E&p magazine 2019 11

HartEnergy.com
N O V E M B E R 2 0 1 9
Basin Modeling
Cementing Advances
Fracture Fluid
Optimization
Emissions
Management
Decommissioning
Special Section:
ADIPEC Technology
Showcase
Unconventional
Report:
OKLAHOMA

EXPLORATION & PRODUCTION
W O R L D W I D E C O V E R A G E
NOVEMBER 2019
VOLUME 92 n ISSUE 11
A HART ENERGY PUBLICATION www.HartEnergy.com
INDUSTRY PULSE
Structural integrity
management data help
decommissioning
8
REGIONAL REPORT
Australia bustling with
exploration and discovery78
COVER STORY: DIGITAL TRANSFORMATION
BASIN MODELING
50 Minimizing the effects of fracture hits using
real-time designs
CEMENTING ADVANCES
52 Modern cementing for today’s
horizontal wells
54 MPC in narrow pressure windows
FRACTURE FLUID OPTIMIZATION
56 Next-generation green friction reducer
58 A clean approach to radioactive
waste management in hydraulic
fracturing operations
EMISSIONS MANAGEMENT
60 Advances in technology enable
engineered emissions controls
DECOMMISSIONING
62 Driving down the dollars
64 Avoiding demolition dangers through
effective planning
SPECIAL SECTION:
ADIPEC TECHNOLOGY SHOWCASE
66 E&P highlights some of the latest
technologies that will be featured at the
2019 Abu Dhabi International Petroleum
Exhibition and Conference (ADIPEC).
76
UNCONVENTIONAL REPORT:
OKLAHOMA
Digital transformation:
in progress18
The strategic path to digital
transformation
20
Putting Big Data to work for
offshore insights
24
Moving past the hype at
Pluto LNG
32

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DEPARTMENTS AND COMMENTARY
ABOUT THE COVER The oil and gas industry’s digital transformation
is underway, potentially saving the industry $100 billion in the process.
Left, shifting market winds are keeping Oklahoma operators swaying,
but they are bending, not breaking as they stand their ground. (Cover
image courtesy of archy13/Shutterstock.com; Left photo by Jennifer
Presley, Hart Energy; Cover design by Felicia Hammons)
AS I SEE IT
Permission to fail 7
MARKET INTELLIGENCE
Three blasts from the past 12
DRILLING TECHNOLOGIES
Waste not, want not 15
COMPLETIONS & PRODUCTION
Can the industry meet the ‘challenge of a generation’? 17
SHALE SOLUTIONS
Recent trends in perforating for limited-entry stimulation 36
Unconventional diagnostics for unconventional wells 40
OPERATOR SOLUTIONS
Subsea compression: developing solutions to keep gas flowing 42
Isolate vertical movement resulting from heave 46
TECH WATCH
Optimizing production of mature waterflood assets with physics-based AI 85
Ensuring the four-way match 88
TECH TRENDS 90
INTERNATIONAL HIGHLIGHTS 92
ON THE MOVE/INDEX TO ADVERTISERS 94-95
LAST WORD
A value-chain approach to reducing emissions 96
COMING NEXT MONTH The December edition of E&P will be our special 2020
Unconventional Yearbook issue. Chapters will include an overview, key players, technolo-
gy, logistics, environment and production forecast. As always, while you’re waiting for your
next copy of E&P, be sure to visit HartEnergy.com for the latest news, industry updates and
unique industry analysis.

ONLINE CONTENT NOVEMBER 2019
Subscribe at HartEnergy.com/subscribeAVAILABLE ONLY ONLINE
Grim outlook for natural gas prices
By Susan Klann, Contributing Editor
Pipeline infrastructure coming online is expected to unleash associated
gas from the Permian Basin’s vast oil production, overwhelming the market,
a recent IHS Markit report says.
Undiscovered Marcellus, Utica natural gas resources soar
By Velda Addison, Senior Editor, Digital News Group
An assessment by the U.S. Geological Survey shows the estimated amount
of undiscovered technically recoverable natural gas jumped to 214 Tcf in
the Marcellus and Utica shale formations.
Artificial intelligence key to unlocking oil, gas sector’s
treasure trove of data
By Mark Venables, Contributing Editor
For the oil and gas sector to benefit from the vast amounts of data it
generates each day, it needs to collect, sort and analyze these effectively
and in a time-efficient manner. According to Ulisses T. Mello, director of
IBM Research, the secret to unleashing the value from these data is
artificial intelligence.
Well interaction data can foster ideal parent/
child relationship
By Mary Holcomb, Associate Editor, Digital News Group
Data are the gateway to mitigating parent/child well interference and
returning productivity, according to experts at the Well Interference Forum
at the DUG Eagle Ford conference.
ConocoPhillips driving data analytics, refracs in the Eagle
Ford Shale
By Blake Wright, Senior Editor, Oil and Gas Investor
ConocoPhillips executive Erec Isaacson offered the audience at the DUG
Eagle Ford conference several lessons that the company has learned
during its decade of operating in the basin.
Technology capital: OFS investment opportunity
By Travis E. Poling, Contributing Editor
Private-equity firms are seeking new technology for oilfield service assets.
Regulator urges Brazil to discuss potential for shale
gas activity
By Brunno Braga, Contributing Editor
Brazil could hold about 514 Tcf of recoverable shale gas resources
combined in the Parnaiba, Reconcavo, São Francisco, Paraná and
Parecis basins, according to ANP.
n Venado Oil & Gas on fast cycle times
Venado Oil & Gas CFO Branden Kennedy explained why the company
is sticking to its roots in the Eagle Ford and how that holds its own
against “Permania.”
n SilverBow rebranded, diversifying
Steve Adam, executive vice president and COO of SilverBow Resources,
discusses the company’s rebranding and acreage position in the
western Eagle Ford.
n Well interference, focus on drilling inventories
Peter Duncan, president and CEO of MicroSeismic, describes a few key
takeaways from the DUG Eagle Ford conference.
By Jessica Morales,Video Reporter, Digital News Group
VIDEOS:

Executive Editor JENNIFER PRESLEY
P: +1 713.260.6400 F: +1 713.840.0923
1616 S. VOSS ROAD, STE 1000
EPmag.com
Chief Technical Director RICHARD MASON
Senior Editor, Exploration RHONDA DUEY
Senior Editor,
Digital News Group VELDA ADDISON
Senior Contributing Editor,
Offshore JUDY MURRAY
Associate Editor,
Production Technologies BRIAN WALZEL
Assistant Editor ALEXA WEST
Group Managing Editor JO ANN DAVY
Associate Managing Editor ARIANA BENAVIDEZ
Corporate Art Director ALEXA SANDERS
Senior Graphic Designer FELICIA HAMMONS
Vice President of Publishing RUSSELL LAAS
Editorial Advisory Board
CHRIS BARTON
Wood
KEVIN BRADY
Highway 9 Consulting
MIKE FORREST
Consultant
GARRETT FRAZIER
Magnum Oil Tools
DICK GHISELIN
Consultant
OLGA KOPER
Battelle
PETER LOVIE
Peter M Lovie PE LLC
ERIC NAMTVEDT
Namtvedt Energy Advisors
DONALD PAUL
USC
KEITH RAPPOLD
Aramco Services
EVE SPRUNT
Consultant
SCOTT WEEDEN
Consultant
TOM WILLIAMS
RPSEA
Editorial Director
PEGGY WILLIAMS
Chief Financial Officer
CHRIS ARNDT
Chief Executive Officer
RICHARD A. EICHLER
HOUSTON, TEXAS 77057HOUSTON, TEXAS 77057
SEE IT
As I
1616 S. VOSS ROAD, STE 1000
P: +1 713.260.6400 F: +1 713.840.0923
JENNIFER PRESLEYExecutive Editor
7
Read more commentary at
HartEnergy.com
JENNIFER PRESLEY
Executive Editor
jpresley@hartenergy.comHartEnergy.com
Chief Technical Director RICHARD MASON
Senior Editor,
Digital News Group VELDA ADDISON
Associate Editor,
Production Technologies BRIAN WALZEL
Associate Editor FAIZA RIZVI
Activity Editor, LARRY PRADO
Digital News Group
Group Managing Editor,
Print Media JO ANN DAVY
Associate Managing Editor ARIANA HURTADO
Creative Director ALEXA SANDERS
Senior Graphic Designer FELICIA HAMMONS
Publisher HENRY TINNE
Editorial Advisory Board
CHRIS BARTON
Wood
KEVIN BRADY
Highway 9 Consulting
MIKE FORREST
Consultant
GARRETT FRAZIER
Magnum Oil Tools
RICHARD “DICK” GHISELIN, P.E.
Qittitut Consulting LLC
PETER LOVIE
Peter M Lovie PE LLC
ERIC NAMTVEDT
Namtvedt Energy Advisors
DONALD PAUL
USC
KEITH RAPPOLD
Aramco Services
EVE SPRUNT
Consultant
SCOTT WEEDEN
Consultant
TOM WILLIAMS
RPSEA
Senior Vice President, Media
E&P/Conferences
RUSSELL LAAS
Vice President, Editorial Director
PEGGY WILLIAMS
Chief Financial Officer
CHRIS ARNDT
Chief Executive Officer
RICHARD A. EICHLER
Permission to fail
The only way to fly is to first trust the fall.
Failure must be avoided at all costs, or so we humans are conditioned to
believe. It starts early: straight As on a report card from school, a perfect
10 in a diving competition or a first-place blue ribbon on a science project are
all examples of how failing to fail can garner praise or reward.
Failure can, however, be its own reward. Sure, it is one way to ensure the
swift ending of a painful project. It also can provide the inspiration needed to
step away from the old way of doing something by trying something new. How
many iterations of an invention are tossed onto the reject pile before success
is realized?
At Hart Energy’s DUG Eagle Ford conference in San Antonio, I had the
pleasure of speaking with a drilling engineer who had made the transition
from offshore to onshore operations. He mentioned how risk is perceived
in the industry as negative if success was not the initial result. It’s what I’ve
heard called the “everybody lines up to purchase Serial Number 002 if Serial
Number 001 was successful” rule of equipment manufacturing. He said the
industry needs to give itself permission to fail, citing the current revitalization
of the offshore oil and gas space as a key example.
The focus of this month’s issue is on the digital transformation underway
in the oil and gas industry, a transformation that is delivering real change to
the value chain. For example, it is inspirational to see the time-savings and
reduced “windshield” time that real-time field monitoring applications have
delivered. Quickly fading are the days when a field operator would drive from
well to well, checking fluid levels and pressure fluctuations on a strip chart
and more.
However, for every successful deployment of a monitoring system, there’s
significant time spent working through a process of trial and error to ensure
the system runs optimally. For every successful digital transformation project
scaled up and made operational, there are many that have stalled out. Of the
five steps McKinsey & Co. list for successful scale-up of a project, “making
technology your enabler, not your bottleneck” is the step that stands out most.
Multiple projects come to mind where the technology didn’t quite exist just
yet, but after a few years—or decades even—the technol-
ogy arrives and the bottleneck clears.
There’s no harm in failing, except in failing to start.
Make technology your
enabler, not your bottleneck.

8
industry
PULSE
November 2019 | E&P | HartEnergy.com
Yang Guo, Aaron Zigeng Du and Manish Patel, DNV GL
For aging assets that can no longer produce at eco-
nomically sustainable rates, identifying the right
time, method and model for decommissioning is consid-
ered by many as the decision to have a major impact on
achieving this target.
But to conduct decommissioning as efficiently and
cost-effectively as possible, there is now a growing con-
sensus that more can be done well before the late stages
of an asset’s life.
Explore SIM data for decommissioning
A structural integrity management (SIM) system is
widely adopted by many offshore operators to look after
their asset. Apart from capturing degradation, it records
changes in loading, modifications catering for new mod-
ules and all design documents used for the assets from
installation through to decommissioning.
The SIM system ensures that assumptions made in
the design phase are safely controlled and managed
throughout the life cycle of the structure. The assess-
ments, according to API RP 2SIM, are continuous with
interactions that broadly fall into four key areas: data
collection, data evaluation, SIM strategy and inspec-
tion program.
A data management system is the backbone of the
SIM system. It is set up for archival and retrieval of
structural data, inspection data and pertinent records,
and collected during design, construction and opera-
tional stages of an asset.
Comparing the common activities associated with
a decommissioning project, such as removal, lift and
transportation, there are many interrelated areas in the
SIM data management system where efficiency can be
targeted during an asset’s operational life.
Over the past two decades, DNV GL’s Fixed and
Floating Structures team has been responsible for more
than 30 offshore assets worldwide using the SIM system.
Weight control
For any asset to be decommissioned, adopting and
maintaining a good weight control procedure as early
as possible can be vital in choosing the right decommis-
sioning method, avoiding schedule delays and prevent-
ing cost escalation.
For instance, when the lifting methodology needs to
be developed and the estimated weight of an asset is
close to the capacity of the crane or the removal ves-
sels, the completeness and credibility of existing weight
records can play a major role during the decision-mak-
ing process.
Any proposed weight change needs to be verified to
ensure the installation remains safe within the allowable
limits. It is not unusual that some small weight changes,
once safely approved, are not recorded properly in a
central weight database, either because the extra weight
is considered trivial, hence making little impact to the
overall center of gravity, or simply due to the noncom-
pliance of an established procedure.
Minor changes once deemed inconsequential can
accumulate and have a significant impact on the overall
center of gravity, which is crucial for offshore lifting
Structural integrity management data
help decommissioning
A SIM system ensures that assumptions made in the design phase are safely controlled
and managed throughout the life cycle of the structure.
The assessments are continuous with interactions that broadly
fall into four key areas. (Source: DNV GL)

9
industry
PULSE
HartEnergy.com | E&P | November 2019
and transport operations. If many unregistered items
are identified, without a proper record, severe delays
can be expected. Therefore, it is necessary for a clear
weight change procedure to be established for offshore
installations and for all weight changes to be registered
promptly and correctly.
If neither design nor installation records are avail-
able, obtaining the exact weight of certain topsides
items on offshore facilities can be practically impos-
sible. Weight allowances are introduced to provide
a certain degree of flexibility throughout the deci-
sion-making process. Such figures can vary signifi-
cantly between 5% and 15% of the proposed weight.
A robust weight control record would help this con-
tingency to lean toward the lower end, indicating sub-
stantial cost savings.
DNV GL’s latest code of practice for marine removal
operations provides guidelines on the level of allowance
to be introduced, in line with the details and sources of
information available.
Knowledge of structural conditions
The inspection program in the SIM system details work
scopes to obtain quality inspection data, which show
the as-is structural conditions with structural anomaly
details. While several codes of practice are available,
what is less common is a sound anomaly management
system to follow up on those identified variances.
All offshore assets under the care of DNV GL’s Fixed
and Floating Structures unit have a centralized anomaly
database that records the details of all historical anom-
alies. During the operation of the asset, this database
has the benefits of monitoring the evolving history of an
anomaly and feeding into the development of regular
inspection plans.
As an example, during discussions on the removal
lifting method for a North Sea jacket platform,
various possible lifting scenarios were considered
against the cost and schedule. Without the existence
of a well-kept anomaly database, the asset owner
would need to commission and wait for the results

10
industry
PULSE
of predecommissioning survey findings, which can
cause inefficiency.
For integrity issues that are difficult to be spotted from
a topside decommissioning survey, an anomaly database
is a useful guide for any decommissioning project to
minimize the number of unwelcome surprises.
For instance, loose bolts for a section of a J-tube close
to the seabed were recorded in the anomaly database
but missed from the commissioned subsea survey. The
reality is, no matter how thorough a decommissioning
survey is, there is always a possibility of missing certain
issues that may become critical during the incoming
decommissioning operation. This margin of error can
be reduced by a properly maintained inspection data
and anomaly database, saving hundreds, if not more
man-hours.
Information management
Given any aging asset’s long service life, a SIM service
provider, along with its understanding of the historical
and ongoing issues concerning the weight, is well-posi-
tioned to provide help in identifying any miss-
ing or inconsistent information that may affect
key decisions.
Asset-specific knowledge, together with
the weight database, can help minimize the
efforts associated with weight reviews and off-
shore surveys.
Even if all information is well maintained
and available, to fully digest and then prepare
it into a list of actions requires an uncertain
length of time, which can be unfavorable. The
SIM provider can expertly justify and prioritize
the required mitigation measures.
The dynamic nature of offshore operations
means all aging assets may have experienced
substantial modifications. From a decom-
missioning point of view, SIM providers can
help verify the records of all implemented
changes and identify key information that is
relevant to the decommissioning exercise.
The other is to review, justify and close out
all incoming changes as well as make simul-
taneous updates to the weight database and
structural model. Therefore, an up-to-date
asset profile is always maintained.
Reaping the beneﬁt of the digital age
More than 400 oil and gas fields have stopped
producing in the last five years, and analysts
expect $32 billion to be spent on decommis-
sioning to 2025.
Digital innovation through artificial intelligence, auto-
mation and machine learning are expected to play a
stronger role in decommissioning activity in the future.
DNV GL has been working with Rolls-Royce and the
Norwegian University of Technology Science to fully
explore the idea of digital twins and develop a cloud-
based virtual representation of marine assets.
The creation of a global weight library is also under-
way to provide a valuable benchmark tool for decom-
missioning weight assessments. This will be available on
Veracity, an open and secure platform built by DNV
GL, facilitating the exchange of datasets, APIs, applica-
tions and insights.
References available.
Have a story idea for Industry Pulse? This feature looks at
big-picture trends that are likely to affect the upstream oil
and gas industry. Submit story ideas to Group Managing
Editor Jo Ann Davy at jdavy@hartenergy.com.
Data Management System
Design
Data
Drawings
Design Basis
Design
Reports
Structural
Anaylsis Models
& Reports
Weight Report
Metocean
Data
Soil Data
Construction
Data
Fabrication
Records
Installation
Records
Material Test
Certificates
Operational
Data
Inspection
Data
Weight
Change Data
Equipment
Updates
Structural Repair
& Modification
Monitoring
Data
Accidental
Events
Natural
Changes
Scour
Marine
Growth
Corrosion
Fatigue
Catastrophe
Events
Climate
Changes
External
Changes
Regulatory
Changes
Performance
Standards
Changes
This diagram showcases a typical data management system, which is the
backbone of the SIM technology. Note, possible data used for decommissioning
are highlighted with a red box. (Source: DNV GL)

12
market
INTELLIGENCE
Richard Mason, Chief Technical Director
This one is a blast from the past.
It is Project Gasbuggy, or an Atomic Energy
Commission experiment in conjunction with the El
Paso Natural Gas Co., and the U.S. Bureau of Mines
and Department of the Interior to fracture stimulate
the Lewis Shale for tight formation gas in Rio Arriba
County, N.M., 55 miles east of Farmington.
Stage count? One. There was no proppant. Instead
the test was a 29-kiloton nuclear warhead detonated
in December 1967 at 4,240 ft below the surface. The
nuclear device was twice as large as the bomb used
on Hiroshima, Japan, during World War II. As is
usual with fracture stimula-
tion, there was a seismic array
to track the Gasbuggy event
with seismic monitoring
extended out hundreds of
miles from the test site.
Worries about a potential
nationwide energy shortage involving natural gas
served as a rationale for the project. New Mexico’s
Project Gasbuggy was part of Project Plowshare,
or an effort to repurpose nuclear weapons for
peaceful application that originated in 1957. The
power of nuclear energy was proposed as a solution
for extracting tight formation gas. In all, Project
Plowshare featured three tests, including the larger
and more widely known test at Project Rulison east
of Grand Junction, Colo. The third and last test
occurred at Rio Blanco, Colo.
In theory, the detonations would create artificial
cavities for the accumulation of tight formation nat-
ural gas. This unusual program was an early day the-
matic precursor to the horizontal/directional drill-
ing and multistage fracture stimulation treatment
that has boosted U.S. natural gas supply to levels well
beyond domestic consumption.
It is also an illustration that the concept of fracture
stimulation for hydrocarbon production has existed in
various forms for decades and incorporated different
techniques reflective of the technology of the time.
In the early days, stimulation was part of an openhole
completion that used explosives, such as nitroglycerin,
delivered via torpedoes assembled on the rig platform
and lowered by wireline to the pay zone.
New Mexico’s Project Gasbuggy was the first of
three nuclear experiments. The detonation created
a 78-ft cavity that collapsed into a rubble-filled chim-
ney. Scientists drilled a borehole in 1968 and per-
formed gas tests regularly until 1976, at which point
the project moved to site restoration.
The second test, Project Rulison, occurred 50
years ago in September 1969 on Battlement Mesa
in Garfield County, Colo., and incorporated a
43-kiloton device, three times the size of the nuclear
device used at Hiroshima.
Rulison also generated a
70-ft cavity and another
rubble-filled chimney upon
collapse. Reentry drilling
began in April 1970 and pro-
duction testing for natural
gas occurred through April 1971, at which time the
project was abandoned for remediation.
At Rio Blanco, about 50 miles north of Grand
Junction, Project Plowshare moved to multistage
fracturing when three 30-kiloton devices were deto-
nated in May 1973 in the upper Williams Fork and
lower Fort Union formations, followed by a reentry
well to the top of the chimney in 1973 and a second
well to the bottom of the chimney in 1974. In all,
the site produced 125 MMcf of natural gas.
Of note, the three nuclear devices were detonated
almost simultaneously and created three indepen-
dent cavities that were not connected. It turns out
the fracture stimulation zone was confined to the
area around each detonation and did not extend
out as far as predicted.
While Project Plowshare generated accessible nat-
ural gas, the high temperatures cooked the gas,
lowering its Btu content. It was the second issue
that brought the project to a close. The natural gas
was radioactive.
Three blasts from the past
Experimental nuclear detonations 50 years ago served as early day precursors to the
horizontal drilling and multistage fracture stimulation methodology that has boosted U.S.
natural gas supply to levels well beyond domestic consumption.
Fears of a natural gas shortage
created innovative early efforts
to develop tight formation gas
via fracture stimulation.

15
drilling
TECHNOLOGIES
While “check the flashlight batteries” is a com-
monly heard phrase before a severe weather
event hits, it is “don’t waste the batteries” that is heard
during the event. Great strides have been made in
the development of energy storage systems, from the
first voltaic pile that consisted of pairs of copper and
zinc discs stacked on top of each other, separated
with a layer of brine-soaked cloth of the early 1800s,
to today’s pink Energizer bunny that keeps going,
going, going. With the deployment of a hybrid energy
storage system, Transocean can now power one pro-
cess with the excess energy stored from generating for
another process.
The system is now operational on the Transocean
Spitsbergen, which is engaged in drilling operations
at the Snorre Field in Norway, according to a press
release. The patented hybrid power system was
“developed in partnership with Aspin Kemp
and Associates, reduces fuel consumption
and increases a dynamically positioned
rig’s station-keeping reliability by
capturing energy generated during
normal rig operations that would
otherwise be wasted, and storing it
in batteries. This energy is then used
to power the rig’s thrusters,” the press
release stated. A 14% reduction in fuel
use during normal operations is targeted,
which leads to a significant reduction in NOx
and CO2 emissions.
“This first of its kind hybrid power upgrade
will further enhance the reliability of our
operations, while simultaneously reducing fuel con-
sumption, operating costs and our environmental foot-
print,” said Transocean’s President and CEO Jeremy
Thigpen in the release. “We are pleased and proud to
work alongside Equinor to jointly identify and imple-
ment more efficient and sustainable technology to
deliver high-value wells to the industry.”
The company’s investment in the technology is
funded in part through fuel-saving incentives in its
contract with Equinor and by the Norwegian NOx
Fund, according to the release.
Thigpen touched on the safety benefits provided
by the hybrid power system in his presentation at Bar-
clay’s 2019 CEO Energy Power Conference in Septem-
ber. “We’re storing energy in these batteries, such that
if we do have a blackout at any point in time, we’ll
have enough power to maintain station and control
the critical components on the rig,” he said. “And that
just ticks the box on every single front.”
Innovations like the hybrid power sys-
tem are what Thigpen referred to in his
remarks earlier this year at the Offshore
Technology Conference (OTC) in May.
He encouraged industry leaders in the
offshore drilling space to continue
focusing on opportunities to innovate.
To become more economically viable,
he noted that the offshore industry’s
continued focus on safety and improve-
ments in drilling efficiency can help reduce
costs and improve time to first oil.
“Innovation has been going on in the
industry for multiple years, ever since the
downturn. It has been quite healthy for the
industry,” he said during his OTC presentation. “It has
forced innovation across the industry. We have been
innovating, whether it has been reorganizing our busi-
ness so we’re more efficient, streamlining automation
and processes, or changing commercial models.”
Innovative thinking and the industry’s willingness to
apply those innovations will continue to carry it into
and through the next decade. By not wasting
those opportunities, the industry
is providing for the wants and
needs of many.
Waste not, want not
Innovation delivers first deployment of a hybrid energy storage system aboard a
floating drilling unit.
HartEnergy.com
JENNIFER PRESLEY
Executive Editor
jpresley@hartenergy.com
(Source: petrmalinak/
Shutterstock.com)
release. The patented hybrid power system was
“developed in partnership with Aspin Kemp
and Associates, reduces fuel consumption
use during normal operations is targeted,
which leads to a significant reduction in NOx
just ticks the box on every single front.”
Innovations like the hybrid power sys-
tem are what Thigpen referred to in his
remarks earlier this year at the Offshore
Technology Conference (OTC) in May.
To become more economically viable,
he noted that the offshore industry’s
continued focus on safety and improve-
ments in drilling efficiency can help reduce
costs and improve time to first oil.
“Innovation has been going on in the

17HartEnergy.com | E&P | November 2019
completions&
PRODUCTION
This year’s Society of Petroleum Engineers Annual
Technical Conference and Exhibition (ATCE) in
Calgary brought together more than 6,000 industry
leaders from companies from around the world to
share ideas and technologies. But without question,
the overriding theme was how the oil and gas industry
will meet the demands of current and future genera-
tions on environmental sustainability.
Speaking during the opening keynote on responsi-
ble energy development, Jackie Forrest, senior direc-
tor of research at ARC Energy Research Institute,
said the oil and gas industry is “facing the challenge
of a generation.”
Indeed the challenge is a substantial one. More
than 1 billion people globally are without reliable sup-
plies of energy. Leigh-Ann Russell, head of upstream
procurement and supply chain management for BP,
noted at ATCE that energy demand will grow by one-
third by 2030.
“It’s a dual energy challenge,” Russell said. “How
do we provide the oil and gas the world needs more
cleanly and more efficiently, and at the same time
break down emissions?”
There is a third component to that challenge: doing
those things economically and in a way that makes a
company a profit and pleases shareholders. Paying
back investors while maintaining a social license to
operate is a tricky balancing act.
However, Jeanne-Mey Sun, executive of energy tran-
sition and clean energy solutions at Baker Hughes,
believes it doesn’t have to be an either/or proposi-
tion. In January Baker Hughes announced its effort
toward achieving net-zero carbon emissions. Accord-
ing to the company, that commitment includes “a
50% reduction in CO2-equivalent emissions by 2030
(compared to a 2012 baseline) and net-zero CO2 emis-
sions by 2050.”
In a conversation with E&P at ATCE, Sun described
a number of technologies designed to reduce carbon
emissions that Baker Hughes has deployed.
Lumen is a methane monitoring and inspection
system that works as a stationary tool or a drone
that helps identify and quantify methane leaks and
concentrations in the air. The company’s modular
gas processing system treats and fractionates flared
natural gas that otherwise would be flared into the
atmosphere and uses the gas in other products. Sun
said that in a project in Iraq, the system has helped
avoid flaring of 200 MMcf/d, which translates to 5.7
MMtons/year.
Baker Hughes’ Becker Zero-Bleed Valve System
captures gas escaping when valves actuate and
re-pipes the gas back into the system. Sun said
the system can capture 25 tons of CO2 equivalent
per year.
“We’ve taken a look at the emissions that occur all
through the value chain,” she said. “We’ve quantified
that, and we have an understanding of the types of
emissions and the types of activities that drive those
emissions. And all of our solutions are designed to
address those drivers.”
In addition to innovative technologies capturing
carbon emissions before they are released into the
atmosphere, incentives are emerging for carbon cap-
ture, utilization and storage.
Any energy transition will be a methodical one, and
oil and gas will play a role in the energy mix of the
future. But if the oil and gas industry is to meet the
challenge of a generation, and not fail future genera-
tions, it will take the industry coming together as a
whole. Discussions such as those had at ATCE are an
important step in the process, but actu-
ally deploying successful technologies
that reduce emissions will prove to be
the ultimate test.
HartEnergy.com
BRIAN WALZEL
Associate Editor,
Production Technologies
bwalzel@hartenergy.com
Can the industry meet the
‘challenge of a generation’?
Industry leaders are making responsible energy development a priority.

COVER STORY:
DIGITAL TRANSFORMATION
18 November 2019 | E&P | HartEnergy.com
The industry’s efforts to reinvent itself
in a digital world are underway.

COVER STORY:
(Source: archy13/Shutterstock.com;
design by Felicia Hammons)
19HartEnergy.com | E&P | November 2019
Jennifer Presley, Executive Editor
One hundred billion dollars—that’s the
amount that the oil and gas industry could
save through digitalization, according to a
recent Rystad Energy report. To unlock these
potential savings, E&P and service companies
are transforming to meet energy demands.
According to the report, about 10% of the
$1 trillion spend on opex in 2018 could be
erased through the use of more efﬁcient and
productive operations possible with automation
and digitalization.
“In addition to cost savings, digitalization
initiatives can also increase productivity
by increasing uptime, optimizing reservoir
depletion strategies, improving the health,
safety and environment of workers and
minimizing greenhouse emissions—all of
which have significant value creation,” said
Audun Martinsen, head of oilfield services
research for Rystad, in the report.
The digital transformation is in progress, as
new digital products are rapidly making their
way into the marketplace. For example, one
of the largest digitalization initiatives to date,
according to Rystad, is the collaboration by
Chevron, Schlumberger and Microsoft to obtain
meaningful insights from multiple data sources
across the upstream and midstream sectors (see
details on pg. 90).
This month E&P’s cover stories examine how
operators, technology innovators and govern-
ment researchers are furthering the progress of
the digital transformation.

COVER STORY:
Faiza Rizvi, Associate Editor
During the past decade, digital transformation
emerged as a driver of revolutionary business prac-
tices in the energy industry, empowering organizations
with unparalleled opportunities. Upstream companies are
catching up on the digitalization uptake, integrating tech-
nologies in their field operations, including the Industrial
Internet of Things (IIoT), cloud computing and artificial
intelligence. According to a recent study by Rystad Energy,
the upstream industry can save up to $100 billion through
automation and digitalization initiatives in the 2020s.
Despite the huge potential, Deloitte’s digital maturity
index shows that the oil and gas industry is lagging behind
all the other sectors in the digitalization race. EY estimated
that only 10% to 20% of the industry is digitalized.
“We’re still at a critical stage because even though
many companies have gained the vision to pursue digi-
tal transformation, they don’t know where to start and
can get frustrated,” said Stuart Harris, group president
of Emerson’s newly formed digital transformation busi-
ness line, speaking at the recent Emerson Global Users
Exchange event in Nashville, Tenn. “We define digital
transformation as smart, connected technologies used
to solve problems, usually involving changes in business
practices. Digital transformation must be guided by
specific problems, but it won’t work unless people are
engaged and appropriate technologies are adopted.”
Harris noted that the challenge most companies face
when conducting digital pilots is trying to scale those
pilots. “Those who start with technology first tend to get
frustrated because a return on investment [ROI] can be
difficult to achieve [with that approach],” he said. “That’s
why it’s important to have a focus, know the metrics of
success and measure your performance against those.”
Taking a step further
Recognizing the need for a dedicated organization
focused on digital transformation technologies and
The strategic path to
digital transformation
Energy companies work to identify opportunities, challenges and
methodologies of new technologies.
FIGURE 1. By engaging the five competencies of digital transformation, companies will unlock the potential of employees and sustain
top-quartile performance. (Source: Emerson)

21
programs, Emerson recently announced its new Digital
Transformation business line. The new department will
bring together critical resources to help manufacturers
develop and implement pragmatic digital transformation
strategies that deliver top-quartile performance, accord-
ing to a press release. The $650-plus
million business combines existing
expertise in consulting, project execu-
tion, smart sensor technologies, data
management and analytics, which are
all a part of Emerson’s Plantweb digital
ecosystem. The organization will help
customers establish a clear vision for
digital transformation and gradually
execute and realize measurable results
at each step of their journey.
Speaking at a press conference during
the Emerson Global Users Exchange
event, Harris identified automated
workflow, decision support, workforce
upskilling, mobility and change manage-
ment as the five competencies of digital
transformation that companies need to
unlock the potential of employees and
sustain top-quartile performance (Figure
1). He also pointed out that the three
critical success factors of digital transfor-
mation are technology decisions driven
by business outcomes, scalable approach
guided by vision instead of doing it all
at once and technology investments that
also are seen as investments in people.
Harris pointed out that while some
companies are executing pilot pro-
grams and seeing early benefits, every-
one needs to connect their businesses
and digital transformation strategies
with practical applications. “Strategy
and business cases are what come first
with digital transformation—not the
technology. Once ROI is captured for
a solution, it can be scaled across the
whole enterprise,” he said.
On a broader scale, once digital
transformation initiatives define the
goals and identify challenges and
opportunities, companies must develop
proofs of concept and pilot projects
that can demonstrate some of that
much-needed ROI. This encourages
further commitment and investment
as well as helps participants to scale up their solutions to
many more applications that can achieve similar advan-
tages and benefits.
“Many digital transformation pilots can get started for
$50,000 to $100,000 in one or a few processes, prove
COVER STORY:

themselves and then scale up to many processes and
save millions or tens of millions of dollars,” Harris said.
“We’ve learned that digital transformation is urgent
because it can help users achieve top-quartile perfor-
mance, add two weeks of uptime, cut maintenance inci-
dents in half or reduce safety incidents by 30%.”
Empowering the workforce
Energy companies face a number of challenges on
their path to digital transformation, many of which are
attributed to the aging workforce. Moreover, several
studies reveal that since the industry is viewed as envi-
ronmentally unfriendly and technologically backward by
the future workforce, companies are in danger of losing
fresh digital talent to other sectors.
Beyond specifying problems, goals and technologies,
digital transformation is impossible without the deep
and continuous engagement of people, especially those
on the plant floor, Harris explained.
“Executive support is essential and information tech-
nology [IT] has to be involved, but it’s most important
for the operations folks to be engaged because they
have the domain knowledge about where it’s best to
apply digital transformation,” he said. “Every functional
group can contribute and take on new roles. They can
serve as bridges connecting lines of stakeholders or
develop internal academies to train colleagues on how
to use new analytics tools.”
Emerson provides technical resources and curric-
ulum development to more than 350 educational
institutions to help students develop the skills that
employers need. Recently Emerson collaborated
with San Jacinto College to help design, equip and
provide training tools for the college’s Center for
Petrochemical, Energy and Technology, which is
designed to empower students of all levels with the
skills and training needed to support careers in the
evolving petrochemical and refining industries.
Digitizing upstream
For the upstream industry, the advantages of IIoT
applications lie in creating value through an inte-
grated deployment strategy, which can potentially
increase production, reduce downtime, limit emissions
and improve safety.
During an upstream panel discussion at the Emerson
Global Users Exchange event, executives of major oil
companies reported that legacy assets, workforce attri-
tion, political climate and cybersecurity are the main
challenges that slow down IIoT and digitalization.
However, they agreed that a well-planned and careful
approach can solve the majority of the issues and help
companies in delivering value through digitalization.
“We had 300 wells, which we couldn’t monitor
remotely, so whenever there was a drop in production,
we had to send someone out in a helicopter,” said
Todd Anslinger, control systems engineer of the IIoT
Center of Excellence at Chevron. He said it took 37
helicopter trips and two weeks to check those wells,
and identify and resolve the issues.
“Since we added Emerson transmitters and Digi
gateways that transfer 4 to 20 milliamp signals to the
cloud via LTE cellular wireless networking, we can
monitor when they go below a certain output pressure,
for example, and determine if they really need a visit
or not. We estimate to save about $25,000 per event,”
Anslinger said.
One of the main advantages of the IIoT and digitali-
zation in general is that users can collect more signals
and data as well as get them much more often. “With
our wireless devices, we can check process or equip-
ment status every hour. For instance, when we inject
CO2
and water into wells, we can see the downhole
pressure more frequently and make better decisions,”
Anslinger said.
Occidental Petroleum implemented the Internet of
Things (IoT) last year and began by proving its viability
and value, researching available IoT platforms, deter-
mining device connections and validating how to create
software containers and analytics, according to Jim Sage,
IT principal for emerging technology at Occidental.
“We learned that it’s important to determine the IoT-
readiness of the larger organization, so over the last
year and a half, we got ready with a cloud computing
that we could plug our IoT solution into. Now, we can
connect edge-computing devices to help control shut-
down devices,” Sage said.
According to Tim White, asset management director
at Valaris (formerly Ensco Rowan), “When events hap-
pen offshore, managers onshore want to know what’s
happening. However, it can be risky to have calls com-
ing in every hour, so we’ve been trying to correlate our
data to better inform our rig managers, so they don’t
have to call as much.”
White added that Valaris will use its increased data
volume and speed to improve maintenance as well as
optimize operations. “One of our big goals is condi-
tion-based maintenance, and we know the IIoT will help
accomplish it as well as reduce staff and deploy ‘tiger
teams’ that can manage multiple rigs,” he said.
Gary Baxter, former production operations director
at EQT Corp., said the natural gas producer recently
COVER STORY:

23
implemented IBM Maximo asset management software
to help its supervisors and managers by showing pro-
duction data on their PCs and smart phones. “This solu-
tion got us involved with IIoT, but we soon found that
we needed 78 database revisions. We couldn’t do all of
them, so we had to revise and implement Emerson’s
ROC800 remote operations controller, which let us do
more analytics,” he said.
Returns on digital investments
New technologies typically involve heavy capital invest-
ments and extended supply chains.
Since new innovations also face scarce funding and
hesitation from higher management, executives at the
upstream panel discussion said IIoT and associated new
technologies must demonstrate their value quickly to
gain acceptance.
“We look to see financial benefits within one year
because if it’s two or three years, then it won’t get
funded because everyone assumes the technology is
going to change anyway,” Anslinger said. “Behavior
changes with familiarity and training, so it’s crucial to
show people what the IIoT can do for them, what dol-
lars and cents they can gain and that it’s cost-effective
to implement.”
In addition to returns, IIoT must also show it can
ease user workloads, White said. He explained that it’s
important to demonstrate the benefits of IIoT to senior
management and convince them that new technologies
can automate tasks and ease the workload of employees.
Adding to that, Sage explained that any effort to
get potential users accustomed to the IIoT can be
helpful because disruptive changes have been coming
so fast. “Most changes in process control and automa-
tion have been incremental, but what’s happening
now is a reallocation of people to learn the new skills
needed as we transition from previous methods to
those based on the IIoT. And once we connect to our
edge devices, the benefits of their data will start to
come in,” he said.
COVER STORY:

COVER STORY:
Abby Humphreys, Kelly Rose and the ORM Team, NETL
The Deepwater Horizon disaster in 2010 released
more than 130 MMgal of oil into the Gulf of Mexico
(GoM) over 87 days and is the largest accidental marine
oil spill to date. Teams of experts assembled to mitigate
the catastrophe, but rapid emergency response and con-
trol efforts were hindered by inadequate tools and large
uncertainties associated with this extreme offshore play.
The tragedy emphasized the need for tools to assess
risks and predict behaviors of a range of offshore engi-
neered-natural systems from the reservoir to the shore.
Offshore U.S. oil production in the GoM accounts for
16% of total U.S. crude production, and globally, off-
shore drilling accounts for less than 5% of the world’s
wells, yet accounts for 30% of total global oil produc-
tion. The efficiency and production from offshore wells
are notable; however, as offshore development contin-
ues to expand and venture into new territories, meth-
ods and resources to improve systemwide knowledge
and support planning, prevention and rapid response
needs for future spills are required to protect human
life and the environment.
The National Energy Technology Laboratory (NETL)
is one of 17 U.S. Department of Energy (DOE) national
laboratories and the only laboratory dedicated to fossil
energy research. NETL’s researchers work to develop,
integrate and mature technology solutions to enhance
the nation’s energy foundation and protect the environ-
ment for future generations. Ensuring the safe, effective
development of the nation’s oil and gas resources is a
key priority in this mission. The advances taking place
within NETL’s offshore research portfolio are available
to help reduce the likelihood of damaging geohazard-
induced events that are associated with offshore hydro-
carbon E&P. Additionally, these technologies can reveal
the economic potential of these domestic resources in
greater detail.
Modeling offshore risk
Developed by a team of geodata science researchers
at NETL, the Offshore Risk Modeling
(ORM) suite improves the prediction
and evaluation of offshore systems by
addressing key gaps in knowledge and
the need for spill prevention aligned to
data-computing solutions across time,
space or regions. Fundamentally, many
of the tools offered in the ORM suite
leverage Big Data and Big Data comput-
ing to help users assess local questions
(e.g., rig placement risks, geohazard
and reservoir property predictions)
using a “big picture” approach. Work-
ing with existing commercial tools and
software systems, this first-of-its-kind
suite provides a comprehensive frame-
work for future predictions, analyses
and visualizations to better inform
offshore hydrocarbon E&P, predict
the fate and transport of potential
spills, improve prediction of subsurface
Putting Big Data to work for
offshore insights
A modeling suite addresses key knowledge gaps to improve the prediction and
evaluation of offshore systems for improved spill prevention and more.
The ORM models and tools can be used in the rapid assessment of oil spill response
preparedness for the GoM. (Source: NETL)

properties for areas with no prior data and identify
regional vulnerabilities.
The NETL team designed the tools and models in
the ORM suite to be easily accessible to the industry,
regulators and scientists for a range of commercial-
and research-related efforts. The ORM suite comprises
digital applications that can be deployed directly on a
personal device, such as a desktop computer, laptop or
tablet, or run through a virtual cloud-computing frame-
work. All tools are available for download or web use.
In addition, there are instances of the ORM suite being
developed for specific users in an online, Dockerized
computing platform to offer greater portability and
utility, as the models and tools are maintained on one
server while data are hosted and/or streamed in real
time from authoritative sources.
ORM suite tools can handle large amounts of data in
the range of gigabytes to petabytes depending on the
scale of the analyses being performed, efficiently utilizing
millions of data from numerous sources. This makes the
ORM suite a comprehensive solution for providing pre-
dictions of potential hazards and mitigating challenges
faced during common offshore oil and gas activities.
When the tools and models are used either individ-
ually or together, the ORM suite can help the offshore
energy industry with worst-case discharge planning and
preparedness, evaluation of site-specific metocean geo-
hazards and improved prediction of subsurface proper-
ties for reserves and drilling calculations.
Components
The ORM comprises two data management and curation
tools and six analytical components that allow end users
to assess and combine data surrounding many environ-
mental, socioeconomic and geological factors. When
used together, the analytical tools provide more holistic
analyses that aid in predicting and preventing risks and
operational costs. The analytical tools included in the
ORM at present are noted below.
The Climatological Isolation and Attraction Model
(CIAM) is a quick prediction and response tool that
applies mathematical theories of dynamical systems and
metocean data, including real-time ocean current pat-
terns, to determine where oil and other particles in the
ocean (e.g., debris, hazardous waste and plankton) are
likely to be attracted or repulsed. CIAM offers offshore
commercial and scientific communities a novel and
efficient way to summarize big ocean current and/or
large wind data and generalizes previous approaches by
calculating transport patterns independent of where a
spill may originate.
The Blowout Spill Occurrence Model (BLOSOM) is
an open-source, comprehensive modeling program that
predicts the fate and transport of oil for hypothetical
and actual offshore spill events to support planning and
spill response preparedness needs. BLOSOM is the first
open-source oil spill and blowout model in 4-D, which
has been compared to and validated against traditional
and industry-applied spill models. Built upon a flexible
framework, BLOSOM consists of several modules to
help visualize and predict the scope of environmental
damage in the event of a blowout, which include behav-
ior in high-pressure environments, subsea dispersants,
gas and hydrate dynamics and other features as well as
utilizing knowledge of how particulates move through-
out all levels of the water column.
Cumulative Spatial Impact Layers (CSIL) is a geo-
graphic information system-based tool that rapidly iden-
tifies and quantifies potential socioeconomic and envi-
ronmental risk. The CSIL tool is capable of handling
multiple disparate datasets, can measure data density
and produce multivariable layers that identify vulner-
abilities within a given area. It can be used in concert
with other ORM tools to support planning, such as
ingesting BLOSOM simulation outputs and summariz-
ing the potential risks or response availability associated
with hydrocarbon events. The CSIL tool can be used to
assess onshore response capabilities to determine what
areas are at risk and how prepared emergency officials
are in the event of a spill.
The Spatially Weighted Impact Model (SWIM) is a
decision-support tool that incorporates relationships
among oil spill information, response availability and
potential risk. Users can apply weights to evaluate mod-
eled spill events based on potential impacts, the magni-
tude of the oil spill and response preparedness against a
“baseline” scenario, which might consist of what differ-
ent users consider to be worst-case events. This feature
allows users to rank and compare different scenarios
and come up with varying plans of action for planning
and response needs.
The Subsurface Trend Analysis improves the predic-
tions of subsurface property values using a combination
of geologic knowledge and advanced spatio-temporal
statistical methods. The approach leverages information
about geologic systems to improve prediction of subsur-
face properties critical for reserves calculations, explora-
tion and resource identification, geohazard prediction,
drilling safety and improved well design.
The Variable Grid Method communicates uncertainty
for data and model results, which is critical when utiliz-
ing multiple tools and approaches. The Variable Grid
COVER STORY:

Method tool provides the flexibility to
use different data types and uncertainty
qualifications, and it preserves overall
trends and patterns observed within the
data while enabling users to customize
the analysis and final product to meet
their needs and best communicate
results in an intuitive manner.
Two ORM applications support data
acquisition, curation and collaboration
useful to both the offshore and broader
fossil energy community. There has
been growing recognition of the value
and challenges associated with data
preservation, curation, management
and reuse, and the ORM team has been
addressing these needs for almost a
decade. This resulted in the building of
the Energy Data eXchange (EDX) and
the GeoCube to address data access,
curation and reuse challenges specific
to fossil energy and ORM users.
EDX is the DOE’s Office of Fossil Energy’s (FE) vir-
tual data library and laboratory. Launched in 2011 and
based on data access challenges identified during the
Deepwater Horizon spill response, FE’s EDX platform
is an online data curation and collaboration platform.
EDX fosters and supports the life cycle of data for FE
users and includes public and private resources for
FE teams. Presently, EDX curates products from fossil
energy research, including data, tools and models, and
it supports select virtual analytical needs of FE users,
such as those performed by the virtual ORM suite.
GeoCube is a custom web-mapping application hosted
via EDX that allows users to quickly view and visualize
spatial data, download resources, identify overall trends
and patterns in the data and share these discoveries
with others. The application allows users to upload and
visualize their own data in a user-friendly manner as
well as spatial datasets served via the EDX platform.
Capabilities
The ORM suite can be applied to improve safe and
efficient operations in offshore systems for a range of
stakeholder needs.
Simulating 4-D oil spill and blowout scenarios: BLOSOM
can model multiple hypothetical and historic oil spill
simulations at various locations and times. BLOSOM
simulations can be coupled with the CIAM to enhance
and validate the predicted fate and transport of oil
spills. BLOSOM does not presently pull data through
EDX, although one could host BLOSOM-compatible
data on EDX for download, which can be visualized
through GeoCube. Together, BLOSOM and CIAM-
coupled models offer an improved prediction of the
fate of oil spill particles, which offers critical informa-
tion to inform oil spill prevention, response and pre-
paredness efforts.
Identifying critical subsurface characteristics: Various sub-
surface conditions can negatively impact hydrocarbon
exploration safety and costs. The Subsurface Trend
Analysis can be used to define potential hazards based
on geologic data and expertise to improve predictions
of subsurface characteristics that may impact drilling,
such as areas of overpressure. The uncertainty associ-
ated with these predictions can be quantified and visu-
alized using the Variable Grid Method. Together, the
Subsurface Trend Analysis and Variable Grid Method
help decision-makers pinpoint areas where overpres-
sure might be present and make confident decisions
regarding mitigation strategies that ensure safe operat-
ing conditions.
Evaluating response preparedness: CSIL can be used to
summarize and visualize oil spill fate and transport
from BLOSOM with the spatial and temporal distribu-
tion of socioeconomic and environmental variables.
Overlapping these data with CSIL helps identify gaps in
response infrastructure readiness. SWIM can compare
and rank multiple scenarios to strategically identify
regions where additional prevention equipment is
needed to improve oil spill preparedness.
COVER STORY:
NETL’s open-source BLOSOM is capable of following the fate and transport of
hydrocarbon discharge events from an array of anthropogenic and natural sources.
(Source: NETL)

Assessing offshore infrastructure integrity: Data from EDX
and GeoCube have been leveraged to identify and visu-
alize historic pipeline and platform failure incidents.
CSIL has summarized metocean data (e.g., wave height,
current velocity and wind speed) to statistically evalu-
ate the effect of extreme environmental conditions on
infrastructure integrity over time.
Implications
The approach of the ORM suite is a paradigm shift from
how the industry and regulators traditionally evaluate
the offshore environment. In the past, local analyses and
smaller-scale datasets were the primary focus in inform-
ing decisions. Industry and regulators have convention-
ally based their models on limited data or information;
however, because of the advanced, data-computing
nature of the tools in the ORM suite, end users now
have access to streamlined, analytical results that incor-
porate larger and more diverse spatiotemporal systems
than conventional models or methods can afford.
Response to the Deepwater Horizon blowout met chal-
lenges in critical areas. Traditional response resources,
such as booms, oil skimming methods and dispersants,
were used in cleanup efforts, but oil traveling under-
neath the sea surface at such extreme water depths posed
new, unforeseen and lasting challenges to both contain-
ment and fate analyses. Predictions of oil transport were
inadequate due to limitations of spill models available at
the time, leading to oil materials such as tarballs
washing up in unforeseen locations. This had
immediate and long-lasting impacts on tourism
and other ocean-dependent industries in the
area. The efficiency of response operations also
was affected by a lack of knowledge about the
geohazards, subsurface reservoir properties and
Deepwater Horizon well infrastructure pre- and
post-blowout, which hampered efficiency and
confidence in subsea and subsurface spill con-
trol efforts.
The tools of the ORM suite were designed to
aid in preventing these and other environmen-
tal hazards from occurring in similar spill sce-
narios through better prediction methods and
risk assessment. With more information on oil
fate and transportation, as well as emergency
response preparedness and geologic properties
from drilling operations, many of the chal-
lenges from the Deepwater Horizon spill may
have been prevented or had their impact dras-
tically reduced.
Outside of spill events, similar data and mod-
eling challenges impact daily operations, planning and
decisions by regulators and the industry alike. While
the capabilities of the ORM suite were influenced and
informed by the lessons learned from the catastrophic
Deepwater Horizon event, they also address daily, “nor-
mal” challenges, leveraging Big Data to inform small-
scale needs and preventing vulnerabilities.
While initially developed with a focus on the GoM,
the capabilities of the ORM suite are not limited to that
region and have been extended to other U.S. and inter-
national waters. The ORM suite is flexible and can be
adapted and integrated into other models to suit end
users’ needs and account for differences in location.
In practice, several components of the ORM have been
leveraged to the DOE and external users to assess oper-
ational and environmental risks for regions around the
U.S., including offshore Southern California and the
Gulf of Alaska. Components of the ORM also have been
utilized beyond the U.S., including users in Australia,
Brazil, India, Mexico, Spain and the U.K.
By applying novel and efficient methods to cross-exam-
ine data across space and time, the ORM suite supports
predictive analyses for safer, more prudent efforts and
rapid-response, real-time assessments. The ORM suite is
able to adapt from one need to the next, filling knowl-
edge gaps, reducing resource uncertainty, assessing geo-
hazard potential and supporting decision-making,
thereby improving operational efficiency and safety.
COVER STORY:
Three tools from the ORM suite—BLOSOM, CSIL and SWIM—have been streamlined
internally to model worst-case hydrocarbon release scenarios and account for
environmental and socioeconomic impacts, with resulting simulations ranked on
user-applied weights. (Source: NETL)

COVER STORY:
Mark Venables, Contributing Editor
Like most oil and gas majors, Australia’s Woodside
Energy is grappling with how best to harness the
myriad opportunities presented to the oil and gas sector
by artificial intelligence (AI). Unlike some, however,
Woodside has some projects underway that are already
delivering significant results.
One of the people charged with overseeing this
transition is Alison Barnes, head of robotics. She is
tasked with leading the efforts to incorporate the use
of intelligence systems on Woodside’s new assets that
are being designed at various engineering houses
around the world. For the role, Barnes leans heavily
on her background as an instrumentation and con-
trols engineer.
“I lived up in Karratha in northwest Australia for sev-
eral years, working on LNG plants and supporting our
gas assets,” she said in a presentation at Offshore Europe.
“I was then moved from production into technology to
head up the robotics lab, and now I get to execute the
executive’s vision for using digital technologies.”
What can AI do?
There are many interpretations of what AI entails, but
Barnes likes to define it as the ability to mimic human
intelligence and/or behavior.
“Many of the examples are familiar in our daily
life, and a lot of what the industry is applying is still
very much in that narrow band isolated to specific
parameters and context,” she said. “The key is obvi-
ously moving past all the hype and making it useful
and applicable. We have all seen the shiny brochures,
the presentation packs, the emotive news articles, but
hopefully, some, like me, have had a chance to play
with this technology.”
Woodside already uses AI in many business processes,
much of it in collaboration with the IBM Watson deep
learning AI platforms. “In implementing several Watson
systems, we discovered that we needed a system that could
work across and outside them. Sometimes it may not be
clear which system holds the information we need, or
related information lives in several systems,” Barnes said.
This led to Woodside developing its own cognitive
assistant, Willow. “Our data science team also works
directly with asset engineering and operations to build a
Moving past the hype at Pluto LNG
An Australian operator is putting AI to good use in its flagship facility.
Woodside Energy has operated the
Pluto LNG facility since its startup in 2012.
(Source: Woodside Energy)

33
range of statistical and analytics tools, using live stream-
ing data from our facilities,” Barnes said. The Maximum
Possible Production tool Pluto LNG uses to compare
current and historical performance is in use to maxi-
mize daily production.
The Maximum Possible Production tool runs every
10 minutes and creates a model that looks at all the
uncontrollable variables and compares them to the
last time they came together in that way. With these
data, the tool advises the operator what it can do with
all the controllable variables. Woodside also has a sur-
veillance hub for engineers, which collects data from
thousands of tags in the plant so they can monitor
and look at specific plant and processes so they can
improve maintenance reference plans and better mon-
itor equipment performance.
Adding intelligence to Pluto LNG
One AI project that Barnes and her team are cur-
rently working on is also at the Pluto LNG facility in
northwest Australia and is focused on intelligent edge
assets. Woodside has operated the Pluto LNG facility
since startup in 2012. Gas from the offshore Pluto
and Xena fields is piped through a 180-km pipeline
to Pluto LNG’s single onshore LNG processing train
located on the Burrup Peninsula near Karratha in
Western Australia.
“The project has moved past proof of concept and
pilot trial, but it is still very much a working piece,”
Barnes said. “Our goal is to build this intelligent asset.
We want to install a data-driven digital nerve system at
the heart of our operating facilities to capture, analyze
and make use of all the available data. Ultimately, this
will enable better decision-making. Our tagline for the
project is to make things work harder, so people can
work smarter.”
When it came to naming the AI system, the team
kept coming back to precisely what they were hoping
to achieve, which was to integrate all the data into one
holistic view. “We all agreed to name it Fuse,” Barnes
said. “What we are working on is fusing technologies
and data to create these intelligent assets.”
A new breed of technology
The essence of Fuse is to use existing data from the site
and integrate those with a host of new data that are made
available by installing a new breed of smart sensors. This
is all combined with what Barnes calls a new breed of
technology such as networks, visualization tools, data
science and robotics, which when combined, provides
continuous feedback of data that learns over time.
“It is still a work in progress, but part of the vision is
to create a tool that provides better than human aware-
ness,” Barnes said. “I want someone to feel like they
can use this tool to look at a piece of equipment and
get more information than they could if they got on a
plane up to Karratha, put on their PPE [personal pro-
tective equipment], went out in a helicopter and stood
in front of the piece of equipment themselves. That is
a challenging thing to do, especially having worked in
operational sites myself.”
As to how Woodside is going about achieving this
lofty ambition, it is a combination of deploying the best
technology available and integrating that with its own
proprietary innovation that fills the gaps the company
felt are in the market. “We are integrating existing
plants, sensors and data,” Barnes said. “But then we
have also had to deploy hundreds of additional sensors
to get the data that we required.”
Gap in the market
When Woodside analyzed what was available in the
market, it found that the best that was on offer did not
fit the requirements. The sensors were either too expen-
sive or too complex to integrate and required specialist
skills. The team’s response was to prototype, develop,
build and certify their own sensors.
“Hopefully there will be new IoT [Internet of Things]
sensors in the market, which we can utilize in the future
as we have no desire to become a sensor company,”
Barnes said. “But in the meantime, it’s helping us
achieve our goal.”
The development of these smart sensors created
another, although not an unexpected, problem for
Woodside—the sheer volume of additional data to man-
age. “We had all this additional data that we never had
before,” Barnes said. “It was too much for operations to
monitor. That is where we deployed analytics tools and
data science to process and understand it.”
She continued, “We have a camera that has a view
of a gauge somewhere in its vision, we can digitize
the reading, look at it over time and, more excitingly,
look at it compared to other pumps, because every-
thing’s now connected. Our algorithm can learn what
is normal, alert you when it sees a case that is not
and then offer some insight or action as to what you
should do.”
More to come from AI
This is just the start of the journey for Woodside. The
next step is to visualize those data and create what has
been dubbed a version of a 4-D digital twin that was
COVER STORY:

spatially referenced—a virtual replica of the site with
embedded real-time data analytics.
“When we are solving problems, I think it is fascinat-
ing because we can now better enable the collective
wisdom and collaboration of many,” she said. “We can
even draw on those different assets and different points
of time if we get it right.”
Barnes concluded, “I think the best way to succeed is
to start and try it. We need to think big, start small and
scale fast. We are taking a very hands-on approach to
assess the usefulness of each technology. We need to
work with our people to identify where best to employ
the technology and bring those who have the technical
expertise on board to change the discussion and show
us how we could do things differently. We must be criti-
cal about their usefulness and mindful to changes to
people’s roles and the skills required. And we’re going
to need to collaborate within and across sectors.”
COVER STORY:
AI-enabled tech targets offshore safety
A partnership develops an autonomous solution to mitigate safety in an offshore drilling rig’s
most dangerous area: the Red Zone.
Mary Holcomb, Associate Editor, Digital News Group, Hart Energy
Seadrill has launched a new technology aimed at safety
management on drilling rigs in one of offshore’s most
dangerous areas. Developed by The Marsden Group,
Vision IQ is an artificial intelligence (AI)-enabled safety
technology aimed at monitoring risks within a rig’s Red
Zone. The high-risk area is the portion of the rig floor
where heavy drilling equipment moves, making it a vul-
nerable spot for injuries. Thus, Seadrill tapped Marsden
to mitigate the danger and ensure a safe environment for
the workers.
“You hear about this digital transformation and every-
one’s focused on technology first. We’re focused on
humans first,” said Jennifer Hohman, Seadrill’s CIO and
vice president, at The Marsden Group’s R&D facility tour
in September.
The partnership, she said, focused on leveraging tech-
nology that informs both people on the platform and
those watching the platform. To optimize rig operations,
the safety system utilizes AI,laser imaging,detection and
ranging, and high-power computing technology.
In perspective,the concept builds on driver-assistance
technology where the radars provide alerts to drivers to
reduce human error and promote safety.
Being laser-based and equipped with three high-reso-
lution cameras, each Vision IQ unit can conduct 3-D scan-
ning to create a dynamically monitored environment of the
Red Zone in real time. The two features work in unison to
identify crew members and provide an advanced alert for
potential danger both in the Red Zone and in the rig’s dog
house.But Marsden and Seadrill wanted to exercise safety
by protecting the worker’s privacy from the technology.
“We’ve been very conscious of people’s individual
identity and not capturing tons of sensitive personal data
about [them],” said Andy Pratt, The Marsden Group’s
president. “We don’t track the names or the individual
biometrics of people.This is about people being safe as
a whole, not individualizing.”
Pratt said Marsden intentionally left out more detail-
oriented technology like facial recognition that would track
people to avoidVision IQ becoming a“blaming toolset.”
“We’re not trying to identify you; we’re trying to iden-
tify the role you do and how you do that, and that’s the
data [workers] contribution to the system,” he said.
Incoming technology into the industry often raises
concerns that it will replace humans. But in developing
Vision IQ, Pratt said his team worked closely with drill
floor workers, which “made all the difference.”
“It’s not about replacing the driller;it’s about giving the
driller new jobs where he can focus on how to optimize
and make things better,” he said.
Seadrill plans to deploy Vision IQ on a rig located
in the Gulf of Mexico and install the technology on 12
more rigs globally following high interest, according to
Seadrill’s director of solutions, John Alvarado. Marsden
also is working on a downsized camera-only module of
the technology for smaller, less critical corridors.
“We’re putting our resources, time and money where
our mouth is,” Hohman said. “We are very serious
about the culture of our company and making sure
everybody on our platform is safe and everybody in
any part of our operations goes home to their family,
friends and children.” ■

36
shale
SOLUTIONS
Phil Snider, Consultant
Shaped charge designers have improved their thought
processes in support of operators and unconventional
well stimulations. Perforating systems for the limited-
entry stimulation market were traditionally approached
by simply making short versions of longer gun systems
the industry had always used. A lot has changed.
Those conducting the perforations and those con-
ducting the fracs are communicating. The U.S. activity
downturn at the end of 2014, with associated layoffs and
company failures, made everybody improve. Operators
that had success with direct sourcing (sand and plugs)
began talking about other category applications, includ-
ing perforating. Operators, manufacturers/service com-
panies and the investment community can now easily
access and analyze data, both public data and private
databases merged to them.
People are analyzing their well results and are forced
to consider changes when offsetting acreage performs
better. Other contributing factors to perforating
change include increasing cluster counts, equipment
shortages, higher temperature explosives shortages
and the ever-changing trade relations with China and
steel tariffs.
Orifice flow equation
In most of today’s designs, it is accepted (perhaps more
than it should be) that injectivity rate of fluid follows the
orifice flow equation and proppants and fluids move uni-
formly together. The orifice flow equation is as follows:
∆P perf =
0.237 ρQ2
D4
Cv2
∆P perf = total perforation friction (psi);
Q = flow rate through each perforation (bbl/min);
D = diameter of perforation (in.);
Cv
= perforation coefficient; and
ρ = fluid density (lb/gal).
The differential pressure across the casing is the
method to treat all the clusters in a stage. Injection rate is
primarily influenced by perforation hole diameter to the
4th power. Operators are developing a better understand-
ing of “correct” Cv
factors, initial perforation hole sizes
and perforation erosion rates during pumping and realiz-
ing low treating pressures are not a measure of success.
Engineers are finally abandoning the old rule of thumb
of “two barrels per minute per perf” for more robust tech-
nical approaches. At a 2-bbl/min injection rate, a .30-in.
diameter perforation has an about 1,540-psi differential
pressure, whereas a .40-in. hole has about a 480-psi differ-
ential. Perforation erosion reduces differential pressure,
leading to understimulated clusters. Operators want to
know actual perforation hole sizes in their specific weight
and grade of casing. The datasheets published by the
American Petroleum Institute are of limited value as gun
systems are tested in a smaller diameter, lower-grade cas-
ing. Industry is increasing testing in P-110 casing in par-
ticular and publishing those results. Older style deep-pen-
etrating charges had hole size variation ranging from .50
in. (zero clearance) to .28 in. (maximum clearance) for
a 3.125-in. gun inside 5.5-in. P-110 casing. The resulting
several-fold variation in injection rate per perforation led
operators’ requests for equal-entry hole charges, which
gained market acceptance.
Recent trends, changes and why
Equal-entry/equal-shallow penetration charges without
carrier centralization have worked extremely well, as have
design variations where the charges shoot at an angle to
the casing rather than perpendicular. Success has been
realized fracturing wells using these style charges, which
penetrate very few inches into the formation. Product
suppliers now compete on cost, lowest percent hole size
variation, number of different sizes they can provide
for specific weights and grades of casing, and ability to
achieve results through two strings of casing in refractur-
ing applications. Operators can obtain the specific hole
size of their request, within about .02 in. This enhances
the ability for engineered perforating designs.
Equal-entry hole charges led operators to conduct
more step-rate testing and determine perf efficiency/
near-wellbore tortuosity. Analysis confidence level
increased with known, consistent size holes. Focus has
moved to higher differential pressures across the casing.
The Society of Petroleum Engineers’ technical papers
Recent trends in perforating for
limited-entry stimulation
Economic improvement is driving technology.

38
shale
SOLUTIONS
on “extreme limited-entry,” written by operators rou-
tinely designing stimulations with 2,500-psi differential
pressures, were well-read and created conversations
across industry.
Shaped-charge design accomplished desired hole size
results with less explosive weight and smaller charges.
This opened up design possibilities including small
charges placed beside each other on the same plane,
rather than individual, sequential charges in the gun.
Field introduction of these gun systems began in 2017,
usually in three-shot/cluster configurations. These
shorter gun assembly length systems having all the
perforations in a single plane reduced near-wellbore
tortuosity—as step-rate analysis proved. Figure 1 shows
information on these systems.
New gun systems, safety and regulations
After the aforementioned turndown in completion activ-
ity, stuck gun issues with “blown port plugs” and associ-
ated remedial costs escalated. The resulting technology
improvement is industry’s migration to disposable sys-
tems rather than managing reusable equipment nearing
the end of its life. One will continue to see improvement
in gun string systems: electric disconnects, data acqui-
sition, gun detonating/hardware components, and
especially plug setting tools and “ball-in-place”
methodologies. The trend in zonal isolation is
increasing where operators pressure test the plug
with the ball in place before perforating. It makes
operational and economic sense not to pump a
whole stage away without a plug holding.
A word of caution: operators’ completion
teams are not electronics experts. They rely heav-
ily on service companies for how wireline trucks/
downhole electronics components, and especially
detonators, function. More explosives accidents
and near misses occur than one hears about, and
companies with incidents typically do not want to
discuss it. Perforating systems have tremendous
energy, and one cannot afford a mistake. A few
years ago, industry experts estimated greater than
90% of accidents occurred after a misrun. People
developing electronics today must ensure systems
are highly reliable, properly interface with other
components and no misruns occur.
Other trends
Perforating cluster count per stage continues to
increase in most basins. The long-term produc-
tion history is reaching the point where data ana-
lytics can determine if economics look as good
as early production results indicated with high cluster
counts. The northeast U.S., with its gas production, gen-
erally has fewer clusters and different geology. Diverters
are finding applications.
Operators utilizing higher (1,500 psi or greater after
initial erosion) differential pressures generally obtain
about 90% perf efficiency. High clay content forma-
tions, notably in some areas of Oklahoma, observe
lower perf efficiencies.
Perforating hole size is decreasing in the last 18
months. Operators are having success with single,
larger holes per cluster.
The “gorilla in the room” is associated with particle
transport and perf erosion studies. Several universi-
ties, operators and a few service companies are trying
to better understand how uniformly the proppants
move with the fracturing fluids and are progressing
numerical simulation. This will lead to a very different
thought process and has implications to frac hits and
proppant flowback. Figure 2 shows one of the more
interesting tests in this arena that a group of opera-
tors and others are conducting.
Editor’s note: Phil Snider is a completions consultant to
GEODynamics.
FIGURE 1. Wells with a higher cluster count were a technology driver for
limited-entry perforating gun designs where 1 to 6 equal-entry hole charges
are shot in a short space. This had the added benefit of shortening gun lengths
(about 70% shorter for the gun section) to reduce lubricator lengths and crane
size requirements. The photo on the right is an example of the same cluster
count perforating assemblies, conventionally and with the technology
improvement. (Source: GEODynamics)
FIGURE 2. An aerial photo ahead of a proppant transport surface test helps
develop understandings of proppant placement and perforation erosion for
each cluster at full frac rates. (Source: GEODynamics)

40
shale
SOLUTIONS
Julian Martin, TGT
In recent years, the Permian Basin has been the most
prolific shale play in the U.S. Production in this area
increased to 3.8 MMbbl by 2019, representing almost
70% of the whole U.S. production growth from 2011
to 2019, according to the International Energy Agency.
The impressive aspect of this achievement is that the
growth has not stopped. On the contrary, the Permian
is expected to continue growing and is estimated to
achieve up to 5.8 MMbbl by the end of 2023.
Such growth doesn’t come easy. Significant advances
in drilling, completing and multistage fracturing will
continue to drive production increases. But evaluating
the performance of fracturing programs and the wells
they deliver is key to optimizing resources and ensuring
maximum return on investment (ROI). Conventional
diagnostic, such as production logging tools, can’t pro-
vide all the insights required to ensure the operator is
achieving the best returns. This article focuses on the
challenges faced when assessing unconventional reser-
voirs in terms of production and TGT’s new Fracture
Flow diagnostic tool that evaluates the flow perfor-
mance of hydraulically fractured wells stage by stage.
Pushing the boundaries
Operators have been drilling aggressively and pushing
the boundaries of hydraulic fracturing beyond conven-
tional standards compared to other plays. The drilled
length of lateral sections has been constantly boosted,
adding more footage as well as more production stages.
The ultimate objective is to penetrate deep into the
target formation, increasing the area of contact with the
specific reservoir or formation, therefore making the
well, its completion and the reservoir one dynamic pro-
duction system.
Champions of this approach include a Houston-
based operator that recently drilled such a well at the
Wolfcamp Formation. The completion included a lat-
eral section of more than 17,900 ft running through the
Spraberry Formation. The completed well had a total
measured depth exceeding 24,500 ft with a custom-
ized completion design and fracturing treatment. The
completion included more than 50 stages and sand was
pumped along more than 2,200 ft of the reservoir to
increase the well productivity.
These extended laterals have been engineered
to optimize production performance and leverage
improvements in drilling, fracturing treatments and
completion designs. The operators have overcome
a number of well construction challenges and have
quickly moved up a steep learning curve.
Like the challenges encountered with well con-
struction, the Permian Basin faces its own challenges.
Following such an extensive multistage hydraulic frac-
turing program, the wells are brought onstream at high
IP rates. But most of these extended-lateral producers
tend to decline dramatically over a very short period.
To help combat this challenge and many others, TGT
has developed a number of application-specific diagnos-
tic products using its True Flow System to quantitively
evaluate flow dynamics throughout the entire well sys-
tem—from the reservoir to wellbore and the dynamic
interplay between the two.
When talking about a hydraulic fracturing job, the
importance of the program design prior to execution
is well-known. During this phase, sophisticated soft-
ware is utilized to model and optimize the fracturing
program, taking into consideration multiple variables.
These variables include formation properties, lithol-
ogy, depth, mechanical stresses and other parameters
Unconventional diagnostics for
unconventional wells
New fracture flow diagnostics help operators elevate fracture performance.
FIGURE 1. Fluid and gas moving through a reservoir generate
acoustic noise. Inside TGT’s Chorus sensor is a highly sensitive
piezoelectric hydrophone that converts acoustic pressure waves
into an electric charge. (Source: TGT)

41
shale
SOLUTIONS
that can affect the final outcome. Another important
consideration is the formulation of the hydraulic frac-
turing fluid. This fluid normally comprises sand (or
proppant), gels (foam or sleek water) and additives that
are pumped downhole following the job design to prop
open the induced fractures and maximize the extension
of the fracture in terms of length, height and aperture
as well as the integrity of the fractured conduit itself, so
hydrocarbons can flow unabated.
Evaluating fracture inflows
TGT’s diagnostic Fracture Flow is able to locate and
evaluate fracture inflows and quantify inflow profiles in
hydraulically fractured wells. The product is delivered
by the company’s analysts using the True Flow System,
which combines several technology platforms—Chorus
(acoustic), Cascade (thermal), Indigo (multisense) and
Maxim (digital workspace)—to acquire, interrogate and
analyze the acoustic spectra and temperature changes
generated by the hydrocarbons or any other fluid flow-
ing from the reservoir through active fractures and into
the completion (Figure 1). This diagnostic capability
goes beyond conventional flow measurement techniques
that generally stop sensing at the wellbore and are there-
fore unable to quantify flow within the reservoir itself.
The Fracture Flow product extract shown in Figure 2
represents the diagnosis of a hydraulically fractured oil
producer with greater than 80 degrees deviation. The
reservoir has a gross thickness of about 1,200 ft and is
fully cased.
The operator’s objectives in this case were to evaluate
the post-fracture performance of three zones and com-
pare the effectiveness of fractured stages by assessing the
production contribution from each fractured interval,
identify crossflow or behind-casing communication, and
increase production efficiency by identifying the opti-
mum production choke for this well system.
The results revealed by the Fracture Flow analysis
revealed that the fractured intervals (Figure 2, blue cod-
ing) were not contributing fully to production in their
entirety. Furthermore, it identified the active zones and
where the main production was coming from (Figure
2, green coding). Fracture Flow revealed that only 62%,
59% and 56% of each zone was actually producing at
the outset. The Fracture Flow analysis also indicated
there were no crossflows among the three zones, which
was another key finding from an integrity perspective.
Thirdly, the Fracture Flow diagnostic program helped
determine the optimal choke size required to ensure the
fractured zones were contributing at the maximum rate.
TGT works in close collaboration with operators using
Fracture Flow to help them reach their frac evaluation
objectives, locate effective fracture inflows, quantify
inflow profiles and assess the effectiveness of fracture
programs, helping to optimize future programs and
maximize ROI.
FIGURE 2. Fracture Flow diagnostics compare fractured intervals (blue) to main producing intervals (green) at different choke sizes to
evaluate the true effectiveness of hydraulic fracturing programs and maximize well performance. (Source: TGT)

operator
SOLUTIONS
Asmund Maland, ABB
Subsea exploration is needing to take place in increas-
ingly extreme harsh environments, as the oil and gas
reservoirs are no longer easy to find close to the shore.
At the same time, the industry faces several key chal-
lenges, such as high costs and risks, low efficiency, and
reliability and nonsustainable issues.
New technology that goes beyond today’s current
capabilities is required to go deeper and farther than
ever before. In an oil or gas field, the more depleted
the existing reservoir, or the more inaccessible it is due
to distance, the greater the need for subsea pumps and
compressors and the technology that powers them. This
is especially crucial to extending the operating life of
existing fields.
Subsea compression
Producing oil and gas from reservoirs located at long
distances from land is a costly proposition that presents
many challenges to offshore operators. Subsea installa-
tions situated far from shore or remote platforms can
be a very cost-efficient solution, as it may eliminate the
need for a fixed or floating topside installation.
Moving the required pumps and compressors from
the topside installation to the seabed increases the
effectiveness of oil and gas extraction. Compressors
are used to maintain output by restoring reservoir
pressure at gas-producing fields as it drops over time.
Traditionally, they have been installed on platforms
above sea level, but with subsea compression, the com-
pressor can now be placed on the seabed. Putting the
compressor on the seabed near the wellheads improves
recovery rates, reduces costs and minimizes environ-
mental impact. Additionally, it reduces the number of
people working in harsh environments offshore, cutting
labor costs and enhancing safety at the same time.
Jansz-Io compression project
The Jansz-Io Field is located about 200 km offshore on
the northwest coast of Western Australia at about 1,350
m below the surface. It is a part of the Chevron Austra-
lia-operated Gorgon Project, one of the world’s largest
natural gas developments. Here, subsea compression is
applied to enhance the recovery and maintain a long-
term natural gas supply of 17.1 ton per year to LNG
and domestic gas plants on Barrow Island. The system
increases the pressure close to the wells and pushes the
gas toward the large LNG plants onshore.
ABB is collaborating in the delivery of a subsea com-
pression system with Aker Solutions and MAN Energy
Solutions for Chevron, where the compression system
will boost recovery of gas more cost-effectively, leaving
a smaller environmental footprint than the traditional
use of semisubmersible compressor solutions. ABB’s
role in the FEED of a subsea compression station is
designing the electrical power system that will distribute
onshore power to the subsea compression station. It
Subsea compression: developing
solutions to keep gas flowing
As oil and gas fields become depleted, energy companies are looking at how they can
extend the life of operating fields, unlocking low-pressure reserves from reservoirs to
maintain plateau production rates.
ABB is collaborating in the delivery of the Jansz-Io subsea compression
system with Aker Solutions and MAN Energy Solutions for Chevron.
(Source: ABB)

operator
SOLUTIONS
needs to be designed in the right way and tested
under many different scenarios to ensure power
is delivered to the compressor reliably and is con-
trolled and optimized. This subsea power will go
deeper and farther with reliable communication,
monitoring and control.
From Åsgard to Jansz-Io
The Jansz-Io offshore field in Australia is the first
location outside of Norway to use subsea com-
pression technology. ABB has been involved in
the development of subsea equipment and sys-
tems for three decades.
This collaborative project is an outcome of sev-
eral years of joint work that includes landmark
developments such as the 2015 delivery of the
world’s first subsea compression system for the
Åsgard Field offshore Norway, where the operator
had discovered that the internal pressure of the
well was dropping rapidly, although there were consid-
erable resources remaining. New ways of boosting the
pressure were investigated with subsea compression.
Although Jansz-Io represents the first time subsea
compression has been used outside of Norway, there
is the potential for subsea compression to be used
globally, wherever the environment requires it. The
company’s collaborative work combines strengths in
subsea, power and automation technologies to develop
solutions that will improve oil and gas production for
the global energy industry.
There are many challenges in optimizing and extend-
ing the life of the fields in Jansz-Io. Not only are we
building a resilient and reliable system to maintain
high levels of production, but the company also is
using its expertise to design them in a robust way to
withstand the harsh environment. The company also
needs to plan and manage the installation, as there are
lots of components that all need to work together. For
example, the equipment is lowered to the seabed and
integrated with the technology without causing dam-
age. Long power cables also require careful handling.
The company needs to enable maintenance in hostile
environments and not forget about handling the data
securely and intelligently.
Beneﬁts of subsea compression
The main benefit at Jansz-Io will be the enhanced recov-
ery and maintained long-term natural gas supply. This
also brings economic benefits, as increasing the amount
of oil and gas that can be recovered from new and
existing fields by deploying compression or pumping
systems at the seabed decreases overall costs per unit.
Looking at the Åsgard project, the world’s first subsea
gas compressor system, as an example, it is predicted to
enable an additional 306 MMboe, corresponding to a
medium-sized field on the Norwegian Continental Shelf.
It also will extend the field’s life to 2032.
The systems also are more reliable and come with less
risk as cables and transformers that have been rigor-
ously tested are being used. Maintenance is decreased
and decommissioning is reduced to towing the substa-
tion away and replacing it with another. With a reduced
environmental impact, the solution is also more sus-
tainable for operators, with a lower carbon footprint.
It uses less energy as compressors are closer to the gas
reservoir in the Jansz-Io Field.
The deeper and farther afield the location of the
subsea compression is, the higher the corresponding
economic benefits with this approach. There is also
less downtime, as there are no or minimal modifica-
tions to be made to existing infrastructure. Removing
the need for local power generation means it uses less
energy to produce the same amount of gas. It can be
up to eight times more energy-efficient. Overall, this
represents a considerable leap as the industry looks to
a new digital future for the industry toward autono-
mous operations.
Have a story idea for Operator Solutions? This feature
highlights technologies and techniques that are helping
upstream operators overcome their challenges. Submit your
story ideas to Group Managing Editor Jo Ann Davy at
jdavy@hartenergy.com.
The subsea gas compression system at Jansz-Io will improve gas recovery
more cost-effectively and with a smaller environmental footprint than a
conventional semisubmersible compressor station. (Source: Aker Solutions)

E&p magazine 2019 11

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