JPT November 2023
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12
GUEST EDITORIAL • Digital Technologies: A Competitive
Advantage Today, a Necessity Tomorrow
The oil and gas industry is embracing digital technology as not just a
differentiator, but as an enabler of innovation. The simple reality is that
if one doesn’t, they risk being out of the game.
20
The Third Way: How BKV Turned to ‘Hybrid’ Refracs
in the Barnett Shale
BKV Corp. has combined bullhead and liner refracturing methods to create
an approach called the hybrid expandable liner system. On the cover: A restimulation operation
in the Barnett Shale of north Texas where
26
It Is Easy To Find Lithium; Turning a Profit Is Hard hundreds of early-generation shale
The best wells in which to find lithium are in old conventional fields where wells have received similar refracturing
rusty pump jacks are pulling out mostly water. treatments since late 2021. Source: BKV Corp.
32
Can Direct Air Capture Deliver?
As money pours into the space, questions arise about whether the method
of removing carbon from the atmosphere is the best investment. DEPARTMENTS
38
Driving Change: Cultivating an Energy Workforce 10 Comments
for Lasting Prosperity 15 E&P Notes
The oil and gas industry’s sustainability and success depend on its ability
98 SPE Technical Papers
to cultivate and nurture a skilled and knowledgeable workforce.
Available
44
Case Study: Qualifying Bismuth Plug Technology 99 SPE News
in Mozambique 105 People
Prior to proceeding with a contract to fulfil a rigless P&A campaign for
106 SPE Events
Sasol in Mozambique, BiSN designed a field trial to prove the effectiveness
of its bismuth plug technology. Although the technology had been used in
19 countries by BiSN for a variety of downhole applications, it had not yet
been qualified for use in Mozambique.
An Official Publication of the Society of Petroleum Engineers. Published in US. Copyright 2023, Society of Petroleum Engineers.
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SPE JOURNAL
50 DRILLING AND COMPLETION FLUIDS
SPE-217973-PA—CRM-Aquifer-
Víctor Soriano, SPE, Well Construction Manager, YPFB Chaco
Fractional Flow Model to Characterize
Oil Reservoirs with Natural Water Influx
52
Low-ECD Inverted Emulsion Fluid Shows Superior Performance
SPE-217972-PA—Physics-Guided
V-Net: An Efficient Surrogate Model 55 Method Provides Real-Time Anomaly Detection
for Well Placement Optimization for Drilling-Fluid Properties
in Petroleum Reservoirs
58 Light-Density Hollow-Glass-Beads Drilling Fluid Achieves
SPE-217471-PA—Capillary-Sealing High Solids-Control Efficiency
Efficiency of Mica-Proxy Caprock
for CO2/H2 Geologic Storage in
the Presence of Organic Acids 62 EOR OPERATIONS
and Nanofluids (Open Access) Elizabeth Barsotti, SPE, Career Development Fellow, MRC
Laboratory of Molecular Biology
SPE-217469-PA—A Continuous
Projection-Based EDFM Model for 64
Study Reviews Largest ASP Project From Laboratory to Pilots
Flow in Fractured Reservoirs and Field Application
SPE-217467-PA—Machine-
Learned Surrogate Models for 68 Process Synthesizes Janus Carbon Nanofluids From Waste
Efficient Oil Well Placement Under Plastics for EOR
Operational Reservoir Constraints
71 Study Evaluates CO2 Storage Potential During CO2
SPE-217466-PA—Synthetic Graphic Mobility-Control Optimization
Well Log Generation Using an
Enhanced Deep Learning Workflow:
Imbalanced Multiclass Data, Sample 74 HYDRAULIC FRACTURING MODELING
Size, and Scalability Challenges Mark McClure, SPE, CEO, ResFrac
SPE-217427-PA—A Review of 76
Modeling Usage of Degradable Fluid-Loss Additive Revamps
Polymer Gel Utilization in Carbon Fracturing Design
Dioxide Flow Control at the Core
and Field Scale (Open Access) 80 3D Integrated Model-Driven Work Flow Developed for Shale
Hydraulic Fracturing
SPE-214385-PA—Rapid Inference
of Reservoir Permeability from 83 Fracture Conductivity Work Flow Models Well Spacing,
Inversion of Traveltime Data Under Completions Design
a Fast Marching Method-Based
Deep Learning Framework
SPE-209979-PA—Semi-Automated
86 FLOW ASSURANCE
Rock Classification for Permeability Celestina Yaaba Kissi, SPE, Offshore Chemist, ChampionX
Estimation Using High-Resolution
Computed Tomography Scan Images,
88
Robust Scale Dissolver Mitigates Mixed-Scale Issue
in South China Sea
Core Photos, and Well Logs
REGIONAL DIRECTORS
AFRICA MIDDLE EAST AND NORTH AFRICA
Oghogho Effiom, Shell Nigeria Mohamed Al Marzouqi, ADNOC
Hisham Zubari, Dragon Oil
ASIA PACIFIC
Henricus Herwin, Pertamina NORTH AMERICA
Hazli Sham Kassim, Petronas Simeon Eburi, Chevron
Robert Martinez, Chimney Rock Energy
EUROPE Kim Oracheski, Strathcona Resource
Pierre Emmanuel D’Huart, Saipem
RUSSIA AND THE CASPIAN
LATIN AMERICA AND THE CARIBBEAN Alexey Borisenko, Schlumberger
Carlos Alberto Petroso, Enauta
TECHNICAL DIRECTORS
COMPLETIONS DATA SCIENCE & ENGINEERING ANALYTICS
Karen Olson, Olson Turner Enterprises Sushma Bahn, Ikon Science
JPT STAFF
Dana Otillio, VP Communications and Publisher Stephen Rassenfoss, Emerging Technology
Pam Boschee, Director, Magazines Senior Editor
Chris Carpenter, Technology Editor Pat Davis Szymczak, Contributing Editor
Megan Couch, Content Manager/Editor Adam Wilson, Special Publications Editor
Trent Jacobs, JPT Senior Technology Editor Blake Wright, Technology Editor
Jennifer Presley, Senior Technology Editor Laurie Sailsbury, Digital Publishing Specialist
I’m Trent Jacobs, JPT senior technology editor, and public is still demanding a reduction in emissions.
welcome to the President’s podcast. Today I am That represents what a lot of people call the
very happy to be talking with 2024 SPE President trilemma. How do we as a society meet the world’s
Terry Palisch. He’s going to be talking to us about energy needs for affordable and accessible energy
the impact that the energy transition is having on that is reliable and secure, but also becoming
the industry and technology and how SPE is helping evergreen and decarbonized. That is what they call
its members adjust to the shifting landscape. the energy trilemma. I think it is more the energy
opportunity, and I say that because I believe it’s the
I am glad to be here with you, Terry. Thank energy opportunity for our industry. I believe we
you for joining us. Can you set the scene for are the best suited to solve the energy trilemma
me a little bit by explaining a concept that you and we are solving it as we speak.
mentioned on your last podcast episode, this is
the energy trilemma … tell us more about that. Let’s open that up a little bit. From where you
Thank you, Trent. I am excited to be talking to you are sitting, what do you see the industry doing
today. Let’s start with the building blocks. Energy to respond to the trilemma?
is the building block of all life: human beings need Our industry has been meeting the world’s energy
chemical energy, and in our everyday lives we need needs for decades. Oil and gas along with coal
energy. Energy essentially drives everything, and helped usher in the Industrial Revolution. We
our population is growing. We expect by 2050 to developed new technologies, things that we never
have another 1 to 2 billion people on the planet, saw coming, like deepwater and shale oil and
or another 20–25%, and at the same time over gas, or unconventional development. The ability
two‑thirds of our world population live in some to take horizontal wells and put multiple fracture
form of energy poverty. stimulations in them completely changed the
Currently, 80% of the energy supplied to the landscape in the US and North America. Right
world comes in the form of coal, oil, and natural now, natural gas is plentiful; we built LNG import
gas, commonly called fossil fuels. That percentage terminals before the shale revolution and now we
has not changed appreciably for decades. The are building export terminals.
jpt.spe.org 5
Along with 2023 SPE President Med Kamal, Regional Director Hisham Zubari, and SPE regional staff, Terry visits with the
leadership and members of the Oman Section and local SPE chapter students.
That is how SPE keeps our members connected to cornerstone of professional development. It is a
technology and new developments. big part of my experience. I think that attending
and participating in these events is really one
I like what you said. It resonated with me when of the critical pieces of our ability to create our
you said linking global networks together energy future.
because in my own experiences of attending
SPE events, I see that. I see people from Tell us about where you have traveled recently.
opposite ends of the world meeting up for the What are some of the events you have attended
fifth or tenth time and exchanging ideas in and share with us some of the takeaways.
real life. I want to ask about your experiences I just got back from a trip to the SPE International
because you have been on the move recently Hydraulic Fracturing Technology Conference
visiting SPE sections and members from around (IHFTC) in Muscat and Offshore Europe in
the globe and participating in SPE events and Aberdeen, which celebrated its 50th anniversary.
conferences. What do these conferences mean Offshore Europe is a critical event for SPE and
to you, why is this so important? the region. We had more than 800 exhibitors
It is important for me to attend as many as I can and 30,000 attendees over 4 days including the
because SPE events exist for the sole purpose of Honorable Graham Stewart, UK Minister of State
connecting our members with technology and for Energy and Security Net Zero, and Gillian
other members to collaborate and network. These Martin, the Scottish Minister for Energy and the
events are only possible because of the dedicated Environment. The IHFTC was the third edition held
volunteers and the SPE event staff. Another benefit in Oman, which is an offshoot of our successful
is the volunteer opportunities available whether Hydraulic Fracturing Technology Conference (HFTC)
it is on a program committee, leading a section, in The Woodlands, Texas, held every year. There
being a co-chair, writing a paper, or making a were over 700 attendees and 126 companies
presentation at a workshop. It gives us a chance from 35 countries. The Oman Ministry of Energy
to display our technology, a chance to network, and Minerals was present, and PDO was the main
a chance to work on our soft skills, and is the host. Both of those are important to the respective
jpt.spe.org 7
The Aberdeen Section leadership hosted a meet and greet with new SPE CEO Simon Seaton and Terry. Also present
were Board members Laura Precupanu, Robin Macmillan, and 2022 SPE President Kamel Ben-Naceur, as well as
several senior SPE staff.
a great reputation for putting on the best events AAPG on carbon capture and storage. There is
focused on technology and networking. an event coming up this month with Geothermal
We have an initiative underway to improve Rising, a geothermal workshop in Colorado.
ATCE called the ATCE Reimagined Group. It is We want to be known as the go-to place for
made up of board members, staff, and an external events that promote technical exchange, thought
resource. We are looking at how to revamp the leadership, networking, and provide a second-to-
Society’s flagship event. none experience.
ATCE has a rich history as our premier event,
but members have said we need to revamp That is exciting news about ATCE. This is a
it and they are right. Our next ATCE will be in show that presents some of the best and most
New Orleans in 2024. It will mark the 100th impactful papers that benefit the oil and gas
anniversary of ATCE and our goal is to lay the industry. Can you tell us what is coming up in
foundation for the next 100 years. Plan on coming your next episode?
to New Orleans. I think it will be a lot of fun and Next month we are going to continue our
very informative. discussion about this connection, connecting our
The other thing we do is partner with other members to technology and each other, and talk
societies whether it is for the Unconventional about the importance of local sections. I think for
Resources Technology Conference (URTeC) or the most members the section is what they think of
International Petroleum Technology Conference when they think of SPE. It gives great opportunities
(IPTC) where we join up with SEG, AAPG, and EAGE. for volunteering and, really, all the important
We are always looking for new ways to deliver aspects of what we need to do and what we
enriched content and to expand the tent into can do to create our energy future. I am looking
related technologies. An event took place earlier forward to it and I hope everybody will be able
this year with the University of Houston alongside to join us. JPT
2024.otcasia.org I #otcasia
COMMENTS
cemented after a gas explosion occurred during drilling Patrick Miller—Chairperson, Petronas
Imran Abbasy, Pakistan Petroleum
operations at a measured depth of 112 m.
Anson Abraham, CNRL
Unplugged in 2011 for use as a pilot well for local
Amir Alwazzan, Dragon Oil
hydrogen production, gas was reported comprising Mariela Araujo, Shell
98% hydrogen, 1% nitrogen, and 1% methane. Jyotsna Asarpota, Halliburton
Hydrogen was then produced as an energy resource Elizabeth Barsotti, MRC Laboratory
to supply local electricity through a company named Linda Battalora, Colorado School of Mines
Petroma, renamed Hydroma. From 2017 to 2019, the Zhiming Chen, China U. of Petroleum
Graham Collier, Consultant
company drilled 24 wells.
Santanu Das, ONGC
Among the new breed of gold prospectors are
Sandeep Dhawan, WellPerform
several startup companies including Natural Hydrogen
Michael Fuller, Chevron
Energy, Koloma, Helios Aragon, Gold Hydrogen, Jeff Gagnon, ExxonMobil
HyTerra, and H2Au. Reza Garmeh, Callon Petroleum
Helios Aragon owns exploration permits in David Gurney, KUFPEC
northern Spain’s Aragon region and will begin drilling Subodh Gupta, Heretech Energy
Nebraska,” the Hoarty well at Project Geneva. HyTerra Muhammad Khan, ADNOC
Celestina Kissi, ChampionX
also holds leases in the Nemaha Ridge in Kansas.
Mahdi Mahmoudi, Variperm
The cost advantages of subsurface hydrogen are
Swamy Margan, Consultant
frequently cited by the early prospectors. For example, Mark McClure, ResFRac
the wells in Mali have the potential to generate Sandeep Mukherjee, Callon
hydrogen gas at a cost of 50 cents/kg, which is Soujatya Mukherjee, Wintershall DEA
only one-tenth the cost of producing hydrogen via Anand Nagoo, Nagoo and Associates
electrolysis using solar, wind, geothermal, or other Gopi Nalla, DeGolyer and MacNaughton
Eudorah Ochai-Audu, Shell
renewable energy sources.
Danny Ochoa, Schlumberger
If commercialization and economies of scale
Carlos Pedroso, Enauta
pan out, this may become the gold standard for
Shahvir Pooniwala, Aramco
hydrogen energy. JPT Kaibin Qiu, Schlumberger
Pierre Ramondenc, Schlumberger
FOR FURTHER READING Michael Romer, ExxonMobil
Babatunde Salawu, Shell
Débora Salomon, Dow
The Curious Case of Geologic Hydrogen: Assessing
Amit Singh, Chevron
its Potential as a Near-Term Clean Energy Source
Victor Soriano, YPFB Chaco
by E.M. Yedinak, US Department of Energy, Advanced
Cornelis (Kees) Veeken, Consultant
Research Projects Agency-Energy. Larissa Walker, QGC
The Occurrence and Geoscience of Natural Junjie Yang, Baker Hughes
Hydrogen: A Comprehensive Review Karam Yateem, Saudi Aramco
by V. Zgonnik, Natural Hydrogen Energy LLC.
jpt.spe.org 11
GUEST EDITORIAL
Digital Technologies
A Competitive Advantage
Today, a Necessity Tomorrow
Girish K. Saligram, Weatherford
H
aving had the privilege of living on three continents, working
Girish K. Saligram has served across multiple industries, and conducting business in several
as the president and CEO of countries, I have seen the impact digital technology has on
Weatherford since 2020. Prior to business, people, and communities. Throughout my career, I
Weatherford, he held leadership have witnessed lifesaving and life-changing digital innovation that changes
roles at General Electric and
the trajectory of organizations and industries. As someone who entered
Exterran Corp. He holds an MS in
the workforce during the dot-com era with a background in computer
computer science and an MBA, and
has worked across industry sectors science, I continue to be amazed by how yesterday’s differentiation
and multiple countries. becomes today’s necessity … and tomorrow’s obsolescence challenge.
The pace of innovation in digital is unprecedented in the annals of
human innovation. Personally, I only need to look at my kids to get a
sense of that. While we learned to ride a bicycle the same way despite
a 3-decade gap, the way we communicate, interact, learn, and create
is radically different, enabled by digital platforms that permeate every
aspect of life. It is natural therefore to envision that the generations
that grow up in these digitally enabled environments will expect,
demand, and enable the same degree of digital connectivity in
business as they come into and subsequently lead our industry.
Oil and gas is an industry that is not just impressive in size, scale,
and scope. It is also a sector that deploys technology across the spectrum
of breadth and depth. It is unique in that it enables the convergence
of several technology domains, including mechanical, material
science, hardware, software, automation, instrumentation, artificial
intelligence (AI), and others. That, too, in some of the most extreme
conditions of temperature, pressure, and accessibility on the planet.
Natural business drivers like operational efficiency have been
complemented by workforce changes and sustainability agendas
to enable this array of technological prowess. In the recent years,
companies have leveraged digital as a competitive advantage. Digital
technologies have enabled cost efficiencies, speed of operations, and
safety enhancements. However, like in other sectors, there are fast
followers as well as disruptors who can leapfrog advances. As a result,
the industry is embracing digital technology as not just a differentiator,
but as an enabler of innovation. The simple reality is that if one doesn’t,
they risk being out of the game.
Generational Changes the industry, and I think we are just getting started.
One of the biggest drivers I see in the changes The physics of constructing a well involves hundreds,
taking shape across our industry stems from a if not thousands, of connections—each being a
convergence of several shifts in the workforce. potential failure point which can compromise the
It is well known that the sector has an aging integrity of the entire asset. Furthermore, manually
workforce, and the Great Crew Change is upon making up so many connections can lead to
us. That, coupled with the fact that we are seeing complacency, which increases the risk of mistakes,
labor shortages in some markets and that it has injuries, or—even worse—fatalities. Outcomes
become increasingly harder to attract talent into such as these cost the industry billions as well as
this space, necessitates change. For example, in potentially its reputation. To eliminate these risks,
the post-COVID-19 pandemic era, we are seeing we must continue to invest in mechanization,
an increased desire to work from home vs. take automation, and remote operations that are
on rotational work—the jobs that are based in the designed to get people out of the red zone while
field are not as appealing as they were a generation delivering predictable and verifiable outcomes.
ago. In addition, the incoming generation demands Investments like this today are what will ensure the
that large corporations do more to make a positive sustainability of our industry tomorrow.
impact on the world. And they’re right. We have
a duty to act responsibly, to improve quality of Better outcomes through AI decision making.
life, and reduce environmental impacts. We must The past several years have shown us just how
think and act differently if we are going to continue quickly technology is advancing the industry. We
competing for top talent—the type of talent that will live in a fast-paced and dynamic environment, and
continue revolutionizing the industry. So, what does if you want to succeed you have to be adaptable.
that mean? From my perspective, there are a several You have to be willing to take risks and be a
key areas our industry must continue investing in. pioneer. A mere 5 years ago, the idea of widespread
AI usage in our personal and professional lives
Operational efficiency through LEAN workflows. would have been incomprehensible to some. Now,
An essential component of innovating is looking it’s everywhere. Just look at your web browser or
at your operating workflows and finding ways online shopping cart.
to improve upon them—keeping the customers’ However, I firmly believe looking to the
needs front and center. Leveraging technology future doesn’t mean turning your back on your
to improve the speed and efficiency of everyday legacy. To the contrary, there is great power
activities such as equipment redeployment, in harnessing your strengths and decades of
inventory management, and fulfillment makes a experience in operations. The key is, you have
sizeable impact when viewed over the long term. to be open to turning things on their head and
Ultimately, our goal is to get the best equipment looking at challenges differently. That’s another
and services to the field for our customers, deliver area where I believe this change in the workforce
safe and quality operations, and yield the highest landscape is actually working to our benefit. You
levels of production out of their assets as possible. have a combination of a wealth of knowledge and
This isn’t a case of taking the same approach with experience from your seasoned workforce and the
a rinse and repeat mindset. Instead, it is a cycle of fresh, different perspectives of a budding workforce
constant reset, refresh, and rejuvenate. combining to unlock new potential, such as
harnessing AI to make decisions. Several companies
Enabling well integrity and remote operations. are leveraging data, machine learning, and AI
Remote operations have been a game changer for to predict what is going to happen subsurface
jpt.spe.org 13
GUEST EDITORIAL
and respond immediately—limiting exposure to can take any traditional oilfield operation and apply
personnel and the environment in the process. a digital methodology to it. In doing so, not only
can you achieve improved drilling performance
Decarbonization Through Technology and enhanced safety, but also improved reservoir
Integration and Optimization productivity. What we’re seeing is that wells
The pathway to lower carbon, renewable energy, previously deemed undrillable are becoming
and a more sustainable world threads its way accessible through technology.
through the energy industry, and we take
responsibility and pride that we can do our part Optimizing Your Internal Business
in helping to deploy and scale lower-emissions Everything we have talked about to this point is
technology. The focus areas I’ve touched on today— about bringing value to the customer. The other
automation, remote operations, and digitalization— part of the equation is delivering value to our
are all essential to the energy transition. shareholders. To do that, we need to optimize
We must continue to revolutionize the oil our business operations by delivering simplified
and gas sector. Existing oil and gas production cost structures, improved internal productivity,
will continue to sustain the world’s overall energy supply chain optimization, and more. This is
needs, but we must accept the responsibility of where generative AI becomes essential as we
actively seeking new methods to help reduce the move forward. As the adage goes, we need to
industry’s carbon footprint and make all operations work smarter and not harder—leveraging data to
more efficient and sustainable by integrating drive decision making. Through generative AI, we
products, services, and digital workflows. For can make predictions about our operations and
example, we are applying existing technology conduct testing scenarios of new business models
in innovative ways and leveraging the expertise before implementing them to define the most
of our people to reduce the carbon intensity of profitable outcomes for all.
our existing operations and also through carbon
capture and sequestration solutions. Closing Thoughts
We must continue raising the bar and seeking
Better Customer Operational Outcomes opportunities for innovation. There are countless
Through Digital Data Mining consumer-based examples of digitalization in other
When I think about digital data mining, I am referring industries coming from a couple of progressive
to pulling data from all parts of the asset lifecycle, thinkers working out of their garage—think Silicon
correlating the data elements, finding commonalities, Valley. Digitalization has the power to upend
and delivering better insights on well dynamics, well industries and change the landscape for the
integrity, and failure points. In our own portfolio, better. Our industry faces similar challenges of
we drive this through production optimization, disruption now, and we have the opportunity to
real-time drilling optimization, and intelligent be the disrupters. We have the opportunity to set
managed-pressure drilling. Furthermore, data mining the standard—so much so that other industries
may also lead to better equipment reliability— will emulate our actions. We don’t have to rely on
optimizing when and how assets are serviced someone else to come in and fix things. Instead, we
to ensure peak performance at optimal costs. need to drive positive change through partnership,
This is a common theme and a view shared by our own innovations, and by leveraging decades
thought leaders in the industry. We’re all out here of experience. If you haven’t already shifted your
trying to do the right thing and make a positive mindset on this, you risk sitting on the sidelines.
impact. So, that means we must get creative. You So, who’s game? JPT
jpt.spe.org 15
E&P NOTES
Tamar platform.
Trinidad is Latin America’s largest producer of blocks in Trinidad and are the largest shareholders
LNG, with installed capacity of 15 mtpa. in the country’s flagship LNG project, Atlantic LNG.
The government is offering 13 shallow-water
blocks, all located on the continental shelf near TotalEnergies Launches Development
areas where both oil and gas are being produced. Studies for $9-Billion Project off
The round’s period for receiving bids will finish in Suriname
early April. TotalEnergies has announced the launching of
Trinidad Finance Minister Colm Imbert the development studies for a large oil project in
announced changes to the fiscal regime, including a Block 58, offshore Suriname. Appraisal of the two
reduction in tax liability for shallow-water producers, main oil discoveries, Sapakara South and Krabdagu,
which the country hopes will make it more attractive. was completed in August 2023 with the drilling and
Among the changes are an increase of cost testing of three wells and confirmed combined
recovery to 60% from 50; the windfall tax was recoverable resources close to 700 million bbl for
reduced to 50% from 70; the period for exploration the two fields.
increased to 8 years from 6; and the bid fee was The reserves, located in water depths
reduced to $30,000 from $40,000. between 100 and 1000 m, will be produced
BP and Shell recently signed production- through a system of subsea wells connected to
sharing contracts to explore three deepwater an FPSO located 150 km off the Suriname coast,
jpt.spe.org 17
E&P NOTES
with an oil production capacity of 200,000 B/D. encountered a 16-m hydrocarbon column in a
TotalEnergies said the project will represent an 20-m gross reservoir section in Jurassic sandstones.
investment of approximately $9 billion. DNO is calling the discovery a play-opener for
The detailed engineering studies will start by the deep turbiditic sands in this area given the
the end of 2023 and the final investment decision is exceptionally good reservoir quality encountered.
expected by the end of 2024 with a first production Plans are underway to further delineate the
target in 2028. discovery and the upside potential in the license.
TotalEnergies is the operator of Block 58, with a Before further appraisal drilling, improved seismic
50% interest, alongside APA Corporation (50%). imaging and remapping will be undertaken to
identify an optimal location for the next well.
DNO Makes Discovery at Norma DNO was awarded an interest in PL984 in 2019
in the North Sea through its wholly owned subsidiary DNO Norge
DNO has made a significant gas condensate AS. The company holds a 30% operating interest.
discovery at its Norma prospect in the Norwegian The other partners in the license are Source Energy
North Sea license PL984. Preliminary evaluation AS, Equinor Energy AS, Vår Energi ASA (20% each),
of the discovery indicates gross recoverable and Aker BP ASA (10%).
resources in the range of 25–130 million
BOE on a P90-P10 basis, with a mean of W&T Offshore Completes Shallow-Water
70 million BOE, in a Jurassic reservoir zone US Gulf Purchase
with high‑quality sandstones. W&T Offshore has completed the acquisition of
Located 20 km northwest of the Balder working interests in eight shallow-water oil- and
hub and 30 km south of the Alvheim hub, gas-producing assets in the central and eastern
Norma is situated in an area with extensive shelf region of the Gulf of Mexico from an
infrastructure in the central part of the North Sea, undisclosed private seller for $32 million.
with tieback options offering potential routes The acquisition has a closing date of
to commercialization. 20 September 2023, and an effective date of
Drilled to a vertical depth of 4800 m with 1 June 2023. W&T used its cash on the balance
the Deepsea Yantai drilling rig, Norma is DNO’s sheet to pay the net purchase price.
first operated high-pressure/high-temperature The deal includes estimated production as
exploration well. At 4650 m, the discovery well of 12 September 2023, of about 2,400 BOE/D
(42% oil) with around two-thirds of the
production operated.
Deepsea Yantai.
The acquired assets, encompassing 30,646
gross acres (22,079 net acres), also add proved
reserves of 3.2 million BOE (49% oil).
Russia’s Zarubezhneft was awarded a block in the and gas terms that would allow contractors to
Nile Delta. have equity shares of more than 50% in some
Zarubezhneft’s win is a rare expansion abroad new blocks to attract investment.
by a Russian company since the invasion of Ukraine The nation is keen to boost output from its rich
in February 2022. gas reserves while it still can, as global investors
Zarubezhneft already operates in seven shift increasingly away from fossil fuels.
countries, including Egypt where it is holds Energy Minister Arifin Tasrif said 68 of the
stakes in production sharing agreements on country’s 128 hydrocarbon basins remained
offshore tracts. entirely unexplored.
The Egyptian government in July announced Tasrif said the new terms were being offered
the start of a $1.8-billion program to drill natural starting from the previously announced third
gas exploration wells in the Mediterranean Sea bidding round this year. The nation is offering
and Nile Delta. three exploration blocks—Akimeugah I and
Akimeugah II onshore blocks, each with estimated
Indonesia Tweaks Oil Terms gas resources of 15 billion BOE, and the Bobara
To Attract Investment exploration block located off West Papua. Bobara
Indonesia’s energy minister announced the has estimated oil and gas resources of around
government had made improvements in its oil 6.8 billion BOE. JPT
FEATURE | Hybrid Refracturing
W
hile refracturing has maintained
a backseat role in the US
shale sector, with capital
overwhelmingly flowing toward new
well programs, there’s been a notable exception
brewing in the Barnett Shale.
Last year, from within the asset that holds
the very well that ignited the shale revolution,
gas producer BKV Corp. announced that it had
become the top refracturing operator in the
US. From November 2020 through February of
this year, covering a span of just 28 months,
the Barnett Shale operator completed an
eye‑opening 369 Barnett refracs.
The breath of life BKV pumped down
those north Texas wells was enough to
temporarily arrest the decline rate of the most
mature of all shale plays. BKV reports that the
Barnett refrac program has generated 371 Bcf/e
of newly proved reserves with a finding and
development cost of $0.79/Mcf/e.
But putting these figures aside, what
else stands out about the campaign is how
it was done.
To rejuvenate many of the vintage
wellbores, the Denver-based operator,
a subsidiary of a Thailand-based energy
conglomerate, said it developed an innovative
approach called the “hybrid expandable
liner system.”
“It is very simply a combination of both
bullhead and liner methods where we attempt
to minimize the downsides and maximize the
positives of both,” Kevin Eichinger, a senior
completions engineer for BKV, explained at a
recent SPE gathering in Houston.
The concept involves installing as little
as a few hundred feet of expandable steel
patches over a well’s original heel-side
perforations to allow for several new plug-
and-perforation stages. The toe-end of the
A refracturing operation in the wellbore is left unlined but new perforations
Barnett Shale—one of hundreds can be added before it is stimulated using a
that BKV Corp. has recently bullhead treatment.
completed in the mature shale
gas play. Source: BKV Corp.
jpt.spe.org 21
FEATURE | Hybrid Refracturing
Chart shows production declines were halted after BKV launched a significant refracturing campaign and workovers
with no new drilling activity. Source: BKV Corp./URTeC 3855094.
In URTeC 3869654 they wrote: “In other basins would have been needed in a full liner installation.
(i.e., Bakken, Delaware, Eagle Ford, etc.) wells Eichinger explained that the patches enabled
drilled in 2017 may be considered ‘older vintage’ “liner‑like pressure handling and pump-down for
wells. In the Barnett, ‘older vintage’ wells are about plug-and-perf operations up to the third cluster
a decade older than that. These small, very early in the well.”
generation hydraulic fracturing treatments present Cemented or packer liner systems could have
a great opportunity for refracturing treatments to also been used in a similar way here to line only a
increase overall well performance.” portion of the well, but expandable patch variants
leave behind larger post-job internal diameters
A Little Patch Goes a Long Way (ID) which the operator found to be a notable
The first well selected by BKV to test the hybrid benefit when running recompletion tools and
refrac concept appeared to be an ideal candidate long‑distance plugs. The expandable system can
since at 843 ft its cluster spacing was more than also be set horizontally which BKV said shortened
twice the basin average. the required liner length and drove costs down.
That combined with a longer-than-average With the patching, BKV’s engineers had a newly
lateral length of about 3,300 ft and a low proppant isolated section more than 2000 ft in length; room
intensity of just 375 lb/ft implied there was plenty enough to squeeze in eight fresh plug-and-perf
of tight gas still hiding behind the pipe. stages with a total of 40 clusters with an average
Thanks to that extra wide cluster spacing, spacing of about 50 ft. By contrast, the single
BKV needed only two expandable liner patches 1,300 ft bullhead stage design included 14 clusters
with a total combined length of 281 ft to cover with an average spacing closer to 100 ft.
the shallowest two clusters of perforated Chemical gas tracers analysis performed
wellbore—or just 8% of the liner length that during the production stage showed 90‑day
Production allocation by stage for the hybrid expandable liner job, using gas chemical tracers.
Source: BKV Corp./URTeC 3855094.
jpt.spe.org 23
FEATURE | Hybrid Refracturing
strings suffering from mechanical integrity issues system’s performance was more closely aligned
or deformation. with that of a full liner job.
But more relevant to some is that as While pointing to a chart showing the
mentioned, liner jobs reduce ID and in a full estimated vs. actual performance data, Eichinger
install that counts for the length of the lateral. said the team concluded that as a hybrid, the
Eichinger related that this issue “isn’t just well performed almost 3 times as well had it been
something that hits you once—ID restrictions hit just a bullhead.
you at just about every point in the operation “As a bullhead-only,” he said, “it would have
throughout the life of the well.” underperformed the fieldwide average; in fact, it
With a tighter ID, Eichinger said operators face would have even underperformed the regional
tough choices on what types of plugs they can run average, but as a hybrid it outperformed the
while still being able to set in the larger diameter regional and fieldwide average of fully lined wells—
casing below the patch and should expect to see and once again, we did this by lining only 8% of
higher treating pressures during a refrac which the well.”
tends to drive up pumping costs. And arguably more One final implication Eichinger highlighted is
important than that, the engineer added that, “when that with the hybrid refrac well proven, BKV has
it’s time to produce, you are producing through that recalibrated its candidate selection process: “Wells
restricted ID with additional flow losses.” with laterals that have really wide cluster spacing
but are too long to bullhead can now be prioritized
Validating a Difference Maker as candidates with higher rankings.” JPT
Another compelling argument that the BKV
refrac study hinges on is a “what-if” scenario FOR FURTHER READING
the engineering team ran to make sure the
hybrid refrac was a true winner. They did this by URTeC 3855094 Hybrid Expandable Liner System:
comparing the well’s actual performance under A Performance-Enhancing, Cost-Effective
the hybrid refracturing treatment to a hypothetical Alternative to Bullhead Refracturing
outcome had a conventional bullhead-style by Kevin Eichinger, Sam French, Ken Day,
treatment been employed. Jared Brady, and Ryan Epperson, BKF Corporation,
Leaning on the gas tracer data once again, and Richard Leonard and Brad Leonard,
a counterfactual performance estimate was ProTechnics, Core Laboratories
generated by focusing solely on the production URTeC 3869654 Integrated Well Performance
from the initial bullhead stage. This effectively Analysis Methodology to Understand
sidelined the contributions the plug-and-perf Production Performance and Identify
stages and means that the bullhead portion Refracturing Candidates in Barnett Shale
of the well would be expected to have similar by Eric Bryan, Rex Richard, Connor Holasek,
performance even if it had been extended to Nima Hosseinpour-Zonoozi, and Dilhan Ilk,
cover the entire length of the lateral. DeGolyer and MacNaughton, and Charles Melvin,
The findings were illuminating for the Kevin Eichinger, Brian Rankosky, Brian Ingalls,
engineering team and showed the hybrid Sam French, and Ken Day, BKV Corporation
jpt.spe.org 25
FEATURE | Lithium Extraction
It Is Easy To Find
Lithium; Turning
a Profit Is Hard
STEPHEN RASSENFOSS, Emerging Technology Senior Editor
F
inding lithium in the water from oil and The race to find lithium is driven by expectations
gas wells is easy. Finding enough to that fast-rising electric car sales will make the lithium
make money is hard. required for batteries in those vehicles a valuable
In the US and Canada there has commodity. Those chasing direct extraction are also
been growing interest in directly betting that their innovations can do what they say.
extracting lithium from the water coming out of Direct extraction from water started looking like
the oil/water separator, which is competing with a real possibility earlier this year when ExxonMobil
more established techniques such as mining and paid $100 million to buy a company holding
evaporating lithium-rich fluids. 120,000 gross acres of leases in south Arkansas.
The price reflected the location in the heart of analyses from the US Geological Survey (USGS)—
the direct lithium extraction industry of the future. some dating back to the 1960s—plus a recent
The area offers a unique combination of lithium- 576‑well survey by the BEG.
rich water plus the infrastructure and expertise The geologists, whose work ranged from hard-
needed to transport, process, and dispose of the rock mining to water research, said this is an early
billions of gallons of water needed for industrial- effort to begin figuring out how to find the lithium
scale mineral extraction. in subsurface water.
Commercial production of battery-quality lithium The survey of past data offers a few places
carbonate in Arkansas is years off. But the sprawling to look for the next Arkansas, starting with the
network of water-producing wells, pipelines, and Smackover in east Texas and elsewhere, as well as
processing that have made the state one of the prospects in south Texas and the Texas Panhandle.
world’s leading bromine producers, lowers the risk The biggest source of US onshore oil production
and cost of commercial lithium production. was not on the list.
The source of the lithium-rich water is the “Unfortunately, there is not much lithium as
Smackover—an oil formation discovered near far as we can tell in the Permian Basin, which is
El Dorado, Arkansas, back in 1921 when a gusher regrettable because there’s so much produced
blew in. A year after that discovery, there were water being pulled out of the ground over there,”
608 producing wells nearby, according to the Nicot said.
El Dorado News-Times. But a consistent message in the report is that
Now with lithium looking like battery gold, it is early in the hunt. At this stage the available
investors are rushing in. In this emotional public data is limited. That and questions about the
market, lithium carbonate prices have swung quality of analyses dating back more than 50 years
like cryptocurrency. led the BEG to do a survey with support from the
As of mid-October, a ton of it was selling for US Department of Energy.
about $25,000. Over the past quarter it averaged The tricky job of getting permission from oil
$32,000/ton. Late last year it stood at $85,000. And companies to sample and test their water was
in 2021 it was going for $10,000, said Graham Bain, done by Kristine Uhlman, a hydrogeologist, who
vice president for subsurface opportunities retired from the BEG some years ago but continues
at Enverus. He offered $25,000/ton as a “go to work on research projects for the bureau.
forward price.” Her pitch to well owners was, “We’ll collect
As with oil and gas, hopes of high prices have your sample and analyze it, and if you have a lot
a way of rapidly increasing supplies, resulting in of lithium, you might make more money from the
price-crashing gluts. So far, most oil companies lithium than you do from the petroleum,” she said.
sound curious but far from committed to lithium. Based on the survey, she wondered if that
“There’s a big rush. I have received several message was exaggerating the chance of success.
requests from companies in the Permian Basin to Only about 6% of the wells had commercial levels
discuss lithium in the water,” said Jean-Philippe of lithium in the water (80 mg/L).
Nicot, senior research scientist at the Bureau of When it comes to lithium claims, landowners
Economic Geology (BEG) at The University of Texas are wise to be cautious, said Laura Capper,
at Austin. principal at EnergyMakers Advisory Group, an
He is the lead author on recent paper that energy industry consultant specializing in water
offered a primer on what’s known about lithium treatment for emerging markets.
brines from oil wells in states from Texas to Based on thousands of water analyses she
Mississippi. It is based on nearly 1,802 water has seen, the average lithium concentrations
jpt.spe.org 27
FEATURE | Lithium Extraction
reported in some industry reports are based on The Smackover in east Texas has some of the
“wishful thinking.” highest lithium concentrations outside of Arkansas,
It some ways it is like the early days of oil, when It has attracted the interest of Standard Lithium,
wildcatters armed with little understanding or tools which is developing a $1.3-billion-plus lithium
for finding oil and gas, drilled a lot of dry holes in production project in Arkansas, the company said
search of a big discovery. on its website.
While the USGS database is the best available But even the Smackover is “not a sure bet”
public starting point for exploration, it has its flaws. everywhere. Nicot said there are wide localized
In the 268 old USGS samples in the Anadarko swings in the test results. The lithium in 12 samples
Basin, the 50 from Texas averaged more than from northern Louisiana, just across from prime
100 mg/L—with the highest numbers concentrated acreage in Arkansas, ranged from less than 5 mg/L
near the Amarillo Arch. On the other side of the to a couple samples exceeding 100 mg/L.
border, Oklahoma averaged less 6 mg/L, the BEG Nicot suspects the differences reflect the
paper said. ability of lithium to travel up to the water-
When the BEG checked on those results by producing formations. “You need a way to
trying to sample “the same areas and possibly the transport the brine because clearly the Smackover
same wells,” the new samples “did not show any is a clean carbonate with no lithium in the rock
Li [lithium] enrichment.” itself,” he said.
The paper concluded that lithium resources One explanation is that lithium comes from
in the Anadarko Basin “need to be more clearly lithium-rich granitic rocks, such as feldspar.
demonstrated.” This theory favors carbonate formations
down near the basement rock because the trip
What Looks Good up is short. Concentrations will vary based on the
Based on the recent BEG review, the most presence or absence of highly conductive faults.
promising spots were the in the Smackover,
ranging from east Texas to Mississippi. Also on
the list were: the gas-producing deep Edwards Lithium Measures Matter
formation in south Texas and, to a lesser degree, Lithium concentrations in brine are measured
gas-producing areas in the Eagle Ford Shale. two ways—ppm and mg/L.
And despite their inability to confirm some In general discussions, 100 ppm and
old positive results in the Anadarko, it is still 100 mg/L are roughly equivalent measures,
a possibility. but not in engineering work.
Shale plays generally lack a feature common to For those working with formulas, this
good lithium water sources, the high permeability matters because lithium is found in fluids with
needed to deliver high volumes of water. A big high levels of dissolved solids—which can
exception is the Permian, particularly in the vary widely—leading to significant differences
Delaware Basin. between ppm and mg/L measures.
While good lithium concentrations have been ppm should be understood as mg/kg—
found in the Marcellus Shale, the water production mg of lithium and kg of fluid whose weight
falls short of what is needed to efficiently extract will vary based on the density of the dissolved
tons of a mineral measured in parts per million solids. A volume measure does not reflect the
(ppm). The same is true in the Haynesville Shale. variability in density.
The Barnett Shale suffers from low lithium Source: Kristine Uhlman, Bureau of Economic Geology.
concentrations.
Carbonates are a plus because they are less likely gas nearby. But these formations would be hard
to combine with highly reactive lithium. to sample because we’re not going to drill 5,000-
There are other origin stories. A paper from or 10,000-ft wells. It just doesn’t make sense at
the Alberta Energy Regulator/Geological Survey this point.”
identified promising areas among deeper strata—
the Devonian. Possible sources of lithium include The Permian Question
granitic pegmatites—an amalgam including In the Permian, old USGS data offered one spot
feldspar. Another source is ancient deposits of that looked extremely promising. A well in the
seawater or meteoric brines that evaporated, northern Delaware Basin—the accompanying
concentrating the lithium. data did not say exactly where—appeared to
The huge gap between the number of have lithium concentrations riveling the best in
produced water samples tested and the number Arkansas—493 mg/L.
of possible formations has left Nicot wanting The problem was other samples from nearby
a lot more samples and the grant money to wells were not nearly as good. The BEG paper said,
collect them. “We believe this isolated concentration might be
Nicot said that he is continually asking well too high by an order of magnitude and might result
owners for water to test “because many formations in a transcription error.”
haven’t been sampled, so we don’t know exactly Even if accurate, that high reading would need
where they are” in terms of mineral content. to be repeated many times over a large area to
On the list of interesting but undrilled deliver the volumes of water needed for lithium
possibilities includes the Smackover in south Texas. extraction. Permian sampling has found relatively
Because an area has not justified drilling by oil low-concentration water in the Wolfcamp, Bone
companies does not mean it is not good for lithium. Springs, and Spraberry formations. But this huge,
“The problem is, you need gas production” deep basin has many horizons to consider.
to justify drilling wells, Nicot said, adding, “You Earlier this year, an emailed report summary
may have high-lithium formations with no oil or from Enverus estimated that five operators in
jpt.spe.org 29
FEATURE | Lithium Extraction
the Delaware Basin could produce from 3,000 to A paper from the Alberta Geological Survey said
11,000 tons of lithium carbonate a year—which previous Canadian papers have set “exploration
at the current price per ton would be worth from threshold values” at a minimum of 75 ppm for
$105 million to $385 million. producing wells, and at an average of 50 ppm as
Based on some quick calculations, Nicot said a regional exploration limit.
that would require lithium concentrations of A review of a 130,000 formation water analyses
around 100 ppm, and the samples he had seen there pointed to lithium levels as high as 130 mg/L
in that area were around 15 ppm. in Devonian carbonates in west-central Alberta.
When asked about the estimates, Bain The paper suggested that like oil exploration, over
said they were focused on the potential of time the industry would get better at identifying
the enormous volumes of produced water top sites for water production.
flowing through Permian pipeline networks. Standard Lithium said it was able to increase
The water from that growing transportation the estimated average lithium levels in one of
network could eliminate two expensive items its Arkansas projects by 52% by tightening the
from the budget for an extraction facility: wells boundaries of its producing area.
and pipelines. On the other side, the prices can rise
For example, a breakdown of the $1.3-billion significantly based on cost overruns, rising
cost of Standard Lithium’s planned extraction interest rates, inflation and the other risks
operation in south Arkansas lists the wells as the associated with scaling up new technology.
highest-cost line item. That plus pipelines equals
nearly one-quarter of the capital cost, and one- Surface Effects
third of the energy cost to run it. Finding a source of lithium water is the gateway to
For big oil companies, extraction could the billion-dollar question: Can you find enough
represent an added source of income. While lithium-rich water production nearby to justify a
lower concentrations would likely mean margins billion-dollar development?
lower than Standard Lithium’s 33% profit (IRR), Unlike oil and gas development, where a
Bain said it could still be “wildly economic.” pipeline connection to the Gulf Coast can make it
He said, “There are going to be other player possible to sell to customers in China, the volume
oil production companies willing to develop of water required for lithium extraction argues for
lower‑concentration sources.” local processing.
Lithium concentration breakevens needed The surface costs shown in Standard Lithium’s
for direct extraction of lithium require educated description of its planned lithium extraction
guesses ranging from details of future lithium project in Arkansas offer a breakdown based
prices to likely performance of new processing on estimates of what they will be if the 2-year
methods. While Nicot uses a 100-ppm limit for construction project begins in 2025 as expected.
breakeven development, sometimes the paper The bottom line looks attractive. The
dropped to 80 ppm. Uhlman said that in China $1.3-billion project is expected to deliver a nearly
45 ppm is used for breakeven. 33% return (IRR) and be worth $3.1 billion (NPV),
Enverus also sees potential in data from both after taxes.
the Alberta Geological Survey. Bain said nine The capital budget for its Lanxess project
companies have been started up to pursue includes 200 miles of pipelines connected to
lithium extraction in an oil- and gas-rich province 64 production and reinjection wells covering
where the highest average concentration 150,000 acres of unitized brine leases. The system
measured is 59 ppm in the Woodbend Group. is expected to handle 3 billion gallons of brine
according to the announcement of that deal. Waters in Texas and Neighboring States.
jpt.spe.org 31
FEATURE | Direct Air Capture
Can Direct
Air Capture Deliver?
BLAKE WRIGHT, Technology Editor
C
arbon removal is one, if not the, hottest the CO2 is compressed and stored in geological
topic in today’s battle over correcting formations deep in the ground, or in some cases,
the global course of climate change, and used to produce low-carbon-intensity products like
direct air capture (DAC) is the current diesel or aviation fuel. The rest of the captured air
darling of the carbon removal space. is returned to the atmosphere.
DAC works to gather CO2 directly from The Biden administration has put its weight
the atmosphere with an engineered system, behind the expansion of DAC facilities in the US.
like how trees absorb CO2 for photosynthesis, The recent Inflation Reduction Act included tax
only faster and with a smaller, but manmade, credits for DAC CO2 as well as broadening the
overall footprint. eligibility of qualified DAC facilities. It decreases
Popular systems use chemical reactions to the amount of CO2 capture requirements from
extract CO2 from the captured air. Once captured, 100,000 tonnes per year to just 1,000.
In addition, the US Department of Energy advance research and development efforts and
(DOE) recently awarded up to $1.2 billion for a pair lower costs.
of DAC facilities in Texas and Louisiana. Energy Big oil is also a leader in the DAC movement,
Secretary Jennifer Granholm called the award a and that doesn’t excite opponents of the
“once-in-a-generation investment.” technology—whether its Occidental’s ownership
When announced in August 2023, it was the of 1PointFive or individual oil company plans to
world’s largest investment in engineered carbon move ahead with their own air capture projects.
removal. The projects—Battelle’s Project Cypress Some see it as a fig leaf for the fossil fuel industry,
and 1PointFive’s South Texas DAC hub—are something that will keep them adding CO2 to
expected to eventually remove greater than the atmosphere as fast, or faster, than they can
250 times more CO2 than the largest DAC facility remove it.
currently operating. Cost also remains a challenge for the nascent
The US government isn’t the only entity putting technology. Today, it is the most expensive method
their money where their mouth is when it comes of removing CO2 from the air. According to the
to DAC. Some of the most active investors read like International Energy Agency (IEA), future capture
a who’s who of the tech industry. cost estimates for DAC are wide-ranging and
Microsoft has signed on to use Climeworks uncertain, reflecting the early stage of technology
services and agreed to purchase up to development, but are estimated at between $125
315,000 metric tons of CO2 removal from Heirloom and $335 per tonne of CO2 for a large-scale plant
Carbon Technologies. Climeworks operates a built today. Smaller facilities, depending on the
DAC plant in Iceland. It is one of the biggest technology deployed, have top-end cost estimates
globally, capturing and storing 36,000 mtpa of of $600/tCO2 and higher. With deployment and
CO2. Both Climeworks and Heirloom are partners innovation, capture costs could potentially fall to
in Project Cypress. under $100/tCO2.
Climeworks’ estimated $12-million Orca There is a US federal tax credit supporting
plant came online in September 2021 and is DAC today dubbed 45Q, which provides up to
due to capture 4,000 tonnes of CO2 from the air $35–50 per tonne of CO2 captured through DAC
every year—equivalent to the emissions from and carbon capture at point sources ($50/tCO2 if
about 870 cars. The captured CO2 is then mixed the captured carbon is sequestered underground
with water and injected into basalt rock 1 km and $35/tCO2 if it’s used for enhanced oil recovery
underground, where it slowly turns into a solid or elsewhere). Additionally, there have been several
carbonate mineral over a 2-year period. legislative proposals to enhance 45Q by providing
Amazon is purchasing 250,000 metric tons of higher credit values and extending its timeline.
carbon removal credits over a 10-year period from According to the IEA, 27 DAC plants have
1PointFive’s $1-billion Stratos DAC project in Ector been commissioned to date worldwide, capturing
County, Texas, and investing in CarbonCapture Inc. almost 0.01 Mt CO2/year. Plans for at least
The DAC investment is part of Amazon’s Climate 130 DAC facilities are now at various stages
Pledge to reach net-zero carbon emissions by 2040. of development (Fig. 1).
In April, online payment firm Stripe teamed
up with Google parent Alphabet, Facebook Oxy’s Billion-Dollar Bet
parent Meta, Shopify, and McKinsey to launch an Occidental has been one of the more active oil
initiative called Frontier, which plans to purchase companies in DAC. In 2020, the company formed
$925 million worth of carbon removal by 2030 1PointFive, a development company to finance
from carbon removal companies in an effort to and deploy large-scale DAC technology matured
jpt.spe.org 33
FEATURE | Direct Air Capture
Mt CO2
amount of CO2 captured. The solution is then
60 Operating capacity
Advanced development
pumped into a pellet reactor where it is combined
50
Early development with calcium hydroxide and forms pellets of
40 NZE
calcium carbonate that hold the CO2. The pellets
30 are then dried, and the potassium hydroxide liquid
20 is filtered and recycled back to the air contactors
10 for reuse.
0 The pellets are then moved to a calciner
2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030
where they are exposed to high temperatures and
Fig. 1—CO2 capture by direct air capture, planned converted into calcium oxide and CO2. The CO2
projects and in the Net-Zero Scenario 2020–2030. is sent off to be compressed and either stored or
Source: IEA.
utilized in the creation of low-carbon products.
The calcium oxide pellets are recycled back into
by carbon removal specialists Carbon Engineering. the process via a slaker where mixed with water it
This past August, Oxy inked a definitive purchase becomes calcium hydroxide that can be returned
agreement to acquire all the outstanding equity of to the pellet reactor and reused to create new
Carbon Engineering for a total cash consideration calcium carbonate pellets.
of $1.1 billion. Oxy has a pair of DAC facilities that are
“This is an important step for our company currently advancing through the permitting and
as it will enable us to accelerate our mission construction process—the South Texas DAC Hub
to lead the world in the large-scale removal of and Stratos in the Permian Basin.
carbon dioxide from the air and help advance For the South Texas DAC Hub, 1PointFive
our shift to a sustainable, net-zero society,” has partnered with the historic King Ranch to
said Daniel Friedmann, chief executive of gain access to 106,000 subsurface acres with
Carbon Engineering. “This transaction will surface access that could support a DAC and
dramatically enhance our ability to continue sequestration hub with up to 30 mtpa of CO₂
developing the technology through to widespread removal through DAC and a storage capacity of
commercialization.” 3 billion metric tonnes. Preparations are underway
Occidental has been working with Carbon to drill test wells at the site to gather geologic data
Engineering on DAC deployment for a half decade. required to obtain a Class VI well permit to safely
According to the company, acquiring Carbon sequester CO2.
Engineering aligns with its integrated net‑zero “At the South Texas DAC Hub, CO2 will be
strategy and provides Occidental, through sequestered in saline formations not associated
1PointFive, the opportunity to rapidly advance with oil and gas production,” said Michael Avery,
DAC technology breakthroughs and accelerate president and general manager of 1PointFive.
deployment of DAC as a large-scale, cost effective, “For Stratos, we have multiple options for captured
global carbon-removal solution. CO2 from DAC, including offering CO2 removal
Carbon Engineering’s DAC system begins credits generated from pure sequestration of
with a series of large fans that pull air into an air CO2 in saline reservoirs. We have announced
contactor where it is absorbed into a solution of agreements with Amazon, Airbus, ANA Airlines,
potassium hydroxide and water, which bonds to the Houston Astros, and the Houston Texans, all of
CO2. The bonding occurs as the air moves across which will be designated for sequestration only.”
a PVC packing system that resembles a honeycomb “We have always believed that global
and is designed to increase the surface area and partnerships and cross-industry collaboration
Oxy, led by Vicki Hollub (center), and its partners in the Stratos DAC held a groundbreaking ceremony for the new
facility on 28 April. Source: 1PointFive.
jpt.spe.org 35
FEATURE | Direct Air Capture
Artist rendering of the Stratos DAC facility currently under construction in the Permian Basin, Ector County, Texas.
Source: 1PointFive.
reducing the time it takes to absorb CO2 from This past August, Shell announced its decision
years to just 3 days. to build a DAC industrial-scale demonstration
Heirloom heats limestone mineral powder unit at the US Shell Technology Center Houston
in a kiln to remove the CO2. The powder is then (STCH). With targeted startup in 2025, the company
spread onto vertically stacked trays where aims to prove the technical viability of its in-house
algorithms inform how to treat the limestone to developed solid sorbent technology.
optimize its ability to uptake CO2. The limestone In 2020, Shell researchers consolidated their
powder is looped through the system to learnings and began a dedicated technology
continuously draw CO2 from the atmosphere. program to develop efficient, robust, and low-
The cyclical process not only reduces costs but cost solid sorbents and a matching process
also reduces how much mineral must be mined, design. In parallel, the team investigated DAC
according to Heirloom. demonstration opportunities and scale-up
By siting Project Cypress in a region with strategies. In July 2023, the decision was made
a history of fossil fuel production and related to start the construction and operation of an
industrial activity, project developers intend industrial-scale demonstration unit that will test
to leverage the existing workforce that has the technical viability and performance of Shell’s
transferable skill sets to construct and operate DAC process. The demonstration is designed to
the facility. The result will bring fossil energy provide the data required to prove the viability
employees into the energy transition and jobs of Shell’s DAC technology at scale, which would
to southwest Louisiana. enable the capture of larger amounts of CO2. The
Supermajor Shell is taking a more disciplined company believes the solid sorbent technology has
approach in pursuing carbon management a high potential to become a techno-economically
technology and projects, keeping a clear line of competitive solution.
sight to profitable returns and the emergence of Originally initiated with a handful of scientists,
supportive regulatory policies in wider markets. engineers, and technology experts in the
That said, the oil company does believe that Netherlands, Shell’s DAC program currently spans
widespread deployment of carbon management four of Shell’s main tech hubs, including the Shell
technologies such as carbon capture and storage Technology Centre Bangalore in India; STCH in
and DAC is significant to the energy transition Texas; Shell’s Energy Transition Campus Amsterdam;
as a whole. and Shell TechWorks in Boston, Massachusetts.
Shell is also involved with the Pelican equipment or energy. So, I’m not sure what the
Consortium, which includes the University of purpose is.”
Houston and LSU. The group is evaluating the In addition to the carbon removal facility
feasibility of building a DAC hub in Louisiana. itself, each must also have pipelines associated
The consortium will focus on evaluating the with it to move the captured carbon to its final
potential for scaling up and deploying multiple resting place, usually deep underground. That new
DAC technologies and address some of the most infrastructure also adds to the system’s overall
challenging aspects of DAC: energy and water carbon footprint.
consumption and land use. “CO2 is very diluted in the air,” added Jacobson.
In August, the DOE awarded grant funding “To extract it you need chemicals and energy. In
to support the $4.9-million first phase of the the best cases, that energy is renewable energy.
Pelican Gulf Coast Carbon Removal study. But there’s a finite amount of renewable energy
available, and if we use renewable energy to run
The Challenges Are Real direct air capture equipment, just like if we use
According to the IEA, capturing CO2 from the renewable energy to run Bitcoin mining, we can’t
air is the most expensive application of carbon use that renewable energy to displace fossil fuel
capture. The CO2 in the atmosphere is much power plants.”
more diluted than in, for example, flue gas from Breakthroughs in DAC are still anticipated and
a power station or a cement plant. This contributes needed to make it more economic and sustainable,
to DAC’s higher energy needs and costs relative to such as lowering the overall energy intensity of
these applications. the removal process. Scalability is also required to
Trees are nature’s CO2 removers, and they are make the impact proponents are advertising. DAC
very good at it. However, it takes more than just also needs a more robust regulatory framework to
planting new trees to meet the targeted carbon- guide and incentivize growth; the lack of governing
free goals of both international governments and policy could stunt broad adoption.
many in the private sector. This requires manmade DAC may be the flavor of the month when it
facilities that while designed to remove carbon comes to carbon capture and storage today, but
from the air, have their own carbon footprint it is clear that the technology needs maturity and
in all phases of development—from design and financial incentives to live up to the commercial
construction to operations. promise those actively pursuing it believe
DAC is not meant to replace cutting emissions it holds. JPT
or to be used as an excuse to kick the can down
the road, but can it be an important part of FOR FURTHER READING
the equation?
“I don’t think it fits at all, in any equation,” said SPE 216660 Innovative Molecular Sponges:
Mark Z. Jacobson, a professor in the Department Next‑Generation Direct Air Capture
of Civil and Environmental Engineering at Stanford Technology Enabled by Metal-Organic
University. “It flat out increases carbon dioxide. Frameworks by A.J. Cruz, I. Parrella, G. Wenz,
It increases air pollution, fossil-fuel mining, and J. Storey, and J. Husk, Baker Hughes.
increases fossil-fuel infrastructure. There’s a simple SPE 215735 Solid Sorbent Direct Air Capture Using
reason for that: it requires energy and equipment. Geothermal Energy Resources (S-DAC-GT)–
It is synthetic carbon capture because you need Model for Region Specific Economic Analysis
equipment and energy to run it vs. natural direct by Timur Kuru, Keivan Khaleghi, and Silviu Livescu,
air capture, such as trees, which don’t require University of Texas at Austin.
jpt.spe.org 37
DRIVING CHANGE
Cultivating an Energy Workforce
for Lasting Prosperity
JENNIFER PRESLEY, Senior Technology Editor
FEATURE | Energy Workforce
T
he old phrase “many hands make light
work” is never truer than when applied
to the energy industry. It illuminates the
world’s darkest corner and energizes its
sluggish economies. Millions of hands also work
together to ensure the power is there to keep the
lights on and global markets humming.
Many also have had a hand over the past
century in building the oil and gas industry into
the multitrillion-dollar industrial sector it is today.
Ironically, it is an industry where a new hire starts as
a “worm,” earns the title of “hand,” and then possibly
ends their career decades later as a “top hand.”
These hands—the industry’s human capital—
are the most important resource in the highly
complex and technical oil and gas industry. From
the oil field to the C-suite, the collective knowledge,
attributes, skills, and experience of the workforce
that inhabit each are critical to ensuring the
industry’s long-term sustainability and future.
According to a recent Accenture study, the
energy industry will experience a lack of up to
40,000 competent workers by 2025. A 2018 study
by Korn Ferry predicted that up to 85 million jobs
could go unfilled due to skilled shortages. EY
reported that Gen Z and Millennials will make up
72% of the world’s workforce by 2029, yet 62%
stated that they find a career in the oil and gas
industry unappealing.
The oil and gas industry is at a crossroads in an
era of rapid technological advancements, shifting
global energy demands, and heightened concerns
over affordability and security. Evolving job
expectations, demographic shifts, and the growing
emphasis on sustainability are expected to play a
pivotal role in shaping the future of the sector.
Technological Advancements
and Changing Job Expectations
The growing renewables sector Amidst this evolution, one of the industry’s
presents an alternative career most pressing challenges is the retention of its
option for the oil and gas skilled workforce. The seasoned professionals
industry’s talented and skilled and specialized experts who have long been the
workforce. Source: Getty Images. backbone of this vital sector are now presented
jpt.spe.org 39
FEATURE | Energy Workforce
~2.3%
~1.0%
US energy transmission capacity would need to more than double to reach the IRA’s full renewable power generation
potential. Source: Bain & Company.
with an attractive alternative for those looking to has necessitated upskilling and reskilling, making
make a change. talent retention a strategic priority for the industry.
The sector is transforming as renewable energy A recent Bain & Company survey of 600
sources gain prominence and environmental executives revealed that finding talent to advance
concerns mount. There is no shortage of big, bold technologies for energy transition is among the
plans to address the energy needs of the future, top concerns among executives in oil and gas,
but it is a future made possible by a workforce utilities, chemicals, mining, and agribusiness. Talent
possessing diverse tools and technical skills. shortages, especially for technical experts, are
“Workforce preferences are changing, slowing down progress.
competition for talent is growing, and many industrial The three most important technologies for
sectors now find themselves competing for many 2030 will be renewable energy, digital, and energy
of the same skills,” said Evelyn MacLean, workforce storage. Sixty-seven percent of executives in the
energy project director for the International Middle East expect low-carbon hydrogen to be
Association of Oil and Gas Producers (IOGP). significant by 2030, according to Bain & Company.
“Our industry also has a reputation challenge The survey found that digital and information
that is damaging our talent pipeline, and therefore, technology talent is at a premium, with about 60%
we have work to do collectively to promote our of executives expecting digital and AI technologies
industry as a viable career choice for anyone who to change their businesses significantly by 2030.
wishes to contribute to energy sustainability, Still, they’re struggling to find the talent that
affordability, and security positively,” she added. can help manage the change. Nearly 40% of the
Technological advancements are transforming executives surveyed said they have trouble finding
the oil and gas industry, giving rise to new job digital and IT talent.
roles and changing expectations. The advent of Let’s consider, for example, the impact of the
automation, artificial intelligence (AI), and advanced US Inflation Reduction Act (IRA) on the number
data analytics has shifted the focus from manual of electricians employed by the drilling sector.
labor to high-tech skills. This digital transformation The demand for electricians will increase as the
adoption of robotics and automation on drilling “Furthermore, digitizing workflows and using
rigs accelerates. Pressure on this demand will generative AI requires a symbiosis between
also rise in the years ahead due to infrastructure humanity and tech—one is enabled by the other.
improvements brought about by the IRA. There’s a lot of excitement about digital across
According to Bain and Company estimates, our industry, which is positive, but we should also
to support the buildout of US power grids from link the discussions to envisioning organizations in
2023 to 2031, about 80,000 new electricians must 2030,” said MacLean.
be added to the workforce each year. The drilling However, the magnitude of this challenge
sector is just one of many that will be challenged to is significant. The younger generation, who are
retain its workforce and recruit new talent. digital natives, have career aspirations and values
Out of the 10,000 energy professionals different from their predecessors. They seek
surveyed for the 2023 Global Energy Talent Index purpose-driven work, learning opportunities, and
(GETI) Report, 80% said they’ve been approached personal and professional life balance. Companies
for another job in the past year, with 40% of those are rethinking their talent management strategies
saying more than a quarter of the approaches to align with these evolving expectations.
came from an outside industry or expertise. Ten
percent have been approached 16 or more times Demographic Shifts and the Talent Gap
to apply for a position outside their company. Demographic shifts are another critical factor
“The digitalization and diversification of impacting talent retention in the oil and gas
industry portfolios mean the workforce increasingly sector. The industry is witnessing a talent gap
has skills synergies with other sectors, such as as experienced professionals retire and fewer
technology, that make them appealing,” said young people opt for careers in oil and gas. This
Ilda Andaluz, executive vice president of global generational shift exacerbates the industry’s talent
human resources at Varel Energy Solutions. “Yet crisis, threatening its sustainability and success.
this is also an opportunity to attract talent from To bridge this gap, the industry must attract and
new industries.” retain the next generation of talent. This involves
The IOGP’s MacLean views the scale of creating an inclusive and diverse work environment,
potential growth expected in the demand for offering competitive benefits, and providing
skills in the modern era as being like the demand opportunities for growth and development.
experienced during the first Industrial Revolution. According to MacLean, the oil and gas industry’s
“Achieving net-zero emissions by 2050 diversity, equity, and inclusion metrics lag others,
represents a civilization-wide transformation of noting that when “combined with our reputational
the energy system and a generational opportunity headwinds, there is no room for complacency.”
for many energy and natural resource companies,” “Even though we enjoy a multi-generational
she said. “It will require millions of new workers to workforce in many areas today, the reality is that
change over tens of millions of pieces of machinery Gen Z and Millennials, who will make up 72% of
and equipment across both the energy and raw the workforce before the end of the decade, don’t
materials systems and to develop hundreds of find our industry appealing,” she said. “Leadership
mines and supply chains for raw materials.” is needed to recognize the situation, promote
She added that the current spate of collaboration as an overall sector, become more
investments in renewables worldwide will continue in tune with the changing workplace preferences,
to strain available workforce capacity, with multiple and work on our attractiveness.”
forecasts predicting scarcity in STEM skills and MacLean noted that multiple actions could
many other areas. positively change the current trends, including
jpt.spe.org 41
FEATURE | Energy Workforce
Executives in the energy sector see talent as a top issue over the next decade
% of respondents who ranked as top three choice
50
41 40
40
34
32
30
22
20
10
0
Image of Energy Attract Organizational Maintaining Adequate Adopting
the industry transition and retain cost and social license capital new ways
workforce complexity to operate of working
The major issues facing the energy industry according to a poll of industry executives. Source: IOGP and Bain & Company.
cultural transformation to cater to more diverse parties to contact us. The committee’s 2024
workforces, investment in training programs and business plan includes introducing five expert
platforms, boosting labor mobility, and providing groups to focus on various activities, from sharing
greater access to technology and the skills best practices to creating multiple deliverables to
development to use it. drive improvements in key areas.”
The IOGP Board in 2022 commissioned a According to the GETI Report, the in-demand
baseline study of workforce challenges, finding workforce is increasingly empowered to seek
that there is a “tremendous need for a growing moves based on personal interests, values, and
workforce that is deeply engaged in solving the career opportunities. Eighty-five percent of those
once-in-a-generation challenges presented by the surveyed said they are considering switching to
energy transition.” another role. Career progression remains the
Additionally, it found that workforce dynamics primary driver; interest in the wider industry and
are quickly changing with the influx of younger ESG are the second and third most influential
talent with different demands and expectations factors, at 14% and 11%, respectively.
from work. Employees are seeking what the report
“The board endorsed the introduction of identified as “sectors at the vanguard of
a standing Workforce Energy Committee, a sustainability and innovation,” with renewables
significant milestone, and will be the first of its kind cited as the most popular energy sector at 49%
industrywide collaborative effort to address the and technology at 27% as the most popular
multifaceted challenges we face,” said MacLean. outside the industry to join.
“The goal is to launch the committee in the first “The future war for talent will be fought on
quarter of 2024, and we invite any interested wider terrain from decarbonization to diversity, as
the sector must broaden its skills base by appealing GETI report on addressing and possibly reversing
to new competitor sectors from renewables to those choices include upskilling and diversifying
technology,” the report said. the workforce to create more cost-effective ways
An often-flagged talking point in the energy to boost skills amid rising supply chain and labor
transition debate is the potential loss of good-paying costs. Doing so would help boost talent retention,
jobs in the fossil fuel sector being offset by jobs in as career progression is a leading driver for
the renewable energy sector. The IRA, for example, career changers.
could create some 9 million jobs connected to MacLean sees influencing the workforce of
the Biden administration’s climate, energy, and tomorrow beginning at an early age if “we are
environmental justice programs, helping to absorb to secure the skills and talents needed in years
some of the displaced fossil fuel workers. to come.”
A study conducted by researchers at the “We need to tackle our culture and deeply
University of North Carolina, the College of ingrained biases and emerge with a more
Management and Technology in Switzerland, compelling commitment to tackle our diversity and
and the University of Pittsburgh, published in inclusion shortfalls. Make it a priority to evaluate
September 2023 in Nature Communications, the ‘how’ and the ‘what’ during performance
reported that the phaseout of fossil fuels by reviews to heighten awareness on building the
2050 could displace up to 1.7 million fossil fuel necessary behaviors to lead multicultural teams
workers in the US and many more globally. in this modern world,” she said.
Using job transition data from the US Census “It is easy to bury our heads in the sand and not
Bureau and skills data from the US Bureau of think about leaving the industry adequately staffed
Labor Statistics, the study assessed whether after our time, but I invite everyone to reflect
people employed in what it identifies as “fossil on how they may contribute to leaving a lasting
fuel resource extraction” are co-located and have legacy in the form of a talent pipeline to ensure
transferable skills to switch to green jobs. energy sustainability, affordability, and security,”
They found that the workers could leverage said MacLean.
their mobility and switch to green jobs. However, Talent retention is a critical factor in navigating
the researchers noted that many of these workers the crossroads of the oil and gas industry. Amid
are not located where green energy production rapid technological advancements, environmental
occurs and are mostly not located in regions where concerns, and shifting global energy dynamics,
green employment will grow despite attaining the the industry’s sustainability and success depend
appropriate skillsets. on its ability to cultivate and nurture a skilled and
“While stakeholders focus on re-skilling fossil knowledgeable workforce. JPT
fuel extraction workers, the analysis shows that
co-location with emerging green employment FOR FURTHER READING
will be the larger barrier to a just transition,” the
researchers said. Location Is a Major Barrier for Transferring
US Fossil Fuel Employment to Green Jobs
The Way Forward by J. Lim, University of North Carolina at
The oil and gas industry’s reputation has impacted Chapel Hill; M. Aklin, College of Management
the choices of young generations and those of and Technology; and M. Frank, University
employment age. Recommendations from the of Pittsburgh.
jpt.spe.org 43
CASE STUDY
O
ver the past 10 years, bismuth plugs creating a barrier that can last forever or be
have been used more often to solve classified as “eternal.”
complex downhole integrity issues and Compared to existing traditional sealing
to permanently abandon wells, both on technologies, a bismuth plug requires a
and offshore. As bismuth technology is significantly shorter seal, resulting in less materials,
relatively new to the market, it often needs to be section milling, and time needed for deployment.
qualified in-country before use on a larger scale. For example, a traditional cement plug might need
This is a significant barrier to the adoption of new to be hundreds of feet in length where a bismuth
technologies in general within the industry and plug can be set at as little as 6 ft.
not unique to the use of bismuth as a permanent
sealing barrier. Field Test—Context, Challenges,
Bismuth and bismuth-based alloys have and Methodology
unique properties that allow them to be used as In May 2023, BiSN was contracted to fulfill a rigless
a sealing material that has the potential to change plug and abandonment (P&A) campaign for Sasol
the industry. It has a specific gravity of 10 which in Mozambique. Before proceeding, BiSN and
means it is 10 times denser than water. In molten Sasol worked together on a well in Mozambique to
form it can displace any fluid in the wellbore. Not qualify BiSN bismuth technology as a permanent
only is it dense but in its molten form it also has abandonment solution in the country.
a viscosity like water, which means it can flow The well chosen for the seal test had several
easily and through perforations, cracks, crevices, complicating factors including the need to set the
or any micro annuli without the need of any seal in open hole through perforations and the thin
pumping equipment. caprocks located in the region.
The most interesting property however The overall goal of the field test was to isolate
is its ability to expand on solidification. BiSN gas-bearing silt from shallower formations by
uses proprietary thermite heaters to melt forming an effective seal. To accomplish this, the
bismuth‑based alloys downhole, which then bismuth plug was required to be set with a 10-m
flow into the annulus through perforations shale window identified by Sasol as a suitable
or section milled windows taking the shape location to set a regional seal to essentially restore
of volume they are filling up. The alloy on the caprock. Previous explorations had revealed
solidification then expands (like ice) which areas of patchy cement from earlier P&A attempts.
creates the gas-tight seal against the surface The methodology of the trial was designed
it is expanding. These alloys not only create around a typical run of bismuth technology with an
a solid mechanical barrier but are also highly extra two steps: the running of ultrasonic cement
corrosion resistant to H2S, CO2, acids, and other evaluation (USIT) and cement bond logs (CBL) to
wellbore fluid that might be present, thereby establish pre- and post-deployment well conditions
Cement repair tool being prepared prior to being run in hole. Source: BiSN.
by an independent petrophysics company. These gun run had been achieved, a 33-ft BiSN Wel-lok
two steps would confirm the results beyond a cement repair tool (CRT), used to set the bismuth
doubt by two different, independent tests to verify plug, was run in hole at 15 m/min and activated
the placement, strength, and any contaminants of by a timer set at 3 hours and hydrostatic switch
the plug during the setting process. by BiSN personnel. After the melting process was
After completing the initial logging tests on completed at 16 minutes, the heater was pulled
13 May, a scraping operation was conducted on out of hole at the rate of 15 m/min, leaving behind
the 9⅝-in. casing to eliminate potential debris a molten pool of alloy, allowing the bismuth alloy
or pathways for leaks. A perforating gun was plug to cool off and fully solidify and create a gas-
meticulously selected, featuring the desired tight seal. The process of deployment, from rig-up
exit-hole diameter and shot density to achieve to rig-down was achieved in 5 hours and 5 minutes.
the necessary flow area for the molten bismuth The 9⅝-in. casing was then milled out to validate
alloy to exit into the annulus. The perforating the bismuth plug set in the 9⅝×12¼-in. annulus.
procedure serves a dual purpose: it establishes The sequence of operations is shown in Fig. 1. The
a pathway for the alloy to access the annulus, final step of the field trial was then completed by
and simultaneously rubblizes the cement behind running the post-deployment USIT and CBL logs to
the casing, creating multiple fractures which determine the effectiveness of the set bismuth plug
then intersect small leaking gaps or micro annuli in the well on 15 May.
within the cement. This creates a flow path for
the alloy to flow into all those fractures and micro Field Test Results
annuli and seal off any gas migration through the The BiSN placement was confirmed by two
cemented annulus. independent logs—USIT and CBL. Review of the
A 1-m section was then perforated in the 9⅝-in. logs was done by independent petrophysicists,
casing, and once confirmation of the perforation and comparison between logs acquired pre- and
jpt.spe.org 45
CASE STUDY
deployment in the
planned zone (Fig. 2).
There was also a
good agreement
between the CBL
and USIT logs, which
are two completely
independent tools,
further substantiating
the success (Fig. 3).
The log is also fully
circumferential around
the casing, verifying
the absence of any
channelling (Fig. 4).
This analysis shows
beyond any reasonable
doubt that the caprock
restoration objective
has been achieved, confirming that the BiSN alloy
filled all available void space, even in regions within
claystone caprocks. The application of bismuth
technology also allows the abandonment of wells
with integrity issues, offering promising solutions
for environments where there is gas trapped under
shallow barriers. The successful results of the
field test allowed for bismuth plug technology to
be qualified for future use in Mozambique for the
effective P&A abandonment of wells.
Conclusion
The adoption of Wel-lok technology led to
several benefits, including improved long-term
abandonment integrity, reduced carbon footprint,
overall cost savings, and the elimination of the
need for extensive section milling. As a result,
significant rig time was saved and health hazards
Fig. 1—Sequence of operations. Source: BiSN.
for rig personnel were mitigated. Additionally,
the CRT effectively eliminated sustained casing
post-placement confirmed successful deployment pressure and vent flows in cemented annuli
of the plug. without requiring surface pumping pressure.
There was a clear difference over the zone This successful collaboration between
where the plug was placed and a very substantial BiSN and Sasol serves as a testament to the
change in impedance, showing a successful effectiveness in revolutionizing P&A practices,
Fig. 2—Comparison of CBL tests, pre- and post-deployment, run by an independent petrophysics company. Source: BiSN.
Fig. 3—Good agreement between CBL and USIT logs. Source: BiSN.
jpt.spe.org 47
CASE STUDY
AUTHOR
Fig. 4—Confirmation of good circumferential placement
Didhiti Talapatra, special
of a BiSN alloy plug. Source: BiSN.
projects engineer, plays a
vital role in BiSN providing
with promising potential for broader application technical solutions for
in the oil and gas industry. The results underscore the sales team to respond
the importance of continued utilization of this effectively to operators.
technology in future P&A operations, further Having worked with BiSN for
solidifying the company’s role in enhancing the 8 years, he is the technical expert in
efficiency and environmental responsibility of well the application of Wel-lok technology for P&A and
abandonment processes. JPT well interventions.
SUBMIT NOW AT
GO.SPE.ORG/SUBMIT-NOW-24
T
oday, the industry faces tremendous
challenges related to safety, efficiency,
“Drilling and completion
sustainability, and socioenvironmental fluid selection is a complex
responsibility. At every stage, well- process in which addressing
construction projects must be concerned about
those aspects to establish measurable barriers
future downhole conditions
for preventing issues. Therefore, drilling and for predicting potential
completion fluids are critical for achieving project problems is vital to eliminating
goals and ensuring operations are executed nonproductive time.”
as planned.
Drilling and completion fluid selection is a
complex process in which addressing future
downhole conditions for predicting potential (ECD) as low as possible while preventing formation
problems is vital to eliminating nonproductive damage. Paper SPE 211539 describes several
time. Conventional deep high-pressure/high- successful applications of low ECD organophilic
temperature wells in South sub-Andean Bolivia or clay-free inverted emulsion fluid in reaching project
unconventional long horizontal wells in Argentina goals in challenging environments.
are pushing drilling-fluid design to its limits with On the other hand, constant monitoring of
regard to keeping equivalent circulating density drilling-fluid properties also is necessary. Fluid
jpt.spe.org 51
TECHNICAL PAPERS | Drilling and Completion Fluids
The complete paper describes the success of respectively. A unique gel structure is provided
using a new low-equivalent-circulating-density by the use of the polymeric viscosifier in the
(ECD) organophilic clay-free inverted emulsion oil-based drilling fluid. Also, it not only increases
fluid (OCIEF) in gas reservoirs at elevated cuttings-carrying capacity but also helps to increase
temperatures and with differential pressures barite sag resistance in the fluid. In the absence
up to 4,500 psi. The objective of the paper is to of low-gravity solids in terms of organoclay and
highlight the superior performance of OCIEF organolignite, an OCIEF shows low plastic viscosity
over barite-based conventional invert-emulsion and a higher rate of penetration compared with
drilling fluids and formate-based, water-based conventional organoclay-based oil-based muds.
drilling fluids in the study. The fluid overcame In the OCIEF described in the paper, the solids
challenges in such an environment without content has been further reduced by replacing the
compromising performance. barite (4.2 SG) with manganese tetroxide (4.8 SG).
The acid solubility of manganese tetroxide would
Introduction make the drilling fluid nondamaging, especially for
The new low-ECD OCIEF, using manganese reservoir zones.
tetroxide as the weighting agent, was developed
with an aim to offer improved drilling performance Formulation of Low-ECD OCIEF. The OCIEF was
in maturing fields. Its nondamaging nature, the designed for long lateral sections where low
result of the presence of the acid-soluble and rates of penetration (ROPs) can be observed in a
micronized manganese tetroxide, would help to slimhole drilling environment with a bottomhole
complete the well with an openhole design. temperature (BHT) of approximately 300°F.
In an OCIEF, the organophilic clay and The OCIEF was tested for drilling in high-static
organophilic lignite are replaced by a polymeric overbalance conditions (3,000–4,500 psi) and
viscosifier and a polymeric filtration-control agent, had to be resistant to potential contaminants.
The OCIEF was formulated with the acid-soluble
manganese tetroxide with a water-phase salinity
This article, written by JPT Technology Editor Chris Carpenter, of 200,000–250,000 ppm.
contains highlights of paper SPE 211539, “New Low- Two 95-lbm/ft3 OCIEFs were formulated.
ECD Organophilic Clay-Free Inverted Emulsion Fluid The 95-lbm/ft3 OCIEF 1 was developed with an
Weighted With Manganese Tetroxide Showed Superior engineered bridging package of variously sized
Performance in Different Fields: Success Story of Drilling
With OCIEF in High‑Overbalance Environment Without
Downhole Problems, Stuck-Pipe Events, and Nonproductive
For a limited time, the complete
Time,” by Vikrant Wagle, SPE, Abdullah Yami, SPE, and
paper is free to SPE members
Abdullah Al Moajil, SPE, Saudi Aramco, et al. The paper
at jpt.spe.org.
has not been peer reviewed.
jpt.spe.org 53
TECHNICAL PAPERS | Drilling and Completion Fluids
target reservoir holding an 89° inclination and screens were picked up and run in hole to the
302° azimuth. bottom successfully.
Field Deployment of OCIEF: Drilling Phase. The OCIEF and PST Fluids Observations.
planned OCIEF density was increased from 85 to Increasing OCIEF density from 92 to 95 lbm/ft3
88 lbm/ft3 to provide additional wellbore stability at 16,225-ft measured depth with direct
as observed in offset wells. A total of 1,686 bbl additions of water-wet micronized weight
of OCIEF fluid was mixed at 70/30 and sheared material to the circulating system led to an
on surface. increase in plastic viscosity and increased demand
The 5⅞-in. drilling parameters were 70– on free emulsifier dosages. The subsequent
100 rev/min, a weight on bit of 14,000–19,000 ft‑lbf, addition of emulsifiers and increased oil
flow rates of 240–260 gal/min, and torque of content decreased plastic viscosity. Fluid-loss
5,000–7,200 ft-lbf. First, the drilling assembly was additive and bridging concentration had to be
run with a 7-in. shoe track to drill 10 ft of rat hole increased to mitigate the effect of increased oil
with 109-lbm/ft3 conventional oil-based fluid from and emulsifier treatments.
a previous 8⅜-in. interval. Then, 30 bbl of high-
viscosity 88‑lbm/ft3 OCIEF spacer was pumped Conclusions
to displace the conventional oil-based fluid. The The authors write that they have used the
88-lbm/ft3 OCIEF high-viscosity spacer was followed oil‑based fluid for more than 25 applications to
by 88-lbm/ft3 OCIEF. The 5⅞-in. hole was drilled at date in 10 different fields and in both vertical
an azimuth of 302° and an inclination of 88° at a and horizontal 5⅞-in. slimhole well designs at
controlled ROP (10–28 ft/hr). different static overbalanced conditions. Drilling
Early in the drilling phase, a pressure spike performance with the OCIEF has been satisfactory,
was noted with increased torque and the and no stuck-pipe events have been documented
drillstring stalled. The density was increased during drilling or completion operations.
from 88 to 92 lbm/ft3 to prevent stuck pipes. The wells drilled with this fluid have
Later, logging while drilling showed indications experienced a reduction in invisible lost time
of formation breakouts, which also are a when compared with wells drilled with formate
good indication of geomechanics issues and fluids in offset wells. This reduction in visible
potential mechanical stuck pipe. The fluid lost time is shown in elimination of reaming
density was increased to 95 lbm/ft3 to continue trips (of between 12- and 24-hour duration)
drilling successfully. on wells drilled with formate fluids and other
A scraper assembly of 9⅝×7 in. was run in conventional fluids. No instances of stuck pipe as
hole with tandem pills for sweeping. Then, a the result of improper fluid properties (e.g., sag,
5⅞-in. cleanout assembly was picked up and run high viscosity) have been recorded. The fluid
in hole. Good hole conditions existed, and no also has been reused successfully in drilling
tight spots were recorded. A viscous spacer was additional wells with minimum treatments based
pumped ahead of the 120-bbl 95-lbm/ft3 PST on density requirements (75–100 lbm/ft3).
fluid that was spotted in the openhole section. The wells drilled with this fluid have showed
The cleanout assembly was pulled inside the a cost reduction of 41% compared with wells
7-in. liner. Then, fluid was circulated over fine drilled with formate fluids. Production from
270/325 mesh screens until the OCIEF fluid was all wells has exceeded expectations, validating
deemed PST‑compliant. The cleanout assembly the fluid’s nondamaging design and its
was pulled out of hole. Then, 4½-in. sand successful deployment. JPT
jpt.spe.org 55
TECHNICAL PAPERS | Drilling and Completion Fluids
Technique Implementation: Anomaly-Detection The method was able to detect the steady state
Software. The proposed method was implemented of the drilling fluid with less than 0.5% of false
by developing a monitoring software capable of positives for Q and zero points of false positives
receiving data from the experimental flow loop for T². Once process health charts were calculated,
and processing the data using a technique based Q and T² were decomposed to generate the
on PCA. The PCA-based technique was used to contribution map of the steady state.
indicate whether the plant was operating in a The lack of false positives indicates that the
normal or abnormal state. method can identify the variable contributions
The software could point out whether a for the steady state of the fluid that is the normal
sample taken in the experimental flow loop was operation of the process. This result occurred for
in a failure state by using a failure-detection Q and T², showing that the training was successful.
algorithm. In this work, three points in a row in
a state of anomaly would be enough to trigger Conclusions
the system-failure alarm. For the implementation The proposed algorithm based on the PCA
of the fault-detection and diagnosis algorithm, technique was able to detect anomalies in the
the Python 3 language was used. The developed properties of drilling fluids. The training process
software, including its interface, was programmed was performed successfully, and the principal
in LabView. Its performance is detailed in the components of the experimental plant were
complete paper. estimated to capture 99.5% of the drilling-fluid-
process total variance. The trained algorithm
Results and Discussion presented less than 1% of false positives for the
This section of the complete paper presents the detection of drilling-fluid anomalies.
PCA coefficient representative of the drilling-fluid The combination of the monitoring of T² and
standard steady state and its efficiency to generate Q and the contribution maps of the process health
process health statistics and its applications statistics provides enough information to assess
regarding process monitoring. The complete paper drilling-fluid health and which anomalies should be
includes a discussion of the authors’ findings corrected by the operators. The system represents
regarding anomaly detection in drilling fluids. an initiative for achieving value from a complete set
The experimental method produced a data set of online drilling-fluid measurements.
of drilling-fluid properties used to train the model The method’s ability to generate contribution
for the fluid standard state. Each coefficient was maps allows the qualitative and quantitative
produced by the PCA technique through the linear identification of process failures. The results of
transformation of the process variables. the contribution maps can be fed into decision-
Each coefficient represents a dimension of support systems or process-correction systems.
the new variable space generated by the PCA The proposed algorithm does not need the
technique, with each variable providing a weight programming of heuristic rules in each process
for the linear transformation that generated variable to be effective in detecting anomalies
these components. The fault-detection limits and faults. In addition, the method proposed is
were calculated from the training data set. The versatile because its output is the list of variables in
proposed method was able to detect the steady failure and the magnitude of these failures. Those
state of the drilling fluid, with the number of false outputs can be fed directly to correction systems or
positives below 1%. indirectly to decision-support systems. JPT
jpt.spe.org 57
TECHNICAL PAPERS | Drilling and Completion Fluids
Light-density drilling fluids with hollow glass beads round spheres made up of a thin shell of
(HGBs) are being used increasingly in applications borosilicate glass a few micrometers thick. The
for drilling depleted formations with minimal losses glass density is approximately 2.50–2.55 SG. The
and increasing rates of penetration. Studies about hardness is approximately 5 on the Mohs scale,
how best to use typical solids-control equipment in between barite (3.5) and quartz (7.0).
are lacking, however, because current practices
and procedures based on barite-weighted muds HGB Large-Batch Mixing
are inefficient. In the complete paper, the authors Based on the testing time to reach steady
report a systematic full-scale test program to conditions and the tanks available at the test
study and optimize solids-control efficiency with facility, it was determined that a volume of
such fluids using centrifuges, hydrocyclones, and approximately 40 bbl was required for the field-
shale shakers. scale solids-control testing. A mixing plant was
used, and the fluid was mixed over a period
HGB Fluid Formulation of 3 days. Good agitation is crucial to mix the
The fluid formulation developed for the field additives and HGBs effectively into the base oil.
test had a target design density of 7.2 lbm/gal. With the exception of the process used to add
Significant effort was put into developing an HGBs, however, no special equipment or modified
HGB fluid that matched or exceeded all design procedures are needed to mix the HGB fluid.
requirements for the existing drilling fluid used to For adding the HGBs, a hopper was used and an
drill a production hole interval in a depleted field. efficient additive process developed while dust
The HGB drilling fluid showed excellent fluid loss was eliminated.
and rheology. An overview of the composition A 100-bbl mixing tank unit mounted on a trailer
and some of the fluid properties is provided in the was used to generate the HGB fluid for testing
complete paper. (Fig. 1). The unit consists of a multicompartment
HGB 19K46 is a product with a nominal 100-bbl tank, a diesel-engine-driven centrifugal
hydrostatic collapse pressure rating of 19,000 psi pump, a hopper, and a series of control valves for
and a density of 0.46 g/cm3 (approximately directing the fluid flow.
3.8 lbm/gal). The HGBs are almost perfectly One specific modification to the tank was
the installation of large eductors at the ends of
the feeding pipe. This ensured good circulation
This article, written by JPT Technology Editor Chris Carpenter,
contains highlights of paper SPE 212470, “Full-Scale Solids-
Control Testing of a Light-Density Hollow-Glass-Beads
For a limited time, the complete
Drilling Fluid,” by Nikolay Kostov, ExxonMobil; Glenn
paper is free to SPE members
Penny, SPE, Contractor for ExxonMobil; and James White,
at jpt.spe.org.
NOV, et al. The paper has not been peer reviewed.
Solids-Control
Fig. 1—Mixing tank used to generate HGB fluid.
Testing
With the test volume
prepared, full-scale testing was initiated. A critical lesson learned was the importance of
test stand was used where the centrifuge, the using a large-opening weir dam plate (285 mm).
hydrocyclone, and the shale shaker could be A small-opening weir plate (242 mm) did not
mounted. The facility allowed monitoring of the allow for HGB fluid to discharge easily from the
feed density through a Coriolis meter. All reported light-side opening and could lead to plugging. For
densities, however, are based on laboratory- optimal performance, high rotational speed (bowl
measured density from samples collected from speed greater than 2,500 rev/min and as high as
each of the three streams: feed, light discharge, 2,890 rev/min) and lower flow rates (30–60 gal/min)
and heavy discharge. Because the largest are recommended. The complete paper contains
uncertainty around the performance of the solids- an extended discussion of the method and
control equipment involved centrifuge efficiency, results of the centrifuge testing.
this was the first device tested. Starting with the
centrifuge also allowed beginning with the fluid as Hydrocyclone Testing
designed and gradually building up solids content The objective of the hydrocyclone testing was to
by adding fine solids first, then coarse solids, and confirm that HGBs are staying with the liquid phase
finally the additional HGB. The full sequence of and not discharged in a high concentration in
testing is provided in the complete paper. the heavy-discharge stream. Another goal was to
establish the effectiveness of the hydrocyclone to
Centrifuge Testing remove drilling solids in the presence of HGBs. The
A 14-in. centrifuge was used that mimics estimated flow rate for the 4-in. hydrocyclone was
equipment often used in the field. The approximately 50–75 gal/min at 75 ft of head. The
performance was deemed very good, with high current setup has a manifold capable of running up
solids-control efficiency and no loss of HGB to four hydrocyclones simultaneously. Testing was
concentration in the light-discharge stream. A conducted using one hydrocyclone.
jpt.spe.org 59
TECHNICAL PAPERS | Drilling and Completion Fluids
Overall, the results from the hydrocyclone drilling fluid. There is no reduction of HGB in the
showed no significant surprises, and behavior light-discharge mode, and many of the sand-
was consistent with expectations. The HGB density solids were removed successfully, but
stayed with the liquid phase, and concentration solids-control-removal efficiency was lower than
of HGB in each stream was consistent with initial in the centrifuge. It is recommended that the head
HGB concentration. One takeaway was that pressure be optimized in the field, but values of
the common recommendation of running the approximately 40 psi are a good starting point, as
hydrocyclone at a head pressure equal to four times are flow rates of approximately 70–75 gal/min.
the drilling-fluid density was not optimal for this
light fluid. The initial fluid density of 7.20 lbm/gal Shale-Shaker Testing
would dictate a head pressure of 29 psi, and, For this testing, a four-screen shale shaker was
when fully contaminated with fine and coarse used, which is often seen in the field. The shale
solids, the density of approximately 8.2 lbm/gal shaker performed as expected, with the HGB
would dictate a head pressure of 33 psi. The best staying in the light-discharge phase and large
performance was observed with higher pressures particles being separated by the screens. The
(greater than 35 psi) at flow rates between recommended screen is rated at API 200, which
60–70 gal/min. As expected, the performance of balances filtering ability and flow rate, but finer
the hydrocyclone with the HGB fluid as designed screen sizes (API 230 or 270) also can be used. The
was not good, with almost no sand-density particles API 325 screens indicated retention of some of the
over 20 microns. With the API 325 silica flour fines HGB particles and increased their concentration
added, again, few particles over 40 microns were in the heavy-discharge stream. Coarser screens
noted and performance was suboptimal. With (API 120 and 80) allowed for higher flow rates
the coarse particles (API 12–200) added, enough and separated drilling solids successfully when
larger particles were present so that a notable higher HGB concentrations (greater than 20%) are
difference between the feed, light-discharge, and used. High shale-shaker inclination angles (greater
heavy-discharge density could be measured. An than 5°) resulted in increased flow-rate handling
improvement in performance with increasing but accelerated screen wear, so these should be
head pressure was noted; the best performance avoided. No HGB breakage was detected in any of
was measured at 38-psi head pressure. Higher the tests. These tests are further detailed in the
pressures also were tested later, and improvements complete paper.
continued. The authors recommend 35–45 psi
and flow rates in the 65–75 gal/min range as a Conclusions
reasonable starting value for the field. The objectives of the full-scale testing were to verify
Once testing with the coarse simulated drilling that existing solids-control equipment can be used
solids was completed, the HGB concentration was to handle an HGB fluid successfully, to find optimal
doubled to approximately 22% by volume and the running parameters for the equipment, and to
hydrocyclone was performance tested again. For quantify solids-control-removal efficiency.
these tests, pressures up to 53 psi were used. At The successful completion of the full-scale
53 psi, roping was observed from the discharge solids-control testing provided better understanding,
port, so the authors recommended keeping the and derisked field use, of an HGB fluid. The testing
head pressure between 45 and 48 psi, which results also provided recommended operating
corresponds to flowrates of 70–75 gal/min. points for various solids-control equipment that
These results suggest that good hydrocyclone should minimize rig time to reach optimal solids-
performance can be achieved with the HGB control efficiency in the field. JPT
EOR Operations
Elizabeth Barsotti, SPE, Career Development Fellow, MRC Laboratory of Molecular Biology
W
e often see and, in some very
unfortunate cases, experience
“Oil is the bedrock on which
ravaging wildfires, colossal floods, modern society is built.”
and scorching droughts. These
“once-in-a-lifetime” climate events have become
increasingly commonplace. The World Health
Organization has referred to climate change as we continue to produce oil while minimizing its
“the biggest health threat facing humanity.” The climate‑harming byproducts?
finger is often pointed at the oil and gas industry Thanks to the ingenuity of industry
as the source of these tragic events. Indeed, professionals around the world, new technologies
according to the International Energy Agency, are emerging that allow us to achieve this goal.
oil companies emit more than 5,000 million Using these technologies, we can simultaneously
tons of CO2 every year. Even so, seeing maximize CO2 sequestration and oil recovery. By
organizations pitted against the industry and using surfactant-alternating-gas or surfactant/
our livelihoods can be disheartening, especially CO2 coinjection processes, oil production and CO2
because we know the other half of the story storage can be tailored to the needs of a specific
that is overlooked but cannot be understated. reservoir, as discussed in paper SPE 212969. The
Oil is the bedrock on which modern society is same industry that produces the building blocks
built. The primary question remains: How can for life-saving medical prosthetics can now also
jpt.spe.org 63
TECHNICAL PAPERS | EOR Operations
The complete paper presents a systematic approximately 9,650 wells. Average incremental
review of the largest alkaline-surfactant-polymer recovery factor was 20% STOIIP with waterflooding
(ASP) flood project in the world, applied in the and 8% with polymer flooding, providing an
largest oil field in China. First, reservoir and fluid ultimate recovery factor of 60%. Cumulative
characteristics are highlighted to understand oil production by ASP flooding had reached
heterogeneity of the reservoir. Next, project 316 million bbl by 2021, making it the largest
history is summarized, including laboratory ASP flooding project in the world.
studies, pilot tests, industrial-scale tests, and
fieldwide application. Finally, typical ASP flood Geological Background and
performance and reservoir management measures Reservoir Characteristics
from over 30 years of experience are presented. The La-Sa-Xing Field is in the north of the
Performances of ASP flood and polymer floods in Songliao Basin of northeast China, comprising
the same field also are compared. the majority of the Daqing field complex. The field
was placed onstream in 1960. The hydrocarbon-
Introduction bearing reservoir has a gross thickness of
In the La-Sa-Xing Field, ASP flooding was studied 1,377 ft and a net thickness of 394 ft. Net pay
in the laboratory from 1987 to 1993 and followed averages 150 ft.
by five small-scale pilots from 1994 to 1999, all Initial reservoir pressure ranges from 1,523
successfully achieving incremental recoveries to 2,585 psi. Reservoir temperature varies from
of approximately 20% stock-tank oil initially in 113 to 122°F. Crude oil has an API gravity of 33°,
place (STOIIP). As a result, industrial-scale pilots a viscosity of 8.5–10.3 cp at reservoir conditions,
were conducted from 2000 to 2007, resulting in an initial gas/oil ratio of 258 scf/STB, and a
increased production by ASP flooding from 3,887 bubblepoint pressure of 1,291 psi. Formation
to greater than 19,000 BOPD in 2007. Fieldwide water salinity is 7000 mg/L. Reservoir rock initially
ASP expansion was launched in December 2007. shows water or weak oil wettability.
By 2021, the ASP-flooded blocks registered a Depending on permeability, three types of
STOIIP of 1.9823 billion bbl. Daily production reservoir sand (Type I, Type II, and Type III) have
was approximately 96,000 BOPD through been identified. Currently, ASP flooding is mainly
applied to Type I sand, with partial application to
Type II Sand.
This article, written by JPT Technology Editor Chris Carpenter,
contains highlights of paper SPE 215058, “A Systematic
Review of the Largest ASP Flood Project in the World: From
For a limited time, the complete
Laboratory to Pilots and Field Application,” by Yunan
paper is free to SPE members
Wei, SPE, Xiaoguang Lu, SPE, and Jianhong Xu, SPE, C&C
at jpt.spe.org.
Reservoirs, et al. The paper has not been peer reviewed.
jpt.spe.org 65
TECHNICAL PAPERS | EOR Operations
Optimization and Reservoir • S tage II, with low water cut at 0.15- to 0.5-PV
Management injection
ASP-Flooding Process Optimization. Efforts have • Stage III, with rebounding water cut at 0.5- to
been made to optimize the ASP-flooding process 0.65-PV injection
since the start of small-scale pilots, including • Stage IV, with high water cut at greater than
well spacing and well-pattern design, productive 0.65-PV injection.
layers and pay-thickness combinations, numbers
of injection slugs, and reservoir management at Correspondingly, fit-for-purpose measures,
different stages. detailed in the complete paper, were taken for
Based on laboratory research and 30 years of each stage.
experience, inverted five-spot patterns at a 5-acre
well spacing were identified as the optimal well Zonal Injection. To improve vertical sweep
pattern in the La-Sa-Xing Field. efficiency, zonal injection was implemented
Layering and pay-thickness combination was in 1,755 wells (36% of all injectors), leading to
optimized to avoid interlayer interference based improved injection profiles. Statistics from 14
on the following guidelines: injectors indicated that the percentage of swept
• The pay-thickness combination for each pay-sand thickness increased from 61 to 82.9%.
production string should be determined Zonal injection was more effective for thinner
by incorporating surface-injection capacity, reservoir units. The swept pay-sand thicknesses
individual well estimated ultimate recovery, for flow units with 3.3–6.6 ft net pay and less
and STOIIP of the project area. than 1.7 ft net pay were improved by 45 and 64%,
• The permeability contrast should be less respectively.
than 2; otherwise, zonal injection should be
implemented. Profile Modification. Conventional profile-
• The pay-thickness combination is defined by modification agents were not effective because of
sand units separated by a laterally extensive the influence of alkalines. Two types of alkaline-
shale barrier. resistant agents were developed and applied,
• When more than two pay-thickness leading to improved sweep efficiency and ASP
combinations exist, production should be usage. Statistics from 181 injectors indicated an
conducted from the bottom to the top to average injection-pressure increase of 197 psi.
reduce the scope of potential future workovers. Meanwhile, the 431 corresponding production
wells had an incremental oil production of 0.96
To improve recovery efficiency and reduce million bbl and an average water-cut drop of 3.6%.
chemical usage, the ASP-flooding process was
optimized to adopt four slugs, including a preflush Scaling Control. Most producers suffered from
polymer slug for profile improvement, an ASP pump blockages caused by scale precipitation
main slug with high chemical concentrations, on pump beams and on the inner wall of the
a secondary ASP slug with low chemical tubing. To remediate the damage, progressive
concentrations, and a final polymer slug to avoid cavity pumps were widely used, extending pump-
breakthrough of the following water chase. maintenance cycles from 87 to 463 days. Scale-
Based on water cut, ASP flooding can be inhibitor and -removal treatments also were
divided into four stages, including the following: implemented regularly. For wells with formation
• Stage I, with water-cut decline at 0- to 0.15-PV damage caused by scaling, hydraulic fracturing
injection was implemented.
Weak alkaline was preferred to strong alkaline efficiency, identify key issues for field-scale
in the ASP solution because the former has fewer applications, provide bases for project design,
scaling problems, a higher liquid-production index, optimized injection parameters, and tested new
and greater incremental oil production. polymer types.
Comparison of ASP-flooding pilots and
Conclusions polymer flooding pilots indicated that ASP flooding
The ASP-flooding project in the La-Sa-Xing Field, outperformed polymer flooding, leading to greater
representing the world’s largest ASP-flooding water-cut drops, a higher percentage of swept pay-
project, is a proven success and is expected to sand thickness, faster annual recovery of STOIIP,
achieve an average incremental recovery of 20% and improved injection and production profiles.
STOIIP with waterflooding and 8% with polymer Fit-for-purpose reservoir-management
flooding. Average ultimate recovery factor with ASP measures such as zonal injection and profile
flooding is expected to be greater than 60%. modification helped improve the ASP-flooding
The progressive approach from laboratory process. Scaling is a major challenge experienced
experiments to pilots and, finally, to fieldwide during ASP flooding. Weak alkaline, rather than
application is a best practice for applying ASP strong alkaline, was recommended for the ASP
flooding to a large field. In-house ASP-flooding solution, because of reduced scaling, a better
studies proved feasibility and led to more than liquid-production index, and greater incremental
10 key pilots. Pilot tests helped evaluate recovery oil production. JPT
jpt.spe.org 67
TECHNICAL PAPERS | EOR Operations
The complete paper describes nanomaterials— The authors present a novel technique to
Janus carbon nanofluids—derived from waste convert waste plastic materials into carbon-
plastics and demonstrates the potential of based nanomaterials for EOR applications.
the nanofluids as highly effective alternative Waste plastics, as a low-cost feedstock, can
nanoagents for enhanced oil recovery (EOR) be converted into high-value-added carbon-
applications at reservoir conditions. A novel, based microparticles through the controlled
sustainable, cost-effective method has been carbonization of polymers. Furthermore, the
developed to scale up synthesis of Janus carbon carbon microparticles (C-MPs) can be surface-
nanoparticles (JC-NPs) from waste plastic feedstock functionalized by post-chemical treatment
by combined pyrolysis, chemical functionalization, and then their chemical symmetry reduced to
and pulverization, which allows for production of nanosize by a ball-milling technique. The resulting
the JC-NPs in mass quantities at an industrial scale. asymmetrically surface-functionalized carbon
nanoparticles (i.e., Janus C-NPs) exhibit both
Introduction nanoparticulate and surfactant-like properties
Recent research has demonstrated that that can be used as new nanoagents in nanofluid
nanoparticles with asymmetric surface properties flooding for EOR applications. Experimental
(i.e., Janus nanoparticles) could achieve a much materials and measurement methodology are
higher efficiency of oil recovery factors with detailed in the complete paper.
very low concentrations of loading compared
with homogeneous nanoparticle fluids. To date, Results and Discussion
however, major challenges facing the exploration Synthesis of C-MPs From Waste Polymers.
and use of Janus nanoparticles exist, impeding Approximately 90% of the plastics produced
scalability of synthesis, tailored chemical globally consist of six types: low-density
functionalization, and the ability to introduce polyethylene, high-density polyethylene,
a diverse set of functionalities. Therefore, new polypropylene, polyvinylchloride, polystyrene,
methods for production of Janus nanomaterials and polyethylene terephthalate (PET). Given their
on an industrial scale are desired. widespread use, these waste polymers constitute
a substantial proportion of global plastic waste.
Therefore, they present an opportunity to be used
This article, written by JPT Technology Editor Chris Carpenter, as precursors in the synthesis of C-MPs.
contains highlights of paper SPE 214799, “Novel Janus
Carbon Nanofluids From Waste Plastics as Sustainable
Nanoagents for Enhanced Oil Recovery: Scaleup Synthesis
For a limited time, the complete
and Performance Evaluation,” by Wei Wang, Sehoon
paper is free to SPE members
Chang, SPE, and Ayrat Gizzatov, SPE, Saudi Aramco, et al.
at jpt.spe.org.
The paper has not been peer reviewed.
jpt.spe.org 69
TECHNICAL PAPERS | EOR Operations
Formation of JC-NPs. To generate Janus structures 14 mN/m. The Langmuir isotherm exhibits typical
of the C-NPs, a method is presented to break features of surfactant-like properties of the JC‑NPs.
homogeneity of the functionalized surface of For C-MPs functionalized by a sulphonating
carbon mechanically through a ball-milling treatment, no Langmuir film formed on the water
process. After the ball-mill-grinding process, the surface because of their hydrophilic properties.
functionalized hydrophilic C-MPs are broken into The Janus nanofluids with a unique combination
smaller submicron- or nanometer-sized pieces of particulate and surfactant-like properties create
(i.e., the C-NPs) and new unfunctionalized surfaces significant effects at the water/oil and rock/fluid
are exposed on the C-NPs while the functionalized interfaces in the EOR process.
surfaces still partially remain, which generates an To evaluate the efficiency of the Janus
asymmetric surface property (JC-NPs). nanofluids for potential EOR applications, interfacial
For a typical ball-milling treatment, a ball tensions (IFTs) have been studied in formulations
mill was used for marking the C-NPs. A quantity of the JC-NPs with petroleum surfactants, and the
equivalent to 140 mL of zirconia beads (0.45‑mm results have shown that the syngenetic effects
diameter) was first loaded into the mill chamber of the surfactant and low concentration of the
as the grinding medium. Then, 10 g of C-MP JC‑NPs in nanofluids could significantly reduce
powder was mixed with 200 mL of water in an IFT at the crude-oil/brine interface. Contact-angle
open mixing vessel and pumped to flow through measurement also reveals that the Janus nanofluids
the milling chamber. The milling speed was set could alter the wettability of crude-oil-saturated
at 3,000 rev/min and the feed material fluids carbonate reservoir rock. Microfluidic flooding
circulated in the milling chamber at a rate of experiments have demonstrated that the syngenetic
100 mL/min. After 2 hours of milling, the C-NPs effects of the surfactant with low concentrations of
fluids were collected and C-NPs were separated the JC-NPs in nanofluids could achieve additional
by centrifuge and washed with ethanol. recovery of crude oil in carbonate reservoirs, in
Before the ball milling, the average size of C-MPs comparison with the use of surfactant only.
was approximately 10 µm; afterward, the size was
reduced to approximately submicron range. Conclusions
The research findings elucidate a cost-effective
Evaluation of Janus C-NPs Nanofluid for EOR. process for the conversion of waste plastic
The synthesized Janus C-NPs were dispersed in a into JC-NPs. This approach contributes to the
mixture of water and organic solvent (chloroform management and reuse of waste plastics and
or hexanol). Upon phase separation, the JC-NPs adds value to the waste stream by transforming
self-assembled at the interface of water and the waste into a potentially beneficial resource.
organic solvent, implying the amphiphilic Janus JC-NPs exhibit amphiphilic characteristics and can
properties of the JC-NPs. be used in EOR surfactant applications. The results
Surface properties of the synthesized Janus demonstrate that these JC-NPs, combined with
C-NPs were further characterized by Langmuir petroleum surfactants, show a synergistic effect that
isotherm measurement. When JC-NPs in ethanol substantially reduces IFT at the oil/brine interface.
suspension were dropped onto water, the JC-NPs This feature, coupled with the ability to alter the
spread on water, while ethanol solvent dissolved wettability of crude-oil-saturated carbonate reservoir
into the water. When lateral pressure was rock, positions JC-NPs as a promising tool for EOR.
applied to the surface, the JC-NPs assembled to a Future studies will focus on a comprehensive
particulate monolayer, and then a bilayer probably evaluation of their performance in EOR, specifically
appeared at a surface pressure of approximately through coreflooding experiments. JPT
CO2 mobility control through foam technology has Materials and Methods
enabled better sweep efficiency and, consequently, Fluids and Porous Medium. In this study, a
better oil productivity during enhanced oil synthetic brine with total dissolved solids of
recovery (EOR) processes. Along with enhancing 20 wt% was used as blank brine and laden with a
oil production, a sound potential exists for in- commercial zwitterionic surfactant that was used to
situ generated foam to enhance CO2 storage. prepare surfactant solutions with concentrations of
However, the effect of the different in-situ foam 0.5 and 1 wt% active matter in the synthetic brine.
generation strategies on the combined goal of Three core plugs were drilled from an Indiana
maximum oil production and carbon storage is not limestone outcrop block. The cores were then
well elucidated in the literature. In the complete cleaned and oven-dried at 95°C.
paper, the authors methodically evaluate the
simultaneous optimization of CO2 storage and oil Experimental Procedure. Vacuum saturation with
recovery using multiple injection strategies. brine was commenced for the three cores. The
porosity of the cores was calculated using their dry
Introduction and brine-saturated weights. Then, the 100% brine-
The current investigation is a continuation of two saturated core was placed in a core holder and
previous studies that provided a methodology loaded into an oven set to 90°C. The pore pressure
for screening and using foaming agents for was fixed at 2,000 psi, and the confining pressure
optimized CO2 storage in sandstone and was controlled at 3,000 psi throughout the flooding
carbonate formations. A base case of tertiary experiment. The brine permeability of the core
CO2 flooding was established for comparison samples was evaluated by measuring the pressure
with in-situ foam generation by two approaches: drop across the core at different brine-injection
single-cycle surfactant-alternating-gas (SAG) flow rates.
flooding and coinjection of CO2 and surfactant. In the first experiment (IL1), oil drainage with
Additionally, the effect of surfactant concentration a flow rate of 0.2 cm3/min was performed to
on foam efficiency, CO2 storage capacity, and oil establish irreducible water saturation of 46.9%.
recovery were evaluated in both approaches at This total flow rate was kept the same throughout
reservoir conditions. the three experiments. Then, a waterflooding stage
was begun and the oil recovery was recorded. After
reaching a plateau in oil recovery, supercritical CO2
This article, written by JPT Technology Editor Chris Carpenter,
contains highlights of paper SPE 212969, “Evaluation of CO2
Storage Potential During CO2 Mobility-Control Optimization
For a limited time, the complete
for Enhanced Oil Recovery,” by Alvinda Sri Hanamertani,
paper is free to SPE members
SPE, Ying Yu, SPE, and Omar El-Khatib, SPE, University of
at jpt.spe.org.
Wyoming, et al. The paper has not been peer reviewed.
jpt.spe.org 71
TECHNICAL PAPERS | EOR Operations
500
Experiment 1: Gasflooding (no surfactant preflush)
scenario and core-scale CO2 storage was quantified
450 Experiment 2: Gasflooding (after 0.5 wt% surfactant preflush) using mass balance.
Experiment 2: Foam coinjection (0.5 wt% surfactant)
400 Experiment 3: Gasflooding (after 1 wt% surfactant preflush)
Apparent Viscosity (mPa.s)
has been reported to have a strong foaming of surfactant preflush in favoring foam generation
behavior in Indiana limestone. In addition, the flow during CO2 flooding that leads to oil mobilization.
resistance exhibited after simultaneous injection Further improvement in oil recovery was achieved
of 0.5-wt% surfactant and CO2 was found to be because of the CO2 foam injection following the
comparable with the flow resistance established by CO2 flooding.
a single-cycle SAG method with 1 wt% surfactant. The complete paper includes a detailed
This indicates that the use of a lower concentration discussion of the authors’ experiments to evaluate
with an optimized injection strategy can be an CO2 storage potential; this section is not included
economic preference for developing a sufficient in this synopsis.
CO2 mobility control.
Conclusions
Evaluation of Oil-Displacement Performance. • In general, the coinjection of surfactant
The oil-recovery experiments were performed solution and scCO2 provided a prominent
mainly to analyze the combined effect of mobility-control effect for the injected scCO2.
two different foam-injection strategies on oil • The flow resistance exhibited after
production. A single-cycle SAG was conducted to simultaneous injection of 0.5 wt% surfactant
evaluate the surfactant performance in favoring and CO2 was found to be comparable with the
the injected CO2 to generate foam and maintaining flow resistance established by a single-cycle
the strength of generated foam for controlling CO2 SAG method with 1 wt% surfactant, indicating
mobility without infusing fresh surfactant solution. that the use of a lower concentration with
In addition, two surfactant concentrations were an optimized injection strategy can be an
considered to evaluate the concentration effect economic preference for developing sufficient
on the oil-displacement performance. CO2 mobility control.
In each experiment, waterflooding was • Increasing surfactant concentration
performed as a secondary recovery technique. encourages more-effective mobility control.
During waterflooding, two-phase production • Compared with the base case, CO2 storage
was observed early, approximately after 0.2-PV potential increased by 51% and 66% by single-
injection, and the oil recovery from this stage was, cycle SAG in the second and third experiments,
on average, 32.19, 44.94, and 26.27% of original oil respectively. Furthermore, subsequent foam
in place (OOIP) in the first (IL1), second (IL2), and coinjection resulted in a 19.1% increase in CO2
third (IL3) experiments, respectively. stored at 0.5 wt% concentration, and a 15.5%
In the first experiment, CO2 flooding was increase at 1 wt% concentration.
performed directly after the waterflooding stage • During CO2 foam injection, the difference in
and was able to produce an incremental oil the established foam strength can affect the
recovery of 27.46% of OOIP and, thus, a total extent of aqueous-phase replacement inside
recovery factor of approximately 60% of OOIP. the core.
In the second experiment, surfactant preflush • The incremental volume of stored CO2 at
was performed after the waterflooding stage. In 1 wt% surfactant concentration was less
this stage, approximately 2.9-PV surfactant solution than that at 0.5 wt%, but the oil recovery
was injected. As expected, the established mobility- was greater.
control effect in the subsequent CO2 flooding • A t higher surfactant concentration, storage
induced a significant oil displacement, resulting in potential was offered by the pore space
an additional oil recovery of 18.15% of OOIP. This previously occupied by the oleic phase rather
incremental recovery indicated the effectiveness than the aqueous phase. JPT
jpt.spe.org 73
TECHNOLOGY FOCUS
T
he purpose of hydraulic fracture modeling
is to improve engineering decision-
“New types of data collection
making. Success requires practical and new ways of analyzing
knowledge, engagement with real data, and interpreting data have
theoretical understanding, and critical thinking.
The payoff is tremendous; design improvements
given engineers a much clearer
routinely yield major uplifts in well performance picture of what is happening in
and project economics. the subsurface.”
What types of papers push forward the state
of the art for hydraulic fracturing modeling?
In the pure development of models,
practitioners adopt different philosophies. Some on the context of how and why the model is
seek faster running models for quicker results. being used.
Others focus on integration of physics, trying to Many of the most influential papers of the
capture the essential elements of all key physical past decade on hydraulic fracture modeling have
processes and how they interact. Still others focus not been modeling papers at all. Modeling depends
on high-precision answers to narrower aspects of on formulating a realistic conceptual model. New
the problem. The appropriate emphasis depends types of data collection and new ways of analyzing
jpt.spe.org 75
TECHNICAL PAPERS | Hydraulic Fracturing Modeling
With the aid of a multiphysics simulator, the • T ight gas formations with high tectonic
authors recently presented a novel use of a influence to mitigate poroelastic effects and
degradable fluid-loss additive (DFLA) as a fracture fissure-dependent enhanced leakoff
geometry additive to reduce the pad volume while • Unconventional reservoirs to avoid repression
achieving the same geometry. In this complete during production
paper, the authors extend advanced slurry flow • Openhole wells to control multiple fracture
modeling with production simulation to propose initiation
the optimal design strategy for fracturing, • Multipad wells to avoid interwell
which may challenge current treatment-design communications and fracture hits
conventions. A novel work flow was developed, • Fracturing treatments aimed at optimizing
with four coupled working blocks of laboratory, and reducing crosslinked pad volume
slurry flow modeling, production analysis, and
machine learning. The new digital framework Despite these benefits, the primary issue of
proposes solutions for the limitations of using an FLA is its potential to damage fracture
current methodology. conductivity and the reservoir. Some developments
of nondamaging FLA have been presented but are
Introduction either operationally complex or difficult to use. This
Across different generations, multiple fluid subject requires special attention to investigate
additives have been introduced to target specific damage and production loss through laboratory
treatment objectives; one of these that has been studies, numerical models, and machine-learning
available for years, but that has been underused, models and define a tailored strategy with DFLA.
is fluid-loss additive (FLA). Theoretical and field
bases have been presented for its use in the Digital Framework for
following applications: Treatment Design
• Conventional prolific reservoirs to mitigate The authors present an end-to-end work flow from
high fluid loss and create sufficient fracture chemistry development to an automated FLA-
geometry assisted fracturing design tailored for a specific
reservoir and well. The framework is broadly split
into three blocks: laboratory testing, fracture
This article, written by JPT Technology Editor Chris Carpenter, modeling, and production modeling. These blocks
contains highlights of paper SPE 210633, “Multimaterial
Multiphysics Modeling Coupled With Post-Fracturing
Production-Flow Simulations: Revamping Hydraulic
For a limited time, the complete
Fracturing Design Strategy,” by Abdul Muqtadir Khan, SPE,
paper is free to SPE members
Vadim Isaev, and Ludmila Belyakova, SPE, Schlumberger.
at jpt.spe.org.
The paper has not been peer reviewed.
can be sensitized together with multiple case runs were selected to investigate the effect of type and
and a large digital database. This data set then amounts of FLA. High-fidelity simulations were
can be subjected to regression and classification conducted with planar 3D geomechanics coupled
algorithms. With enough data built in the toolbox, with high-resolution material transport. The
a fully coupled data- and physics-based forward model fully accounts for material degradation as a
model can be created that can output the fracture function of instantaneous reservoir temperature
design with DFLA type, concentration, and pad and exposure history. Material presence was
volume with inputs of reservoir properties and defined in each grid cell as a single component or a
pore-throat descriptions. The tool infrastructure mixture of proppant, polymer, and FLA with given
is built to allow the model to retrain and update volume fractions. Fracture conductivity distribution
with real field data addition. was calculated using laboratory correlations for
In the first block, multiple laboratory tests fracture damage of each material combination.
evaluate DFLA performance. The laboratory tests The third block involves production modeling
include static and dynamic leakoff tests to evaluate with field operating conditions to study the effect
reduction in spurt loss and wall-cake building of degradability of the FLA used and the amount
leakoff coefficient with varying concentrations of of FLA pumped. The current paper intends to
DFLA in the fracturing fluid. Additionally, core-flow couple Block 2 and Block 3. High-resolution
tests are performed to understand the effect of simulations from Block 2 accounting for material
DFLA on regained permeability and validate the degradation and material delegation for each
postulation of its nondamaging nature. grid block (proppant, polymer, and FLA) allowed
In the second block, the results from Block 1 calculation of fracture-conductivity distribution and
are fed into an advanced slurry flow multiphysics quantification of fracture damage for each material
fracture model, which is a modified numerical combination. The modeling footprint was then
code. The first step in Block 2 is to run multiple transferred to a fracture-productivity calculator
combinations of leakoff coefficients and pad to analyze the effect of polymer and FLA on post-
volumes and evaluate the fracture geometry. This fracturing productivity index (PI).
approach allows creation of an equivalency of
pad volume to achieve a given fracture geometry Production Simulations
if the leakoff reduction is known from Block 1. The results from fracturing simulations also were
A previous paper explored coupling Block 1 and transferred to a fracture-productivity calculator
Block 2. That paper demonstrated that DFLA to analyze the effect of polymer and FLA on
shows a more than 40 and 30% decrease in leakoff post‑fracturing cumulative PI.
coefficient and spurt loss, respectively, compared
with the baseline borate fluid at loadings of Operating Conditions. The productivity
30 lbm/1,000 gal. Then, 32 cases were modeled performance was evaluated for multiple cases for
in the multiphysics simulator with pad volumes each treatment-schedule scenario to predict the
and leakoff sensitivities, which allowed calculation optimal strategy based on reservoir properties and
of the reduction of pad volume for given DFLA conditions. The cases were built on intuitive logic to
performance. The results showed that up to 65% relate the permeability, leakoff properties, porosity,
of volume from the pad can be reduced. reservoir pressure, and stable drawdown in flowing
The complete paper includes an extensive conditions. Higher reservoir quality is associated
discussion of the procedure and results achieved with faster reservoir pressure depletion and allows
in the Block 2 components of multiphysics fracture producing the required gas (hydrocarbon) rates
simulation. Multiple treatment-pumping schedules with a lower drawdown.
jpt.spe.org 77
TECHNICAL PAPERS | Hydraulic Fracturing Modeling
Results and Discussion. In considering relative enable realization of the full digital framework
production for Scenarios 1–4 based on performed for a tailored fracturing strategy.
production calculations, the authors observed • Near-wellbore diverter particles that can be
the following: used as FLAs in the presence of vuggy fracture
• All scenarios with FLA were pumped successfully porosity have been discussed in the literature.
even though pad volume was significantly less
for the FLA case in most scenarios. The resulting Conclusions
fracture geometry for FLA and non-FLA cases • A n approach for calculating effective leakoff
was comparable for all scenarios. coefficient is presented when FLA is added
• Degradable FLA is intuitively less detrimental to the fluid system. The effective leakoff
for production compared with non-FLA cases. coefficient can be calibrated using laboratory-
Cumulative production for scenarios is slightly experiment results.
better for DFLA, and noticeably better for DFLA • FLA can enhance fracture geometry
for Scenarios 3 and 4. considerably (up to 30% higher half-length)
• The production simulations demonstrate and enhance production up to 18%. The
that the benefit of FLA is enhanced for higher approach used in the complete paper provides
leakoff cases and bigger treatment sizes conservative estimates because spurt-loss
because the polymer reduction is substantial. reduction caused by FLA addition has not
Also, the degradability of the FLA has a much been captured in the current numerical model.
larger effect in these scenarios. Experimental results have shown up to a 40%
• The relative production enhancement shown reduction in spurt loss with FLAs.
in Figs. 15 and 16 of the complete paper might • The conductivity evolution across fracture
seem low at 2–3%, but absolute production development is consistent with the distribution
realization can be significant depending on the of proppant/FLA volume ratio. Proppant
reservoir potential. increases the conductivity, and FLA reduces
it. This effect has been studied through this
Discussion multimaterial model in all scenarios.
• T he study largely provides synthetic cases but • Degradability of the FLA can be critical
also shows the validity on a field case loosely depending on the mass of the FLA used in
based on the Oman formation. the treatment; the effect on production can
• The retained-conductivity-factor approximations be up to 18%.
varying as a function of crosslinked fluid mass • The following benefits have been realized
are currently represented by linear correlation. through modeling of DFLA use:
This assumption requires corroboration or ° Production enhancement
validation against empirical and analytical data. ° Reduction in volume of water-treating fluids
• Digital advances in core studies and slot testing ° Reduction in the amount of polymer and
can be used to build reservoir-specific DFLA associated damage
strategies. ° Mitigation of poroelastic effects in tight
• Multiple machine-learning work flows in reservoirs
the field of fracturing have been developed. ° Control of the differential pressure at the
Following similar predictive work flows, a fracture face and reduction of consequent
descriptive digital database with FLA properties, filtrate invasion
core-flow results, and production forecast ° Reduction of flowback and fracture-cleanup
coupled with machine-learning algorithms can time JPT
The Longmaxi shale gas play in China is unique cost an extra $300,000 for interventions in each
because of multiple tectonic deformations in its problematic well.
geological history. While its hydraulic fracturing While the risk of screenout, fracture hit, and
design has matured after a decade-long evolution, casing deformation is common, risk levels vary for
the success of every well cannot be ensured different reservoirs. No work flow is available that
without considering heterogeneity. To address could be developed to identify and reduce these
these challenges, a multidisciplinary team was hazards. In this study, ultradeep shale gas at Pad X,
formed to work on a pad; through the team’s buried almost 3900 m in the Luzhou Block, was
efforts, designed proppant volume achieved zero selected to recognize and mitigate these risks (Fig. 1),
casing deformations, fewer screenouts, and weaker where four wells were positioned 300 m apart. The
fracture hits. The key to effective mitigation was lateral length of X-1 is roughly 1000 m, while the rest
continuous 3D geological and geomechanical (G&G) of the wells are roughly 1900 m in length.
modeling through ongoing iterations with field data.
3D G&G Modeling
Background By combining seismic interpretation, seismic inversion,
The Longmaxi shale play in the Sichuan Basin is petrophysical analysis, and 1D geomechanical
approximately 20 000 km2 and is buried between modeling while adhering to the Longmaxi-Wufeng
2000 and 4500 m. This play has more than Shale modeling technique used in neighboring
10 trillion m3 of gas reserves and is made up blocks, the authors established a G&G model with
of shallow and deep reservoirs. dimensions of 40×40×0.5 m for the Luzhou Block. The
Currently, the operator has moved to the pad model was refined to 8×8×0.5 m by using well
deeper Luzhou and Chongqing blocks buried at a logs to better characterize the variations in stage level.
depth greater than 3500 m. Nearly 200 horizontal
wells per year are planned in the next 5 years. Natural Fractures. 3D surface seismic data was
A fracture hit with tens of MPa increase was the only reliable source available to predict natural
observed. Four casing failures were observed fractures in the shale and design the fracturing job,
on 32 of the wells in this block, which made though the uncertainty was unavoidable. To display
the unstimulated length more than 200 m and fault-/fracture-system characteristics, seismic
attributes, including variance, ant tracking, and
curvature were examined.
This article, written by JPT Technology Editor Chris Carpenter,
contains highlights of paper SPE 212406, “3D Integrated G&G
Model-Driven Mitigation Work Flow on Screenout, Frac Hits, and
For a limited time, the complete
Casing Deformation in Ultradeep Shale Hydraulic Fracturing,”
paper is free to SPE members
by Jianfa Wu and Bo Zeng, PetroChina, and Lipeng Wang,
at jpt.spe.org.
SLB, et al. The paper has not been peer reviewed.
TVD
Before hydraulic fracturing, the discrete –3800
fracture network (DFN) model was built, controlled –3860
by ant tracking. The ant-tracking approach had
–3920
several input factors to manipulate, making
–3980
identification of the best ant-tracking cube
challenging. In most instances, however, the
model could capture the main natural fracture
corridors. From the DFN model, the northeast/east,
north/south, and east/west natural fracture sets
could be clearly identified.
jpt.spe.org 81
TECHNICAL PAPERS | Hydraulic Fracturing Modeling
features, pressure depletion, well spacing, slurry pressure perturbation was promptly reduced
rate, and fluid volume. To forecast fracture hits to a lower level following the implementation of
on Pad X, it was necessary to first examine the mitigation techniques on the fracturing sequence.
underlying causes.
The primary cause of the fracture hits seen Casing-Deformation Mitigation and Validation.
in Pad X were the natural fracture corridor and In addition to fracture volume and slurry-rate
the hydraulic fracture connections. As a result, control, dynamic evaluation of slippage was used
close natural fracture corridors for each stage to optimize the fracture sequence. Increased pore
were found to be at high risk for fracture hits pressure during fracturing could have a greater
before fracturing. effect on the slippage of natural fractures across
Wells X-3 and X-4 but less effect on that of Well X-2.
Casing-Deformation Causes and Risk The initial fracturing sequence followed a
Identification. To identify the factors influencing sequence of Well X-2, Well X-3, and then Well X-4.
casing deformation, a variety of features was Well X-3 is easiest to be shear-deformed, then Well
examined. The Luzhou Block’s casing deformation X-4, and, finally, Well X-2, considering the natural
mostly was caused by shearing across the casing. fracture density and slippage under the same pore-
The stages with high casing-deformation risks pressure increase induced by fracture hits. Finally,
at Pad X were identified by calculating the natural the sequence was changed to Well X-3, Well X-4,
fractures’ stability before fracturing. The casing- and then Well X-2.
deformation risk was updated depending on iteration
of the DFN model and in-situ stress field. Finally, 18 Conclusions
stages with high casing-failure risk were identified. After practicing the model-driven work flow on
mitigating screenout, fracture hits, and casing-
Risk Mitigation and Validation deformation risks during Pad X hydraulic fracturing,
Screenout Mitigation and Validation. During the most screenouts were avoided, fracture hits were
fracturing job, quick adjustments to the pumping weakened, and no casing deformation occurred in
schedule were necessary to reduce screenout. For the study pad. The authors conclude the following:
the stages with high screenout risk as the result of • The G&G model is the basis for identifying
natural fractures, gel breakdown, proppant slugs, hydraulic fracturing risks.
or limited proppant volume were used to mitigate • Easily activated natural fracture corridors
the risk. For the stages with high screenout risk crossing the wellbore at a medium angle were
because of possible opening of bedding planes, the main cause of screenout. Proppant slugs
step-up rate was practiced to limit the bedding- and viscous breakdown at the beginning of
plane opening. For the stages with less potential fracturing are the preferred ways to mitigate
fracture initiation, two more clusters were added. screenout.
Ultimately, the average ratio of actual • The continuous natural fracture corridors and
proppant volume to planned proppant volume hydraulic fracture connections are the main
of all high-screenout-risk stages was 97%. For cause of fracture hits.
neighboring stages, performance was improved • Unstable natural fractures are the main cause
after adopting mitigation measures. of casing deformation. Lowering the effect
of fracture hits by adjusting the fracturing
Fracture Hit Mitigation and Validation. The sequence and controlling the fluid volume
staggered zipper fracture was adopted. The and slurry rate could help mitigate casing
observed fracture hit indicated by wellhead- deformation. JPT
Combining fracture and reservoir diagnostic degradation, unpropped fractures, and proppant
analysis with integrated geomechanics and reservoir embedment, can all be considered in the novel
simulation is an efficient and cost-effective approach fracture-conductivity-calculation methodology.
to generate realistic fracture geometry, understand
fluid flow behavior, and define fracture-conductivity Fracture-Conductivity-Calculation
distribution in unconventional reservoirs. The Work Flow
complete paper presents a case study of integrated The conductivity work flow developed by the authors
geomechanical and reservoir simulation with a uses simulated proppant concentration from a
developed fracture-conductivity-calculation work fracture model and experimental conductivity
flow that was validated with diagnostic results to measurements of propped and unpropped
evaluate well spacing and completions design. fractures to define variable conductivity along
hydraulic fractures. Conductivity measurements
Introduction included sets of long-term (50‑hour) experimental
This study extends that of previous authors by fracture-conductivity tests with various mesh
matching field fracture diagnostics and reservoir sizes, proppant types, and closure stresses.
simulation using variable fracture conductivity. The conductivity-calculation work flow developed
In the example used by the authors from by the authors was applied to the integrated
the Hydraulic Fracturing Test Site 2 (HFTS-2) simulation project of multifractured horizontal wells
development, multiple fracture diagnostic methods in the HFTS-2 project. Fig. 1 shows a flow chart of
were used to calibrate hydraulic fracture models. the work flow from fracture propagation modeling
Once the model was calibrated, a new proppant- through integrated reservoir simulations. In general,
conductivity algorithm assigned conductivity values the work flow consists of developing a 3D geological
along the hydraulic fractures based on a physics- model, creating and calibrating parent wells’
based model calculation of proppant concentration. hydraulic fracture models, calculating the fracture
Multiple mechanisms, such as stress- and pressure- conductivity based on proppant concentration,
dependent effects, time-dependent conductivity history-matching the parent wells’ production and
constraints with reservoir simulation, performing
fracture-propagation modeling for child wells, and
This article, written by JPT Technology Editor Chris Carpenter, history matching and predicting the estimated
contains highlights of paper URTeC 2023-3864710, ultimate recovery (EUR) for the entire pad.
“A Comprehensive Simulation Study of Hydraulic Fracturing
Test Site 2 (HFTS-2): Part I—Modeling Pressure-Dependent
and Time-Dependent Fracture Conductivity in Fully
For a limited time, the complete
Calibrated Fracture and Reservoir Models,” by Han Li,
paper is free to SPE members
Jichao Han, SPE, and Jiasen Tan, SPE, Occidental
at jpt.spe.org.
Petroleum, et al. The paper has not been peer reviewed.
jpt.spe.org 83
TECHNICAL PAPERS | Hydraulic Fracturing Modeling
Fig. 1—Flow
chart of the Fracture
integrated Conductivity
simulation Calculation
work flow.
The first FO-based well-interference and and well interference, the time-dependent fracture
production-logging test was performed using a conductivity was calculated for simulated fractures
proprietary procedure developed by ConocoPhillips in Wells BW3H and BW4H.
with an 18-hour shut-in period. The analysis of The mild degree of overlap observed between
Well BW4H DAS data showed no identifiable well the conductive fractures of Wells BW3H and
interference between Well BW4H and the offset BW4H may explain the observation that two-
wells, but the shut-in and open intervals were too well interference tests did not show meaningful
short to record sufficient pressure-gauge response evidence of well interference, but several vertical-
for estimating well-interference behavior. and slant-well pressure gauges captured a clear
The second interference test was performed in pressure response from the shut-in and open-well
September 2020 with longer shut-in and open time events. The hypothesis of fracture-conductivity
periods (3–6 days) on two child wells, BW3H and degradation over time caused by production
BW4H. In general, this two-well interference test did is shown to be plausible by integrating the
not show any meaningful evidence of interference, observations of multiple diagnostics data sets
but several vertical- and slant-well pressure gauges together. By including the pressure-dependent
captured clear pressure responses from the shut-in effect from production into the fracture-
and open well events. By integrating the pressure conductivity calculation, the calculated fracture
derivative analysis and pressure response from conductivity is expected to be lower.
gauges in Wells B5PH and B6S during the two-
well interference test, it could be observed that, Conclusions
during the second interference test, the conductive The authors reach the following conclusions:
fractures from Wells BW3H and BW4H did not • By using multiple diagnostic data sets,
severely overlap each other because no meaningful calibrated hydraulic fracture models can be
interference signature from pressure derivative developed for both parent and child wells.
analysis was recorded, but some mild degree of • A rigorous fracture-conductivity-calculation
conductive fracture overlap between the two wells methodology was developed based on
was expected based on the pressure response from simulated proppant concentration and net
multiple gauges in Wells B5PH and B6S. closure stress. Multiple physical mechanisms,
In evaluating the initial fracture conductivity such as pressure-dependent effect, unpropped
from the child wells’ simulation results, a large fracture conductivity, and time-dependent
degree of well interference is expected during conductivity degradation, are considered in
the early period of production in the HFTS-2 the methodology.
wells. Because propped fracture conductivity • By applying the fracture-conductivity work flow
decreases over time as the result of production and measured far-field pressure constraints
depletion and time-dependent effects, however, in a test case, the production history was
fracture conductive length and the degree of well matched for full wellbore simulations of both
interference should decrease over time. the parent and child wells.
In a reservoir simulation model, creep effect can • Creep deformation can result in propped
be modeled using a transmissibility multiplier placed fracture-conductivity loss and conductive
in the schedule section. Within the simulation grid, fracture dimension shrinkage over time. Along
the fracture dimensions become smaller over time with the fracture-conductivity work flow,
as proppant-pack conductivity is lost. creep deformation is critical for estimating an
To demonstrate the effect of creep accurate EUR and for optimizing well spacing in
deformation on fracture-conductivity change unconventional reservoirs. JPT
jpt.spe.org 85
TECHNOLOGY FOCUS
Flow Assurance
Celestina Yaaba Kissi, SPE, Offshore Chemist, ChampionX
T
his year has seen a focus on gas
development projects and the energy
“Flow-assurance issues remain
transition. Flow assurance plays an prevalent today, and an
interesting role in this area. Even analysis of existing solutions,
though the attention has been on the energy
transition, where gas development is concerned,
key to the success of oil and
the production processes through which gas is gas producing facilities, needs
produced cannot be ignored. Thus, flow-assurance to be addressed.”
issues remain prevalent today, and an analysis of
existing solutions, key to the success of oil and gas
producing facilities, needs to be addressed.
Tackling mixed-scale issues in the oil field using mixed scales in 24 hours at well temperatures
a novel robust scale dissolver (RSD) was studied with no incompatibility with production chemicals,
in paper SPE 211187. Scaling, an incompatible- pumping, and wireline components. This was
fluids-related flow-assurance problem in oil and done under laboratory conditions. A field trial was
gas wells at various locations in the Malaysian completed, with outstanding results for the RSD as
basin, results in rapid oil production decline. RSD it proved capable of reviving the well by resolving
is said to be capable of dissolving up to 100% of mixed-scale issues.
jpt.spe.org 87
TECHNICAL PAPERS | Flow Assurance
Fig. 1—Dissolution test with the RSD at room temperature. (a) A 5-g deposit was placed in a test tube; (b) the RSD was
added; and (c) the sample was left overnight, after which the deposit sample was more than 98% dissolved.
because of the increased interfacial area of the (SARA) analysis; determination of microcrystalline
droplets. Previous studies have reported that the wax using high-temperature gas chromatography;
microemulsion can be pumped without causing a measurement of composition ratio of deposits
significant increase in pumping pressure. through loss-of-ignition (LOI) tests; and mineral
characterization of inorganic component by
Problem Statement X-ray fluorescence analysis (XRF) and X-ray
Field PN is in the South China Sea off eastern diffraction (XRD). The XRF serves as a chemistry
Malaysia and has been categorized as a marginal analysis, while XRD identifies and measures the
field. It is one of the waxiest fields in Malaysia; presence and amount of minerals. Dissolution and
the water cut for its wells is reasonably high from compatibility tests were performed with crude
sandstone reservoirs. Therefore, scale-buildup oil, pumping, slickline components, and current
tendency and wax precipitation are high and production chemicals such as scale, corrosion,
may cause production tubulars to bottleneck, and wax inhibitors.
leading to a declining production rate. Well 1 in
Field PN suffered from mixed scales, verified by Results and Discussion
laboratory analysis and observed from the wellsite Laboratory Analyses. Several laboratory
throughout the tubing string and the near-wellbore analyses were conducted for pre- and post-RSD
casing. The total downtime of Well 1 was more pilot execution in Well 1. Detailed SARA analysis
than 95%, mostly because of sand and scale indicated that the sample contained both macro-
cleanout. The RSD formulation was applied and and microcrystalline wax. A saturate compound
evaluated. The success criteria of RSD deployment was the major component (more than 50),
in Well 1 were tubing clearance and well revival to showing that the sample was highly waxy. The
resume production. wax appearance temperature is 71.4°C, and pour-
point temperature is 54°C. The manual laboratory
Methodology practice considered the volatile nature of the
The deposit characterization was performed crude oil present in the deposit; a portion of this
through saturate, aromatic, resin, and asphaltene composition was dissipated through the testing
jpt.spe.org 89
TECHNICAL PAPERS | Flow Assurance
apparatus and processes. The standard deviation from the beaker and was cleaned. The sample was
of up to 7% is a widely accepted range in laboratory dried and weighed to determine the percentage
practice for establishing SARA composition. of weight loss. No obvious physical changes or
An LOI test was conducted, revealing that the weight loss were observed in the pumping and
deposit was 99.56% organic and 0.44% inorganic. wireline components.
Further analysis was conducted on the inorganic
sample to determine the probable inorganic Post-Job Treatment Evaluation. The treatment
content. XRF analysis determined that the major was designed for the pumping phase. The scale
inorganic content element was chlorine, while XRD cleared in the bottomhole portion after RSD
determined that the major mineral was halite. treatment accessed the end of the tubing and
Halite, commonly known as rock salt, is the mineral was completed successfully. Well 1 was revived
form of sodium chloride. Thus, the results between after RSD treatment, but overall well revival was
XRF and XRD are consistent. inconclusive because of operational constraints.
The dissolution test was conducted by using Thus, performance evaluations can be performed
the RSD. Based on the LOI results, organic content using simulation analysis. Prejob liquid production
contributed 99.56% of the total deposits sample. was 152 B/D with a matched tubing size of
As observed from the wellsite, the recovered 1.35 in., whereas fullbore is 2.991 in. Based on
sample was retrieved at shallower depths where simulation analysis performed through tubing
organic scale was likely to be deposited, whereas, sensitivity, Well 1 has the potential for post-
in deeper sections of the tubing, inorganic scale job improvement by clearing the tubing, which
was most likely to be deposited. The dissolution will increase production from 30 to 90 B/D with
test was conducted with a wellbore temperature pretreatment well-parameter conditions.
of 50°C (Fig. 1). The results showed that the RSD
can dissolve the deposit sample more than 98%. Conclusions
Meanwhile, at higher temperatures, the RSD can The Well 1 sample of organic and inorganic
dissolve 100% of the sample. deposits was dissolved successfully using the
Compatibility tests with production chemicals RSD. By elevating the temperature to 50°C, scale
such as scale, corrosion, and wax inhibitors also dissolution was expedited and the RSD formulation
were performed. The RSD was tested individually completely dissolved the deposit. Accordingly,
with those production chemicals, and the results field-equipment-compatibility tests showed that
showed that no incompatibility issues existed the RSD was compatible with pumping components
between the RSD and the production chemicals. and slickline wires. The RSD pilot in Well 1 has
Before job execution, a compatibility test demonstrated that mixed scales were cleared
was conducted with the pumping and wireline from the entire tubing after the wellbore-cleanout
components, including plunger seal, rubber seal, phase; the end of the tubing was accessed, and a
pump-plunger packing, suction and discharge through-tubing operation was performed. After
valve, butterfly-valve rubber seal, O-ring, segment receiving RSD treatment, Well 1 was revitalized;
seal-plug valve, hose, and stainless-steel wire. The however, because of operational challenges, the
objective was to evaluate the compatibility between overall success of the well revival was inconclusive.
the pumping and wireline components with the Thus, simulation analysis was used to evaluate
RSD. The sample was weighed and transferred into performance. The results demonstrated that Well 1
a breaker. Approximately 100 mL of the RSD was has the potential to increase its liquid production
added into the beaker and soaked for 24 hours from 30 to 90 B/D while maintaining the same well-
at room temperature. The sample was removed parameter conditions as before RSD treatment. JPT
Well MERO-006T is an oil development well that came Q2100X sand. The crude oil in the reservoir is
into production in March 1988 and has been plagued waxy and has resulted in several wax-cutting
with incessant wax buildup. Research indicates that jobs across the production life of the well. By
a wax-inhibition tool can be deployed in the well. February 1989, the production rate had declined
The complete paper highlights the thermodynamic to 198 BOPD on 28/64-in. bean. A dewaxing job
modeling approach adopted to determine the wax was completed, and production rose steadily,
appearance temperature (WAT) in Well MERO‑006T, peaking at 1012 BOPD at 195-psig tubinghead
the well-modeling approach to estimate the depth at pressure and 0% basic sediment and water in
which wax formation would occur, and the optimal May 1991, after which the well quit production
depth for the wax-inhibition tool based on life-cycle- because of wax by November of that year. Several
production expectations from the well. unsuccessful attempts were made to produce
the well until March 1994, when stimulation, wax
Introduction cutting, and nitrogen-lifting intervention was
Problems associated with wax deposition can performed. In April 1994, the interval produced
occur anywhere in the production system, from the dry at an average rate of 160 BOPD on 36/64-in.
reservoir to the terminal. Wax deposits result from bean until January 1995, when it quit again. Wax
the cooling effect of oil flowing from high-pressure cutting was performed in June 1997; the interval
reservoirs through the wellbore to the surface. produced dry at an average rate of 300 BOPD on
Depressurization of the oil as it is produced leads 36/64-in. bean. The well produced at approximately
to its expansion and temperature drop, which 300 BOPD until March 2003, when production rate
induces crystallization of wax. Considering the dropped to 170 BOPD. Solvent soak and dewaxing
effects of wax deposition on producing wells was performed in Q4 2004, and the well was
and facilities, prevention of the phenomenon opened to flow; production fluctuated between
is preferable to correction. 500 and 100 BOPD. The well was closed in for
low productivity as the result of wax formation
Challenges in October 2005. However, in 2017, the well’s B
Well MERO-006T was drilled and completed as annulus pressure was found to be higher than
a single-string single in November 1981 on the maximum allowable annulus surface pressure at
the wellhead. Post-risk assessment, the well was
classified as high-risk. In 2018, a remediation using
This article, written by JPT Technology Editor Chris Carpenter,
contains highlights of paper SPE 211943, “Prediction
and Prevention of Wax Deposition in MERO-006T:
For a limited time, the complete
A Thermodynamic Modeling Approach,” by Obiora Nwosu,
paper is free to SPE members
Olugbenga Daodu, SPE, and Basil Ogbunude, SPE, Shell,
at jpt.spe.org.
et al. The paper has not been peer reviewed.
jpt.spe.org 91
TECHNICAL PAPERS | Flow Assurance
static pressure was 3,453 psia, while the initial this depth was estimated at 2,529 ftah; however,
bottomhole temperature (BHT) was 218°F. The considering the expected late-life production
well was completed in 1988 with 3½-in. tubing. profile (increasing water cut), the wax appearance
Model predictions indicated that wax depth is estimated at 4,419 ftah. The wax-inhibition
precipitation would begin when the fluid tool is proposed to be installed at approximately
temperature decreased from the initial BHT 3,000 ftah in the production tubing in order to
of 218°F to the predicted WAT of 151.8°F. For account for mid- to late-life production. A profile
selection of the correct wax-inhibition tool, will be created at this depth in the production
considerations were made to ensure that tubing to install the tool with functionality to
installations were made a few feet below the remove and replace it by wireline when its life
depth corresponding to the cloud point, as well as cycle is exceeded.
possession of a flow area large enough to ensure
zero effect on oil-production rate. However, Conclusion
sensitivity was carried for late-life water cut (82%) Because of the historical, incessant wax buildup
to achieve a single installation for the remaining in Well MERO-006T, which has led to production
well life cycle, arriving at the corresponding depth deferment and loss of revenue, a longer-term
of 4,419 ft along hole (ftah). Based on these critical solution was proposed to install a wax-inhibition
long-term factors, the sensitivity of installation tool in the production tubing to mitigate this
at 3,000 ftah provided the best overall well- flow-assurance issue. Based on past experience
performance outcome. This will ensure effective where the tool has been installed and wax buildup
performance at the initial stage and mid- and late continued unabated, it became necessary to
life of the well. It was also essential to create a determine the temperature and depth of wax
profile close to this nucleating point (3,000 ftah) formation in future wells in order to optimally
for hanging the tool in the installation design. install the tool and improve its probability of
The closer the tool is to the nucleating point, the success in eradicating wax buildup. A well-
more effective its performance. Plans are in place modeling and thermodynamic-modeling approach
to monitor closely the effectiveness of the wax- was adopted, therefore, to address these critical
inhibition tool after deployment for purposes questions of temperature and depth. The tool also
of optimization. The worst-case outcome will be is proposed to be wireline-retrievable to facilitate
remedied by the typical wax-cutting approach tool replacement and maintenance without
for the well. carrying out a full-scale workover. It is estimated
that installing this tool would improve Well
Results MERO‑006T’s availability by 30% and avoid biannual
Well-model predictions indicated that WAT for costs of approximately $2 million associated
Well MERO-006T was predicted to occur at 172.5°F. with repeated wax treatment and intervention
The wax appearance depth corresponding to in the well. JPT
jpt.spe.org 93
TECHNICAL PAPERS | Flow Assurance
however, can only account for limited parameters. Quantitatively, the precision, recall, and F1
For example, the Reynolds number only considers score metrics were used for this analysis. The
the inertia and viscous effects, while the Froude precision is defined as the fraction of relevant
number only considers the inertia and gravity instances among the retrieved instance, while
effects. Therefore, a mechanistic multiphase-flow recall is defined as the fraction of relevant
model is used in this study that accounts for all instances that are correctly retrieved.
dimensions of the multiphase-flow problems and Neither precision nor recall can be used
reduces them into one dimension, namely the independently to assess overall model accuracy
discrepancy between the predicted value and in predicting flow pattern. A model that almost
experimental data. always predicts stratified flow will likely produce
The mechanistic model discrepancy analysis high stratified-flow recall but low stratified-flow
offers wide-ranging insights into the current precision. On the other hand, a model that only
multiphase-flow predictive capability, which predicts stratified flow in obvious cases will
can be used as a basis for future improvement produce the opposite. Many approaches exist to
efforts. Dimensionless numbers then can be used combine precision and recall into a single metric
to provide information on operating conditions that captures classification accuracy. The authors
where improvements (or special attention to the used the F1 score, which is appropriate when
uncertainty estimates) are particularly needed. the precision and recall are evenly weighted. The
This analysis also can be used to reveal outliers Tulsa University Fluid Flow Projects (TUFFP) Unified
(a subset of experimental data that differ from Model (henceforth “model”) was used for the
the model prediction in substantially larger analysis presented thereafter.
margins than the rest of the data). As a general
rule, experimental data are more trusted than Flow-Pattern Analysis
model predictions. Mechanistic models have been The confusion matrix of the model flow pattern for
extensively validated, however, establishing that the HP data set is described and analyzed in the
discrepancy outliers may reveal valuable insights complete paper.
into the data or the model. The model formulation allows simultaneous
In traditional flow-pattern-prediction accuracy modeling of flow-pattern transition and
assessments, experimental flow-pattern data are hydrodynamics by the slug unit cell model.
superimposed on the flow-pattern map predicted Starting with the slug-flow assumption, the model
by a model for constant fluid properties and solves for the film- (bubble-) zone fraction, which
pipe geometry. This analysis cannot be extended is the fraction of the slug unit cell not occupied
when the latter parameters are varied. In this by the slug body. When the film-zone fraction
study, the authors adopted a confusion matrix approaches zero, the model predicts a transition
used for classification problems used in the to dispersed bubble flow. Conversely, when it
literature. This analysis has been used for flow- approaches unity, the model predicts a transition
pattern-classification accuracy in low-pressure to segregated (stratified or annular) flow. This
data. Four general flow patterns were considered: approach can estimate the flow-pattern-prediction
stratified, annular, intermittent, and dispersed uncertainties for a given computed film-zone
bubble. Subpatterns are grouped into one of fraction value.
these four categories. For example, stratified wavy
and smooth are grouped into stratified flow; and Pressure-Drop Analysis
churn, slug, and elongated bubble are grouped Outlier Analysis. An essential step in the model-
into intermittent flow. performance analysis is identification of prediction
jpt.spe.org 95
TECHNICAL PAPERS | Flow Assurance
outliers, where the discrepancy between data and liquid holdup. An additional screening criterion
model is substantial. These outliers may indicate was implemented: the measured holdup shall
deficiencies in either the data or the model or both. not be smaller than the no-slip holdup for
An efficient way to identify such outliers is through horizontal and upward-inclined flow. Once again,
a violin plot, which displays the data distribution for these figures showed noticeable outliers for
several categories (in this case, the data source). upward low-liquid-loading data sets, particularly
The plot consists of the “violins,” which represent around the onset of liquid accumulation.
the data distribution for each category, computed Some data sets seemed to be systematically
with a kernel density estimation. Within each violin, underpredicted by the model; however, they
a white dot represents the median (Q2), a thick were still well within the standard deviation of
black line represents the interquartile range (Q1 the errors. The holdup value was always between
to Q3), and a thin black line represents the 95% 0 and 1, so the model could not underpredict
confidence interval of the data. The violin plot for more than 100%. The violins may reach values
the model pressure-drop prediction on the HP data smaller than –1, however, as an artifact of the
set is shown in Fig. 3 of the complete paper. The kernel density function used to generate the
analyses of the violin, parity, and discrepancy plots data distribution. Parity and discrepancy plots
are detailed there as well. for the holdup analysis are detailed in the
complete paper.
Combining Pressure-Drop Analysis With
Flow-Pattern Confusion Matrix. The authors Closure-Relationships Analysis
combined the pressure-drop and flow-pattern- The performance of mechanistic models depends
prediction accuracy analyses. This analysis is on the quality of the closure relationships used
useful to assess whether pressure-drop prediction to complement the conservation equations. From
errors stem from flow-pattern misclassifications the HP data set, several closure relationships
or deficiencies in the hydrodynamic model within were evaluated: entrainment fraction, slug or
the flow patterns. pseudoslug length, slug or pseudoslug-body
Misclassification of annular flow as stratified holdup, slug or pseudoslug frequency, and
flow, even though it is very common, does not slug or pseudoslug translational velocity. The
contribute to significant pressure-drop errors. On interfacial friction factor is one of the more
the other hand, misclassifications of intermittent commonly tuned closure variables because it
flow as stratified flow, and stratified flow as serves as a catch-all term used to match the
intermittent flow, have noticeably more significant model to data. To the authors’ knowledge,
effects on pressure-drop errors. Nevertheless, however, the variable itself is not directly
when the stratified flow in experiments was measurable (it is inferred from measured
correctly predicted by the model, the pressure- holdup by assuming a particular modeling
drop prediction error was even higher. It is framework). Therefore, the interfacial friction
important to note that this group of data was closure validation was excluded in this paper.
quite sizeable compared with other boxes in the The authors also analyzed closure relationships
confusion matrix, indicating that the stratified-flow for wave celerity, amplitude, and frequency.
model needed improvement. Because they are not used in the TUFFP unified
model, however, they also were excluded from this
Holdup Analysis paper for the sake of brevity. The results of the
Outlier Analysis. A similar data-screening work closure-relationship analysis are detailed in the
flow using a violin plot was implemented for complete paper.
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TECHNICAL PAPERS
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SPE NEWS
Nominations for SPE International and 1. Start the process early. Although
Regional Awards are open. Identify your nominations are due 15 February for International
colleagues who best qualify and submit your Awards and 1 March for Regional Awards, it is
nominations soon. International Award important to identify a candidate for nomination,
nominations close on 15 February, and Regional letter writers, and supporting documents as early
Award nominations close on 1 March. as possible.
I attended my first SPE awards banquet in 2. Identify a nominee and the award
2007 at the Annual Technical Conference and most suited for their accomplishments.
Exhibition (ATCE) in Anaheim, California. I was Have a discussion with the nominee about their
a new assistant professor at The University of career and where they best fit in and be sure
Texas at Austin and relatively new to SPE and that they meet the eligibility requirements. I
the industry. suggest reviewing recent winners of the award to
I was mesmerized by the whole awards determine if the nominee’s accomplishments are
banquet experience: the entertainment, dinner, comparable. If you believe that there is an award
flashing lights and music when winners were for which you are best suited, don’t be shy about
announced, fancy awards, and speeches. It was approaching a colleague about nominating you.
like the Oscars, but for engineers! 3. Consider a Regional Award before an
At the time, I only recognized the names of International one or a technical award/SPE
a few of the winners but would later learn that Distinguished Member Award before the more
these were the professionals that wrote landmark prestigious ones like the SPE John Franklin Carll
books, developed impactful equations, and made Award for Distinguished Professionals or SPE/AIME
discoveries that changed the trajectory of our Honorary Member Award. Importantly, winners of
energy future. Regional Awards are automatically nominated for
Since that first memorable experience, I have the International Award the subsequent year. Also
attended the awards banquet annually, nominated consider awards that are historically overlooked
dozens of colleagues, and written dozens more by nominators, for example the SPE/AIME Charles
letters of recommendation. I was honored to F. Rand Memorial Gold Medal and the SPE/AIME
receive the 2014 SPE Regional Young Professional Robert Earll McConnell Award.
Outstanding Service Award, 2017 SPE Distinguished 4. The nominator should work closely
Membership, and most recently the 2022 SPE with the candidate to develop a thorough
Lester C. Uren Award. nomination form. I recommend including very
Receiving these awards were some of the most specific accomplishments, possibly in bullet form,
exciting, fun, and humbling nights of my life. I hope that the review committee can consider and
to share that wonderful experience with as many compare to other nominees.
SPE members and colleagues as possible. 5. Identify and contact up to six colleagues
My advice to anyone aspiring to nominate a to write letters of recommendation for the
colleague, or be nominated, is as follows. nominee. Ideally, these colleagues should be very
jpt.spe.org 101
SPE NEWS
jpt.spe.org 103
SPE NEWS
EUGENE ALLEN “AL” changes in the world made immature basins such
BREITENBACH, 1994 as those found in the former Soviet Union, China,
SPE President, passed several countries along the Pacific Rim, and many
away on 31 August. He countries in South America become available
was 86. Breitenbach’s for exploration for the first time in decades.”
career began at Mobil Throughout his tenure, he highlighted his four
Oil and later Marathon goals: to review the SPE financial system so that
Oil before starting his own SPE could more accurately investigate costs and
company, Scientific Software income and return to profitability; to define the
Corporation, an energy consulting company. He new SPE worldwide organization that would reflect
is credited with writing one of the first computer the changes that were occurring; to adopt a policy
programs for black-oil reservoir simulation. In and proceed with intersociety relations; and to
1968, he coauthored SPE 2020 on fluid flow begin to solve the question of how to provide our
simulation equations. technology to the new generation of “competent
An SPE member since 1960, he served generalists.” Speaking about his presidency
on several committees including Reservoir during SPE’s 50th anniversary in 2007, he said
Monitoring and Testing (1970–1971), Education “My role during this challenging period was to be
and Accreditation Committee (1975–1980), the designated SPE cheerleader leading the pursuit
Symbols and Metrication (1965–1984), of our vision. It was an honor to serve.”
Distinguished Service Award (1983–1986), Breitenbach held bachelor’s, master’s, and
SPE/AIME DeGolyer Distinguished Service PhD degrees in petroleum engineering, all from
(1988–1991), Denver Section Officers (1986–1992), Stanford University.
United States Council (1990–1993), Middle East Oil
Show Program Committee (1992–1993, 1995–1997),
Nominating Committee (1990–1991, 1993–1995),
Distinguished and Honorary Member Award
committees (1994–1995), and SPE Foundation In Memoriam
Executive (2000–2002). He also served as This section lists with regret SPE members
chairperson of the Education and Accreditation who recently passed away. If you would like
Committee (1978–1979), chairperson of the to report the passing of a f amily member
Distinguished Service Award Committee who was an SPE member, please write to
(1985–1986), SPE/AIME DeGolyer Distinguished service@spe.org.
Service Committee (1990–1991), chairperson of the
Ernest G. Dugas, Lafayette, Louisiana
United States Council (1993–1993), and chairperson
Cary Griggs, Midland, Texas
of the Nominating Committee (1994–1995).
He was the recipient of the SPE Regional Service William B. Hopkins III, Houston, Texas
Award, SPE John Franklin Carll Award, and SPE William G. Lowrie, Columbus, Ohio
Distinguished Membership. Stephen J. McClaine, Midland, Texas
As SPE President, he focused on “Winds of Kerry Lloyd Zemp, Denver, Colorado
Change.” He summarized this theme as “political
jpt.spe.org 105
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