occur. Regulations are
based on this principle, especially the
ones created for work in reneries.
Although most hydrocarbon rening
industries worldwide adjust their safety
and regulation mechanisms, there is a
global standard rule provided by the
American Petroleum Institute (API),
composed of 180 operational rening
safety standards, which are approved
by the American National Standards
Institute (ANSI). It should be noted
that API standards are required in
most countries for reneries to operate
API Standards Base for Safety
The 180 regulations of the API created
for the industrial rening complex are
based on avoiding accidents, consider-
ing solutions in the form of regulations,
with the use of the pyramid created in
1931 by H. W. Heinrich. This pyramid
is represented with two key concepts in
the eld of safety as established by the
API document titled “Process Safety
Indicators for the Rening and Petro-
chemical Industries.”
Safety accidents can be placed on a
scale representing the level of con-
Many precursor incidents occurred
with lesser consequences for each
accident that occurred with greater
Pyramid tier 1 events refer to safety
events that are represented as the
most consequential incidents as the
result of real containment losses.
This type of accident is closely
related to the loss of toxic or volatile
uids in the facilities.
At this tier of the pyramid, the regula-
tions established by the API that inte-
grate the proper management of the
processes within the facilities enter the
scene to avoid possible spills of hazard-
ous substances, either volatile or toxic.
In the Recommended Practices (RP)
2001, provided by the API in 2019, it
is mentioned that the best ally to deal
API Foundation for Refinery
Safety Regulations
By Andres Ocando
Photo courtesy of Concawe
Safety pyramid. Image courtesy of API
Oilman Magazine / September-October 2020 /
API Workplace Injuries and Illnesses Safety Report. Source: API
with process failure and to avoid Tier 1
of the Heinrich pyramid, is the cor-
rect digitalization of the industry. This
limits the intrusion of human error and
does not put lives in jeopardy, using
PLC valves, and sensors for detection
of leakage and odors, under the man-
agement of the supervisory control
and data acquisition system (SCADA),
added to the standard emergency spray-
ing systems for reneries.
Tier 2 of the pyramid sets out spill
events with respect to inert uids
that may cause problems of minor
consequences, but these in turn may
cause major operational problems in
the facilities.
What is established by the pyramid
encourages the rules of best practices
to have as the main alert for the
second tier of the pyramid, where a
failure not visualized on time generates
an unexpected spill which, despite
containing a non-toxic or dangerous
substance for human personnel, marks
an Amber Alert in the mechanisms of
action, and encourages the inspection
and reconditioning of all processes
before and after this.
The API in its RP 2001 (8th edition)
mentions this point in particular and
establishes a series of action rules in
view of these situations, including the
use and implementation of the SCADA
system for the management of diluent
pumping toward the distillation and
enrichment processes of hydrocarbons,
as well as the presence of highly quali-
ed and experienced personnel to avoid
unnecessary alarms in case of spills.
Tier 3 of the Heinrich pyramid ad-
dresses problems related to weak-
nesses in safety systems, ranging
from the entry of unauthorized per-
sonnel into a certain area, to a failure
in the inspection of the raw material
entering the renery, as well as the
inspection of automated processes.
For the correct prevention under this
tier, the use of experienced personnel is
established as well as automated pro-
cesses to perform multiple random and
periodic inspections in the established
safety systems. In this way, the auto-
mated system is constantly inspected
and the personnel is kept alert to be
prepared for any unexpected event.
The lowest tier of the pyramid
deals with operational discipline and
performance in process manage-
ment systems. This is addressed to
those responsible for compliance
with the methodologies expressed in
the operating manuals, i.e., human
personnel, their degree of discipline,
experience and commitment to com-
ply with what is programmed.
The lack of personnel training is one
of the main reasons for operational
problems in reneries. In the RP 2001
document (9th edition), it makes special
mention of the training of those in-
volved in the development of process-
es, as well as the correct employment in
the activities corresponding to qualied
The 187 parameters intended by API
and the American National Standards
(ANSI) for a safe environment in ren-
eries, in addition to being a requirement
for operation, are an alternative that,
if followed to the T, give the system
an almost foolproof functionality, as
explained in the document “Comments
of the American Petroleum Institute,
prepared by the API for the State of
Washington in 2018, in which an as-
sessment of reneries on U.S. territory
was conducted.
It should be noted that the U.S. govern-
ment requires the operation of rener-
ies under API regulations. The results
show that the 187 standards established
under the RP 2001 document, in all its
editions, fulll the goal of establishing
a safe environment by far.
In this exercise, 520 companies from
Continued on next page...
Oilman Magazine / September-October 2020 /
both the public and private sector
were compared with reneries
operating under the standards
established by the API. The result is
that the number of accidents per year
is 0.6, regarding important cases.
On the other hand, the API conducted
a survey in recent years, collecting
safety data during the processes.
Process safety involves the application
of good practices of operation,
maintenance, inspection, engineering
and processes, i.e., compliance with
the Heinrich pyramid. These are the
The study was conducted from 2012
to 2016 and included approximately
85 reneries per year. The analysis
was based on the problems related to
tier 1 and 2 of the Heinrich pyramid
divided into 200k hours of work per
man. The results showed that the
practices established by the API for
the management of operations in
reneries kept the cases of danger or
accident to a non-existent amount.
In light of these results, there is no
doubt that the best practice for an
environment free of accidents is
prevention based on the prediction
of possible accidents, from minimal
circumstances that can lead to major
problems. The 180 regulations
prepared by the API as regulations
for the proper functionality of the
reneries are guaranteed as the best
way to avoid accidents (this type of
document obeys a copyright and may
not be used unless the proper training
is obtained). Thanks to this document,
it is now a federal requirement that a
renery must have a permit to operate.
It also requires training of personnel
by the Occupational Safety and Health
Administration (OSHA).
The use of helmets, safety suits and
gas masks are the rst line of defense
for workers in reneries but, if the
degree of danger with which workers
do their job every day is analyzed,
it can be concluded that without a
proper and hermetic safety system
the zero accidents goal cannot be
achieved. Automation and process
management followed to the T are
here to stay, and every day they save
more lives and jobs.
Andres Ocando, 30, is
a petroleum engineer,
who has been working
for PDVSA for ve
years, in positions such
as reservoir engineer and geome-
chanical engineer. He currently
works as a project analysis engineer.
There, he has optimized the data
collection process for the develop-
ment of geomechanical models.
He has experience in copywriting
and is currently a technical writer on
topics related to the oil and technol-
ogy industries. He collaborates on
important technical magazines such
as OILMAN and SPE. Quality and
responsibility are two words that
describe him perfectly.
Ocando is currently pursuing
higher studies at the University of
Zulia to obtain a master’s degree in
petroleum engineering.
API Process Safety Event (PSE) Public Reporting per API RP 754. Source: API
Get the Oil & Gas news and data you need
in a magazine you’ll be
to read.
To subscribe, complete a quick form online:
Questions? Call or email anytime. • (800) 562-2340 Ex. 5
Oscar Waldo Williams
Saga of a Pioneer Spirit
(1853 – 1894)
Edited by Janet Williams Pollard and Jim N. Hammond
"One of the riders, clothed
in [a] black overcoat and
riding a black horse bleeding
from a wound in the hind leg,
passed the Plattsburgh Road,
and with some diculty
turned his horse back at a
point not far from where
I was hugging my tree. I
thought I caught a sardonic
grin on his face when he got
sight of me against [the] tree.
I never knew who he was,
although I heard a rumor
that the horseman in black
was Jesse James."
– Oscar Waldo Williams
Four-O Winds Publishing | Abilene, Texas | Spring 2020
To purchase, contact Clay Pollard at
Oilman Magazine / September-October 2020 /
A sense of normalcy is returning to the
oil patch, at least compared to the roller
coaster ride that took place in March
and April of this year. For much of this
summer, WTI has hovered around $40/
barrel, giving operators some stability in
pricing and the chance to make money
in some of the more cost-effective
portions of the Permian, Delaware and
Eagle Ford plays. And with Chevron’s
recent blockbuster purchase of Noble
Energy, many have predicted a return
of robust acquisition activity to oil and
gas plays in Texas.
But a recent Texas Supreme Court
decision suggests that parties acquiring
oil and gas leases may face a challenge
they did not anticipate in the past:
consent-to-assign provisions that courts
may be ready to enforce.
Most energy lawyers and landmen have
seen plenty of consent-to-assign provi-
sions in leases, farmout agreements and
other oileld agreements. In general,
these agreements come in two variet-
ies: “hard” and “soft.” A hard consent
allows a party to decline to consent for
any reason (or no reason). A soft con-
sent requires a lessor’s consent, but the
lessor cannot “unreasonably withhold”
that consent.
Texas courts have recently looked at
each of these types of clauses, with
implications for oil and gas acquisitions
throughout Texas.
Hard Consent: Possibly Enforceable
in Texas?
Many Texas energy lawyers will tell you
that hard consents for oil and gas leases
are not enforceable under Texas law.
This is because Texas (and other states)
reject unreasonable “restraints on the
alienation of property,” i.e., we do not
want to stop people from buying and
selling property, including oil and gas
leases. With this default, most lawyers
think that Texas courts, when presented
with such a clause, would nd it unen-
forceable and strike it from the contract.
But the Texas Supreme Court’s decision
last year in
Barrow-Shaver Resources
Company v. Carrizo Oil & Gas, Inc.
may call this analysis into question. Car-
rizo was a lessee on a 22,000-acre lease
in north-central Texas. Barrow-Shaver
was prospecting in the area, trying to
form a large drilling prospect. The
parties entered a farmout agreement,
under which Barrow-Shaver would earn
a partial assignment of Carrizo’s interest
in the lease in exchange for its services
in drilling a producing well. The parties
negotiated a consent-to-assign provision
that required Carrizo’s consent to any
Barrow-Shaver assignment:
The rights provided to [Barrow-
Shaver] under this Letter Agreement
may not be assigned, subleased or
otherwise transferred in whole or
in part, without the express written
consent of Carrizo.
Later, Barrow-Shaver wanted to assign
its interests in the farmout to a third
party, Raptor Petroleum. It secured the
consent of many parties, but Carrizo
did not consent to the assignment. In-
stead, it offered to sell its interest in the
lease to Barrow-Shaver for $5 million
– a deal Barrow-Shaver did not accept.
When Carrizo did not consent, Barrow-
Shaver’s deal with Raptor fell through.
Barrow-Shaver sued Carrizo and alleged
that the consent-to-assign provision
was silent when it came to why Carrizo
could withhold consent. Based on
this purported silence, Barrow-Shaver
introduced testimony from a noted oil
and gas law professor, who testied
that “charging for consent to assign is
inconsistent with the custom and usage
Buyer Beware: Consent-to-Assign
Provisions in the Oil Patch
By Christopher Hogan
Photo courtesy of zhengzaishuru –
Oilman Magazine / September-October 2020 /
of the industry” and that Carrizo’s
refusal to consent was a breach of the
farmout. The jury agreed and awarded
$27.6 million in damages for breach of
the farmout.
The Texas Supreme Court had to
determine whether Carrizo breached
the consent-to-assign provision. The
Court noted that under the farmout,
the consent needed to be express and
in writing, but had no other require-
ments, including any requirement of
reasonableness. And the Court declined
to create any kind of implied duty –
meaning a duty that would exist even if
not mentioned in the agreement – of
reasonableness. And despite Texas’s
prohibition on unreasonable “restraints
on the alienation of property,” the
Court passed on using this standard to
imply a reasonableness requirement for
the consent-to-assign provision.
Could this rejection of an implied
reasonableness requirement be the sign
of a sea change when it comes to hard
consents in Texas oil and gas leases?
The core of the farmout agreement is
the assignment of a party’s fee interest
in a lease, exactly the kind of interest
transferred when a lessee assigns a
lease to a third party. If a hard-consent
provision is enforceable when it comes
to farmouts, perhaps they are for
standard lease transfers, too.
If so, acquisitions like those of Chev-
ron may become quite a bit harder. As
a practitioner, many leases I see have
consent-to-assign provisions, and it
seems like many acquiring parties skate
over them. But if they prove to be
enforceable, future large-scale transac-
tions may become increasingly difcult
as they will depend on securing the
approval of dozens – if not hundreds –
of third parties.
There is also reason to think that courts
will not apply the
case to
simple lease acquisitions. The Texas Su-
preme Court did emphasize that a farm-
out involves more than just transferring
property. It also contemplates that the
acquiring party will render services (e.g.,
the drilling of wells) after the property
transfer. Personally, I think future courts
will nd this distinction important and
continue to reject hard-consent assign-
ments unrelated to farmout agreements.
Soft Consent: A Checklist for
Operators looking at a soft consent-
to-assign provision have often been
wracked by the same question: what is
an “unreasonable” refusal to consent
to an assignment? Until recently, Texas
courts provided little guidance on this
question. But the Northern District of
Texas recently provided a roadmap for
operators to follow on this question.
The Court’s decision in
Foundation for Medical Education &
Research v. BP America Production
involved a lease amendment
that did not permit the lessee to transfer
the lease without the lessor’s consent,
which “shall not be unreasonably
withheld.” When the lessor and lessee
got in a dispute about assigning the
lease, the issue landed in federal court.
The Court had to determine if the les-
sor’s refusal to consent was reasonable.
This was a difcult inquiry, as no other
Texas court had outlined how to deter-
mine reasonableness in this scenario.
So the Court outlined a list of several
factors to consider when determining
whether a party’s refusal to consent to
an assignment is reasonable:
the buyer’s solvency and record on
making prompt royalty payments;
the buyer’s industry reputation for
honesty and reliability;
the buyer’s prior working relationship
with lessor;
the buyer’s ability to run the leasehold
in an efcient manner;
whether the buyer is a “lease ip-
per” that will not actively develop the
property; and
whether the buyer would increase the
number of non-cost bearing interests
on the property, such as overriding
royalties and production payments.
Looking at all these factors, the Court
found the lessor’s refusal to consent to
the assignment was unreasonable and
refused to enjoin the transfer.
Takeaways for Operators Looking to
Acquire Leases
The two cases discussed above deal with
different consent-to-assign provisions,
but they both show that these clauses
could throw a wrench into a potential
burst of oileld acquisition activity. If
future courts read
permit hard consent-to-assign provi-
sions going forward, operators will need
to be extra diligent to make sure they
check leases they are looking to acquire
for these provisions and secure consent.
Mayo Foundation
case shows that
courts may not void soft consent-to-
assign provisions, but also provides the
criteria that courts will likely consider
in determining whether a lessor is being
reasonable. By considering these fac-
tors in advance, operators faced with
an obstinate lessor (or one who wants
to squeeze out some extra money in
exchange for consent) should have a
better idea how they’ll fare in court if
they have to litigate the issue.
If a wave of acquisitions does indeed
hit the oil patch, buyers should keep
a close eye on any consent-to-assign
provisions and consider the effect of
these clauses before going on a buying
Christopher Hogan
is a founding partner
of Hogan Thompson
LLP, a Houston-
based commercial trial
boutique with a focus on representing
energy companies operating in the
Permian Basin, Eagle Ford Shale, and
other oil and gas producing areas.
Hogan has successfully represented
energy clients in numerous
arbitrations and in both Texas state
and federal jury trials. The rm’s
client roster includes Fortune 500
companies Chevron, EOG, Marathon
Oil, BP, and Ovintiv, in addition to
Callon Petroleum and Escondido
Oilman Magazine / September-October 2020 /
In 1912 the French geophysicist Con-
rad Schlumberger, after recording the
rst geological map of equipotential
curves, applied the data to locating
iron ores and subsurface structures
that could form traps for miner-
als such as oil and gas. Conrad and
his brother Marcel were pioneering
petroleum engineers from France’s oil-
rich Alsace region who 14 years later
founded Schlumberger Ltd. In 1927 a
crew working for Schlumberger in the
historic Pechelbronn basin of Alsace
lowered an electric sonde (a transmit-
ter tool) down a well in the oil sands,
creating the rst well log in history
and the birth of wireline logging.
Still widely used in drilling operations,
wireline logging acquires data by lower-
ing electrically powered instruments
down a well shaft to record critical
measurements after a well is drilled. As
oil and gas exploration pursued deeper
reservoirs, newer logging technologies
such as Measurement While Drilling
(MWD) enabled operators to obtain
data during drilling – instead of after –
at higher and more extreme angles. In-
troduced in 1980, MWD offered added
exibility for oil wells in areas where
wireline logging and other traditional
measurement tools were not practical
options. Four decades later, MWD is
an integral part of many drilling op-
erations, providing wellbore position,
drill-bit and directional data, as well as
real-time drilling information.
MWD technology allows oil and gas
companies to drill directional and
horizontal wells to depths of 40,000
feet – equivalent to almost six-and-
a-half times as deep as the Grand
Canyon or 15 times the height of the
world tallest building, Burj Khalifa
in Dubai. Yet wells that deep present
signicant challenges in transmitting
MWD data to the surface without
interruption. Sophisticated telemetry
systems associated with MWD can
mitigate this problem, but not all
systems are alike. Understanding the
features of the most common MWD
telemetry will help drilling operators
choose the right MWD for the job.
Mud Pulse Telemetry
Mud pulse telemetry is the most
common method of MWD wireless
transmission. As the name suggests,
data derived from measurement tools
is encoded into pressure pulses that are
transmitted to the surface through a
mud channel. This signal is received on
the surface using pressure transducers
and then decoded to produce real-time
Within the scope of mud pulse
telemetry, three types are associated
with MWD:
Positive pulse telemetry deploys
a valve that is repeatedly opened
and closed to restrict the mud ow
within the drill pipe, producing an
increase in pressure that is visible at
the surface. On the plus side, posi-
tive pulse systems provide a strong
signal that is easy to modulate; on
the minus side, this method suffers
from low data throughput.
Negative pulse tools briey open
and close the valve to release mud
from inside the drill pipe out to
the annulus, producing a decrease
in pressure that can be seen at the
surface. Negative pulse systems are
simple to design, making them very
reliable, but these systems are also
subject to low data throughput.
Continuous wave telemetry systems
generate sinusoidal pressure uc-
tuations within the drilling uid,
encoding the digital information in
the pressure wave. Continuous wave
provides the highest telemetry rates
as compared to positive and nega-
tive pulse systems; however, this
type of system is more susceptible
to jamming from debris.
Although mud pulse telemetry
provides relatively low transmission
Choosing the Right MWD Telemetry System
Reduces Well Delivery Costs
By Shadi Mussa
Photo courtesy of Shadi Mussa
Oilman Magazine / September-October 2020 /
rates, most of these systems use
compression to reduce the size of
the data, allowing more data to be
transmitted to the surface.
Mud pulse systems are extremely reli-
able and cost-effective when the mud
and pumps system can provide for
good data transmission. Effective use
of any mud pulse system requires mud
properties that align with the speci-
cations of the MWD service. Using
pumps that are in good condition, with
pulsation dampeners charged, will help
ensure that your mud pulse telemetry is
not attenuated or interrupted.
Electromagnetic Telemetry
Electromagnetic (EM) telemetry
encodes the data from the downhole
assembly onto a carrier signal that
is transmitted by electromagnetic
waves through the earth. This signal
is received at the surface through
ground stakes and then decoded. EM
technology is mainly used for drilling
operations on land, as receiving the
EM signal in offshore rigs requires
putting the stakes in the seabed, which
can be a complex operation. EM
signals travel faster than mud pulse,
delivering almost-instantaneous update
rates and reducing latency between
data acquisition and receiving such data
on the surface.
One of the major advantages of EM-
MWD is its ability to work bi-direc-
tionally, transmitting data both uphole
and downhole. Another advantage is
that EM technology has no rotating or
mechanical parts, which improves tool
reliability and reduces maintenance
costs, producing an overall more cost-
effective option when compared to
mud pulse telemetry. Finally, EM is not
dependent on the mud channel or mud
pumps, which can make it suitable for
more aggressive mud systems, as well
as air or foam drilling.
Despite all these advantages, EM has
one signicant drawback in that the
EM signal may attenuate quickly due to
resistivity in the formation or surface
noise generated by electrical equip-
ment. When employing EM, proper
EM signal modelling is required prior
to running the service to evaluate sig-
nal’s strength and quality.
Acoustic Telemetry
Acoustic telemetry is another
methodology in which the downhole
data is encoded into a sound wave that
is transmitted through drill string or
Drilling depths to 40,000 feet, far exceeding the deepest and tallest natural and man-made structures,
requires sophisticated telemetry systems for uninterrupted data transmission.
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Oilman Magazine / September-October 2020 /
the earth formation and received at
the surface through an acoustic probe
installed at the well head. The data is
then decoded and interpreted for use
during the drilling operation.
Sound waves travel faster and are
denser than air, which helps to reduce
the latency in the transmission. Like
EM, acoustic telemetry is not affected
by the mud channel, and thus makes
this system easier to operate than any
of the MWD mud pulse systems.
While acoustic MWD provides high
data rates as compared to EM and
mud-pulse, the fast attenuation of
sound waves requires that wireless
repeaters be placed in the drill string,
which generally makes this service
more costly than EM and mud pulse
telemetry systems.
Wired Drill Pipe
Wired drill pipe (WDP) is a wired
telemetry system that connects the
surface system to the downhole tools
through a conductor wire and special
connections that are incorporated
inside the drill pipe.
WDP has multiple advantages over
all other wireless telemetry systems,
starting with superior telemetry rates
that allow you to monitor all the
measurements from downhole in real-
time, which allows for and promotes
faster drilling without holding back to
steer and place the wells more ac-
curately. Additionally, WDP utilizes
extra sensors placed along the drill
string to measure the pressure and
temperature, enabling monitoring for
hole cleaning and other important
parameters such as equivalent circula-
tion density (ECD), which plays an
important role in reducing well con-
trol issues and stuck pipe situations.
WDP also provides real-time updates
of downhole shocks and vibrations,
allowing more effective mitigation to
reduce damage to downhole tools.
With developments in rig automation,
WDP provides a closed loop system
for downhole and surface automation
that drastically increases efciency
and reduces drilling risks and costs.
The initial investment required to
wire the pipe and downhole tools
for WDP to create this closed
loop system is a stepping-stone
toward digitizing the oileld, which
would spur the biggest oil services
advancement in a generation.
Hybrid Telemetry
Some MWD systems combine
multiple types of telemetry, such as
mud pulse and EM, to allow effective
switching from one system to another
if drilling complexities arises. While
hybrid telemetry may add cost to
the project, it eliminates the need
for longer trips to change downhole
tools, reducing non-productive time.
In today’s market, hybrid telemetry
offers the best benets of mud
pulse and EM systems by extending
reliability with the intended
redundancy of both systems, but
because the EM signal is limited to
land operations, hybrid systems are
the best t for land drilling.
For offshore operations, mud-pulse
telemetry still stands as the strongest
rival among all telemetry systems;
however, because WDP signicantly
reduces the cost and complexity of
offshore drilling, I believe WDP
is the ultimate MWD system for
offshore drilling.
In determining which telemetry is the
best option for a project, you must
understand the challenges and com-
plexities of the drilling environment
to select a system that will perform
optimally in those circumstances. Fac-
toring the well objective and environ-
mental challenges into any evaluation
of MWD systems is key to perform-
ing successful drilling operations and
reducing well delivery costs.
Shadi Mussa is a global
technology product
champion for one of
the world’s leading
oileld services
companies. An expert
in communication engineering,
petrophysics and telemetry, for two
decades Mussa has specialized in
innovative telemetry systems for
advanced surveying, measurement
while drilling (MWD) and logging
while drilling. His signicant
experience in drilling and
measurements includes working in
the two largest oil eld regions, the
Middle East and North America’s
Permian Basin. Mussa is a frequent
speaker at industry events and was
most recently a presenter at the
2020 IADC/SPE International
Drilling Conference.
Electromagnetic (EM) signal propagation from downhole MWD tool to the surface
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An effective AI platform needs a reli-
able master data strategy and cloud
computing source to build upon, as
well as sound data integration and
cleansing for optimal performance and
Over the last few years, adoption of
articial intelligence (AI) by companies
has surged 270 percent. Companies are
pushing to invest more in AI technol-
ogy and this trend is only going up.
Despite the eagerness, however, AI
applications are not simply plug and
play. Just like construction, laying a
solid foundation rst is crucial before
anything can be built upon it. A reliable
and sound master data strategy (MDS),
cloud computing capabilities, and data
integration and cleansing are all part of
the foundation AI must be built upon.
How Does My Master Data Strat-
egy Connect With AI?
Before discussing the connection
between an MDS and an AI platform,
let’s rst dene MDS and why its
purpose is key to AI implementation.
An MDS is how a company organizes
its data and what gives it meaning or
context to transactions and analytics.
Master data can be internally or ex-
ternally dened. It provides the who,
what, when, where and why relating to
business processes.
An effective MDS is crucial to imple-
menting an AI platform, as data is the
fuel that powers AI analytics. As major
oil and gas companies formed different
segments of their enterprise based on
geographic locations, operational lines,
or even specic reneries, they inad-
vertently created data silos. These data
silos can trap data and may classify the
same object with different names.
An MDS should incorporate data from
these silos, determine universal naming
conventions, and clean data of dupli-
cates and erroneous data. This drasti-
cally reduces headaches and delays dur-
ing the AI implementation process by
avoiding the daunting task of digging
through data to determine where and
why the AI application failed.
Why Is Cloud Computing and Stor-
age Benecial to AI?
The emergence of Amazon AWS,
Google Cloud, and Microsoft Azure
has led to an explosion of different
use-cases and capabilities. Cloud com-
puting and storage are incredibly ben-
ecial to an AI platform because of its
real-time data collection, data elasticity
and global availability. The scalabil-
ity of the cloud allows companies to
increase data storage, and, therefore,
enables them to grow on a global scale,
particularly as their computing power
needs expand over time.
The cloud allows for IoT devices at
remote oil wells to constantly upload
data for faster compilation and AI ana-
lytics than ever before. Data scientists
currently spend about 80 percent of
their time nding, retrieving, consoli-
dating, cleaning, and preparing data
for analysis and algorithm training. By
leveraging the infrastructure provided
by a cloud platform, all of these steps
can be drastically reduced. Therefore,
data scientists can focus on what’s truly
important: building and training AI
analytical tools to make them perform
better, faster and more efciently.
A new breakthrough in cloud comput-
ing and storage is the emergence of
data lakes, which can store structured
and unstructured data, and relational
and non-relational data, allowing the
collection of raw data from a variety
of sources like IoT devices, CRM
platforms, and other current databases.
Allowing an AI platform access to all
this data enables it to run faster, more
complete analytics without moving the
data to a separate system beforehand.
However, similar to planning an MDS,
data lakes should be carefully con-
structed to lend their architecture to
better dening, cataloging and securing
received data. For example, the data
lake platform Snowake integrates
with a company’s current cloud storage
and transforms it into an effective, AI-
ready data lake.
Considerations Before Implementing
AI in the Oil and Gas Industry
By Patrick O’Brien and Ian Campbell
Source: Amazon AWS
Oilman Magazine / September-October 2020 /
How Does Data Integration and
Cleansing Connect to AI?
Access to clean data is the lifeblood of
any AI application. Data integration
is the ability to view data from differ-
ent sources together in one location,
and this is needed in an AI project to
connect all the necessary inputs to the
application. However, in each place the
data resides, it may be represented in
a different format or coding language,
and it may even be separated into silos
or in the hands of different business
groups with different priorities. To
consolidate all of this data into one
AI application, a process or computer
program must be developed to extract
the necessary data, convert it for AI
use, and nally integrate it into the AI
Data cleansing is sifting through it to
ensure that it is:
Consistent across datasets
Using uniform metrics
Conforming to dened business
In the end, it ensures that your data
is of the right quality to support the
applications that use it, which is par-
ticularly important to AI applications
because of the massive quantities of
data they consume.
How to Get Started with Data Inte-
gration and Cleansing
Data engineers play a critical role in
data integration and cleansing, with the
goal of integrating data into systems
across the company, including AI ap-
plications. They typically have experi-
ence with SQL and NoSQL databases,
as well as other programming lan-
guages that allow them to extract and
transform data. Additionally, if data
is in the hands of different business
units, form a cross-business team to
lead integration efforts. This ensures
that as data is moved between business
sectors, each sector gets the data it
needs to do its job.
Data must be cleansed on a regular ba-
sis, referencing the standards and nam-
ing conventions dened by the MDS.
This will keep data uniform across the
organization and maintain its integrity
over time.
AI needs the proper support in order
to make the magic happen. The tech-
nological foundation provided here
will ensure that AI can add value to
the business.
The next installment of this mini-
series will discuss where and how to
start an AI implementation project to
achieve a sustainable and effective AI
This is the second installment of a
three-part series discussing AI’s poten-
tial and critical role in oil and gas, how
a company can prepare for an AI plat-
form, and important steps to executing
a sound AI implementation.
Patrick O’Brien is an
intern with Opportune
LLP’s Process & Tech-
nology group. He is
concurrently pursuing
an undergraduate degree in chemical
engineering and an MS in nance at
Texas A&M University.
Ian Campbell is an
intern with Opportune
LLP’s Process & Tech-
nology group. He is pur-
suing an undergraduate
degree in management information
systems with a certication in business
analytics at Baylor University.
Source: Amazon AWS
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Oilman Magazine / September-October 2020 /
COVID-19 has undeniably shaken
global economies to their very core,
and the world has responded by
changing at rapid speed. Additionally,
the pressure of climate change
looming in the background has also
become an immediate threat. With
these enormous challenges in front
of us, it’s understandable to feel
I left the energy sector and joined
the AI space a few years ago as I,
too, felt powerless. I felt some of
our challenges as a species were
insurmountable without AI helping
us. How can one person, or even a
team of people, possibly understand
something as complex as climate
change, and all its interconnected
causes and effects?
Having joined the AI space, focusing
on energy, I spend a lot of time with
governments, energy companies and
the general public, discussing energy.
One topic keeps coming into focus
as top of everyone’s agenda – that of
decarbonizing oil companies. People
feel that change will take decades
(understandably aggravated by the
big oil companies’ multi-decade
ambitions), but I feel a large piece of
the puzzle is being missed. Namely,
the fact that AI, used intelligently by
our humble species, can dramatically
reduce the time it takes to cut out a
lot of carbon from the oil out gas
Why Oil Companies?
Oil companies have been in the
spotlight for quite a few years around
the huge carbon intensity of their
operations. I’d like to demonstrate
how all functions within an oil and
gas company can use AI to carry out
the rapid decarburization that their
shareholders and our planet demand.
To highlight the importance of this
trend, a lot of oil and gas companies
have been stating their aims to go
carbon neutral by a certain date
– see BP’s announcement to be
carbon neutral by 2050, Equinor’s
commitment to cut emissions in
Norway to near zero by 2050, Shell’s
aim to become a net zero emissions
energy business by 2050, and Total’s
announcement that its global VC fund
will be pointed toward “fostering
carbon neutrality.”
This is good as oil companies emit a
lot of carbon; BP’s annual emissions
being roughly equivalent to the entire
country of Australia.
In fact, energy companies have
emitted the most carbon of any
enterprise, government or country
ever, and the widely accepted
consensus is that this cant continue
for nancial (stranded assets) and
moral (less pollution for future
generations) reasons.
Pressure for energy companies to
have low-carbon strategies initially
came from student groups and
grassroots protests. More recently
pressure has come from some of
the world’s biggest money managers,
such as BlackRock, which owns huge
amounts of shares in the supermajors
and is, therefore, exposed to the risk
this industry faces from a low-carbon
future without a valid plan in place.
It’s clear that we will have to move
away from oil to hit the ambitious
emissions targets most major
governments have set. This is a huge
challenge. Moving from 100 million
barrels of oil a day to signicantly less
will take a long time as oil is baked
into almost every industry on the
planet, from transport to plastics to
cosmetics to TV screens.
Moving away from oil has certainly
started. Transport systems are
moving relatively quickly toward
EVs, and we will eventually nd
alternatives to plastics. COVID-19
has also temporarily reduced oil
consumption dramatically as most
ights globally are grounded, and
demand has plummeted as people stay
at home and dont travel. The wider
Decarbonizing Oil and Gas Using AI
By George Hackford
Image courtesy of SparkBeyond
Oilman Magazine / September-October 2020 /
move to new cleaner technologies
is slow, however, and there is a way
to immediately decarbonize the
extraction of oil and gas resources
using AI, while the larger industry
trends toward cleaner technologies
take place.
What is AI and What Can it Do for
my Energy Company
AI is a meaningless term, as those
in the industry come to appreciate.
In this series, I’m using this oft-
abused term to represent a suite of
technologies that can and will make
decisions on their own, when used
intelligently by a human controller.
These technologies include machine
learning, deep learning, computer
vision, robotic process automation
and natural language processing,
mostly. McKinsey, as always, does an
excellent job of summing up what AI
is in this exec read-me.
Decarbonizing the end users of the
oil and gas companies’ core products
(i.e., you and I) is a different story, so
I’m going to focus on decarbonizing
an oil and gas company’s operations
using AI, tackling use cases such as:
Removing the causes for gas
aring, a huge CO2 problem
Reducing fuel usage and associated
emissions across a shipping eet
Stopping methane leaks in oil and
gas pipelines before they happen.
In my experience, simply having a
good, cross-function data strategy
could dramatically reduce emissions.
Most major oil companies are fast,
deep-pocketed movers in the AI and
cloud space, so wider experimentation
shouldnt take too much convincing in
the long journey of decarbonization.
Over the next few weeks (one
article a week), I’ll be detailing how
anyone can use AI technology to see
a huge decarbonization impact in
upstream, midstream and downstream
departments of a typical oil and gas
major. The rst stop will be a deep-
dive into using AI to decarbonize the
upstream operations of a typical oil
company, then moving midstream,
downstream and concluding with a
look at the future.
George Hackford serves as the lead
impact strategist in Energy, Power
& Resources at SparkBeyond. He is
experienced in setting up successful
data science/AI projects and capa-
bilities across large organizations.
He is particularly interested in AI
in the energy and power space, and
sees AI adoption as a natural next
step for the sector.
Oilman Magazine / September-October 2020 /
A review of best practices and steps
for projects to produce sustainable AI
Articial intelligence (AI)
continues to surpass
what experts thought
was possible.
Governments and
companies of all
industries are
pouring billions
into implement-
ing the tech-
nology. In the
energy industry,
AI has thoroughly
permeated the
exploration and pro-
duction sector. Now it’s
popping up in many forms
across midstream and downstream
as well. The power and complexity of
AI lends itself to making AI projects
complex as well as different from other
IT projects. When getting started with
AI, including a dened AI governance
and other AI-specic considerations
leads to sustained value from the pow-
erful technology.
It All Starts with AI Project
AI projects lend themselves to an Agile
methodology. Since AI is new to the
business world, AI projects are more
likely to experience setbacks and course
corrections during implementation.
Agile minimizes costs of redirection
while delivering benet sooner, making
Agile a better approach for AI imple-
Effective AI governance also involves
choosing your battles wisely. Choose
a relatively small and specic business
use case to enable and enrich AI at rst,
as this reduces risk while allowing the
enterprise to prove the business utility
of the tool. If you start with an activity
that has broad effects across the com-
pany, bumps in the road will be
more costly and time-con-
suming. Win a smaller
battle before trying to
win the whole war.
After you’ve won
your rst AI
battle, you can
begin to leverage
the resulting AI
solution to solve
other business
problems. As busi-
ness needs evolve,
AI governance plays
an ongoing role to ensure
that AI projects and applica-
tions are prioritized effectively and
continuously evaluated. When plotting
the course for the company’s future
with AI, resource constraint and busi-
ness benet must be weighed against
each other to inform where it is wisest
to apply your AI technology next.
A good way to accelerate AI adoption
through the organization is spreading
the word about these projects. If AI
successes have been effectively evan-
gelized, when company leaders have a
potential AI need, they are more likely
to think of the project team, generating
more work for them.
What Skills/Personnel Do You
In addition to what IT projects typically
include, here are some of the roles that
can accelerate an AI project:
Executive Sponsor – An Executive
Sponsor provides the funding for
the project and maintains alignment
with the company strategy. Success-
ful AI implementations benet from
support from the executive ofce.
Product Owner – The Product
Owner is ideally from the business
unit instead of the IT group. Busi-
ness alignment ensures the products
are helpful to the business, and lets
the business see where the products
can be applied to add value. This
prevents solutions from becoming
just what IT thinks is the next cool-
est toy.
Project Management – Project
Management takes the lead on or-
ganizing the governance, personnel
and requirements. Filling leadership
roles with individuals that have ex-
perience on AI projects ensures that
project decisions and design will be
informed by the proper insight.
Data Engineers – Data Engineers
will extract and integrate the nec-
essary data into the AI platform.
Having several data engineers on the
project is necessary due to the size
and time-consuming nature of the
Data Scientists – In an AI project,
data scientists develop and train the
AI. The algorithms the scientists
design are what give AI the ability to
“learn,” and to operate with reduced
supervision. Data Scientists are usu-
ally employed by the provider of the
software or by another third party.
These key personnel will continue to
be important as AI use cases spread
throughout the company. Largely the
same group should be on each new
AI project. From these projects, the
participants will pick up skills that other
employees wont have. For this reason,
it is most efcient to treat these person-
nel as your AI “factory” to be called
upon for future projects that apply the
use case to other areas.
Building Your Sustainable AI
Strategy and Implementation
By Ian Campbell
Oilman Magazine / September-October 2020 /
Helping Employees Adapt to The
New Tool
With any disruptive, technology-driven
change comes resistance. Harvard Busi-
ness Review cites AI’s lack of transpar-
ency, the hype surrounding AI, fear
of losing control over work, and the
disruption of familiar work patterns as
reasons why employees may hesitate to
adopt. These impressions leave em-
ployees reluctant to fully utilize new AI
applications, which subtracts from the
value of technology investments.
Despite employee discomfort, AI often
does not replace jobs, and only makes
existing jobs more enjoyable. One com-
mon use for AI is to automate tasks
that are repetitive, time-consuming,
and dont add value, which leaves the
more enjoyable value-added tasks for
the humans. Therefore, an AI solution
may actually make employees happier
once they understand what it does. To
move toward this understanding, visual
demonstrations of the process an AI
app uses has shown to be an effective
means of gaining employee trust. Most
people are visual learners and, when
people understand something, they can
begin to trust it.
Bringing in External Help
Oil and Gas consultants can be a
catalyst for organizational improve-
ment and innovation, and AI projects
are no exception. Bringing a blend
of energy expertise with technology
delivery experience, they can introduce
a value-added Project Management
capability to lower delivery risks and
better ensure successes are delivered
early. In addition, energy consultants
can be effective change agents, help-
ing the organization understand the
impact of AI on jobs and harness the
power that AI presents. Finally, they
can assist the organization with moving
beyond project-based governance into a
business-led AI governance framework
which is essential for sustaining and
expanding the benets of AI.
Consultants and subject matter experts
assist in bridging the gap between soft-
ware and client. It isnt feasible to build
AI software in-house, so an existing
AI product should be brought in by a
software company and customized to
meet requirements. However, not all AI
software can be customized to t the
task or industry as desired. Consultants
can leverage their industry experience
and technical know-how to help deter-
mine the right AI software for the job,
and how to customize the software to
meet a client’s unique needs.
Furthermore, consultants can help pre-
pare the client to support the applica-
tion in the long term by assisting with
data cleansing and data integration, set-
ting up ample computing power, help-
ing establish controls and compliance
methods for AI, training employees to
use the AI system, and more. These
activities provide the foundation crucial
to a sustainable AI solution.
AI projects are unique and require new
approaches and skills. Like all projects,
the right governance, leadership and
knowledge can unlock enormous value.
Contact Opportune today to see how
we can help drive your AI implementa-
tion journey.
This is the nal installment of a three-
part series discussing AI’s potential
and critical role in oil and gas, how
a company can prepare for an AI
platform, and important steps to
executing a sound AI implementation.
Ian Campbell is an
intern with Opportune
LLP’s Process &
Technology group.
Currently attending
Baylor University, Campbell is
pursuing an undergraduate degree
in management information systems
with a certication in business
Source: Medium
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Oilman Magazine / September-October 2020 /
The oil and gas industry has quickly
made leaps and bounds in combatting
COVID-19, and the offshore sector
has been forced to develop creative
and innovative tactics in winning the
battle. Like the various types of work
that make up the shale industry, the
offshore world serves as the workplace
for many, but is also taxed with having
to create a safe living environment in
addition to a safe working environment.
The once commonplace activity of
managing shifts for 24-hour operations
and extended schedules has quickly
become a logistical nightmare.
An incredible amount of time and
effort goes into scheduling offshore
work and ensuring living space is
available, most often described by a
term known as “Persons Onboard” or
POB. With the current standards and
guidelines of social distancing and strict
hygiene orders, providing a safe working
and living atmosphere has monopolized
the attention of many companies.
Limiting personnel in living quarters on
an offshore facility results in a decreased
size in workforce.
Headquartered in Louisiana, LLOG
Exploration is a deepwater operator
in the Gulf of Mexico and has faced
the challenges of COVID-19 head on.
According to LLOG geologist, Eric
Zimmermann, the company’s approach
in dealing with the virus originated with
adhering to the guidelines authored by
federal and state-run organizations and
agencies in the know.
“LLOG’s course of action is in line
with the CDC,” said Zimmermann. “We
are also following those guidelines of
the Louisiana Department of Health
and we’re partnering with our telehealth
Although LLOG is not quarantining
workers going to their offshore sites
now, it has exhibited ingenuity with the
precautions currently in action. Rota-
tions known as “hitches” have been
extended to decrease the workforce’s
exposure to potential outside contami-
nation. When maintaining health off-
shore, limiting ingress and egress with
land is crucial. Keeping the working
population isolated allows for the ability
to only be concerned with controlling a
potential outbreak offshore.
“Limiting contact is a huge defense,
said Zimmermann. “We’re prioritizing
work to be done. If it can wait, then
it is postponed for now. We are also
conducting a screening process of
checking temperatures and if any
COVID symptoms are presenting
Other companies offshore have
adopted this postponement of work
practice and while it is agreed necessary,
it has wreaked nancial havoc on
some service providers in the industry.
Coupled with the decline in oil prices,
the pandemic has greatly affected the
nancial bottom line of many.
“We have seen a signicant decrease in
earnings,” said Mike Bethea, CEO of
Offshore Technical Compliance LLC,
an offshore service provider.
The COVID-19 pandemic is widely
considered a uid situation and
information is continually changing.
Zimmermann said LLOG conducts
bi-weekly meetings dedicated to steering
the company’s response.
“The pandemic is dynamic and a top
concern for us.” said Zimmermann.
Offshore service providers have also
had to develop their own COVID-19
action plans to protect their employees,
but also due to the requirements
implemented by companies like LLOG.
These partnerships have not only
increased awareness, but they have also
Deepwater Manages Pandemic
on Land and at Sea
By Nick Vaccaro
LLOG Who Dat Production Facility. Photo courtesy of LLOG Exploration
Oilman Magazine / September-October 2020 /
attempted to tip the scales in a positive
direction specically with limiting
the number of COVID-19 cases
Headquartered in Louisiana, Offshore
Technical Compliance provides a variety
of services including digital pressure
testing. In addition to other services
offered, it conducts work on major
offshore facilities and for many different
companies. According to Bethea, major
E&Ps and operators want assurances
that companies such as his have
pandemic preparedness plans in place to
prevent individuals, who are potentially
infected with the virus, from showing
up at heliports and docks. In fact, this
practice is widely represented by third-
party management systems, such as
ISN and Veriforce, where the pandemic
preparedness plan must be uploaded
to the system to provide validation and
verication to the customer.
All members of the offshore
community are concerned with the
general health and safety of every
person on the facility, but additional
factors are in play as well.
“The impact of a positive test
offshore is extremely costly,” said
Bethea. “A variety of policies have
been implemented by our customers
to ensure safety and decrease the
possibility of additional costs.
Bethea noted that early check-ins have
yielded positive results with workers
quarantining prior to going offshore.
This is an increase in costs; however,
it is proactive behavior that can assist
in keeping the infection rate to a
minimum, if at all.
Oilman Cartoon
By Steve Burnett
Continued on next page...
Oilman Magazine / September-October 2020 /
Although most of these new proce-
dures and policies are costly, deepwater
companies are not shying away from
providing them. Zimmermann stated
that LLOG is committed to medivac
quickly, if needed, to remove work-
ers from a facility should they display
COVID-19 symptoms.
In addition to the new and challenging
logistics of working offshore, the
customers and contractors share
another issue. Both have employee
teams that reside on land and support
their offshore activity. They are,
therefore, tasked with ensuring safe
working environments in their own
ofces as well as for those working
“Our ofce is on a platoon system and
we are staggering work times,” said
Zimmermann. “We have instituted a
no-touch policy and we have a team
that cleans our facility daily. Masks are
also required in all communal areas of
our ofces.
Bethea stated his company’s ofce
response is in line with agency
regulations. Staff is limited to no
more than ten people in the ofce at
a given time and must practice social
distancing. Staff members who are
not in the ofce have the capability to
work from home.
“Our employees are required to wear
masks when entering our building, but
can take them off when they reach
their individual ofce spaces,” said
Bethea. “If a person does not feel well,
we want them to stay home.
Bethea feels Offshore Technical
Compliance’s vigilance has played
an important factor in why it has
experienced no cases of COVID-19
on a company level. Disinfecting
protocols have been instituted in its
ofces with a professional service
cleaning the facility twice a week. Food
must be closed and sealed, and hand
sanitizer stations have been staged at
commonly touched surfaces. Ofce
personnel have also been tasked with
cleaning and wiping surfaces in their
personal workspaces.
Because COVID-19 directly affects all
aspects of business, offshore compa-
nies have been forced to change their
thinking and how they can adapt to the
new normal. Task forces and special
committees are being devised to meet
business needs. Zimmermann indicat-
ed that LLOG’s HSE staff is leading
its offshore efforts and staying educat-
ed with the virus’ changing effects.
Bethea said that Offshore Technical
Compliance’s management team
is monitoring its response globally
as services are provided on an
international level. He explained that
it is challenging because, in addition
to the federal and state guidelines
revolving around COVID-19, the
company must also follow the
guidelines of other countries where its
services are provided.
“We have a relationship with a
management company in Mexico
that helps us over there,” said Bethea.
“That company is bilingual.”
Considering that, as of this writing,
the U.S. appears to be witnessing an
increase in COVID-19 positive cases,
many offshore companies have been
looking to the future and attempting
to establish protocols to deal with
the pandemic for an extended period.
According to Zimmermann, LLOG
is meeting regularly to examine
information and plan for potential
strategies needed for the company to
coexist with the virus.
Bethea said that Offshore Technical
Compliance is relying on innovation
to shape any needed strategies. The
company is investigating bundling
services to be competitive and is
focusing on global markets where it is
not as simple to cease work.
Speculation over how conducting
business may be forever altered after
COVID-19 has run its course has
plagued the offshore industry. With
reports of increased numbers in
positive cases, as well as the possibility
of vaccines on the horizon, one
question is continually repeated: Will
the pandemic leave behind lasting
effects that will permanently change
the business models of offshore
companies around the globe?
“It is a little early to tell what the
post-COVID world will look like, but
we have aggressively acted to get our
digital communications platforms to a
high level,” said Zimmermann. “This
utility will certainly be a centerpiece to
how we do our business in the future.
Zimmermann added that many
adjustments will be made and that
teleconferencing has been invaluable.
He indicated that the capability to
share a screen has been a very useful
feature during those teleconferences.
He also said he envisions corporate
travel being streamlined.
According to Bethea, he sees many
tactics remaining in the workplace.
Practices such as distancing when pos-
sible and hand washing should be re-
maining in use as needed. He feels the
pandemic has revolutionized how the
world uses the telephone and foresees
video conferencing being the primary
form of communication. He is also
convinced that remote working will be
regularly instituted in the workplace.
“One thing we have learned from
this pandemic is to be exible,” said
Bethea. “We will be better prepared in
the future.
Nick Vaccaro is a freelance
writer and photographer.
In addition to providing
technical writing services,
he is an HSE consultant
in the oil and gas industry with
eight years of experience. Vaccaro
also contributes to SHALE Oil and
Gas Business Magazine, Louisiana
Sportsman Magazine, and follows
and photographs American Kennel
Club eld and herding trials. He
has a BA in photojournalism from
Loyola University and resides in
the New Orleans area. Vaccaro
can be reached at 985-966-0957 or
Beachwood navigates teams
to find deals that no one else can.
508 West Vandament Avenue, Suite 304 l Yukon, OK l (405) 467-4366
We don’t market to test the waters, we hit the market to make waves.
Oilman Magazine / September-October 2020 /
Ongoing chemical treatments are
among the top production costs in
almost every basin, coming in at
around eight to ten percent on average
on the low end. As oil prices whipsaw
across the line between prot and
loss, producers are looking for ways to
manage every possible cost, including
For efciency’s sake, most operators
rely on the expertise of the chemical
provider to assess the mix and dosage
of chemicals to protect equipment
from scale, corrosion, parafn and
other elements that can interrupt
production and create signicant
replacement costs. In evaluating
costs, operators lack the time and
chemical suppliers lack the incentive to
determine dosage efciency as long as
the treatment is basically working. The
assumption has been, “It’s working, so
we must be doing it right.
A series of discoveries in the remote oil
elds of Montana led to the develop-
ment of a tool that could signicantly
reduce chemical requirements through
better blending of those chemicals with
the production stream.
First Discovery: Injected Chemicals
can be Less Effective
A 2005 inspection of tubing being
removed from a Montana well during
an electric submersible pump (ESP)
replacement offered a major revelation.
As the North-Pole-frigid December
morning air met the tubing, globs of
a gooey, scaly substance were evident
with the top 20-30 joints of tubing,
globs that quickly peeled off onto the
ground. Subsequent testing showed this
to include some scale, but to mostly
consist of the concentrated treatment
chemicals. Anecdotally, other workover
crews have reported seeing this kind
of mass on ESPs where chemical is
ushed down the casing.
This epiphany was huge. It meant a
large percentage of the chemicals
reached the downhole equipment they
were intended to protect.
That eld
was dotted with stripper wells, whose
water cut reached as high as 98 percent,
producing 500-4,000 barrels a day. In
that environment, pump replacements
costing $75-$125,000 coming at about
three-and-a-half year intervals often
mangled prots for this operator and
Most of the larger chemical suppliers
had left the area 20 years earlier due
to falling demand for their products
as a result of shrinking production. A
small local provider, N-Run, founded
in 1999, was behind the discovery of
unmixed chemicals on the tubing.
The solution appeared to involve the
insertion of an in-line static mixer
into the sidestream ow at the point
of chemical injection just prior to
discharge into the casing, before
dropping to the uid level. This mixer
would cause mass transfer, as calculated
by the Reynolds number (Re), creating
uid turbulence in the pipe. The
resulting turbulence would induce
a mixing action, much like a spoon
blending the ingredients of a cake
recipe. It would transfer chemical mass
into the uid mass. Other industries
have long used static mixers to reduce
chemical consumption, so it seemed
logical to apply it to oil and gas.
Depending on the well and the chemi-
cal design, that uid mass could be
single phase—oil alone with a trace of
produced water—or it could be three-
phase, consisting of gassy uids with
a 50 percent water/oil mix. Increasing
the contact capacity of the treatment
chemical with the uid itself is clearly
the most fundamental factor in improv-
ing the chemical’s performance.
To create and test such a mixer, Tellerus
Patented Chemical Mixing Tool Improves
Results While Slashing Chemical Spending
By Paul Tarmann
This challenging installation in the southern ank of the Williston Basin was using 10.5 qt/day of
emulsion breaker to treat 18 gravity tight emulsion at 55˚F Red River crude. It produces 220 barrels
of uid daily at a 60-40 oil/water ration. Over a ve-year period, several chemical providers tried
repeatedly to nd a more effective and economical mix. Within 90 days of installing the inline mixer,
chemical usage was reduced to 4.5 qt/day, saving the producer $14,147 per year in chemical costs.
Oilman Magazine / September-October 2020 /
came into existence in 2007. The
company’s development team created
a static mixer with bafes and vanes
inside the pipe, which would cause the
liquid to churn and spin as it passed
through. That action would create the
needed Reynolds number, allowing the
complete mixing of chemicals with the
One challenge with this turbulence is
that it can cause cavitation erosion over
time. Early trials used carbon steel in
device manufacture, which proved to
last only a few months due to corro-
sion caused by the bubbling out of acid
gases, including H
S and CO
, that had
previously been dissolved in the liquid.
This is similar to the way a soft drink
bubbles and foams when the can is
Switching to 316 stainless steel solved
the issue of corrosion in almost all
cases. In a Williston Basin installation
involving high levels of H2S, the
operator preferred not to pay the
premium for stainless steel, so Tellerus
used Schedule 80 carbon steel for the
casing. Because the internal bafes take
the greatest stress, they were still made
of 316 stainless steel. This proved to be
Tellerus’s personnel inspects units at
regular intervals (previously six months,
now approximately two to three years
depending on well volume), but there
have been almost no leaks or replace-
ments since the switch to stainless steel.
Further design tweaks led to greater
efciency, less welding and other
improvements. Most components are
threaded, simplifying eld inspection
and documentation. Welded or bolted
ange ttings are also available for
Continued on next page...
9955 International Blvd.
Cincinnati, OH 45246
(513) 247-5465
in stock
Photo courtesy of Tellerus
Oilman Magazine / September-October 2020 /
producers who prefer them to
threaded joints for pressures above
125 psi. Units are available in lengths
of two to eight feet.
The mixing stack inside the tool
housing does create a small amount
of back pressure (eight to ten percent)
due to bafes in the static mixer,
but eld trials have shown this to be
more than overcome by the improved
performance achieved through better
mixing of chemicals.
Field Trials for Phase One
Field tests initiated in 2008 involved
installing static mixers in the treatment
sidestream ow of several wells whose
ESPs failed at the previously stated
three-and-a-half year intervals, in spite
of extensive uses of scale and corro-
sion inhibitors. As of this writing, the
wells with mixers installed at that time
are still in service 12 years later.
In another eld trial, the mixers
were installed on several leases using
emulsion breakers to treat owlines
at the surface. Here the improved
mixing of chemicals resulted in a 35
percent drop in owline pressure
(from 150-175 psi to 110 psi), which
helped boost production by six barrels
per day.
Discovery Two: Complete Mixing
Requires Less Chemical Volume
Early phase testing made no adjust-
ment in the amount of chemicals
injected. During the downturn of
2015, however, clients began looking
for ways to reduce costs, and chemical
injection rates were on that list. They
asked Tellerus to experiment with
lessening scale and corrosion-reducing
chemicals and monitoring the results.
The goal for the operators in question
was to cut chemical costs by 40 to 50
Field Results for Discovery Two
The trial reduced injection rates to
approximately 60 percent of previ-
ous levels while continuing to use
the same chemicals. At this writing,
ve years later, there have been no
observed increases with corrosion or
scale since making that change.
Another test involved an emulsion
breaker application used to separate
heavy black oil (18° API), cold (55°F).
This improved predictable oil delivery
to the sales tanks while reducing
chemical demand by 40 to 80 percent.
For a trial in Wyoming’s Big Horn Ba-
sin, a major operator installed several
mixers with the goal of improving
the chemical performance on multiple
leases. Treatments included reverse
breakers and water clarifying polymers.
The company had existing surface
discharge permits that required sig-
nicant tank room and large settling
ponds in order to achieve permitted
water quality.
The Tellerus mixers installed in the
trial improved oil/water separation
with a 400 percent reduction in oil
carryover. Tellerus then expanded
that trial to other types of treatment,
including multifunction inhibitors,
with similar results.
Winning Combination
Numerous users have observed that
this is a seemingly simple solution, but
its results are profound. Most units
pay for themselves in a few months,
even on stripper wells like the ones
in Montana. Field trials have shown
that the greater blending of chemicals
with the liquid have greatly enhanced
the effectiveness of those chemicals.
Effectiveness improves to the extent
that the amount of chemicals required
can be reduced by 40 to 80 percent in
most cases.
The patented static mixer design was
among the nalists for the 2019 Na-
tional Association of Corrosion Engi-
neers (NACE) Corrosion Innovation
Award international competition. It is
also under consideration for adoption
by the technology wing of a superma-
jor oil company. The Reynolds effect
is valid at any ow rate achievable in
the oil patch. It is clear that this solu-
tion is not just for small wells; larger
wells stand to benet even more from
this tool.
Paul Tarmann is founder and
CEO of both N-Run and Tellerus
Corporation. He has 38 years
of experience in upstream oil
and gas production chemicals,
working with a broad range of
applications common to all basins
worldwide. Tarmann is a member
of the National Association of
Corrosion Engineers and also a
lifelong member of the Society of
Petroleum Engineers. The Tellerus
website is
Chem Use Rate Qt/d Chem Cost $ per day Flow Line Pressure
Oilman Magazine / September-October 2020 /
A 3D Digital Twin is a virtual replica
of assets, consisting of “point cloud”
data captured by Light Detection and
Ranging (LIDAR) scanners, which is
used to update Piping and Instrumen-
tation Diagrams (P&IDs). This data
is connected to a plot plan and users
can navigate between the three (plot
plan, point cloud and P&IDs) to per-
form a virtual walkthrough of a facil-
ity, where the data mentioned above
has been curated and made accessible
in the Cloud via a web browser. A 3D
Digital Twin can be useful for buyers,
sellers and due diligence service pro-
viders of industrial, above-ground as-
sets with some degree of mechanical
complexity in the oil and gas, process,
mining and manufacturing industries.
The benets of a 3D Digital Twin
Overcomes issue of outdated
engineering drawings pushed to the
VDR, spurning questions regarding
as-built status.
Provides users with richly detailed
asset virtual reality and browser-
based access to perform a virtual
asset walkthrough.
Reduces Q&A about as-built status
of the assets since P&IDs are
updated and accurate, reducing
time to complete due diligence.
A viable and timely alternative to
physical inspection of assets.
Provides seller with a marketing
tool to showcase the assets with
guarantees of accuracy and
reduced buyer remorse.
Supports due diligence profession-
als (including SMEs, valuation,
and Representation and Warranty
policy underwriters) with more
accurate and comprehensive data
describing the assets, resulting in
shorter time frames to complete
due diligence.
Overcomes travel restrictions to
inspect assets.
Web and cloud-based, providing
ease of access with no software to
download and install.
Provides a longer-term foundation
for digital transformation,
including risk-based inspection
and predictive maintenance,
and subsequent addition of 3D
modeling of corrosion loops.
Supports regulatory compliance
where inspectors and auditors
require conrmation of assets
and changes over time to correct
Situation and Problem
A midstream operator decides to
sell certain assets in its portfolio,
including a 200MMcfd natural gas
processing plant and compression
facility. Both facilities are over
10 years old and have undergone
various engineering changes and
modications during their lives,
including the replacement of certain
equipment and conguration
changes in piping, controls and
other instrumentation. Both are
subject to the recently enacted
DOT/PHMSA Megarule requiring
operators to have updated as-built
documentation of affected assets,
as well as OSHA process safety
management for certain assets.
No updates to P&IDs have been
Using 3D Digital Twins to support Mergers
and Acquisitions Due Diligence for
Industrial Assets and Facilities
By Brent Stanley
Photo courtesy of mCloud
Continued on next page...
Oilman Magazine / September-October 2020 /
made by the operator since initial
construction. The operator suspects
that pushing outdated information
regarding the assets, including out of
date P&IDs, is going to generate a
lot of questions. In addition, buyers
and other due diligence professionals
would potentially want to inspect the
physical assets, which is problematic in
the current pandemic. Other operators
in the industry have similar assets for
sale, reective of the recent market
Action Taken
The operator made the decision to
create a 3D Digital Twin for the to-
be-sold assets, and the following steps
were taken.
1. The operator provided a plot plan
to the 3D Digital Twin vendor,
who created a “key plan” from that
document and Google Earth which
indicated the number and location
of scanning locations.
2. LIDAR scans of the facilities
were performed and LIDAR
SMEs provided Virtual Reality
headsets to facility personnel, and
remote assistance was provided as
instruction on where and how to
perform the scanning.
3. Current P&IDs were provided
to the Digital Twin vendor, who
Laser scan linked to an intelligent P&ID to support virtual inspections of assets.
Benet Category Without 3D Digital Twin With 3D Digital Twin Impact
Deal Velocity
Scheduled for 6 months, actual was 9
Schedule accelerated to 5
Seller able to divest assets
faster than the competition
Seller Asset Valuation
Delays and questions undermined the
value of the assets
Buyers were able to satisfy due
diligence without encountering
major obstacles
Higher asset valuation
Buyer Condence
Inability to physically inspect assets
delayed deal and created uncertainty
Due diligence completed
ahead of schedule
Faster deal close, reduced
buyer remorse
Representation and
Warranty Insurance
Underwriting extended due to lingering
questions which seller struggled to answer
Underwriting competed ahead
of schedule
Faster deal close
Oilman Magazine / September-October 2020 /
upon receiving the LIDAR data,
updated the P&IDs to reect as-
builts and made them intelligent
(auto-recognition of equipment,
instrumentation and piping circuits,
materials data and specications as
was present on the P&IDs).
4. The resultant Digital Twin
was uploaded to the cloud and
credentials created for users to
access through a web browser.
5. Entire process, Steps 1- 4, was
completed in xx weeks.
Buyers and Due Diligence
Professionals Perform Virtual
The seller exports updated P&IDs
as pdf les with CAD layers from
the 3D repository and pushes these
les to the VDR. Seller also provides
a link and credentials to buyers and
due diligence professionals to access
the 3D repository. Buy-side is now
guaranteed accurate data as well as the
ability to perform a virtual inspection
of the facility, with the ability to
navigate between a plot plan, 3D of
the assets, and the intelligent P&IDs.
In addition, seller allows the 3D data
to be used by buyer Representation
and Warranty insurer underwriters,
accelerating the issuance of a policy,
which allows the seller to pocket a
percentage of the deal which would
otherwise be tied up in escrow for
several years.
In this case, the use of a 3D Digital
Twin provided the following benets:
Using 3D Digital Twins to support,
M&A due diligence is a novel
solution which benets sellers
and their ability to move ahead of
competing assets which do not
leverage this solution. Buyers likewise
benet from increased condence
of understanding what they are
acquiring. For M&A activity where
there are above-ground assets
of some mechanical complexity,
using a 3D Digital Twin increases
transparency of what is being sold,
providing guaranteed accurate data
with the ability to perform remote
inspection of the assets. Improving
deal velocity is the ultimate benet.
Brent Stanley is
the VP business
Connected Industries
for mCloud, and
has degrees in mechanical
engineering, math and physics
from Case Western Reserve
University. He has spent the last
20 years implementing digital
transformation projects for Fortune
500 and industrial companies,
including oil and gas and process
industries. Stanley is a subject
matter expert in adoption of 3D
Digital Twin solutions to support
mechanical integrity and RBI
initiatives and has worked closely
with industry participants to
achieve regulatory compliance for
the operation of assets affected
by PHMSA, OSHA and other
regulatory bodies.
Are you looking to expand your reach in the oil
and gas marketplace? Do you have a product
or service that would benefit the industry?
If so, we would like to speak with you!
We have a creative team that can design your ad!
Call us (800) 562-2340 Ex. 1
Oilman Magazine / September-October 2020 /
Well drilling, the second step in the
downhole process, begins when the su-
percial casing is put in place and ends
when the well is set to begin the hydro-
carbon production. It is commonly the
process of greatest investment; for this
reason, it is the main gauge when study-
ing new projects.
Because of what drilling means for
the investment of the project, all the
operational problems that generate loss
of time are taken into account. When
this NPT (Non-Productive Time) is
taken into account in the wells in the
Gulf of Mexico, the study outlined in
“New Drilling Optimization Technolo-
gies Make Drilling More Efcient” by
D.C-K. Chen revealed that 25 percent
of lost time is NPT, translating to $1.5
million per well.
According to Chen, operational
problems such as loss of circulation,
variations of the EDC, pipe clamps or
problems related to borehole cleaning,
among others, are problems that go
hand in hand with borehole stability,
and he explains that the best way to deal
with these difculties is with the con-
tinuous use of new tools and techniques
for drilling.
Understanding the needs of the market,
the drilling process has been perfected
over time, so have the special tools for
projects and the use of new techniques
to meet the different operating needs
of the formations, in order to create a
solution for each problem, or a single
solution for several problems.
Tools Used in Drilling
The tools used for drilling consist basi-
cally of the drilling rig; this element has
different versions that have been born
over time, in order to reach new levels.
The drilling rig is an element composed
of elements such as crown block, der-
rick, traveling block, swivel, standpipe,
Kelly, rotary drive, draw works, engines,
blowout prevention equipment, mud
pump and mud pit. On surfaces and
in the subsoil, it consists of drill pipe,
casing, cement and drill bit. This is the
basic conguration of a drilling rig; this
group of elements represents the four
systems that govern drilling.
Lifting system
Rotation system
Circulation system
Power system
Its mission is to ensure a surface/reser-
voir connection and thus transport u-
ids trapped in the subsoil. Although it is
easier said than done, an easy goal does
not always exist, so there are different
alternatives for different challenges:
Percussion drilling: When there are
wells to be built at depths not greater
than 30 meters, this type of method
is most often used, as it works for
unconsolidated formations. The
rst of the drilling methods used, it
was based on employing a hard and
heavy bar that had a drill bit at the
tip, which collided against the soil
repeatedly, shrinking the gravel with
the help of a bailer. The structure
is a tripod that supports the weight
and the drilling process was done by
using cables. To maintain the stability
of the borehole, a casing was used
that prevented it from collapsing and,
at the same time, isolated the proce-
dure. This method is still applied in
Rotary drilling: With the passage of
time, research offered new opportu-
nities to exploit oil, but meant drilling
to greater depths. Due to this, one of
the most common forms of drilling
in the world was born. Originally
built for wells of more than 3,000
feet of depth, over time it varied
to what it is today. The equipment
consists of a tower of about 40 me-
ters which supports the equipment
Drilling Tools Most Used and Techniques
to Exploit Formation Conditions
By Raul Palencia
Drilling equipment and technique. Photo courtesy of Liebherr
Oilman Magazine / September-October 2020 /
conguration, and contains a motor
that, along with the rotary table, is in
charge of generating the drilling, the
drill bit being responsible for destroy-
ing everything in its way. The uid
control equipment is responsible for
raising the gravel to the surface and
maintaining the pressure differential
in equilibrium. In turn, it is con-
nected to the system, thus preventing
blow-outs, being able to send a line
of uid pressure to counteract the
pressure of the formation, if neces-
sary. Capable of working in any type
of formation by modifying certain
elements and, with a speed of 40 to
250 rpm, this drilling rig has been on
the market for over 50 years.
Drilling Rigs
Drilling rigs were born from the idea
of making direct drilling on the sea-
bed. The reason? Geological studies
showed large reservoirs established in
the sea and the best way to take advan-
tage of them was with the use of boats
equipped to move the drilling rigs and
to be autonomous in order to perform
the whole process.
The common operation of this type of
drilling is using a rotary table, and over
time different drilling rigs were devel-
oped, such as:
Semi-submersible platform
Self-elevating platform
Fixed platform
In the beginning, they consisted of
necessary equipment to fulll tasks;
today, they have comfortable facilities to
accommodate professionals.
Directional Drilling
Directional drilling rigs are a necessary
variation born from the common rotary
table rigs, there are different congura-
tions, but they are based on the use of
a bottom motor that is responsible for
controlling the direction of the drill
bit, from the surface the position of
the drill and its degrees of inclination
is controlled, either with a manual or
digital system.
This drilling rig was born in view of the
need to create oriented wells; in turn, it
has the ability to create several wellbores
Percusion drilling. Photo courtesy of Dando Drilling & Prospecting International
Drilling rig. Photo courtesy of Energy World
Rotary drilling. Photo courtesy of Fundamentals
of Onshore Drilling
Continued on next page...
Oilman Magazine / September-October 2020 /
from the same location on the surface,
providing low costs and solutions to
geological problems. It is used globally
and companies such as Halliburton or
Schlumberger, among others, use this
technique in marine stations, managing
to exploit the reservoirs optimally.
Electro Drilling
This type of drilling is similar to ro-
tary drilling but, unlike being driven by
combustion engines, electro drilling is
driven by electric motors. This impor-
tant difference includes the change in
the type of control to the drilling, the
rotor that drives the movement of the
drill bit is close to it, being only a few
tubes above it.
Currently used in Nordic and Asian
countries, it provides the benets of a
hydraulic drilling rig and is applicable
in high pressure, high temperature
(HPHT) conditions. The biggest draw-
back of this drilling rig is its mainte-
nance but, despite this, it is an optimal
option for new elds.
Drilling Techniques
Drilling techniques vary according to
the type of challenge faced. The correct
choice of drilling rig, drill bit, location
and other factors is only the rst part
of the job. With the knowledge of the
conditions of the formation comes a
critical decision: drilling under balance
or over balance.
Drilling Over Balance
This drilling technique is the most used
in the world. With the use of drilling
uids of optimal features, it tries to
increase the hydrostatic pressure that
causes the liquid column on the side-
walls to overcome by a margin of 15
percent or more, ensuring that the uids
found in the different formations that
are drilled stay in their place and do not
enter the well.
Commonly used to prevent bursts in
areas of over formation pressure, and
when the conditions of the formation
are not fully known, this type of tech-
nique creates larger whitewash on the
sidewalls, making the area cleaning do-
overs more concurrent, and also mak-
ing it more difcult to lift the gravel to
the surface resulting in longer operating
times. It is used in all types of forma-
tions from extra hard to soft, and it is
very common for drilling mud to enter
the washed area of the target reservoir.
Drilling Under Balance
Mainly used in consolidated formations,
the drilling under balance technique
consists of employing a hydrostatic
pressure similar to or less than the one
offered by the formation. The least
amount of pressure is used where
there is a functional balance in which
the sidewalls maintain the balance and
where the formation uids do not enter
the wellbore.
For the use of this method, it is neces-
sary to have a complete knowledge of
the formation, especially of the be-
havior of the shale, since these are the
ones that normally represent the zones
of over pressure. When a balance is
achieved, the expenses of densifying
material decrease, the creation of very
thick seals on the sidewalls is avoided,
which prevents operational problems
such as pipe pegs, area cleaning do-
overs and creation of caves, among
others. This translates into saving time,
which in turn is the direct denition of
saving money.
It is not common to use this technique
for the construction of oil wells, due
to the margin of risk faced by the work
team, but it is very common to use it
to drill the target area. With the use of
RFT or MDT equipment to calculate
pore pressure, the response pressure of
the reservoir is known. This facilitates
Directional drilling. Image courtesy of Maxon Group
Over and under balance.
Image courtesy of Andres Ocando
Oilman Magazine / September-October 2020 /
the task of cannonade and helps expo-
nentially to handle a low skin factor.
Drilling is a task that, despite main-
taining its original essence of using
a drilling rig to break the balance of
the subsoil, has found itself obliged
to evolve over the years to provide an
answer to the different challenges faced
by the industry, as it seems, the industry
will not cease to have new obstacles
and the engineer surely will not cease to
have new answers.
Raul Palencia is an engi-
neer and researcher with
more than 10 years of
experience as a geolo-
gist. He graduated from
the prestigious University of Andes
(ULA), later he received a master’s
degree in Reservoir Engineering at
the Venezuela Hydrocarbons Univer-
sity. During his career development,
he worked for oil companies in posi-
tions such as: eld geologist, reservoir
engineer and reservoir simulation. He
has worked in Argentina, Ecuador,
Mexico and Venezuela. He currently
resides in Texas.
A recent report by the International
Energy Agency (IEA) entitled “Gas
2020: Analyzing the Impact of the
COVID-19 Pandemic on Global
Natural Gas Markets” was published
in June 2020. The lengthy report
emphasizes supply, demand and trade,
and, in part, states:
After a four percent drop in 2020,
natural gas demand is expected to
progressively recover in 2021 as
consumption returns close to its
pre-crisis level in mature markets,
while emerging markets benet from
economic rebound and lower natural
gas prices. The impact of the 2020
crisis is, however, expected to have
repercussions on the medium-term
growth potential, resulting in about 75
bcm of lost growth over the forecast
period, 2019 to 2025. This forecast
expects an average growth rate of 1.5
percent per year during this period.
The Asia Pacic region accounts for
over half of incremental global gas
consumption in the coming years,
driven principally by the development
of gas in China and India. While
the prospects of natural gas remain
strong for these two markets, the
outlook is highly dependent on China
and India’s future policy direction
and recovery path in the post-crisis
environment. In spite of the current
economic headwinds and uncertainty,
natural gas still benets from strong
policy support in both countries,
with ongoing reforms to increase
the role of gas in the energy mix.
Future growth in the industry sector,
which constitutes the main driver
of incremental gas demand in both
countries will, however, highly depend
on the pace of economic recovery,
both for domestic and export markets
for industrial goods.
In a time of uncertainty, it is certain
that natural gas will be of utmost
importance in the near future.
Liquied natural gas (LNG) will be
key in the global energy recovery;
however, geopolitics, infrastructure
development, regulatory policies and
investment will be very challenging.
Academy award-winning producer,
Gray Frederickson, Mei Li Hefner
and I served as producers of the
documentary lm
The Grand Energy
Transition (The GET),
released in
2012. It is based on the book of the
same name by Robert A. Hefner,
III, founder and owner of GHK
Exploration, who pioneered deep and
ultra-deep natural gas exploration,
primarily in western Oklahoma. In
the book, which Ted Turner deemed
important enough to buy for members
of Congress and Fortune CEOs,
Hefner forecasts the continuing
decline of coal and oil, and predicts
the coming “age of energy gases.
America’s abundant natural gas will
serve as the major bridge to this new
energy age, along with wind and solar
power, to create a new, hydrogen-
based economy.
Natural gas is an energy answer that
is available today. We denitely should
be putting it to use now. For years I
have voiced my belief that natural gas
reserves are critical to a strong U.S.
economy and extremely important
for America’s energy security. Natural
gas is an abundant, clean fuel that has
many domestic uses, from heating our
homes to serving as an alternative to
gasoline. It is the bridge fuel to our
country’s energy sustainability. Future
generations are depending on us to
keep the American dream alive.
Natural Gas: Beyond the Pandemic
By Mark A. Stansberry
Mark A. Stansberry
Oilman Magazine / September-October 2020 /
Environments in oil and gas wells are
harsh, complex and abrasive, wreaking
havoc on drilling systems and equip-
ment, which are especially difcult to
replace or repair when in boreholes
miles underground. For manufactur-
ers in this space, industrial 3D print-
ing, known as additive manufacturing
(AM), has been a game-changer.
AM technologies showed early
success in the oil and gas industry
by producing plastic components,
but they lacked durability for all
drilling applications. Today, with AM’s
advancements, specically printing
durable metals like (stainless) steels,
nickel alloys and copper alloys, enables
companies to design products meant
for extremely challenging drilling
tactics and complex geometries.
And the industry is taking notice.
Major industry players, like BP, Shell
and Total have begun establishing Joint
Innovation Projects (JIPs) to develop
guidelines and economic models for
using AM in the oil and gas industry. In
fact, it’s estimated that within the next
ve years, 3D printing in the oil and
gas market will be worth $32 billion.
By 2030, it’s expected to be worth over
$60 billion.
Benets of Industrial 3D Printing
It’s no surprise the AM market is
anticipated to boom within a decade; it
just makes business sense. For manu-
facturers supplying and servicing the
oil and gas industry, AM helps validate
designs faster and reduces time to
production. AM produced applications
are often more durable compared to
their traditionally produced counter-
parts, allowing for complicated features
like a variety of lattice structures and
thin but durable webbing or complex
channels which can increase the per-
formance of applications such as drills,
injection nozzles for gas turbines and
even turbine blades. In fact, according
to Siemens, “If you can 3D print a tur-
bine blade, you can print pretty much
Reduced costs and time to market
arent just appealing to manufacturers.
Customers also benet from increased
drill accuracy, reduced drilling times,
and fewer maintenance disruptions
through smart and hybrid AM repair
If we look at the supply chain aspect
of AM, distributed manufacturing con-
cepts with digital inventory also create
tremendous benets for CAPEX heavy
industries such as oil and gas. Simply
put: 3D printing on-demand. Because
there is a lot of maintenance in the
eld, organizations only have two
choices – on-site warehousing, which
leads to large amounts of working
capital, or fast supply, which creates
high transport costs, especially in far-
ung locations, like North Dakota or
on a rig.
Common Challenges
Though the benets are clear, as AM
continues to grow in the industry,
many businesses arent making it be-
yond pilot mode. Although every orga-
nization has a unique implementation
journey, when we look at companies
who have struggled with AM, there
are many similarities. Namely, bringing
on AM is a change strategy, just like
when you implement any other novel
technology. And, like with any digital
transformation, it involves rethinking
your design processes, your manufac-
turing philosophy, and your value and
supply chains – a process that’s easier
said than done.
Let’s back up for a second and revisit
this idea of optimizing value chains
through AM.
The “manufacturing” part of “additive
manufacturing” refers to the full
end-to-end manufacturing process
journey, involving a large number
3D Printing Readiness:
How to Get Setup for Success
By Fabian Alefeld
Photo courtesy of EOS
Oilman Magazine / September-October 2020 /
people, processes, and decisions.
This is known as the value chain – the
entire universe of people, processes,
and organizational infrastructure that
goes into the process of creating
and delivering goods, starting within
research and development (R&D)
through production all the way through
to marketing and aftersales.
The AM process is similar to traditional
manufacturing, which has a complex
value chain in itself:
The efforts begin well before and
extend well beyond production.
You need experts within your orga-
nization to identify where and when
AM makes sense.
You need technical specialists to
dene product specications.
You need designers and engineers
to ensure that your products meet
those specications.
You need experts to explore and
validate the materials that can be
And of course, you need to dene
and rene the manufacturing pro-
cesses to make it happen.
So, imagine what it takes to transform,
improve and optimize every link in
that chain. That’s what’s involved in
successful AM implementation.
Steps to Ensure Your Company
is AM Ready
Overcoming challenges, putting them
into perspective, and seeing them as
“growing pains” are all part of ensuring
your organization is in the right place
to succeed. There are a few critical
components to keep in mind in this
vein as you begin your AM journey.
1. Start with the end in mind
Here’s the good news: The rst and
most crucial step in any AM journey
doesnt involve costly investments in
technology at all. It involves looking
inward at your organization and
dening your challenge and desired end
goals. Part of this includes identifying
where you’ll need new knowledge and
No one knows what form 3D printing
will take in the beginning. That’s the
point of starting with your long-term
strategy and determining the smaller,
more incremental objectives that will
help get you there.
2. Rethink how you think of
By beginning the process now, you’re
putting the organization in a better
place to explore AM at scale. While
your rst steps may be modest, they’ll
work toward more signicant 3D print-
ing strategies. AM is an agile technol-
ogy. It’s not just a small project that
starts with one person or application
and scales up. It’s built to move quickly
and scale rapidly throughout your or-
ganization. With industrial 3D printing,
you can build parts overnight and take
them through multiple iterations. This
process works best if your company is
set up to be an agile organization.
Currently, many companies still
innovate in waterfall structures.
There’s a very linear approach with
waterfall methodologies that follows
a dene, design, develop, test and
implementation process. On the other
hand, agile models develop in circular
spurts and close to the customer in
quick iterations. Coupled with 3D
printing, agile is the only way you can
increase knowledge throughout your
value chain and make sure the journey
is clear to all related functions.
3. A single “AM team” isn’t the best
As you can see, industrial 3D printing
is an entirely different way of thinking.
This means creating agile teams that
arent bound by traditional methods
and setting up your organization so
you’re optimizing that approach. Ideally,
you’ll need people from all parts of
your business with in-depth knowledge
of 3D printing who can also work
together uidly. Something that works
well in this regard is the “Team of
Teams” approach.
Popular in the software development
space, “Team of Teams” means people
can still operate in their current hierar-
chical structure. At the same time, they
can also form teams cross-functionally
by not taking any existing hierarchy or
function into account. In this approach,
it’s not unusual for a member of the ex-
ecutive team to be on another team in a
non-leadership role. Instead, they might
be led by a lower-level leader (making
executive buy-in and support that much
more important).
Agile team setups create an open work
environment. They provide opportu-
nities to pull people in as needed to
make sure you have all of the necessary
expertise on a particular project.
4. Your AM journey will be like no
Remember, industrial 3D printing
isnt as easy as turning on a printer. It
requires extensive prep work and buy-
in from all levels of your organization.
And even if your competitors are
already using 3D printing for similar
applications, how you use AM can (and
should) be sculpted to your specic
There will be failures and challenges.
But if you let your in-house knowledge
and business objectives dene how
you deploy additive manufacturing
throughout your organization, then
you’re ready and primed for success.
Fabian Alefeld is the
North American man-
ager for EOS’s Addi-
tive Minds consulting
practice, which works
with organizations across a variety of
industries to maximize their efforts at
every stage of the AM journey from
start to part. For more information,
visit In May 2020,
AMCM, an EOS Group company,
announced its AMCM M 4k-1 (single
laser) and AMCM M 4k-4 (four laser)
industrial DMLS metal 3D printing
platforms, which offer high-perfor-
mance, customizable platforms ideal
for oil and gas applications.
Oilman Magazine / September-October 2020 /
The decrease in oil demand as a result
of the COVID-19 pandemic, along
with the worldwide pendulum of
supply and demand, has put many
energy companies in nancially
difcult positions, including
evaluations of operating efciencies of
their overhead and capital development
projects, as well as constraints on cash
ow and liquidity concerns with credit
facilities or other sources of nancing.
Accounting for the nancial
reporting effects of these events and
circumstances should be considered
whether reporting on quarterly results
or evaluating year-end nancial
When the pandemic rst began
shaking up the global economy,
many public companies had limited
information to quantify the nancial
impact on their operations, either
through quarterly reporting or annual
Now that the dust has begun to
settle and prices are showing signs of
stabilization, albeit at depressed levels,
energy companies need to continue
to evaluate the longer-term impact of
lower commodity pricing environments
and the impact of nancial reporting.
For energy companies preparing
quarterly nancial reports or
considerations for year-end reporting,
here are some areas to consider:
Impairment and Recoverability of
When evaluating oil and gas assets
for impairment, management needs
to consider whether circumstances
related to the lower priced commodity
environment represent indicators that
an asset may be impaired. Evaluating
oil and gas assets for impairment
falls under ASC 360-10-35 (Reg S-X
4-10 for full cost method companies),
which includes proved properties,
equipment, facilities and would include
any midstream operations such as
processing plants, pipelines or related
facilities. Unproved properties are
evaluated for impairment under ASC
Proved Property
The rst step for evaluating impairment
is whether any events or changes
in circumstances indicate the assets
carrying amount my not be recoverable.
Such events or changes may include
change in regulation, revisions to
reserve estimates, and lower than
expected commodity pricing, among
Successful Efforts Method
Under this method, impairment is
evaluated by eld rst by estimating
the undiscounted pretax projected cash
ows, and risk adjusted probable and
possible reserves maybe included in
certain situations. Forward strip pricing
curves are typically considered, along
with management’s best estimates,
for evaluating the reserve value.
Companies should ensure that any
completion or service costs, if they
have had any revisions, are included
in the net cash ows. If there are any
indictors in which the asset’s carrying
amount exceeds the undiscounted
cash ows, discounted cash ows are
typically used to determine the effect
of the impairment charge to adjust the
properties to fair value. However, other
methods are allowed for management’s
determination of fair value.
Financial Reporting Impairment
Considerations for Oil and Gas Companies
in the Low-Price Environment
By Matt Federle
Photo courtesy of Worksite LTD
Oilman Magazine / September-October 2020 /
Full Cost Method
Under this method at a high level,
impairment is evaluated using the
ceiling test approach for reserves at
12-month, rst day of month SEC
pricing, discounted at 10%, with the
frequency being either on a quarterly
or annual basis. With the current
model known for the rst six
months of 2020, a company would
have a reasonable basis to determine
whether there is an impairment or
to expect an impairment based on
the trailing 12-month SEC pricing
average, along with expected pricing
for the remainder of 2020.
Proved undeveloped reserves, under
either method, should only be
included in reserve reporting for a
development plan able to be drilled
within ve years, and companies
need to consider whether they have
the corresponding ability and access
to capital to develop and include
those proved undeveloped reserves
based upon the current economic
Based on current West Texas Interme-
diate (WTI) pricing from January 2020
through June 2020, the SEC 12-month
average pricing would be expected
to range from ~$35/bbl to ~$40/
bbl (considering six months of actual
pricing and at futures strip deck
prices for the rest of 2020 at $35/bbl
and $45/bbl).
For natural gas, Henry Hub (HH)
pricing from January 2020 through
June 2020, the SEC 12-month average
pricing would be expected to range
from ~$1.7/mmbtu to ~$2.1/mmbtu
(considering six months of actual
pricing and at futures strip deck
prices for the rest of 2020 at $1.6/
mmbtu and $2.5/mmbtu).
Unproved Property
Unproved property is required to be
tested at least annually for impairment
to determine whether the book value
is greater than current assessed value
either at individual property basis
or group basis, and an impairment
should be taken. With decreased com-
modity pricing and expected delays
or reduction in capital development
plans, companies need to evaluate
whether their unproved property is
These and other factors should be
included in the evaluation of whether
the unproved acreage should be
considerations of lease renewals and
other wells drilled in the
corresponding area or on
neighboring operators’ leases
considerations of any exploratory
drilling in the area
changes in capital deployment plans
the ability of access of capital to
develop and extend current leases
Midstream and Other
Midstream companies and energy
companies that arent reserve based
follow the guidance in ASC 360-10-
35, whereas indicators are evaluated
whether or not the asset’s carrying
amount may not be recoverable.
Companies should evaluate whether
the carrying amount of their property,
plant and equipment, typically using an
undiscounted cash ow model if there
are changes in pricing or timing of
cash ows, supports the carrying basis
of the property as recoverable.
Also, energy companies with oil
inventories, goodwill, equity method
investments, accounts receivable and
other intangibles should evaluate
whether any indicators resulting from
lower commodity prices would indicate
an impairment for nancial reporting
purposes, in accordance with other
corresponding GAAP treatment.
Are you looking to expand your reach in the oil
and gas marketplace? Do you have a product
or service that would benefit the industry?
If so, we would like to speak with you!
We have a creative team that can design your ad!
Call us (800) 562-2340 Ex. 1
Matt Federle is a partner, Assurance Services, for Weaver, a
national accounting rm. He is a member of the Texas Society
of Certied Public Accountants, the American Institute of
Certied Public Accountants, the Council of Petroleum
Accountants Societies and the Dallas Young Professionals in
Energy. Federle can be reached at
Oilman Magazine / September-October 2020 /
For years, organizational leaders in dan-
gerous industries have searched for ways
to improve organizational performance
and prevent serious injuries and fatalities
(SIFs). This is particularly true for oil and
gas companies where the potential for
burns, amputations, fractures and other
serious incidents are ever-present. In fact,
OSHA reports that employees in the oil
and gas industry are especially at-risk for
experiencing life-altering safety incidents
(Soraghan, 2017). What can be done to
prevent these SIFs from occurring? Also,
how can leaders maintain focus on im-
proving safe production culture with tight
scal demands and a pandemic?
Four Key Fundamentals
Investing time, energy and resourcing to
advancing these four factors will pay divi-
dends now and in the future.
1. Learn from exemplars: Smart leaders
study and learn from leadership pioneers.
The late Paul O’Neill, former CEO of
Alcoa, was a erce advocate of employee
safety and took big risks committing to
injury prevention. He took the bold step
of saying there were no budget constraints
for safety at Alcoa, even if that meant
lost revenue and an unhappy board of
directors. O’Neill famously stated, “I was
prepared to accept the consequences of
spending whatever it took to become the
safest company in the world,” (Lagace,
2002). He told staff that there was no
budget cap for safety and that leaders
would be red if they talked about the
cost of injuries to employees. He didnt
want to send the wrong message that
money trumped caring about people. He
was also an early proponent of what is
now called a “just culture” where incidents
were openly analyzed for future preven-
tion and employees were not blamed
following incidents. He did, however, re
leaders who tried to hide injuries. Put-
ting people over prots paid off. Injuries
dropped 85 percent during his tenure at
Alcoa and market value rose from $3 bil-
lion to more than $27 billion. Paul O’Neill
viewed safety as an investment instead
of a cost…as was proven right. Strong
leaders improve their own safety leader-
ship actions by learning from others who
found high levels of success.
2. Network with trusted advisors:
Smart executives regularly meet with
fellow leaders from a variety of different
industries. It’s common knowledge that
there are no “quick xes” and effective
leaders need to seek experiences from oth-
ers who’ve managed similar challenges that
they’re facing. This networking includes
conferences, forums and executive leader-
ship groups. These formats allow leaders
to share best practices and brainstorm so-
lutions to common obstacles leaders face.
Strong leaders also get guidance from ad-
visory rms and coaches who have years
of experience helping companies navigate
difculties. These partner organizations
help develop customized assessments,
roadmaps and innovative programs like
human performance or behavioral safety
to improve safe production culture.
3. Demonstrate active caring: Innova-
tive leaders stress caring and compassion
over compliance. Incidents and inju-
ries drop as the quality of relationships
between leaders and employees improves
(Hofmann & Morgeson, 1999). A new
plant manager at a still mill in Ohio inher-
ited an unhealthy culture with signicant
distrust between managers and employees.
One of his rst acts as plant manager
was to set up 30-minute meetings with
every employee in the facility to discuss
whatever issues were on their mind (safety
or otherwise). He called the meetings
“30 minutes with Bob” and promoted
them in person, during other meetings,
via email and through other communica-
tion channels. When we arrived on-site
to conduct safety training, a number of
employees told us how much they liked
the meetings and appreciated his effort. As
importantly, numerous employees who’d
not had the meeting referenced the meet-
ings as an indication the new leader cared
about his employees. This simple move
sparked a change in the hearts and minds
of employees and demonstrated legitimate
active caring. Effective leaders embrace the
philosophy of coach Lou Holtz who said,
“Others dont care what you know until
they know that you care.
4. Improve eld manager and supervi-
sor soft skills: Effective corporate leaders
invest in the soft-skills of eld-level man-
agers and supervisors. These leaders inter-
face directly with employees and set the
tone for organizational culture and perfor-
mance. Unfortunately, the skills needed to
attain these positions arent always those
needed to effectively lead others. Here are
a few guidelines for eld leaders to con-
sider when engaging employees in the eld
Four Fundamentals to Improve
Safe Production in Lean Times
By Eric Michrowski and Josh Williams
Photo courtesy of Propulo Consulting
Oilman Magazine / September-October 2020 /
(and virtually during the pandemic):
Show Compassion: Show authentic
caring for employees beyond just safety
and business requirements. Ask about
their well-being beyond physical safety
and if there extenuating circumstances
to be aware of. Building relationships
improves culture in the short-term and
pays dividends in the future.
Psychological Safety: Foster an open
environment where employees are
comfortable raising issues and asking
questions. Setting up one-on-one touch-
points via phone (or in person) helps
establish and maintain good rapport.
It also keeps you locked in with any
“stucks” employees may have.
Walk the Talk: Emphasize safety as
much as production, increase leader-
eld engagement, get and use more
employee suggestions and feedback,
and focus on proactive efforts needed
to attain desired results. People that are
on the job, doing the job, often have the
best understanding of real issues and
how to solve them.
Interactive Discussions: Ask open-
ended questions to promote in-depth,
collaborative discussions. This provides
you with an opportunity to update
employees on key issues they need to
be aware of. It also provides an oppor-
tunity to recognize and appreciate their
efforts and accomplishments.
Active Listening: Demonstrate
effective listening skills. This is more
important now than ever. It’s also
more challenging when face-to-face
interactions arent possible. Video chats
should be used as much as possible with
an emphasis on employees’ feedback
more than your own comments.
Recognition: Increase the frequency
and quality of recognition. Show-
ing genuine appreciation for safety
(and other) practices and participation
increases the likelihood this will hap-
pen more in the future. It also boosts
morale, discretionary effort and doesnt
cost a penny.
Employee Participation: Increase
employee engagement in policies,
suggestions, observations and other
systems. Engaged employees are ve
times less likely to have a safety incident
and seven times less likely to have a lost
time incident (Vance, 2006). According
to a Gallup meta-analysis study, engaged
employees had 48 percent fewer safety
incidents versus disengaged employees
(Harter et. al., 2009).
Follow Up: Capture all learnings from
these interactions with employees.
Respond quickly and effectively to any
concerns. Closing the loop with em-
ployees’ issues demonstrates that you
value their opinions and are commit-
ted to making their lives better. Also,
advertising successes demonstrate real
leadership commitment.
Why it All Matters
Improving safe production culture builds
morale and minimizes the probability of
serious safety incidents. Investing in safety
also provides a good return on investment.
High injury rates disrupt business oper-
ations, undermine motivation, interfere
with productivity, generate unforeseen
costs and affect long-term protability
(Argilés-Bosch et al., 2014).
Each prevented lost-time injury or ill-
ness saves $37,000, and each avoided
occupational fatality saves $1,390,000
(NSC Injury Facts, 2013).
Over 60 percent of CFOs reported that
each $1 invested in injury prevention
returned $2 or more (Liberty Mutual
Chief Financial Ofcer Survey, 2005).
Improving safety culture leads to re-
duced turnover and increased employee
engagement (Huang et. al., 2016),
improved job satisfaction (Clarke, 2010),
and fewer injuries (Beus et. al., 2010).
A review of 18 case studies showed
an average increase of 66 percent in
productivity, 44 percent in quality, 82
percent in safety performance, and 71
percent in cost benets for companies
that implemented effective safety initia-
tives (Maudgalya et. al., 2008).
Call to Action
Smart leaders regularly learn from leader-
ship pioneers, network with trusted advi-
sors, demonstrate active caring, and invest
in the soft skills of eld managers and
Leaders who effectively apply these four
fundamentals will improve safe production
culture and organizational performance.
This is especially important in tight scal
times and a pandemic.
Take a few moments and assess how
you’re doing with these four key factors.
What are you doing well? How can you
improve moving forward?
Honest self-assessment will enable positive
actions in the future. Improving these four
factors will make you a better leader and
help improve your safe production culture
and overall organizational performance.
Dr. Josh Williams is a
partner with Propulo
Consulting, a global
management consulting
rm delivering signicant
and sustainable improvements in
organizational performance. For over
20 years, he has partnered with clients
around the world to drive increased
discretionary effort and improved
strategic execution. Williams is the
author of Keeping People Safe: The
Human Dynamics of Injury Prevention
and received the Cambridge Center
National First Prize for his research on
behavioral safety feedback. Contact:
Eric A. Michrowski is
president and CEO of
Propulo Consulting,
a global management
consulting rm
delivering signicant and sustainable
improvements in organizational
performance. He is a globally
recognized thought leader and guru in
Safety & Operational Performance and
a highly sought-after executive speaker
who is recognized for his innovative
evidence-based approaches to safety
and operations. Michrowski has been
featured on TV, in articles, on podcasts
and has an upcoming ForbesBooks
book to be published this year. Contact:
Oilman Magazine / September-October 2020 /
April 2020 saw oil prices dip negative
for the rst time in memory. A mix-
ture of COVID-19 travel restrictions
worldwide, an oil price war and poten-
tial global recession led the oil price to
tumble. As a cyclical industry, the oil
and gas sector is used to weathering
storms, but this is the second in quick
succession after the 2014-15 crash,
meaning this one is different.
It’s likely the impacts of this downturn
will be here for a while; despite prom-
ising signs of a price recovery, we’re
going to have to get used to operating
at a low oil price for some time. There
are even “concerns that we may be
seeing the beginning of a second wave
of the pandemic,” according to Bjornar
Tonhaugen, SVP, Head of Oil Markets
at Rystad Energy.
Naturally, companies will look both
internally and externally to reduce costs
in response, whether that’s by delaying
works, reducing headcounts or cutting
expenditure along the supply chain;
however, the best answer is likely to be
innovation. For example, the industry
is already embracing digital solutions
such as remote monitoring, but could a
rethink of project design and planning
help, too? All sorts of innovation will
come into play: PwC notes that “in-
novation is king for longevity – time to
double down on … new ways of work-
ing.” This intelligent approach to inno-
vating and nding new ways of working
can offer operators a solution to ensure
maximum return from any investment.
Reduced Working Offshore
We’ve seen offshore staff numbers
reduced to help protect from
COVID-19 and it’s not clear yet when
those numbers will return. Oil and Gas
UK suggests 4,500 staff have been
“stood down” as a result of coronavirus.
Safety is always of paramount
importance, but this introduces a new
aspect to consider.
Previous downturns have meant that
operators have already looked for ways
to create efciencies, lessen time off-
shore and reduce the number of people
needed for certain operations. For exam-
ple, the introduction of smart platform-
to-shore communication systems helps
reduce the number of people needed
offshore and, consequently, helicopter
ights, signicantly reducing both risk
and cost. Operators can also reconsider
their drilling project approaches to the
same effect. For example, solutions that
can help safely and quickly navigate the
early stages of new drilling operations
are a smart approach to achieving the
same effect at an early stage, by reduc-
ing the number of personnel needed
on drilling rigs. Naturally, we’ll see the
sector continue with this type of evolu-
tionary innovation to keep staff safe and
protect the bottom line.
Oil and gas companies need innova-
tive solutions to help adapt to changing
operational practices and, while these are
current, short-term changes in reaction
to COVID-19, it is likely these changes
will become long-term ones if proven
to be effective and of good value. With
all aspects of project costs being revised
and revisited and a lingering pandemic
threat, reconguring offshore operations
to utilize solutions that require a slimmer
offshore workforce remains a key driver
going forward.
Race to First Oil
These longer-term changes to personnel
deployment will also be mirrored in the
perennial drive to reduce time to rst oil.
As soon as the well is drilled, the clock
starts ticking as operators look for fast
returns on investments.
In the near term, we’re likely to face a
global recession alongside sector-specic
challenges, making banks risk-averse and
capital harder to come by. Therefore,
being able to demonstrably reduce time
to rst oil wont only provide a faster
return, it will reduce project risk, making
it more likely the operator can raise
credit and get the project off the ground
Future Forward Operations: Putting
Innovation at the Top of the Offshore Agenda
By James Larnder
Photo courtesy of karlstury –
Oilman Magazine / September-October 2020 /
in the rst place. One way to do this is
to take a modular platform approach
to eld development, such as that of
our Sea Swift platform. Designed to be
fabricated across multiple locations, in
local yards and assembled on-site using
available installation infrastructure,
the reduced-steel design allows for
simultaneous progress on different parts
of the platform. With this approach,
platforms can be up and running in as
little as 10 months.
There is no crystal ball to see where the
oil price might go, and varying predic-
tions offer a range of both pessimistic
and optimistic outlooks but, under any
scenario, innovation that cuts time to
rst oil and brings rapid returns on
investment will be welcome.
Costs Over Time
Operators can go further to reduce
project risk and make developments
more attractive by rethinking
procurement approaches. The signicant
upfront costs incurred when buying
equipment do put assets on the
company balance sheet, but can be a
major drain on CAPEX. Rental options
can be a powerful alternative. Upfront
costs are reduced and operators benet
from the provider’s expert technical
support, further lowering risk to large
projects. Sometimes this shift in mindset
is an effective way to change the
project’s fortunes without changing the
fundamental engineering.
Ultimately, this amounts to a change
in mindset comes when considering
Traditionally, these costs are looked at in
isolation, but a TOTEX or whole-lifes-
pan approach could be the best way to
shave millions of dollars off the project.
With the oil price hovering around the
$40 mark, choosing a solution that of-
fers lower total cost of ownership could
be the factor needed to make a project
viable, including decommissioning. This
is where having a future-forward ap-
proach is key. Decisions need to look
beyond short- to mid-term outcomes
so that all innovations and options are
considered with TOTEX in mind.
For every project, every operator will
have the need to strike a unique balance
between upfront and ongoing expendi-
ture, meaning that exibility is key. This
exibility is be delivered by new ap-
proaches to established industry meth-
ods to put new options on the table.
During this downturn, we’ve collabo-
rated extensively with operators and the
supply chain on how to forge the best
path forward based on their individual
circumstances. We’ve seen smaller,
nimble operators jumping at the chance
to get rigs at a reduced CAPEX and
thereby open up opportunities market
conditions are offering.
Innovative Solutions
If there’s one thing the cyclical nature
of oil and gas has taught us, it’s you cant
afford to stand still. The industry will
continue to adapt and evolve and use
innovation to get us out of tight spots.
With operators now facing the job of
making projects viable with an oil price
around $35-50, creative results will be
tried and tested to maximize returns.
Following the downturn of 2014-15,
operators have already slimmed down
operations with the “low hanging fruit”
solutions implemented. The short time
elapsed since the last downturn means
that costs hadnt started to creep up-
ward again and the industry was already
in innovation-mode. Keeping – and
evolving – that mindset of innovation
for marginal gains will be crucial for
the industry to weather this unexpected
lower oil price storm.
Graduating with a mas-
ter’s degree in chemical
engineering from Not-
tingham University and
having almost 20 years’
experience in the oil and gas sector,
James Larnder has worked for service
companies in a variety of project
engineering, offshore, operational
and management-based roles both in
the U.K. and overseas. Since joining
Aquaterra Energy, Larnder has devel-
oped the company’s service range and
assumed a number of roles including
project engineering, technical sales, as
well as being involved with the com-
pany’s product strategy and business
Advertise with us!
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Oilman Magazine / September-October 2020 /
One hundred years is a major milestone
and the observance of a centennial
usually calls for a celebration but, with
the world in the midst of a pandemic,
there hasnt been much fanfare as this
year quietly marks the centennial of the
rst commercially producing well in
the Permian Basin. Not the Santa Rita
No. 1 (named after the patron saint of
the impossible), which came on in 1923
and is often cited as the discovery well,
but the Texas & Pacic Abrams No. 1,
in Mitchell County, Westbrook, Texas.
The late Betty Orbeck, longtime
director of archives for Midland’s
Petroleum Museum, whose papers are
housed in the Southwest Collection/
Special Collections Library, Texas
Tech University, wrote a letter in 1995,
supporting that assertion, and historical
marker Atlas No. 5335001230 conrms
Orbeck’s written account.
The text of the marker, which was
reported missing in May of this
One Hundred Years In
The Permian
By Rebecca Ponton
Aerial View of Midland, Texas, 1928. Photo courtesy of The Petroleum Museum, Abell-Hanger Foundation Collection
Oilman Magazine / September-October 2020 /
year (and, hopefully, has since been
recovered), reads:
The rst commercial discovery oil well
in the Permian Basin was named for
W.H. Abrams, leasing agent for the
Texas & Pacic Land Trust. The well
rst produced oil in February 1920 at
a depth of 450 feet; but in June 1920,
a better showing of oil was found at
2345 - 2410 feet. On July 16th, 1920
the well was “shot” with nitroglycerin.
As a crowd of 2000 people looked on,
a great eruption of oil, gas, water, and
smoke shot from the mouth of the
well almost to the top of the derrick.
Shortly after, the well owed at a rate
of 129 barrels daily, but soon settled
down to 20 barrels per day. From this
well and a well nearby, the Rio Grande
Oil Company laid the rst commercial
oil pipeline in the Permian Basin.
The rst load of oil went through the
pipeline on April 3, 1922. W.H. Abrams
No. 1 was re-designated on May 1,
1968 as Westbrook Southeast Unit No.
701, formed to increase oil recovery
from the Westbrook Oil Field by water
ooding. This enhanced oil recovery
technique has produced 67 million
barrels of the more than 100 million
barrels of oil recovered from this eld.
Designated as major elds, only a small
number produce 100 million barrels
of oil or more. Fifty-six major elds
are located in the Permian Basin, the
fourth largest oil producing area in the
US. (1967, 1996)
Author Tom Pendleton captured the
ethos of Texas’s nascent petroleum
industry in his novel,
The Iron
which was published in 1966
to great acclaim, eventually earning it
the nickname “the wildcatter’s Bible.
(While there are times when the book,
now out-of-print, can be found for a
reasonable price, it is not unusual to
see it being sold online for hundreds
of dollars.) Over 50 years – and a lot
of false starts – later, a movie by the
same name was nally released in 2018
(to far less enthusiasm), immortalizing
the hardscrabble, sometimes violent,
life in the oil elds in the early days
of the “Wild West” Texas. While both
were works of ction, there certainly
is no shortage of stories about real-life
wildcatters and West Texas oilmen,
like Michael Late Benedum, Joseph
I. O’Neill, Jr., George Thomas Abell,
and Clayton Williams, Sr., (and later his
son, “Claytie”), who were involved in
the frontier days of the Permian [see
According to the Texas Railroad
Commission (RCC), which gets its
gures from the Federal Reserve Bank
in Dallas, the greater Permian Basin
now accounts for nearly 40 percent
of all oil production in the United
States and 15 percent of its natural gas.
Last year,
based on numbers
coming from Aramco, reported that
the Permian had overtaken Ghawar
in Saudi Arabia as the world’s top
producing oil eld in late 2018.
No oil-producing region, regardless
how prolic, is immune to the vagaries
of the cyclical petroleum industry, but
the Permian Basin in West Texas and
southeastern New Mexico seems to
have somewhat of a Teon® shield.
During the 2014 bust when West
Texas Intermediary (WTI) plummeted
from a high on June 7th of $107.95/
bbl. to $44.08 by January 28, 2015, the
Permian appeared to be the one place
that might emerge relatively unscathed.
The industry has been on a roller-
coaster since then with WTI prices
reaching as low as $27.94 on February
9, 2016, and as high as $75.30 on
October 1, 2018, remaining fairly
steady in the interim. After dipping to
$42.53 on December 24, 2018, WTI
rang in New Year 2020 at $63.27 on
January 6th before the unthinkable
happened on April 20th – the price
of oil went into negative numbers
for the rst time since NYMEX
began trading in 1983. The
market corrected itself, as it normally
does, and, as of this writing (August
14, 2020), WTI is currently at $42.01.
(Source: EIA)
Producers in the Permian have proven,
thanks in part to technical innovations
– namely, horizontal drilling – that
they can run leaner operations, drill
more economically and, according the
Federal Reserve Bank in Dallas, break
even at around $50 a barrel, although
that varies depending on location and
other factors, but no one could have
predicted the current situation the
world nds itself in.
Previous scenarios dont begin to
compare to the economic, political
and social upheaval in 2020, with
Continued on next page...
President Donald J. Trump signs oil and gas permits at the Double Eagle Energy Rig in Midland,
Texas, July 29, 2020. Photo courtesy of Shutterstock/Mark Rogers
a worldwide pandemic, oil price
wars, unprecedented levels of
unemployment, and the stock market
crash. In oileld terms, this is a
of epic proportions. (“Downturn”
doesnt quite convey the sense of
displacement that is reverberating
through the industry and the world
at large.) According to Haynes and
Boone, which monitors oil and gas
bankruptcies, over 30 companies
have led for protection during the
rst seven months of 2020, including
some major players like Chesapeake,
Denbury, Rosehill, and Sable Permian
Resources, among others.
The average rig count, as reported
by Baker Hughes, in August for
District 8 (Midland) was 64 – far
greater than that of any other district
in Texas. The RRC reported that
Midland independent exploration
and production company, Summit
Petroleum, LLC, led for nine permits
– the highest number the week of
July 1st - 7th and a surprisingly high
number in the middle of a crisis, as
other companies scale back on drilling
– for horizontal wells in Upton Co.
Even in times of disruption, the
industry keeps innovating and making
adjustments. One of the rst reneries
to be built in the U.S. since the late
‘70s is slated to be constructed by
Meridian Energy Group, Inc. north
of the town of Kermit in Winkler
County, although according to the
company’s website, it has “allowed
its option on this site to expire while
. . . evaluating potentially more
viable alternative sites in the area.
The proposed one billion dollar,
60,000 bdp Walton Renery (also
known as the Permian Renery)
will be Meridians second (after the
Davis Renery in the Bakken in
North Dakota) to operate under
its new Environmental and Social
Management Plan (ESMP), which
aligns with the Equator Principles. As
CEO William Prentice told
in February, not because it is being
forced to by the government or in
order to receive government funding
or subsidies, but because “its founders
and management team . . . wanted to
create a rm that would be a protable
agent of change in cleaning up one of
the most archaic and dirty segments of
the energy industry.”
Another renery, this one in Pecos
County northeast of Fort Stockton, is
being developed by MMEX Resources
Corp. to process lighter crudes.
In addition to a 10,000 bpd crude
distillation unit (CDU), there will
be a 100,000 bpd facility producing
transportation-spec fuels.
The headline-dominating news to
come out of the Permian was last
year’s acquisition of Anadarko – and
its 240,000 acres – in a gutsy move
by Occidental Petroleum CEO Vicki
Hollub. After a bidding war with
Chevron over the prized acreage and
production, and a protracted battle
with billionaire activist investor Carl
Icahn, Oxy emerged victorious,
becoming the largest landholder in
the Permian with three million net
acres. On August 8th, the date of the
closing, Oxy’s stock opened at $46.57;
as of this writing, it is priced at $13.82.
Hollub has made it clear in interviews
that she believes the Permian will
continue to be a major contributor
to the country’s energy resources, as
she told
in January 2019, “for
many years to come,” something she
reiterated in similar terms at the recent
Society of Petroleum Engineers (SPE)
virtual conference in July.
West Texas was the site of a late July
campaign fundraising trip by Presi-
dent Donald Trump, where he gave
a speech at a $2,800 a plate private
luncheon held at the Odessa Marriott
Hotel (for $50,000, couples could have
their photo taken with the president
Oilman Magazine / September-October 2020 /
Oilman Magazine / September-October 2020 /
Chapter 8: Drilling the University
No. 1-B Well
When the University 1-B well nally
struck oil at 8,525 feet on December
1, 1928, Clayton [Williams, Sr.] was
not there to see proven his
hypothesis that commercial
quantities of oil did exist at
deeper levels in the Permian
Basin. He had resigned from
Texon on August 1st hav-
ing become engaged to be
married. He would later say
that he resigned because he
did not want to raise a fam-
ily in the rough world of the
oilelds. Clayton had hired
his brother Waldo as an as-
sistant engineer in 1926, and
Waldo was on the site during the last
few months of drilling.
The story of the completion of the
University 1-B is a part of Texas oil his-
tory lore. According to both [author and
historian Samuel D.] Myres and Waldo,
[Frank] Pickrell decided that enough
money had been spent on the project
and ordered [Carl] Cromwell to stop
drilling at 8,500 feet. “Carl accepted the
order,” Waldo wrote, “but later when
talking over the prospects of a producer
with me, he suggested that he disappear
without telling me the order to shut
down and that I carry on down until
we had a producer or a dry whole. On
December 1st, the bailer would not go
down against the gas pressure and on
the 2nd of December the well owed
40 barrels of high gravity oil.
It took Waldo and the crew two days
to locate Cromwell, who was drinking
heavily in Sweetwater, Texas. “However,
he was sober the minute he absorbed
our message and within ve hours was
on the ground in efcient charge of the
situation.” By January 1, 1929, Univer-
sity 1-B was producing more than 1,600
barrels a day of high-quality oil and, ac-
cording to Myres, proved
the practicability of deep
wells both in the Big Lake
eld and elsewhere in
West Texas.
Locating the University
1-B was the most notable
achievement in Claytons
oileld career and provid-
ed the foundation for his
reputation as one of the
Permian Basin’s signicant
petroleum engineers. He
did not boast about the
discovery in his personal papers and let-
ters, writing only specic details associ-
ated with the location and drilling of the
well. But he was ercely proud of the
discovery, [daughter] Janet Pollard says.
“I remember one Christmas after I was
married, we were in Fort Stockton at
Daddy’s house and a man dropped by.
This man had recently had some success
in the oilelds, and he was talking about
various wells including the University
1-B. ‘I located that well,’ I remember my
dad said, and the man replied, ‘The hell
you did.’ My dad got very angry, stood
up and said, ‘The hell I didn’t.’ I thought
he was going to get into a ght, but the
man backed down and apologized.
Excerpted with permission from the
Harsh Country, Hard Times:
Clayton Wheat Williams and the
Transformation of the Trans-Pecos
by Janet Williams Pollard and Louis
Gwin (Texas A&M University Press;
September 1, 2011).
Harsh Country, Hard Times:
Clayton Wheat Williams and the
Transformation of the Trans-Pecos
by Janet Williams Pollard and Louis Gwin
and for $100,000 per person sit
at a roundtable with him). Ac-
cording to the
Odessa American
the event raised about $7 million.
After the fundraiser, President
Trump signed four permits that
will allow for the expansion
of pipelines and railroad infra-
structure, including two that will
provide for crude from Texas to
be exported to Mexico. He then
went back to Midland, where he
had own in, to visit a rig site
owned by Double Eagle Energy.
The area is no stranger to
presidential visits. After
President Barack Obama’s 2009
inauguration, President George
W. Bush and First Lady Laura
Bush ew to Midland, where
Bush had worked in the oil
industry prior to entering politics,
to mark the end of his two terms
as president. In 2012, President
Obama stopped in the tiny town
of Maljamar, near the larger
towns of Hobbs and Carlsbad, in
Lea County, part of the Permian
Basin that extends into New
Mexico. He then traveled to oil
and gas production elds located
on federal lands in the area,
which were the site of more than
70 active drilling rigs at the time.
The attention to the Permian by
presidents from both parties only
serves to underscore the regions
importance to America’s energy
strategy 100 years after the Texas
& Pacic Abrams No. 1 gave the
nation a glimpse of the potential
it held for the future.
Rebecca Ponton is Editor-in-
Chief of OILMAN’S newly
launched companion publica-
tion, OILWOMAN Magazine.
She is an energy contributor
to and the author
of Breaking the GAS Ceiling:
Women in the Offshore Oil &
Gas Industry (Modern History
Press; May 2019).
Oilman Magazine / September-October 2020 /
With growing worldwide momentum
in decarbonization, the oil and gas
industry is starting to acknowledge
its impact on climate change, and
is now increasingly committing to
carbon neutrality goals and taking
part in collaborative decarbonization
initiatives. The majority of greenhouse
gas (GHG) emissions associated with
the oil and gas industry are Scope
3 in nature, i.e. emissions from the
combustion of fossil fuels. Oil and gas
majors are taking steps to eliminate
their Scope 3 emissions, but this is
a long-term and complex endeavor;
tackling Scope 1 emissions is easier as
they are within the direct control of oil
and gas companies.
The majority of Scope 1 emissions for
the oil and gas industry comes from
aring of associated gas, a form of
natural gas that is frequently produced
as a byproduct in oil production. Due
to a variety of safety, economic and
convenience factors, it is common
practice in the oil and gas industry to
burn associated gas via aring or vent it
directly into the atmosphere. The aring
of associated gas represents a grow-
ing source of GHG emissions for the
sector, particularly in regions like the
U.S. that have experienced rapid devel-
opment in recent decades. While aring
volumes and rates vary signicantly
depending on the reservoir and its char-
acteristics, aring emissions can make
up a signicant portion of upstream
GHG emissions. In the U.S. Bakken oil-
eld, for example, venting, aring and
fugitive methane emissions contribute
nearly 90 percent of the eld’s upstream
GHG emissions due to its moderate gas
content and high are rates.
Flare reduction goals have been at
the forefront of decarbonization with
growing commitments from both
industry players and government
entities to eliminate aring altogether
by 2030. In order to meet these are
reduction goals, particularly in regions
without direct access to gas markets,
operators must nd a productive use
for the associated gas.
There are several existing options for oil
and gas operators to reduce aring at
new and existing facilities. The simplest
and most optimal solution is to leverage
gas pipeline infrastructure to capture,
gather and transport associated gas to
local gas markets, but this is not always
a feasible or economical option for all
assets. In remote offshore facilities,
for example, the high capital expense
of building new pipelines may not be
justied for the volume of associated
gas that could be sold to onshore
Another practical solution is to use
associated gas to power operations
on-site. One emerging idea from
Crusoe Energy Systems involves
the use of associated gas to power
modular onsite data centers for digital
operations like bitcoin mining. This is
a unique approach to are mitigation
that enables operators to make a prot
on produced gas in areas with limited
takeaway capacity, but would not be
feasible for most offshore assets due to
its large footprint.
One way to overcome the lack of gas
pipeline infrastructure is to simply
leverage oil pipelines instead. Doing so
requires the conversion of associated
gas to a liquid form, which can be done
through Fischer-Tropsch technology,
in a process known as gas-to-liquids
(GTL). Fischer-Tropsch technology
is proven at the commercial scale in
Malaysia and Qatar but it has only been
deployed for large-scale operations. To
date, there is no small-scale Fischer-
Tropsch project that proved successful.
The economic viability of GTL projects
is dependent on the price differential of
natural gas and crude oil; in periods of
low natural gas price and high oil prices,
GTL Technology for Flare Mitigation is
Critical to Tackling Scope 3 Emissions
By Holly Havel
Photo courtesy of Lux Research
Oilman Magazine / September-October 2020 /
GTL projects can be economically
viable. The world witnessed such a
situation in the early 2010s when oil
prices were over $100/barrel. At that
time, multiple companies offering small-
scale Fischer-Tropsch solutions popped
up and targeted associated gas streams;
however, oil prices crashed in 2015 and
destroyed the economic prospects of
GTL projects using associated gas. The
ongoing pandemic suggests that it is
unlikely oil prices will reach their heyday
of the past decade.
Despite the challenging economic
situation caused by the crash in oil
prices, small-scale Fisher-Trospch
technology developers survived and
have turned towards greener pastures
– renewable fuels. Companies such as
Fulcrum Bioenergy and Velocys are
currently developing GTL projects
converting solid municipal waste into
renewable hydrocarbon fuels in the U.S.
and U.K., respectively, leveraging the
nancial credits available for low-carbon
fuels in those countries. Over the past
few years, Fischer-Tropsch technology
has found yet another use-case – CO2
utilization. In this area, CO2 and
hydrogen (presumably obtained from
water electrolysis) are converted into
liquid hydrocarbon fuels via a series of
processes including Fischer-Tropsch.
The application of Fischer-Tropsch in
CO2 utilization has so far only been
tested at the demonstration scale, but
the rst commercial-scale project will
be built in 2026 by Norsk e-Fuel in
Producing hydrocarbon fuels from CO2
is counterintuitive as the CO2 itself
originally came from fossil fuels. Norsk
e-Fuel is essentially building a plant
that is based on reversing the combus-
tion process. Despite its challenging
economics, the process is necessary for
the energy transition. Unlike the road
transportation sector which can be de-
carbonized with electricity, the aviation
and marine sectors will still rely on hy-
drocarbon fuels due to its unparalleled
energy density compared to batteries. If
we cannot change the type of fuel we
use, then we need to change its source
– in this case, swapping crude oil with
CO2 and green hydrogen.
Fischer-Tropsch technology offers
a unique opportunity for oil and gas
companies looking to succeed in the
transition to a low-carbon economy.
Synthetic fuels made from CO2 are
for the industry
to neutralize its
Scope 3 emissions;
however, the
market for CO2-
based fuels is still
immature. But
technology can
also be used in the
more pressing case
of eliminating the
industry’s Scope 1
emissions through
abatement of
aring. Admittedly,
synthetic fuels
from associated
gas merely
offsets Scope 1
emissions to Scope
3 emissions, but deploying Fischer-
Tropsch technology today will provide
the oil and gas industry with valuable
expertise and know-how in anticipation
of the technology’s much-broader
deployment for CO2-based fuels. This
means oil and gas companies should
prioritize Fischer-Tropsch technology
today in their quest for carbon
Holly Havel is a research
associate for the energy
team at Lux, where
she conducts research
on technological
developments and market trends in
the oil and gas and power generation
industries. Prior to joining Lux
Research, Havel worked as a wellsite
geologist on oil rigs in Oklahoma
where she logged lithology, drilling
parameters, gas units and formation
tops for the duration of the well
logging period. More recently, she
has experience as a scientist for an
environmental consulting company
where she conducted eld activities
at active petroleum release sites and
submitted regulatory reports to local
and state agencies. Havel holds a B.S.
in geology from Union College.
Oilman Magazine / September-October 2020 /
With operational disruptions,
supply chain lags, and reductions in
consumer spending, the coronavirus
pandemic continues to impact
business globally.
Stalled or stopped business activities,
combined with a slowed demand
for oil, are particularly affecting the
energy sector. The oil and gas industry
is used to whiplash reactions to
market changes and, consequently, can
take downsizing, restructuring, and
mergers and acquisitions (M&A) in
stride. After all, our current economic
landscape marks the sector’s third
price collapse in 12 years. In some
ways, this downshift is no different to
prior cycles.
The fact that the demand side of the
supply-demand imbalance is due to
a global pandemic is a considerable
wrinkle. From full-time staff to
offshore workers, pipeline personnel,
and local and global contract workers,
the pandemic impacts the way each
position in the industry is both
executed and managed.
In addition to the breakeven price
point of a given eld, a further
consideration for business leaders will
be their response to any international
and regional outbreaks. Has
COVID-19 prevention training been
added to health and safety policies?
Have employee and contractor testing
been taken into account?
These concerns are critical for
any company and they are only
compounded when adding a new
group of employees and contractual
arrangements to their own over the
course of an M&A, a practice that may
become more common in the energy
sector moving forward, given that over
30 oil companies have already declared
bankruptcy this year. According to
Business Insider, experts predict more
will follow.
M&A and Reorganizations
In July 2020, Chevron announced
its acquisition of Noble Energy in
an all-stock transaction, targeted to
close in Q4 2020, and breaking the
ice on M&A in the current cycle.
While signicant, the deal is a fraction
of what Chevron was considering
paying for Anadarko (acquired by
Occidental) just a few quarters ago.
From an activity perspective, the M&A
represents an important pivot from
otherwise cost-controlled measures
across the industry. Chevron has stated
that its latest acquisition will add
$300 million in cost synergies to the
organization post-merger.
For Chevron, Occidental and Mara-
thon Petroleum, integrating their
workforces requires the same level
of execution expected under normal
circumstances, which includes plan-
ning for such variables as cultural t.
After all, up to a third of integrations
that fail are due to an organizational
mismatch, according to research by
McKinsey. “In this industry,” the re-
port states, “the importance of culture
is magnied by its impact on safety
and operational risk.
A recent survey of the energy industry
workforce conducted by the University
of Houston supports this assessment,
with 55 percent of respondents
suggesting the energy industry
should invest even more in employee
How COVID-19 Is Forcing Oil And Gas
To Rethink Workforce Management
By Richard Marshall
Photo courtesy of Nakisa
Oilman Magazine / September-October 2020 /
health and wellbeing in light of the
How can organizations simultaneously
track such essential health and safety
concerns, gain insights about the
impact on business operations in real
time, and plan for business continuity?
The answer may be technology.
The Business Impacts of
Modernizing IT
In 2017, during an uptick in the oil
and gas industry, energy giant Phillips
66 chose to invest in company-wide,
enterprise resource planning (ERP)
technology. With 80 percent of
Philipps 66’s workload now hosted
in the cloud, the organization’s
digital transformation has proven
to be a game-changer, revealing the
critical value of leveraging IT to both
improve global workforce visualization
and streamline business operations.
The company was one of the rst of
its kind to announce a $700 million cut
in spending in 2020 and has credited
the speed at which it could make such
an important decision to its digital
transformation. As early adopters in
the sector, Phillips 66 led the way for
other companies in the industry to
follow suit.
While it may seem counterintuitive,
with spending under scrutiny and a
freeze on IT budgets, now is an ideal
time for players in the energy sector to
consider a human capital management
(HCM) solution to support a true
business transformation able to sustain
long-term business operations.
Digital HCM solutions support data-
based decision-making and as a result
– seen in the Phillips 66 example – can
accelerate an organization’s desired ac-
tion plan by enabling data conversion
and reporting, offering modeling and
visualization of data across multiple
organizational structures, and by
measuring the impact of any potential
and implemented changes including
workforce realignment, reduction in
force and more.
Human Capital Management
Technology for 2020
It’s no surprise that Gartner’s latest
Hype Cycle for Human Capital
Management analysis conrms that
the pandemic has sparked signicant
demand in the evaluation and redesign
of workforce management processes
and technologies.
When all the relevant stakeholders
are able to access a single source of
organizational truth in a purpose-built,
secure, and cloud-based collaborative
solution, an organization moving
through the COVID-19 crisis can
accelerate value delivery. While
managing potentially new remote work
mandates, all the while considering
performance management, scheduling,
activity tracking, and health and
safety precautions for a diverse and
international workforce. Real time
access to accurate, reliable HR data
makes this possible.
With the help of technology, HR
professionals and business leaders can
easily visualize their team members
in the Permian Basin or the North
Sea on the global map and quickly
drill down into each population.
Furthermore, they can apply lters
for critical employees and high
performers or other diversity and
inclusion (D&I) metrics to learn how
a divestiture or reorganization might
affect performance on an individual or
company-wide level.
An HCM solution like Nakisa
Hanelly can also help shape a tailored
communication and retention plan
for key talent (an unforeseen by-blow
of many reorgs or M&A), ensure
effective succession planning, and
allow stakeholders to understand
instantly how their new business
model might impact company
demographics or diversity metrics.
Likewise, aggregating salary and
benet information in a single
solution allows business leaders and
HR professionals to quickly test and
determine the nancial impacts of
different scenarios and provide the
concrete data – the dollars and cents
– needed for those realized savings,
whether they add up to $300 or $700
All of this is possible while avoiding
the churn of spreadsheets and stafng
of manual workloads still prevalent
in most organizations in the energy
sector, which means an organization
can achieve its target Key Performance
Indicators (KPI) more quickly and at
less cost.
The pandemic has increased the need
for business agility in the oil and gas
industry. Leveraging the benets of
technology to align goals and drive
organizational transformation can
unlock competitive leadership, distin-
guishing those who simply survive the
current disruption from those able to
reinvent themselves and thrive.
As head of Nakisa’s
Global Oil & Gas
Industry Practice,
Richard Marshall is
responsible for leading
initiatives to enhance the delivery of
value to customers and prospects
in the vertical from the Nakisa
solution set. He has covered oil and
gas and energy services at Nakisa
since 2016 and at different times
in his private-sector career, which
began in investment banking in New
York and London. Marshall’s prior
experience includes work with JP
Morgan, Deutsche Bank, RBC, PNC
and SAP, in addition to serving as
CFO of a portfolio of companies.
He served for eleven years in
the Canadian Forces, nishing
as a Captain on C-130 Hercules
transport aircraft. Marshall holds a
BA from the Royal Military College
of Canada, an MA in international
economics from Johns Hopkins
University, and an MBA (nance
and accounting) from Columbia
Business School.
Oilman Magazine / September-October 2020 /
During these challenging times, with
rigs drastically cut and completion
crews on indenite hold, nding ways
to immediately impact cash ow is
critical. If you are a C-Suite, division
VP or eld leader, there are a number
of impactful strategies your team can
implement today to drop more revenue
into the bottom line.
The strategies that will drive immediate
cash ow results are pragmatic and
entail aligning people, processes,
technology and data. This includes
getting out in the eld and starting a
conversation with pumpers, building
a production optimization process led
by eld production teams, leveraging
production and non-op data, and
empowering the back ofce with the
right technology to boost cash ow.
Pumpers, lease operators and other
eld staff are often overlooked as an
opportunity area.
Take immediate action to visit and
engage with eld production teams.
Acknowledge fractured leadership
and create a clear channel of
Field production teams have valuable
insight into production optimization.
Empower eld staff to create short-
term plans to improve their wells.
Redirect capital from drilling and
completions projects to eld staff
projects to increase cash ow.
Production operations often rely on
fragmented, legacy technologies.
Cloud-based solutions enable
collaboration among eld and back
A unied platform eliminates data
silos, streamlines eld operations and
Operated and non-operated data is
key to uplifting margins and reducing
Create a data management culture to
ensure data quality and availability.
Leverage non-op data to improve
revenue forecasts and accruals.
Bridging the Gap Between
Executives and Field Staff
It’s ironic that after spending
millions to drill and complete a well
with much fanfare, operators often
unceremoniously hand over the daily
upkeep of a new well to eld staff that
is charged with maintaining it for its
entire lifespan. And while drilling and
completion teams are often rewarded
with celebratory events when they
reach certain targeted goals, production
teams are often inadvertently ignored.
Dont wait! Immediately set up time
to visit eld production teams; both
group sessions and a few one-on-one
meetings will prove to be immensely
helpful in the effort to increase cash
ow. Dont rush it. Senior leadership
should devote plenty of time for
these visits, as they could have the
biggest impact the organization has on
increasing base production all year.
For mission critical eld staff that has
been unintentionally marginalized, it
is important to create a dialogue, not a
monologue or pep talk. Ask meaningful
questions, then be sure to listen. Hear
what they have to say and encourage
them to open up and share their ideas
around improving well performance
and reducing downtime. Most eld
staff will have a plan for increasing
the base production of their wells in
Implementing the Right Strategies to
Immediately Boost Operator Cash Flow
By Kevin Decker and Steve Haglund
Photo courtesy of Shutterstock
Oilman Magazine / September-October 2020 /
multiple ways. They just need help with
a few roadblocks, a budget or simply
encouragement to help get their ideas
and plans into motion.
Acknowledge fractured leadership.
Be transparent when talking to
production teams. While drilling and
completion departments often have
one VP or senior leader over the entire
division, production often suffers from
“fractured leadership.” It can include
production eld leadership, divisional
or business unit leadership, engineering
leadership, reservoir leadership, and
sometimes other teams with a vested
interest in impacting eld production.
This often produces mixed messages to
eld production personnel, leading to
conicting or wasted efforts, projects
and time.
By getting out in the eld and
listening to eld staff as well as
acknowledging fractured production
operations leadership, management
teams can open up a clear channel
for incorporating valuable eld-level
insights that can provide immediate
payoff for production optimization and
increased cash ow.
Building a Continuous
Optimization Process Led from
the Field
Leveraging new channels of
communication with eld production
teams, the next step management teams
can take to quickly boost cash ow is
to create clearly aligned and unied
processes to enhance base production
backed by a small budget and
investment of senior leadership time.
Due to fractured leadership, eld
production teams often receive multiple
different plans, strategies and initiatives.
Rather than taking a top down planning
approach, start a grass roots initiative
that enables eld production staff to
initiate their own plans for optimizing
production for their well set. Listen
to their ideas and align those insights
across teams to begin building a
broader plan guided by those closest to
the wellhead. That plan can serve as the
initial draft for foremen, optimization
teams, engineers and others to add their
Most pumpers, lease operators, automa-
tion or measurement techs have un-
tapped ideas about improving base pro-
duction (wells they know will respond
if someone will listen). Let those ideas
help you design your short-term road
map. That plan should be simple and
cohesive with a laser focus on improv-
ing cash ow immediately, including:
Articial Lift – insights into
optimal set points and equipment
conguration for rod lift, ESPs, etc.
Oil Stock Management – ideas
around improving hauler efciency
and accelerating sales runs.
Daily Process Optimization –
reducing pumper admin burdens so
they can focus on optimizing their
Operating by Exception (OBE)
– giving explicit permission to
prioritize wells with most down
Downtime Reduction – ideas around
proactively preventing compressor/
equipment failure and minimizing
downtime when wells are ofine.
Technical Innovation – short-term
technology ideas with big potential
for increased volume and reduced
Field production teams will often move
heaven and earth to hit a goal set by
their CEO, COO or VP. Set challenging
but achievable goals in each of the
areas above with a short-term end
date, then measure the progress on at
least a weekly basis. To succeed, senior
leadership will need to invest a little of
its time and energy as well as nd ways
to redirect capital to eld production
staff and their cash ow projects, such
as investing portions of unused drilling
and completion budgets.
Figure 1: Cash Flow Generating Strategies Leveraging People, Process, Technology, and Data
Continued on next page...
Oilman Magazine / September-October 2020 /
Uplifting Margins with Operated
and Non-Op Data
In addition to optimizing production,
accurately booking reserves and
accruing for inbound revenue (volume)
and expenses is also key to uplift
your margins. Operated and non-
operated data holds the key to optimize
both revenue and costs; however,
organizations must rst create the right
data management culture.
Within every oil and gas company
exists vast potential to improve cash
ow leveraging existing information
about assets and production, yet it is all
too often trapped in data silos or the
data is simply underutilized. To unlock
this revenue-generating potential, take
the time to automate processes and
empower the right resources with data
management and QC tasks.
Automate production workows
– Wherever possible, automate
manual production tasks across your
organization to free up time for
those techs and staff to nd, validate
and analyze your data. Dont assume
that it’s already been done, because
often those tasked with automating
workows have job security concerns
that interfere with that automation.
Demonstrate that automation
enables them to analyze versus input
the data.
Free up production engineers – Do
a quick engineering process review
and nd out if your production
engineers are doing true engineering,
rather than preparing AFEs, county
courthouse visits, endless slide decks
for leadership, etc. If not, allow them
to do what they love and give them
the production data to do it. They
will nd your best opportunities if
they have the time and the data.
Find your data analysts – In every
organization, there are several
(although often quiet) data junkies
that feed on data analysis projects.
Get them engaged to nd the best
production cash ow projects across
your operations. There are hundreds
of them waiting to be discovered and
analyzed but need someone with the
time and focus to do research.
Validate the data – Spend a little
time empowering your IT, eld
operations, and production
accounting teams to identify where
opportunities exist to clean the
data. Very often, over time, teams
build data correction into their daily
routine, rather than validating it at
the source. Cash ow generating data
analysis depends on the quality of
your data and the simple yet effective
processes that validate it and keep it
Remember your reservoir engineers
– Every volume and process
improvement that enhances the
data makes your reservoir forecasts
better, which mean more accurate
cash ow and nancial projections. It
pays to invest time and energy in to
automating and validating this data
so it represents the clearest, most
accurate picture available.
By engaging your teams (engineers,
analysts, IT, and newly identied data
analysts) your organization will be
more prepared than ever to quickly
compile a list of the best opportunities
to immediately boost cash ow for
minimal capex/LOE.
Non-op data is one of the most
overlooked assets that can boost
or optimize cash ow, including
reconciling revenue paid versus
production volumes, improving
reservoir production forecasts for non-
operated wells, and improving revenue
accruals for non-operated wells. Timely
access to non-op data is also critical
to identify risks associated with shut-
ins or curtailed production. However,
this vital data is often poorly circulated
among partners with many operators
prioritizing well data management for
their operated assets over wells they
only have a working interest in.
Exercise your rights to your non-op
data by working directly with your
partners to obtain the data you need or
participate in free or low-cost reciprocal
data sharing/trading network to
deliver non-op data right into your well
Empowering the Back Ofce with
the Right Technology
As advanced in technology as the
industry has become in areas such as
drilling, completions and geoscience,
other aspects, such as business
segment and enterprise level resource
planning software (ERP) on platforms
designed 30+ years ago, are virtually
antiquated yet still considered “Best
Figure 2: Cloud-based Visual Representation of Field Assets and Allocation Networks
Oilman Magazine / September-October 2020 /
in Class.” Think of what ERP covers
in an oil and gas business and the
implications are astonishing. Upstream
companies pervasively rely on vintage
technology to run their business, from
production operations and allocations
to their general ledgers and revenue
disbursement. Adding to the overall
lack of innovation is the industry’s
addiction to spread sheet allocations
and workarounds in a Silicon Valley
Choice of production operations
technology is the key to building a clear
channel of communication with eld
production teams, collaboration around
production optimization processes,
and creating a free ow of data in
the organization. However, legacy
technology, dozens of point solutions,
and data silos impede successful
execution of these strategies and all
too often inject delays, errors and
unnecessary costs for the organization.
Maintaining complex allocation
networks, for example, and calculating
daily allocations are critical to operator
revenue; however, cumbersome
legacy software, manual processes
and spreadsheet-based solutions add
signicant time and uncertainty that
often limit visibility into production
and cash ow.
A unied production operations
solution built on the Cloud offers
scalability and affordability while
accelerating data acquisition,
processing, allocation and nancial
reporting. As a result, operators can
nally connect the eld with the back
ofce to gain the up-to-date view of
production and revenue they need to
manage cash ow.
Operators looking to benet from
the Cloud and an integrated software
platform are increasingly turning to
W Energy Software. The company
pioneered the oil and gas industry’s only
unied production operations solution
built on the Cloud that features
modern eld data capture tools,
production reporting, visualization of
assets and allocation networks, and
an extremely powerful and capable
allocations engine. As a fully integrated
upstream ERP platform, production
accounting seamlessly ows into
revenue and nancial accounting where
production volumes are linked with
actual commodity pricing to provide
operators with a precise view of their
nancials, eld costs and revenue.
Yet the most valuable benets of
a unied platform and W Energy
Software are stability, predictability
and reliability. By eliminating the need
to maintain the dozens of software
applications and tools that operators
have historically relied on and providing
a common and consistent dataset, W
Energy Software elevates condence in
your analysis, calculations and nancial
results. When combined with increased
performance, that trust can empower
an operator’s workforce, reduce risk
and accelerate business performance.
The oil and gas business is an industry
slow to change eld practices unless
better alternatives are proven. Change
is often difcult, especially with deeply
ingrained eld and back ofce cultures,
top down management, fractured
leadership, underutilized datasets and
legacy technology. But, with all of these
challenges, there is still immediately
actionable opportunities to make
impactful change today. With a holistic
strategy for creating a clear channel of
communication with eld production
teams, driving grassroots insights,
harnessing operated and non-op data,
and deploying a unied production
operations platform, operators can
drive profound change across the
organization that converges on
maximizing revenue, reducing costs and
improving cash ow.
Steve Haglund has
over 20 years of
experience in strategy,
business development,
operations, and
consulting practice development
in the information technology and
oil and gas industries. He serves as
Vice President of Field Operations
at W Energy Software where he
spearheads the software developer’s
eld solutions for upstream and
midstream. Haglund was previously
President of NeoFirma (acquired by
W Energy Software in 2019), where
he grew the software company into a
category leader in mobile and cloud-
based oil and gas eld operations
solutions. Prior to that, Haglund
co-founded and served as President
of Insolexen, a business integration
services company and Michigan
Fast50 Award winner, which was
acquired by Percient, a public, IT
services consultancy. Before that,
he served in various capacities with
webMethods, Andersen Consulting,
Baker-Hughes, and FMC. Haglund
graduated from the University of
Illinois with a B.S. in Chemical
Engineering and holds an MBA
with Honors from the Cox School
of Business at Southern Methodist
Kevin Decker has
nearly 30 years of
experience with
independent E&Ps,
building and leading
teams in the space where nance,
eld technology, and operations
services converge. His extensive
experience includes optimizing eld
production processes, developing
best-in-class M&A integration
processes with 135 acquisitions in
10 years, and optimizing drilling
efciency and base production by
applying data science and analytics to
operations support center challenges.
Decker is President of Peake, LLC, an
energy, technology, and management
consulting rm. He spent the
bulk of his career at Chesapeake
Energy where he held various senior
management positions, including
Director of Intelligent Production
Operations, Director of Integrated
Field Operations, and Director of
Operations Data Services. Decker
earned a B.S. in Accounting from
Oklahoma State University and is a
Certied Public Accountant.
Oilman Magazine / September-October 2020 /
Drilling is an essential component
in the oil and gas industry with
operators using drilling as a method
to excavate oil underground and from
various resources. With drilling being
as signicant as it is, it should also
be performed efciently, yet many
operators have difculty in this area.
There are many oil and gas operators
using outdated equipment during
onshore and offshore drilling
ventures, which not only causes
inefciency, but poses potential harm
to workers out in the eld. Using
legacy drilling technologies and
following old industry standards can
hinder performance, increase risks
for workers and affect prots. With
this being a clear issue in the industry,
oil and gas operators have been
searching for solutions to improve
their operations.
Fortunately, oil and gas solutions
company Sigma Drilling Technologies
took note of this issue, developing
a line of products that focus on the
improvement of drilling processes.
Sigma’s line, which includes pulsation
control technology, was designed to
help oil and gas operators save on
costs and provide higher efciency
during the drilling process. Founder
of Sigma Drilling Technologies,
Justin Manley, provided more insight
into the company’s products, the
benets Sigma’s products provide to
oil and gas operators, and how such
products are helping to strengthen
operations in the industry.
With a mission to improve oil and
gas operations for customers through
technology, Sigma was established
through one simple question, “Why
hasnt anyone xed this yet?”
Noticing a clear issue in the way
companies carried out processes,
Sigma resolved to help those
companies operate more efciently.
According to Manley, “Our initial
product offering solved a 70-year-
old problem our customers were
simply just dealing with. Helping
our partners achieve superior
performance and protability while
decreasing risks to personnel and
assets in the eld is our driving
force and how we operate.” Sigma
uses products that can utilize a
company’s existing equipment
while eliminating their equipment’s
inherent aws. “We believe in
win-win relationships and our
customers have really responded to
our philosophy,” says Manley.
To provide the best solutions to oil
and gas operators, Sigma operates
in a very niche market segment,
developing unique products
to enhance each user’s drilling
and operational experience. “Our
industry handles energy mitigation
generated by the reciprocating
pumps on the rig, better known
as mud pumps,Manley explains.
“To mitigate these harmful energy
signatures, mud pumps need to be
outtted with pulsation dampeners.
The industry standard pulsation
dampener was designed over 70
years ago and utilizes a bladder
charged with nitrogen gas. This
was a tting solution 70 years ago
when operational pressures were
signicantly lower than modern drill
plans,” Manley says.
Recognizing that many companies
were still operating through
this outdated solution that was
incompatible with modern drill plans,
Sigma designed several proprietary
technologies for the market, such as
its Charge Free Conversion Kit, to
upgrade existing equipment. All of
Sigma Drilling’s technologies revolve
around a proprietary technology or
our Charge Free technology. We have
created unique products designed to
utilize existing designs and equipment
but alleviate all the complications
created by antiquated pulsation
dampeners,” states Manley. “Our
proprietary Charge Free technology
always has the proper compression
rates to ensure high performance
Improving Operations Through Technology:
How Sigma Drilling Technologies is
Revamping Industry Drilling Practices
By Tonae’ Hamilton
Photo courtesy of Sigma Drilling Technologies
Oilman Magazine / September-October 2020 /
and fantastic measurement while
drilling (MWD) signal detection and,
most importantly, never exposes rig
personnel and equipment to potential
catastrophic failure. Many of Sigma’s
products install directly into our
customers’ existing assets, creating a
“t it and forget it” experience that is
second to none,” Manley asserts.
With technological trends, such as rig
systems automation, on the rise in
the industry, many drilling companies
will be relying on solutions providers
to keep their operations up-to-
date and to stay competitive in the
industry. Sigma is on the forefront of
these trends, developing equipment
that is designed to provide high
operational performance. “Designing
and manufacturing equipment with
[these trends] in mind has helped
position Sigma as the exclusive
choice for pulsation equipment,
Manley says. “Automation systems
are built on predictable outcomes
and performances. Our Charge Free
technologies are designed to deliver
just that, predictable performance.
In addition, Sigma’s innovative
Charge Free Conversion (CFC) Kit
directly targets pulsation dampeners
and mud pumps, some of the biggest
issues drilling contractors face.
“Contractors found themselves in a
constant ght with the mud pumps
because the pulsation dampeners
were inadequate to handle modern
mud pump conditions. Sigma’s
CFC Kit was designed to deliver
outstanding performance across
all operational pressures. The
CFC Kit utilizes a dual energy
mitigation system that not only uses
compression for energy absorption,
but also deploys a system for kinetic
exchange,” explains Manley. The
CFC kit resolves the issues that arise
from using pre-charged bladders with
standard pulsation dampeners. “The
CFC Kit delivers predictable, high
performance while eliminating costs
and potential safety risks.
Although the oil and gas industry
is slowly but steadily embracing
technology and operational changes,
the drilling sector of the industry still
has a long way to go. “The oil and gas
industry is rooted in traditions. With
strong ties to traditions comes strong
resistance to change,” states Manley.
“Drilling contractors have dealt
with the fact that pulsation control
equipment simply hasnt kept up with
the increased demands of modern
drill plans. If a broken leg is all you
have ever known, you dont take time
to think about xing the leg,” Manley
points out.
As a result, Sigma is focused on
promoting growth in the industry by
helping its clients gain next level op-
erational efciencies through technol-
ogy. “As an industry, American energy
has evolved and adapted to these
challenges by utilizing new and im-
proved technologies and Sigma rmly
believes we will all be better for it.
Sigma rmly believes if we assist our
customers in becoming more ef-
cient, more protable, and providing
safer working environments for their
employees, we are doing our job.
With a push for more modernization
within the industry, it is crucial for oil
and gas operators to maintain up-to-
date drilling processes and, therefore,
they need direct access to the latest
technologies from oil and gas
solutions providers to make or keep
their operations current and efcient.
“The mud pump is the heart and soul
of drilling operations and having a
smoothly operating pump system
is key to achieving successful drill
plans,” explains Manley. “We at Sigma
feel we should be driving higher mud
pump performance, thinking about
better ways to clean up MWD signals,
pushing the boundaries of what is
achievable, and all of our initiatives
are with one goal in mind: how do we
make it better?”
While the industry has been
experiencing a wave of technology
and software solutions, drilling
processes remained unaffected for
the most part, until recently. Oil and
gas solutions companies, like Sigma,
are revamping the way the industry
operates. Sigma has made it their
mission to support drilling companies
by offering products that improve
operational performance and existing
equipment and promote safety
and prots. Oil drilling processes
will continue to be enhanced and
equipment performance will continue
to improve with companies like Sigma
supporting the industry. “We pride
ourselves at being the trusted partner
and problem solver for our users,”
says Manley. “We make available
resources to help folks in the industry
understand their equipment and
how to improve its performance.
Information is what helps the
industry move forward and keep
people safe, and it is what we strive to
Photo courtesy of Sigma Drilling Technologies
Oilman Magazine / September-October 2020 /
Eric Eissler: Please provide some
background as to what your
company does and how you do it.
Spencer Albright:
MineralWare is an
cloud-based oil and
gas asset manage-
ment platform. We
provide the lead-
ing software for
managing mineral,
royalty and non-
operated working interest assets. Our
clients are able to see their position on
a map, track revenue, ensure accurate
payments, locate missing payments,
access nationwide well, permit, and
production data, and much more. Min-
eralWare was founded with the goal of
easing the management of oil and gas
assets by automating and consolidating
processes that traditionally are executed
EE: Could you provide a deeper dive
into all the software you use to track
mineral rights?
SA: The MineralWare software package
is designed to be a one-stop shop for all
mineral and royalty management needs.
With permits, nationwide production,
revenue and corresponding analytics,
clients can track the life cycle of their
wells. Additionally, our robust land
module allows clients to map and
manage lease activity and provide a
secure auditable location for their land
EE: As a newer company, what do
you feel it was that got you out of
the gate on the right foot?
SA: From the beginning we knew, to
be successful, we had to prioritize the
client and the client’s experience. It is
one thing to build powerful and robust
software, but the secret to our success
has been our focus on satisfying the
needs of our clients. Our core values
of S.E.R.V.E (Service, Excellence,
Relationships, Virtues and Enthusiasm)
are what we strive to live out every day
in our client interactions. We have a
retention rate of more than 98 percent
this year which shows that we are on
the right track.
EE: Managing mineral rights is not
an easy task. Are you connected to
government databases to keep track
of all the mineral rights? How does
that work?
SA: I feel land is changing hands or
new boundaries are being demarcated,
[so] how do you keep track of all the
action? From the beginning we wanted
to source our data directly from the
government organizations populating
it, so we spent a signicant amount
of time and resources to connect
to each producing state’s databases
which allows us to provide up-to-date
information for our clients. The rest
comes directly from clients. If an
asset is sold or gifted, they are able to
make the modications to their owned
interests directly on the platform.
EE: Could you expound on how
things go wrong (what are some
common issues?) and how your
services allow the user to handle the
SA: We have a diverse group of
clients from family ofces, acquisition
companies, universities/foundations
to nancial institutions, so the issues
vary signicantly. Some clients have
little experience in the oil and gas
industry and are starting with the need
to understand what they own while
other clients manage multiple complex
accounts and need the ability to provide
scheduled reports to shareholders,
investors or their own clients. A
common theme across the entire
mineral ownership spectrum is lost or
suspended revenue, commonly referred
to as “suspended funds.” This can
occur for a variety of reasons, some of
which are as simple as failure to sign
a division order or as complicated as
title disputes. Using our nationwide
fabric of well data and mapping
technology, our software automatically
identies areas of potential suspense
and our team helps recover those
funds for our clients and bring those
wells into payment. It is important
to stay organized as a mineral or
royalty owner in order to make well-
informed decisions when receiving
correspondence from an operator or
purchaser. Our software solves this
problem by organizing and storing
everything in a digital ling cabinet tied
to interests and leases. MineralWare
provides a solution to a wide variety of
consumer needs.
EE: What are some of the reasons
I would want to use your service
over another one?
SA: The quality of software and
customer service is something that
differentiates us from the rest of
the mineral management software
packages on the market. MineralWare
is continually launching new features
developed in partnership with our
Interview: Spencer Albright,
President, MineralWare
By Eric R. Eissler
Oilman Magazine / September-October 2020 /
clients to ensure that as their needs
change our software maintains the
signicant value that it has from the
beginning. Additionally, as mentioned
earlier, we pride ourselves on the level
of service we provide – if any of our
clients have account issues, our client
success team provides the perfect
solution to any problem. Our team is
continually working to push monthly
updates in order for us to stay up-to-
date on the latest market trends and
consumer needs. In light of the level
of customer service we provide, most
of our competitors belong to larger
tech conglomerates that are not solely
focused on improving their solution.
We are a standalone company that is
only focused on improving our mineral
management product, and it shows.
EE: How has your software reduced
paperwork? Does it make it more
efcient in buying and selling
SA: Our software has automated time-
consuming back ofce processes for all
of our clients. With our platform, cli-
ents receive lease expiration alerts, per-
mit proximity alerts, rig location alerts,
new well alerts, and other monthly
summary alerts, along with much more.
With the launch of our sister platform
Energy Domain in the spring, users will
be able to monitor areas of interest and
quickly buy and sell directly. The listing
process is completely streamlined with
land and revenue data already being
digitized in MineralWare and readily
available in any format through our
custom reporting feature.
EE: Where do you plan to go from
here? All software gets upgrades
and updates; is there anything in the
works that you can tell us about?
SA: We work to improve our software
every day! Our goal is to continue to
add features that our current clients
request, and future clients need. Our
next big add will be non-op, joint
interest billing (JIB) tracking and
reporting and analysis to link with
everything we already have. This will
provide even more visibility for our
owners and ALL of their interests. We
have made a heavy investment in our
development team and will be rolling
out other products in addition to
Energy Domain in 2021.
Virtual Conference 2020
2-6 November 2020 |
part of the
Oilman Magazine / September-October 2020 /
The energy industry is very cyclical
and, while companies should take
advantage of economic ups and
market changes that give them an edge,
it is imperative to keep in mind that
a downturn will follow. It is easy to
focus on growth without having a Plan
B, which causes concern as companies
depend heavily on commodity prices
and market factors that fall outside
their realm of control.
During the most recent downturn of
2020, we have been in the trenches
alongside oil and gas leaders as they
scramble to stay protable. While
production scales back, highly success-
ful and industry-leading operators are
altering their strategies and shifting
their mindset with a determination to
crush costs, streamline operations and
re-evaluate their technology landscape.
Our consulting and back ofce/IT
outsourcing rms, EAG Services and
EAG 1Source, were founded on the
premise of alleviating unique business
challenges upstream and midstream
oil and gas companies inevitably face.
We’ve been in the business for 17+
years and have served as a “source of
relief ” to our clients, weathering the
highs and lows of multiple economic
downturns, transforming businesses to
thrive after bankruptcy, and effectively
collaborating with leadership to maxi-
mize human capital, all while working
within parameters in respect to life’s
most precious commodity – time.