Henry B.

Gonzalez Convention Center

San Antonio, Texas, USA
16–18 October 2023

SHARING VISIONS
FOR THE FUTURE
OF ENERGY FIND OUT
MORE AT

ATCE IN NUMBERS
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ATCE2023JPT

6,000+ 66,000+ 400+ 50+

international E&P sq. ft of technical presentations international
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Contents
10 
GUEST EDITORIAL • Is CO2 Removal Technology Key
Volume 75 | Number 6

to a Sustainable Future?
The innovations in the carbon removal space are gaining attention for
their potential to curb global climate change but they each face particular
challenges in implementation.
18 
Offshore Decommissioning: Planning for the End
at the Beginning
With global decommissioning activities forecast to reach $100 billion
through 2030, early planning for it could go far in helping to minimize
risk and associated costs.
22 
Who’s Right? Imaging of Fractures Often Delivers
Conflicting Measures
When there are two ways to measure something, and they offer
significantly different numbers, which do you use?
30 
Flood Management: Solving Conformance On the cover: According to the US Bureau
or Sweep Efficiency Problems—Part 2: Connecting of Safety and Environmental Enforcement,
the offshore energy industry has averaged
Problems to Solutions
200 platform removals in the Gulf of
In Part 2 of a series of articles, the author focuses on generating a Mexico per year over the past decade.
connection between the problem types and various methods of trying Source: Getty Images.
to solve these problems.
36 
Journey to an “A” Grade Gas Certification
This article describes the MiQ grading framework for natural gas in more
detail and explains practical pathways for industry participants to achieve DEPARTMENTS
any desired MiQ grade.
4 President’s Column
40 Case Study: China Field Test of Dissolvable Collet
Demonstrates Time and Cost Savings 8 Comments
A dissolvable collet field tested in an unconventional completion led to 14 E&P Notes
an average running time of 32 minutes per stage in a vertical section and 88 SPE Technical Papers
19 minutes per stage in the horizontal section. Available
89 SPE News
96 SPE Events

An Official Publication of the Society of Petroleum Engineers. Published in US. Copyright 2023, Society of Petroleum Engineers.
 Recent Content from
SPE’s Journals
To view these papers, go to
OnePetro, www.onepetro.org,
and search by title or paper
number or navigate to the journal.
Technology Focus
The complete SPE technical papers featured in this issue are available

SPE JOURNAL free to SPE members for 2 months at jpt.spe.org.

SPE-214680-PA—Unsupervised
Adversarial Domain Adaptation Regression 44 COILED TUBING
for Rate of Penetration Prediction
Pierre Ramondenc, SPE, Coiled Tubing Domain Head, SLB
SPE-214692-PA—In-Depth Laboratory
Proppant Transport Study Using HVFRs 46 
Engineering Approach Uses Underbalanced Coiled-Tubing Drilling
for Marcellus High TDS Environments
49 Riser Allows Live-Well Intervention With Coiled Tubing
SPE-214684-PA—Apparent Heat of From Monohull Vessel
Reaction of Heavy Oil with Application
of Accelerated Rate Calorimeter 52 Casing Leak Repair Allows Continued Hydraulic Fracturing

SPE PRODUCTION
& OPERATIONS 55 ACIDIZING
SPE-210173-PA—Methane Emissions Imran Abbasy, SPE, Managing Director and CEO,
Quantification and Resulting Pakistan Petroleum Limited
Methane Emissions Reduction
in the Permian Basin Enabled by 57 
Simulator Aids Design, Analysis of Acidizing Jobs
Automated Unmanned Systems With Fluoroboric Acid
SPE-214686-PA—Leak Detection
in Natural Gas Pipelines Based
60 Study Investigates Ineffectiveness of Acid Fracturing
on Unsupervised Reconstruction for Tight Reservoir Rock
of Healthy Flow Data
63 Multistage Acid Stimulation Uses Straddle Packer,
SPE-210432-PA—Kaolinite Effects Real-Time Telemetry
on Injectivity Impairment: Field
Evidence and Laboratory Results
66 HYDRAULIC FRACTURING OPERATIONS
SPE DRILLING
& COMPLETION
Shahvir Pooniwala, SPE, Subject-Matter Expert, Saudi Aramco

SPE-214691-PA—Using Transient 68 
Hydraulic Fracturing Unlocks Potential of Europe’s Largest Reservoir
Modeling to Define the Effects of
Heave on Wellsite Operations
71 Advanced Diagnostics Aid Understanding at Hydraulic Fracturing
Test Site 2
SPE-214679-PA—Application of Group
Method of Data Handling via a Modified 74 Integrated Optimization System Improves Hydraulic
Levenberg-Marquardt Algorithm in the Fracturing Operations
Prediction of Compressive Strength
of Oilwell Cement with Reinforced Fly
Ash Based on Experimental Data 77 EOR OPERATIONS
SPE-214685-PA—Quantification Soujatya Mukherjee, SPE, Senior Reservoir Engineer,
of Shrinkage-Induced Cracking Wintershall DEA
in Oilwell Cement Sheaths
79 
Data-Driven Virtual Viscosity Meter Augments Inline,

SPE RESERVOIR EVALUATION

& ENGINEERING
Laboratory Measurements
82 Technique Evaluates Polymer Injectivity
SPE-214683-PA—Stochastic
Estimation of Barrels of Oil Equivalent in High-Salinity/High-Temperature Carbonates
Conversion Factor for Natural Gas
Volumes from Offshore Carbonate 85 Efforts Lead to Formulation of High-Performance ASP
Fields in Ultradeep Waters
SPE-211475-PA—Smartwater Synergy
with Chemical EOR: Studying the
Potential Synergy with Surfactants
SPE-212726-PA—Stage-by-Stage Hydraulic
Fracture and Reservoir Characterization JOURNAL OF PETROLEUM TECH­NOLOGY ( JPT) (ISSN 0149-2136) is published monthly by the
through Integration of Post-Fracture Society of Petroleum Engineers, 222 Palisades Creek Drive, Richardson, TX 75080 USA.
Pressure Decay Analysis and the Flowback
To contact Customer Service, call 1.972.952.9393 or service@spe.org, or Update Your Profile
Diagnostic Fracture Injection Test Method
at https://www.spe.org/members/.
SPE BOARD OF DIRECTORS
Get more
2023 President
Medhat M. Kamal
2022 President
Kamel Ben-Naceur out of your
Chevron Fellow Emeritus Nomadia Energy
Consulting SPE membership
2024 President Secretary
Terry Palisch Mark Rubin, Society of
CARBO Ceramics Petroleum Engineers

REGIONAL DIRECTORS
AFRICA MIDDLE EAST AND NORTH AFRICA
Oghogho Effiom, Shell Nigeria Hisham Zubari, Dragon Oil

ASIA PACIFIC NORTH AMERICA

Henricus Herwin, Pertamina Simeon Eburi, Chevron
Neil Kavanagh, Woodside Energy Robert Martinez, Titan Rock E&P
Deb Ryan, S&P Global Platts
EUROPE
Laura Precupanu, OMV Petrom RUSSIA AND THE CASPIAN
Ignatiy Volnov, Lukoil
LATIN AMERICA AND THE CARIBBEAN
Gail Ramdath, Tucker Energy Services

TECHNICAL DIRECTORS
COMPLETIONS DATA SCIENCE & ENGINEERING ANALYTICS
Karen Olson, Olson Turner Enterprises Silviu Livescu, University of Texas at Austin

DRILLING PRODUCTION AND FACILITIES

Robin Macmillan, Data Gumbo Hamad Al-Marri, Saudi Aramco Two simple steps will
HSE AND SUSTAINABILITY RESERVOIR help us serve you better!
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 PETROLEUM++

ATCE, Financial
Results, and GEODE
Medhat Kamal, 2023 SPE President

The Annual Technical Conference and Exhibition throughout the industry. We usually get a chance
(ATCE), SPE’s flagship event, will be held in San to meet with friends that we have not seen for a
Antonio, Texas, from 16–18 October. I encourage while and to create new friendships with members
all members to seriously consider attending ATCE that we meet during the conference.
this year to benefit from the knowledge sharing One of my favorite activities during ATCE
presented by fellow members across all disciplines is the alumni receptions. I always look forward
of petroleum engineering. to catching up with my classmates from my
Some SPE conferences are topically focused, universities and learning from their experiences.
such as the reservoir simulation, hydraulic fracturing, This year, ATCE promises to provide all the benefits
and HSE conferences. ATCE, on the other hand, is I just described as we welcome people back to our
the conference where all petroleum engineering in-person events after the COVID-19 pandemic. It is
and related disciplines are discussed and serves encouraging that more and more of our members
as a barometer to help professionals gauge which are coming back and attending events after we lost
specific competencies are needed now and in the this opportunity for several years.
future. It is also important that we are aware of the As a member of the SPE Legion of Honor, I
developments and the changes in other technical had the opportunity to attend numerous ATCEs
areas and of the directions our industry is taking starting with my first conference in 1973 held in
based on the changes in economic, political, and Las Vegas. I’ve attended and enjoyed every ATCE
technical arenas. ATCE is an excellent venue for all of since then, minus one I was unable to attend
us to obtain a broad range of information and trends. in Calgary.
I am sure that most of our members are also I would like share with you some of the
aware of the additional benefits that may be history of ATCE since its inception in 1924. The
obtained through attending ATCE. We know of conference in San Antonio will be the 100th
the extensive exhibits where service, technology, edition of ATCE. As most of our members know,
and manufacturing companies provide members SPE was originally the petroleum branch of the
with the latest developments and enhanced American Institute of Petroleum and Metallurgical
products. Some national and international Engineering (AIME). It became its own society in
organizations show their work and major projects. 1957, and in 1958, ATCE was held in Houston.
All discuss developments that are affecting our The event rotated between several US cities since
profession and provide guidance about what we and was held for the first time outside the US in
need to know to continue having successful and Florence, Italy, in 2010.
enjoyable careers. Since SPE became an independent society,
Another advantage of attending ATCE is the ATCE was held 16 times in Houston, 11 times in
ability to network with our colleagues and friends Dallas and New Orleans, eight times in Denver

4 JPT | June 2023

 PETROLEUM++

Med Kamal, 2023 SPE President, talking about the future of our industry and the path forward for students and
young professionals at Penn State University.

and San Antonio, three times in Las Vegas, twice to do the best you can to attend ATCE this year
in the Los Angeles area and Dubai, and once in and beyond.
San Francisco, Washington DC, Florence, Italy,
and Amsterdam. Industry Activity
An interesting fact about ATCE attendance: The activities in the energy industry, in our
It does not necessarily reflect the ups and downs organizations, and our companies are trending
of our industry. Attendance sometimes increases back up and getting excellent financial results.
when there is a downturn in the industry, which Additionally, with the attention in the energy
may be an indication that members desire to make landscape on climate change issues and the
more presentations and increase networking to continued developments in new forms of energy,
improve their chances of retaining their jobs. we find there is a continuous recalibration of the
The highest attendance of ATCE over the years activities of our companies to continue working
was more than 10,000 attendees in Houston in and obtaining positive financial results in the
1984 and in 2015. In 1998, Hurricane Georges traditional oil and gas business while devoting
hit New Orleans, resulting in the cancellation of needed efforts in a practical way to both mitigating
ATCE. However, there were many of us who had climate change issues and in developing new
already arrived in the city before the hurricane forms of energy. A look at some of the recent
in preparation for the event and were trapped first‑quarter results can shed some light on that
in hotels downtown. We had nowhere to go point and will remind all of us that there is no such
with travel out of the city shut down, so we all thing as a constant trend in our industry. Activities
got together and decided since we had already will continue to be recalibrated, reflecting the
prepared our presentations to go ahead and changes in the world economy and the demand
present to each other in the hotels. This was a for our products.
unique and extremely informative experience. We Chevron announced financial results showing
had a chance to listen to presentations outside our a profit of nearly $6.6 billion in the first quarter,
areas of expertise. I remember that I heard more an improvement over the first quarter 2022
drilling talks during this meeting than in any other ($6.3 billion) and $6.4 billion in the fourth quarter
place since I usually attend talks in the area of of 2022. “While commodity markets remain
reservoir engineering. We actually had a meeting. uncertain, our approach remains unchanged,”
Although the conference was officially cancelled! said Mike Wirth, Chevron’s chairman and chief
ATCE will continue to be the flagship meeting of executive officer. “Capital and cost discipline
our Society as it has all the advantages and services applied to advantage assets in both traditional
that benefit our members. I encourage all of you and new energy businesses mean a steady return

jpt.spe.org 5
 PETROLEUM++

Technical sessions at 2023 OTC were well attended.

of cash to shareholders.” Wirth said that while the oil and gas production and liquefied natural gas
diesel demand had declined, jet fuel demand had divisions and place the renewables business in the
increased. “Gasoline demand is essentially back to downstream division.
pre-pandemic levels globally,” he said. “In Asia, we In February, BP rowed back on plans to slash its
see demand coming back as China continues to 2019 oil and gas output levels by 40% by 2030, and
open up and mobility increases.” now it envisages a 25% cut.
ExxonMobil reported a first-quarter profit Saudi Aramco gained $31.9 billion in the first
of $11.4 billion, compared with $5.48 billion quarter of 2023 and paid $19.5 billion in dividends
a year earlier. Earnings were down from the for Q4 2022 which is a 4% increase over the
$12.8 billion earned in the fourth quarter of previous quarter. “The results reflect Aramco’s
2022. Darren Woods, ExxonMobil’s chairman and continued high reliability, focus on cost and
chief executive officer, expressed confidence in our ability to react to market conditions, as we
the future, though he said the global outlook for generate strong cash flows and further strengthen
energy markets would depend heavily on China’s the balance sheet. Reinforcing our commitment
economic recovery. “Gasoline demand looks to maximize long-term shareholder value,”
pretty reasonable,” Woods said. “Jet demand commented Amin H. Nasser, Aramco president
and transportation looks like it’s trending up. and chief executive officer. “We are also moving
Expectations look pretty healthy.” forward with our capacity expansion, and our long-
Shell reported adjusted earnings of $9.6 billion term outlook remains unchanged as we believe
for the first 3 months of the year, comfortably oil and gas will remain critical components of the
beating analyst expectations of $8.6 billion. The global energy mix for the foreseeable future.”
company posted adjusted earnings of $9.1 billion SLB reported revenue of $7.7 billion, an
over the same period a year earlier and $9.8 billion increase of 30% year on year; GAAP EPS of $0.65
for the final quarter of 2022. Shell is also splitting increased 81% year on year; EPS, excluding
up its renewables and low-carbon division as charges and credits, of $0.63 increased 85%
part of CEO Wael Sawan’s shake-up to boost the year on year; net income attributable to SLB of
company’s returns. The changes come as Sawan, $934 million increased 83% year on year; and an
who took office at the start of the year, signaled SLB Board approved a quarterly cash dividend of
that Shell is considering ditching oil-reduction $0.25 per share.
output targets as part of its energy transition plans. The figure shows the sustained increase in rig
The changes to the renewables business come count following the economic downturn in 2015
2 months after Sawan announced plans to combine and then the COVID-19 pandemic in 2020.

6 JPT | June 2023

 PETROLEUM++

Another indication of the industry rebound is award up to $165 million to expand geothermal
the increased attendance at this year’s Offshore energy deployment by leveraging technologies
Technology Conference (OTC). More than 1,300 and workforce from the oil and gas industry over
companies from 104 countries showcased their 5 years.
technologies and equipment on the exhibition The skills our members have in the drilling,
floor, spanning more than 276,000 ft2. In addition, completions, production, reservoir, data science,
countries from around the world brought together and HSE&S disciplines are critical to advancing
energy industry delegations to showcase the vast geothermal and many of our members work in
offshore energy opportunities globally on the this space, as shown by our Geothermal Technical
exhibition floor. OTC was pleased to welcome more Section which is already 1,700 members strong.
than 31,000 participants this year, a 30% increase SPE has a long history of identifying areas
from last year’s conference. where technical advancement will benefit the
industry and capturing the state-of-the-art
GEODE Funding technology. This project is clearly in line with our
SPE and consortium partners Project Innerspace mission to disseminate technical information, and
and Geothermal Rising were awarded $165 million the SPE Board approved submitting a proposal
in the first phase of the US Department of Energy’s in collaboration with two other not-for-profit
(DOE) “Geothermal Energy from Oil and Gas societies, Project Innerspace and Geothermal
Demonstrated Engineering” (GEODE) project. Rising. This proposal pulls in the cooperation of
This represents an example of some great a consortium of universities, national labs, SEG,
progress on the second + of my Petroleum ++ AAPG, and industry.
theme, namely advancing additional energy sources. I would like to thank the Geothermal Technical
Last July, the DOE announced its GEODE Section for expressing their desire to participate
Funding Opportunity Announcement which would in the project and Silviu Livescu, Tim Lines, and
John Boden for presenting to and obtaining the
Board’s approval last October and for their hard
work during October and November in drafting the
proposal and working with our partners to build
the consortium.

Around the World

Last month, SPE presidents continued to visit
sections and chapters around the world both in-
person and virtually. Kamel Ben Naceur visited SPE
chapters and sections in Saudi Arabia, Romania,
Thailand, and in Timor-Leste. I participated in
meetings with Port Harcourt, Nigeria; Nazarbayen
University Student Chapter in Astana, Kazakhstan;
and Penn State Student Chapter in State College,
Pennsylvania. Terry Palisch opened the Oklahoma
City Oil and Gas Symposium, participated in Well
The international rig count shows a sustained increase Completions ATW in Scottsdale, Arizona, and
since the 2015 economic downturn and then the 2020 visited the chapters at Florida A&M and Texas Tech.
COVID-19 pandemic. Source: Baker Hughes
Until next month! JPT

jpt.spe.org 7
 COMMENTS

Economic Realities
of Energy Transition
For example, Equinor put an indefinite hold
Pam Boschee on its plans for a floating offshore wind farm,
JPT Managing Editor Trollvind. Initially planned to have an installed
capacity of about 1 GW and annual production of
4.3 TWh, the electricity was to be used to run the
Troll and Oseberg fields.
The operator cited “challenges facing the
No one expected the energy transition to be broader offshore wind industry,” including how
without hiccups, and recently, those hiccups rising costs changed its original view that Trollvind
have been heard within and outside the oil and would not require any financial support. “It is no
gas industry. longer a commercially sustainable project,” Equinor
Daniel Yergin, vice chairman of S&P Global and said in a statement. It added that the unavailability
author of several books, wrote how previous energy of preferred technology made the concept less
transitions evolved over the course of a century or viable and that the proposed timeline was not
more and did not “wholly displace the incumbent achievable to the level required to go forward.
technologies.” Oil became the world’s No. 1 energy Shell recently pulled out of the Northern
source in the 1960s, bumping coal from the top. Endurance Partnership, Britain’s CCS project
“ … Yet we now use three times more coal than we targeting industrial decarbonization. Another
did back then, with global consumption hitting a equity holder, National Grid, also withdrew
record high in 2022,” he noted. from the project, dropping its plans to construct
He continued, “By contrast, today’s transition pipelines to transport the CO2 to the North
is intended to unfold in little more than a quarter Sea. The equity holdings were acquired by
century and not be additive.” Yergin cited a 2021 the remaining project partners, BP, Equinor,
paper by Jean Pisani-Ferry, an economist at the and TotalEnergies.
Peterson Institute for International Economics, The need for return on investments (ROI)
who wrote that moving too rapidly to net‑zero was highlighted in a survey of global energy and
emissions could precipitate “an adverse supply natural resource executives by Bain & Co. in
shock—very much like the shocks of the1970s” May. The responses showed executives believe
and that it “is unlikely to be benign and their companies are outperforming the rest of
policymakers should get ready for tough choices.” the world in reducing emissions but expect the
The outcome of those tough choices rate of decarbonization to slow down over the
is becoming evident, both in policy and next few years. The surveyed companies expect
companies’ actions. to deploy about a quarter of their capital on new

8 JPT | June 2023

 JPT EDITORIAL REVIEW BOARD

growth businesses in 2023, many of these focusing on Barbara Pribyl—Chairperson, Consultant

Imran Abbasy, Pakistan Petroleum
low‑carbon technologies.
Anson Abraham, CNRL
The executives aren’t concerned about accessing
Amir Alwazzan, Dragon Oil
capital for low-carbon businesses, but “need to ensure Mariela Araujo, Shell
adequate returns on the investments.” Four out of five Jyotsna Asarpota, Halliburton
executives considered the ability to create acceptable Elizabeth Barsotti, MRC Laboratory
Linda Battalora, Colorado School of Mines
returns on projects a main barrier to decarbonization.
Zhiming Chen, China U. of Petroleum
Customers demonstrate an unwillingness to pay—not
Graham Collier, Consultant
universally, “but enough to make it hard to scale low- Santanu Das, ONGC
carbon businesses.” They look to government policy Sandeep Dhawan, WellPerform
and regulatory support to help bridge the gap. Reza Fassihi, Beyond Carbon
Complicating ROI is how it is perceived in the eye of Michael Fuller, Chevron
Jeff Gagnon, ExxonMobil
the investor. What investors value is not limited to the
Reza Garmeh, Callon Petroleum
dividends they may receive. Individual and institutional
Subodh Gupta, Heretech Energy
investors are increasingly paying attention to ESG Dennis Harris, Chevron
(environmental, social, and governance) criteria. Hussein Hoteit, KAUST
Norway’s $1.4 trillion wealth fund, which invests Mehdi Izadi, ExxonMobil
Siddarth Jain, Sharjah NOC
Norwegian state revenues from oil and gas production,
Simon James, CS8 Consulting
on 26 May said it would vote for shareholder proposals
Swathika Jayakumar, Core Laboratories
at Chevron and ExxonMobil to adopt a medium-term Colin Johnston, Worldwide Oilfield Machine
Scope 3 greenhouse gas (GHG) reduction target. Muhammad Khan, ADNOC
Scope 3 refers to emissions not produced by the Celestina Kissi, ChampionX
company itself or from its owned or controlled assets, Ergun Kuru, University of Alberta
Mahdi Mahmoudi, Variperm
but those it is indirectly responsible for, up and down
Swamy Margan, Baker Hughes
its value chain. Mark McClure, ResFRac
Last year, the fund said it would push the Graham Mensa-Wilmot, XCIDrill Technology
companies it invests in to cut GHG emissions to net Patrick Miller, Petronas
zero by 2050, in line with the Paris Agreement. It Sandeep Mukherjee, Callon
Soujatya Mukherjee, Wintershall DEA
emphasized that it would not divest from big emitters
Anand Nagoo, Nagoo and Associates
to achieve these targets and would instead be an “active
Gopi Nalla, DeGolyer and MacNaughton
shareholder” to effect change. “The easy way to cut Eudorah Ochai-Audu, Shell
down emissions is to sell out,” fund CEO Nicolai Tangen Danny Ochoa, Schlumberger
said. “But someone needs to own these companies and Carlos Pedroso, Enauta
it does not solve the problem, quite the contrary.” Shahvir Pooniwala, Aramco
Kaibin Qiu, Schlumberger
When Shell CEO Wael Sawan discussed the
Pierre Ramondenc, Schlumberger
company’s 2022 record profits of $39 billion, he said, Michael Romer, ExxonMobil
“Profit without sustainability erodes our license to Babatunde Salawu, Shell
operate. Sustainability without profit erodes our Débora Salomon, Dow
shareholder support and financial capacity to play Amit Singh, Chevron
Victor Soriano, YPFB Chaco
a meaningful part in the energy transition. We must
Cornelis (Kees) Veeken, Consultant
continue to provide energy and do it with fewer
Larissa Walker, QGC
emissions. We can only do this with the backing Junjie Yang, Baker Hughes
of our shareholders because it is their capital that Karam Yateem, Saudi Aramco
enables us to invest in the energy transition.” JPT

jpt.spe.org 9
 GUEST EDITORIAL

Siddharth Misra, Is CO2 Removal

Technology Key to a
SPE, is an
associate
professor at
Texas A&M
University who
has published
two books and
Sustainable Future?
developed nine
technologies related to Siddharth Misra and Sateesh Kumar Puri, Texas A&M University
machine learning and electromagnetic

T
sensing for energy and earth resource
exploration. In 2018, he received the he urgent need to address climate change has unleashed a
US Department of Energy Early Career
wave of innovative ideas on how to mitigate the greenhouse
Award, and in 2020 he was honored
with four international awards for gas (GHG) emissions that are driving the problem. Among
his contributions to exploration the approaches considered to hold great promise is carbon
geophysics and subsurface dioxide removal, or what some call negative emissions technologies.
engineering. Misra holds a bachelor’s
of technology degree in electrical
These strategies have attracted significant attention in recent
engineering from the Indian Institute years and involve removing carbon dioxide (CO2) from the atmosphere
of Technology, Bombay, and a PhD and storing it in long-term sinks such as oceans, forests, and
degree in petroleum and geosystems
underground geological formations.
engineering from The University of
Texas at Austin. He can be reached at What follows is a closer look at how these strategies work, their
misra@tamu.edu. potential to address the global climate crisis, and the challenges they
currently face.
Sateesh Kumar
Puri is a civil
engineer with Direct Air Capture (DAC)
a master’s of
This technology captures CO2 directly from the air using chemical
technology
degree in reactions and/or physical processes. The captured CO2 can then be
structural stored in a long-term sink, used for food processing and cement
dynamics manufacturing, or combined with hydrogen to create synthetic fuel. There
in earthquake
engineering from
are currently about 20 direct air capture plants operating worldwide.
the Indian Institute of Technology Climeworks’ Orca plant in Iceland, the largest operating DAC plant
Roorkee and is currently pursuing a in the world, has the capacity to remove 4,000 tons of CO2 per year
master’s of science in construction
and store it deep underground. The majority of commercial direct
engineering and management from
Texas A&M University. His track air carbon capture techniques utilize large fans to force ambient air
record includes successfully leading through a filter, with a liquid solvent, often amine-based or caustic,
the development of the Chennai
being used to absorb CO2 from the gas.
Metro Rail Project Phase I, resulting
in significant reductions in rework There are three chemical processes that are being studied extensively
and project delays. Additionally, his for purposes of DAC: causticization using alkali and alkali-earth hydroxides,
work on academic projects such carbonation, and organic-inorganic hybrid sorbents consisting of amines
as seismic design of buildings with
irregular configurations, analysis of
supported in porous adsorbents. Additionally, others are exploring
proposed construction planning of a membrane separation methods based on semipermeable membranes
state highway, and design of refugee to capture CO2, which require less water and a smaller footprint.
camps in Turkey, demonstrates his
Perhaps the biggest challenge facing this technology’s ability to
commitment to the advancement of
sustainable engineering practices. scale up lies in its ability to be economically successful given current
carbon credit pricing regimes balanced with the unknown amount of

10 JPT | June 2023

 GUEST EDITORIAL

energy DAC units will need to achieve meaningful grinding, dispersing, and dissolving minerals like
capture volumes. olivine, limestone, and silicates to address ocean
acidification and sequester CO2.
Ocean Fertilization Another approach is in-situ mineral carbonation
The aim of ocean fertilization (OF) strategies is to that involves injecting CO2 into silicate rock formations
enhance certain biological processes in the oceans to promote carbonate formation underground.
that will lead to increased uptake of atmospheric While enhanced weathering has the potential
CO2 followed by permanent storage in deep to be effective in capturing CO2, it also has the
oceanic layers. potential to result in negative side effects including
The technique involves the addition of nutrients unexpected shifts in water and soil chemistry, the
such as iron, phosphorus, and nitrogen to the release of heavy metals, alterations in carbon and
ocean for stimulating the growth of phytoplankton nutrient cycling, and high energy and resource
that absorb CO2 from the atmosphere. When the use associated with mining and transporting rock
marine species die, they sink to the ocean floor, materials. The impact of such scenarios on aquatic
taking the absorbed CO2 with them, where it is and terrestrial ecosystems may need to become a
stored permanently. key consideration for project developers.
However, the implementation of OF has not
been thoroughly studied and there are limited Biochar
long-term experiments. Additionally, certain OF This approach to carbon removal comes in the
storage approaches are subject to reversibility. In form of a stable charcoal produced by heating
other words, the stored carbon may not remain organic material (such as agricultural waste or
sequestered permanently and could be released forestry residues) in the absence of oxygen. Chief
back into the atmosphere due to the constant processes employed here include slow pyrolysis,
changes in ocean conditions such as temperature fast pyrolysis, gasification, or torrefaction.
or nutrient availability. When biochar is added to soil as a soil
This issue highlights the need for caution and amendment, it can help to sequester carbon for
thorough study before implementing OF as a long periods of time, decades to thousands of
carbon dioxide removal strategy. The Convention years, which has made it an attractive option for
on Biological Diversity and the London Protocol CO2 removal and storage.
have called for appropriate regulations and Biochar also has the potential to improve crop
assessments of risks and impacts related to productivity through improved soil fertility and
climate‑related geoengineering and OF. water retention capacity. However, one notable
concern is the energy and emissions associated
Enhanced Weathering with the production of biochar, particularly if fossil
This approach involves land- or ocean-based fuels are used to power the pyrolysis process.
methods that accelerate natural geological
weathering to remove CO2 from the atmosphere Soil Sequestration
and permanently storing it in solid minerals or This strategy refers to the storage of atmospheric
ocean alkalinity. CO2 in soil organic matter. Certain farming
In-situ carbonation of silicates by spreading practices, such as no-till farming, cover cropping,
finely ground silicate rock, such as basalt, over and crop rotation, can increase the amount of
large areas of land is an example of a land- carbon stored in soil.
based enhanced weathering technique. Ocean- Generally, practices that promote plant growth,
based techniques involve increasing alkalinity by reduce soil disturbance, and increase soil organic

jpt.spe.org 11
 GUEST EDITORIAL

matter are effective in capturing CO2 in soil. environmental indicators, such as soil quality,
Increasing soil carbon can enhance soil fertility, biodiversity, water consumption, and metal scarcity.
improve water retention, reduce erosion, and By doing so, we can ensure that we’re not shifting
increase biodiversity. environmental burdens from one area to another
but are truly creating a sustainable future.
Environmental Impacts of CO2 Removal True assessment of environmental impacts
Carbon dioxide removal technologies have requires a cradle-to-grave approach instead of
the potential to play a vital role in mitigating cradle-to-gate approach. In the context of carbon
climate change. However, as with any large-scale dioxide removal technology, cradle-to-grave
technology, they also have environmental impacts assessment refers to a comprehensive approach
that need to be considered. that considers the entire life cycle of a carbon
One way to assess these impacts is through dioxide removal technology, from its development
a life-cycle assessment (LCA), which considers and implementation (cradle) to its end-of-life
the environmental impact categories such as management or disposal (grave).
global warming potential, acidification potential, This approach includes all the stages of a
eutrophication potential, human toxicity potential, technology’s life cycle, such as design, construction,
ecotoxicity potential, depletion of natural resources, operation, and decommissioning, and considers the
and land use. environmental impacts associated with each stage.
Global warming potential measures greenhouse The cradle-to-grave perspective provides a more
gas emissions, while acidification potential and complete picture of a technology’s environmental
eutrophication potential assess contributions impact than a cradle-to-gate approach, which only
to acid rain and nutrient pollution in water considers the environmental impacts associated
bodies, respectively. with the production and implementation of the
Human toxicity potential and ecotoxicity technology and not its end-of-life impacts.
potential measure the potential for harm to
human health and the environment through toxic Accounting for the Side Effects
emissions, while depletion of natural resources While the most reliable technologies with low
measures the potential for contributing to the uncertainty and limited side effects are soil carbon
depletion of nonrenewable resources. sequestration (SCS) and biochar, OF is likely to have
Finally, land use assesses the potential for the largest non-GHG burden due to its elevated level
converting natural habitats into agricultural of uncertainty and unknown side effects. Additionally,
or urban areas. By considering these impact the multifunctionality of a product system should also
categories, we can gain a more comprehensive be accounted for, as biochar and SCS systems often
understanding of the environmental impacts of a provide multiple product functions.
product or process over its entire life cycle. While most carbon dioxide removal technologies
As we work to address the urgent challenge cause various side effects, DAC appears to cause
of climate change, it is important to expand our fewer harmful environmental side effects compared
understanding of LCAs beyond GHGs alone. While to other technologies. Therefore, the development
GHG emissions contribute to climate change, non- and implementation of DAC systems could be a
GHG emissions can also have negative impacts on viable option for achieving net-zero emissions while
the environment and human health, causing air minimizing harmful environmental side effects.
pollution, acid rain, smog, and more. Afforestation and reforestation have the
That’s why it’s important to assess removal potential to be sustainable and scalable options for
technologies on a wide range of non-GHG carbon dioxide removal. Although, the effectiveness

12 JPT | June 2023

 GUEST EDITORIAL

of these methods is
Multifunctionality and Environmental Impact of CO2 Technology
dependent on available
Technology Multifunctionality Environmental Impacts
resources like land, water,
Afforestation and Timber production, watershed Altered water use, changes
reforestation protection, soil conservation in albedo, habitat loss and nutrients.
Biochar Carbon sequestration, soil Air pollution; energy, water, Overuse of these
amendment and land use resources can have negative
Direct air carbon — Air pollution; energy, water, impacts on sustainable
capture and land use
development and result in
Enhanced weathering Carbon sequestration, soil Land and water use,
amendment changes in albedo
negative effects on food
production, biodiversity, social
Ocean fertilization Fishery Acidification, eutrophication,
habitat destruction cohesion, and human rights.
In conclusion, carbon
Potential Negative Side Effects of CO2 Removal Technology dioxide removal technologies
Technology Negative Side Effect 1 Negative Side Effect 2 offer a range of options for
Afforestation and Land use change Habitat destruction reducing atmospheric carbon
reforestation
levels, but their effectiveness
Biochar Loss of biodiversity in Greenhouse gas emissions and sustainability depend on
monoculture plantations during production
several factors, such as their
Direct air carbon High energy requirements for Large-scale deployment
capture carbon capture could lead to land use durability, scalability, and
competition potential side effects.
Enhanced weathering Changes in water chemistry Alterations to soil nutrient
balance While some of these
Ocean fertilization Changes in ocean chemistry Negative impact on marine have the potential to be
ecosystems
sustainable and scalable,
Soil carbon Changes in land use Reduction in crop yields in e.g., afforestation and
sequestration the short term
reforestation, they also
Uncertainties of CO2 Removal Technologies
face constraints related to
Technology Uncertainties
land, water, and nutrient
Afforestation and The duration for a newly planted forest to reach full maturity and
resources. On the other hand,
reforestation effectively sequester carbon, as well as the influence of local methods such as DAC have
conditions (e.g., climate, soil type, and planted species) on
carbon sequestration rates, are uncertain. lower risks of leakage and
higher durability. However,
Biochar There is uncertainty regarding the long-term stability of biochar in
soil and its impact on carbon sequestration. Additionally, it is their energy consumption
unclear how the effectiveness of biochar in sequestering carbon and potential physical
may be affected by local soil conditions.
effects on the environment
Direct air carbon Uncertainty exists regarding the profitable prices for carbon require further research
capture removal, the amount of energy required, and the availability of
suitable carbon storage sites. and evaluation.
Ultimately, a
Enhanced weathering There have been limited experiments on enhanced weathering
and how it may impact carbon sequestration, and the rate at comprehensive approach
which weathering occurs remains uncertain. that combines carbon
Ocean fertilization There is uncertainty surrounding the reversibility of carbon removal technology with
storage via ocean fertilization, and the potential impact on
aquatic ecosystems and species productivity. other climate change
mitigation strategies is
Soil carbon The accurate measurement and quantification of soil carbon
sequestration sequestration is uncertain, along with the impact of local soil necessary to address the
conditions on sequestration rates. overall challenge. JPT

jpt.spe.org 13
 E&P NOTES

Equinor’s Njord Field Back in Business Ten new wells will be drilled on Njord from an
Norway’s Minister of Petroleum and Energy Terje upgraded drilling facility and more exploration will
Aasland officially reopened Equinor’s Njord field in be carried out close to the field.
the Norwegian North Sea on 15 May after a half- In addition, two new subsea fields have already
decade of extensive upgrades to the platform and been tied back to Njord. On 8 April, the Equinor-
the floating storage and offloading vessel (FSO). operated Bauge field started production, while
The field started production in 1997 and was the Fenja subsea field, operated by Njord partner
originally expected to produce until 2013. However, Neptune Energy, came on stream on 27 April.
systematic work with increased recovery means Recoverable volumes from the two fields combined
that there are still large volumes of oil and gas left. are 110 million BOE.
New discoveries in the area can also be produced Plans call for future partial electrification of
and exported via Njord. the Njord field based on power from shore via the
In 2016, the platform and FSO were Norwegian Sea Draugen platform, thereby reducing
disconnected from the field and towed to shore annual CO2 emissions by around 130,000 tonnes.
for upgrade work. On 27 December 2022,
production resumed from the Njord field. Arrow Discovers New Oil Reserves
“This is the first time a platform and an FSO in Colombia
have been disconnected from the field, upgraded, Arrow Exploration encountered around 148 ft
and towed back offshore. We have now doubled the of net oil pay in its Carrizales Norte 1 (CN-1)
field life,” said Grete B. Haaland, Equinor’s senior exploration well on the Tapir Block in the Llanos
vice president for exploration and production Basin of Colombia. The well was spud on 1 May and
north. “It has been a big and demanding job, partly reached total depth of 9,190 ft on 11 May.
carried out during a pandemic, and I would like The hydrocarbon-bearing intervals included
to thank everyone involved in preparing Njord for 26 ft of net pay in Carbonera C7 sands. The
continuing its supply of oil and gas to the market. reservoir characteristics are similar to those
With the prices we anticipate in the coming years, encountered in the highly productive Rio Cravo
this comprehensive upgrading project will be repaid Este (RCE) series of wells. Another 64 ft of net oil
in just under 2 years after startup.” pay was found within the Gacheta formation and
Equinor believes the work will not only double 58 ft net oil pay within the Ubaque formation.
the field life, but could double production and “The CN-1 discovery is an extremely important
produce around the same volume from the field and material event for Arrow and is further evidence
as it has produced so far, around 250 million BOE. of the potential of the Tapir block,” said Marshall
Abbott, chief executive at Arrow Exploration. “All
primary targets in the well have clear indications of
Njord field. oil pay and have the potential to greatly increase
the company’s reserves and production. Currently
there are no reserves booked at the Carrizales Norte
field. Apart from the exceptional technical results,
the CN-1 well was drilled on time and under budget.
Arrow plans to test several zones over the following
weeks and then make a decision on which zone to
bring on production.”
A testing and completion program is under
review. Testing will likely begin with the deeper

14 JPT | June 2023

 E&P NOTES

Ubaque, followed by the Gacheta, and then the Presidents field. Trio owns an 85.75% working
highly porous and permeable C7 reservoirs. Tests interest in the find.
will be conducted over the following weeks, with
production forecast to begin in early June. The Turkey Touts Billion-Barrel Find
Carrizales Norte-2 well will be drilled immediately in Cudi‑Gabar Area
upon completion of CN-1. Turkey’s state oil company TPAO has confirmed a
billion-barrel find following the drilling of appraisal
Trio Strikes Oil in California wells from its Sehit Aybuke Yalcin-1 well. The
Trio Petroleum believes it has encountered a exploration test was drilled 20 km northwest of
“major accumulation” of oil and gas in its South Cizre and 7 km northeast of the Sehit Esma Cevik
Salinas project located in Monterey County, field, which now produces about 10,000 BOPD.
California. The HV-1 well is a 2-mile stepout from The well was drilled to a total depth of 2771 m
Trio’s HV-3A discovery well that found high-quality, and encountered more than 162 m of light
mid-gravity oil at depths between 3,750 to 5,100 ft. oil‑bearing reservoir.
The well drilled through approximately 1,800 ft “This is the largest onshore discovery in
of the Monterey formation with major indications Turkey and gives TPAO a chance to build a new
of oil and gas prior to reaching total depth at regional office in Sirnak,” said TPAO Chairman
6,631 ft. The company is currently running well And Chief Executive Melih Han Bilgin. “Developing
casing from surface to total depth to complete Sehit Aybuke Yalcin and Sehit Esma Cevik with
the well and is beginning its evaluation of the further discoveries will not only channel capital
well data collected. to stimulate economy in Sirnak, but also let TPAO
“We plan to put the HV-1 well on production build a state-of-the-art oil refinery to unlock
after we finalize completion operations and our the potential in the region, including fields in
evaluation of the new data we are acquiring neighboring countries.”
from the well, after which we will have a better TPAO will drill back-to-back appraisal wells
understanding of production rates, which we plan and conduct well tests through the end of 2023
to announce when available,” said Frank Ingriselli, to help construct a full-field development plan.
chief executive of Trio. Test production began at Sehit Aybuke Yalcin at
The well was drilled on a new oil and natural the end of April, and the production target is set
gas field that the company refers to as the for 100,000 B/D, boosting oil production in Turkey
more than twofold.
Additional exploration wells are being planned
Trio Petroleum well. for the Cudi-Gabar area in the second half of 2023.
A FEED agreement has already been signed for a
pipeline, but the contractor was not revealed.
TPAO holds 100% working interest in blocks
AR/TPO/K/M48-D2,D3,D4 and AR/TPO/K/N48-A1,
A3, A4.

TotalEnergies-Led Group To Drill Offshore

Lebanon
A consortium led by TotalEnergies will start drilling
for oil and gas off the coast of Lebanon at the
beginning of September, the country’s Caretaker

jpt.spe.org 15
 E&P NOTES

Energy Minister Walid Fayyad said, according to China’s national energy companies are
Reuters. The consortium, which includes partners accelerating the development of more costly,
Eni and QatarEnergy, has assigned a rig for the geologically challenging oil and gas resources
offshore southern bloc known as Bloc 9. following President Xi Jinping’s call to boost
“The rig will start working in Lebanon in domestic energy supply.
September ... before the end of the year we will
know if there is a discovery,” Fayyad told reporters Petronas Carigali Farms Out Stake
at the World Utilities Congress in Abu Dhabi. in Samarang PSC
Lebanon formally delineated its maritime Petronas Carigali has entered into a farm-out
border with Israel in October after years of agreement (FOA) with SMJ Sdn Bhd (SMJSB),
mediated talks. Fayyad said a potential discovery a company wholly-owned by the Sabah State
could impact whether a deadline for applications Government for the sale of Petronas Carigali’s
to explore in eight additional offshore blocs is 50% of nonoperating participating interest in the
extended yet again, past June. Samarang Production-Sharing Contract (PSC).
“I have been hearing from players in the field Last month, Petronas Carigali and SMJSB
that they are keen to see the result of the drilling inked a Heads of Agreement to record the parties’
in Bloc 9 before they make decisions as to further agreement and confirm SMJSB’s participation in
investments or commitments in Lebanon,” he the Samarang PSC; this is superseded with the
told reporters. execution of the FOA.
The minister said Lebanon would aim to The FOA marks the second significant
boost imports from Iraq by bumping up the development between Petronas Carigali and
volume of an existing swap deal and through SMJSB following the Commercial Collaboration
new commercial agreements. Agreement signed between Petronas and the
Lebanon and Iraq have already renewed an Sabah State Government on 7 December 2021.
annual deal that allows Beirut to import 1.0 million Under the FOA, Petronas Carigali will continue
tonnes of heavy fuel oil per year that it then swaps to be the operator of Samarang PSC with SMJSB on
for gas. In exchange, Iraq has access to Lebanese board as the nonoperating partner. The Samarang
healthcare and other services. field, which is located 50 km off the coast of Sabah
is currently producing approximately 36,000 BOED.
Sinopec Strikes Oil With Deep Well The gas production, at 134 MMscf/D, is part of the
in China’s Tarim Basin supply for customers in Kota Kinabalu and Labuan.
Sinopec has come up trumps with oil and gas
shows in its Shunbei-10X exploration well in the 88 Energy Awarded Project Leonis
Tarim basin. The well, located in the Aksu area of Acreage on Alaska’s North Slope
China’s northwestern region of Xinjiang, tested at 88 Energy Limited subsidiary Captivate Energy
flow of 600,000 m3/D of oil and gas, making it the Alaska was awarded notices from the Alaskan
50th well struck at a depth exceeding 8000 m in the Department of Natural Resources (DNR), Oil and
Shunbei field, Sinopec said in a statement. Gas Division, covering the entire Project Leonis
Drilled to a depth of 8591 m (5.34 miles) below lease area. In late 2022, Captivate Energy Alaska
the surface, Shunbei is one of the world’s deepest was declared the highest bidder for select acreage
oil and gas fields being commercially developed, offered as part of the North Slope Areawide 2022
the firm said, adding that Shunbei’s oil and gas Oil and Gas lease sale. The Project Leonis acreage
production so far reached 7.7 million tonnes of comprises 10 leases covering approximately 25,430
oil equivalent. contiguous acres.

16 JPT | June 2023

 E&P NOTES

Ashley Gilbert, 88 Energy managing director, oil fields—Orion, Polaris, West Sak, and Milne
said, “Project Leonis benefits from proximity to Point—demonstrate successful development of
infrastructure and services at Prudhoe Bay and the USB reservoir.
Deadhorse, as well as a historical well that indicated Further analysis will determine the future
oil shows and calculated pay in the Upper Schrader potential of the acreage and define a possible
Bluff (USB) zone of interest. Importantly, the lease exploration program and timeline for the project.
area is covered by an existing 3D data suite, allowing
us to undertake detailed, informed analysis to IGas Energy Plans New Lincolnshire Well
properly understand the exploration opportunity. IGas Energy was granted planning consent to
Our team will now be busy utilizing a suite of modern develop a new oil wellsite in Lincolnshire in the UK
analysis techniques to further advance the project.” close to its existing Glentworth-K site which has
The Project Leonis lease area is fully covered by been producing oil for 60 years.
the Storms 3D seismic data suite and contains the Lincolnshire county council granted planning
historical exploration well, Hemi Springs Unit #3, permission for an initial appraisal well and up to
drilled by ARCO in 1985. Historical drilling targeted six horizontal development wells in the second
the deep Kuparuk and Ivishak reservoirs, the main phase of the development. The first phase has the
producing intervals in the giant northern fields at potential to add around 200 BOPD, and the second
that time. Review of the Hemi Springs Unit #3 well phase could add a further 500 B/D, IGas said in
indicated over 200 ft of low-resistivity bypassed log a statement.
pay within the USB reservoir, with good porosity The oil produced at the site will be sold to a
and oil shows evident over this interval. Nearby domestic refinery.  JPT

jpt.spe.org 17
 FEATURE | Decommissioning

OFFSHORE
DECOMMISSIONING
Planning for the End
at the Beginning
JENNIFER PRESLEY, Senior Technology Editor

Source: US Bureau of Safety and

Environmental Enforcement.

18 JPT | June 2023

 FEATURE | Decommissioning

I
t is the $100 billion elephant in the room. It is He noted that the 2021 survey found Europe
the last item on a never-ending list of things to with the largest market, with 33% of spending,
do that gets delayed until it can no longer be followed by Asia Pacific and North America with 23%
deferred. It is the decommissioning of mature and 17%, respectively. Decommissioning in the GOM
offshore oil and gas fields, and—like death and is expected to grow at a compound annual growth
taxes—it is an unavoidable certainty. rate of about 6.89% from 2020 through 2030.
Decommissioning, the safe and environmentally “There’s not been an update on the numbers
sound removal, disposal, and repurposing of since 2021,” Lamothe said. “However, based on the
obsolete infrastructure, marks the end of a field’s size and magnitude recent bankruptcies in the Gulf
operational life cycle. A critical part of the process of Mexico and the number of assets being returned
is the plugging and abandonment (P&A) of wells to to predecessors in title, I sense that the North
ensure that hydrocarbons, other fluids, and gases American market is greatly understated.”
do not escape the wellbore. As bankruptcy causes more asset liabilities to
As the world grapples with the need to transition boomerang back to previous owners, so do the risks
towards cleaner energy resources for the future, the and costs associated with decommissioning.
decommissioning of mature or inactive offshore oil These boomerang assets are the result of what
and gas wells has become a growing concern. These Lamothe said “is the lack of a full understanding
wells, which have been in some state of operation of the chain of title obligations for the federal
for decades, now present a range of environmental, leaseholders, the discounting effect of net
economic, and social issues that must be addressed. present value.”
While many factors delay decommissioning He added that “the cost is always cheaper in
activities, advance planning is one way to manage the future and sometimes coupled with the ‘not in
the risk and expenditures associated with it, our careers’ mentality. Assets that are no longer the
speakers said during the “Starting with the End in shiny penny in many companies’ portfolios and not
Sight: Planning for Decommissioning to Ensure necessarily getting the attention they deserve.”
Long Term Success” opening keynote at the 2023 A study conducted by researchers at the
Offshore Technology Conference (OTC) in May. University of California–Davis and Louisiana State
University, published in May 2023 in Nature Energy,
Accumulating Liabilities found that of the more than 4.4 million oil and gas
In areas like the Gulf of Mexico (GOM), for example, wells drilled in the US, only 113,000 are located
oil and gas production has been the cornerstone offshore or in coastal waters and represent an
of the region’s economy for more than half a outsized share of the production. The federal
century. According to the US Bureau of Safety and offshore wells have contributed 15% of all US
Environmental Enforcement there are about 1,885 production over the past 2 decades, with state waters
active production platforms on the GOM Outer adding to that number, according to the study.
Continental Shelf, with over 60% of these facilities The researchers’ review of the data led to
more than 25 years old. Over the past decade, the the estimation that the cost to P&A all 14,000
offshore energy industry has averaged 200 platform unplugged, nonproducing wells in the US GOM
removals per year. offshore waters, inland waters, and wetlands is
“IHS Markit forecasted that the global offshore $30 billion. Of that number, the shallower wells
decommissioning spend will reach almost $100 billion closer to shore make up 90% of the inactive wells
in 2021 through 2030,” said Ryan Lamothe, director but only 25% of the total P&A cost.
of decommissioning at Hess, adding that it is “an In his OTC presentation, Steve Louis, senior vice
increase of over 200% from the prior 10-year period.” president of decommissioning for Houston-based

jpt.spe.org 19
 FEATURE | Decommissioning

Promethean Energy, peeled back the layers of what Partnering Up

he sees as a “highly complex problem” to reveal that Working early on decommissioning plans can make
it is more than an engineering or an HSE problem a big difference, as can working with partners.
contributing to the delays. It is a cultural problem, too. “Decommissioning should not necessarily be
“There seems to be a reluctance until recently a competitive environment, at least not from an
to share experiences, ask for help, spend money, operator’s perspective,” said Lamothe. “There’s no
speak to regulators, and even invest in innovation,” intellectual property here that we should safeguard
he said. “Often the industry chooses to do the bare against, right? There are no reserves at stake here.
minimum, and in doing that, accumulates liabilities.” And I will argue that there are potentially some
technologies that the service companies want to
Breaking the Cycle keep for themselves. Still, the operators ought to
While all these factors contribute to delays in work together to figure out how to abandon these
decommissioning projects, he said that the most properties and decommission these as efficiently as
significant problem to overcome is procrastination, possible as an industry.”
which is embedded in the business in that Lamothe said the first question an
“executives are focused not on the next quarter operator should consider when contemplating
century, but the next quarter.” decommissioning is to determine if it has the
To break this cycle, Louis urged operators to availability of in-house engineering expertise to
begin with the end in sight, advice that he credits support the project or if it should consider using
to Stephen Covey, author of The 7 Habits of Highly a designated agent. This approach has become
Effective People. popular in the GOM.
“To act before the problem occurs, to build For example, Promethean Energy’s
a plan, and prioritize the important over the dedicated end-of-life business unit—Promethean
urgent,” he said. “The plan should provide a flexible Decommissioning—is focused exclusively on the
approach to prioritizing the huge list of activities safe, cost-efficient, and timely decommissioning
that enable us to optimize the sequence for of assets that have already reached COP,
decommissioning and thus reduce costs and risks.” according to Louis. Its single focus is to be a
Louis cited the UK’s North Sea Transition designated accountable decommissioning operator
Authority’s requirement of decommissioning managing interfaces and engagement with all
planning 6 years in advance of the cessation of project stakeholders.
production (COP). A recent project had the company working on a
“If we’re not tracking our asset retirement set of boomerang assets that had been reassigned
obligation estimates periodically, we’re going to for decommissioning following a bankruptcy. The
be surprised,” he said. “If we don’t engage with overall scope of work included 11 leases, nine
regulators until we have a decom order then we platforms, nearly 200 wells, and more than 30
miss out on finding many win-win opportunities.” pipeline segments. The company and its partners
By not engaging with the supply chain or hiring de-risked the project, mobilized, and began offshore
people to get the best team in place until after decommissioning in 100 days and executed with an
the COP of a GOM asset, it will be more difficult exemplary HSE record.
to obtain those resources, he added. For its decommissioning projects, Hess
“If we don’t start planning our COP during evaluates each on a case-by-case basis and adjusts
our production and operations and maintenance, their program as needed, Lamothe said.
we’re probably going to be wasting a lot of money,” “Currently, we’re going direct managed or
Louis said. operated for many of our traditional portfolio

20 JPT | June 2023

 FEATURE | Decommissioning

assets, but with boomerang properties, we’ve “When we do a deepwater well design now
elected to go with a designated agent approach,” in the Gulf of Mexico, it has to go through an
Lamothe said. abandonment review as part of that well design
Hess, with its deepwater focus, has limited process,” he said. “We’re finding with wells that we
familiarity with the GOM shallow-water shelf drilled 20 years ago that we’re going back now and
assets. When its legacy West Delta Block 79 field looking at how we’re going to abandon those wells.”
boomeranged back to Hess after Fieldwood Energy Lamothe offered as an example placement of
declared bankruptcy in 2021, Hess opted to use packers or the well completion assembly.
Houston-based White Fleet Abandonment as its “At that point in time, we might have left
designated agent. ourselves an easier and cheaper path for
“Hess has had no involvement with this field abandonment in the future by adjusting the
for over 20 years, having sold the properties in completion design,” he said. “We have implemented
2004,” Lamothe said. “Ongoing activities include that into our well-delivery and facilities-delivery
decommissioning and abandoning 115 wells, 13 process to review how we’re going to decommission
pipelines, and seven facilities. Since receiving these and abandon at the very early stages of planning.”
properties less than 12 months ago, we’ve made all Decommissioning offshore oil and gas assets
seven facilities safe, which is no small undertaking is an inevitable and critical aspect of the industry
given the condition that they were in. We flushed that requires planning and collaboration among
hydrocarbons from all seven facilities and all operators, regulators, and service providers. By
13 pipelines.” adopting a long-term perspective and focusing
He said that Hess has permanently abandoned on early engagement with all stakeholders,
25 wells, plugged and temporarily abandoned operators can optimize costs, minimize risks, and
two dozen more wells, and is currently running ensure assets’ safe and efficient abandonment.
simultaneously two rigless P&A spreads in the field. Implementing lessons learned from past
“We’re also in the process of mobilizing a experiences into future projects and fostering
hydraulic workover unit for a couple of the more a cooperative environment within the industry
technically challenging wells, and we’re on track to will be essential in addressing the $100 billion
have two more platforms ready for removal and challenge ahead. JPT
reefing later this year,” he said.
Another critical consideration is access to FOR FURTHER READING
legacy information such as field data. Lamothe
said that concerning its boomerang properties, the Financial Liabilities and Environmental
information was severely lacking. Implications of Unplugged Wells for the Gulf
“We were stepping back into these projects with of Mexico and Coastal Waters by M. Agerton,
little to no knowledge of the state of the facilities or University of California Davis; S. Narra, B. Snyder,
the condition of the wellbores,” he said. “We’ve often and G.B. Upton Jr., Louisiana State University.
found that the wells in the facilities were left in an
unacceptable and noncompliant state. So that has
resulted in significant spending upfront.” Join the SPE Plug and Abandonment Technical Section,
Hess is using the experiences and lessons dedicated to cost-effective well decommissioning and
learned during decommissioning to improve the leakage prevention from abandoned wells, including the
design of its newer deepwater wells. The operator repair of failed or patently inadequate prior abandonments
uses a well-delivery process that features a of old wells that were plugged off under outdated industry
decommissioning review. practices or regulatory expectations.

jpt.spe.org 21
 FEATURE | Fracture Imaging

Who’s Right?
Imaging of Fractures Often
Delivers Conflicting Measures
STEPHEN RASSENFOSS
Emerging Technology Senior Editor

T
here are two ways to measure how much When oil companies run side-by-side tests,
entry holes grow due to erosion during there are enough differences in the hole size
fracturing, and the results they offer are measurements to raise the question: Which
often different. one is right?
This matters because these competing While the averages and trend lines for the
technologies, one using cameras and the other data sets look close enough for engineers used to
ultrasound, have become an essential tool for noisy downhole data, differences in the measures
measuring fracturing performance. of specific entry holes can be disconcerting for

Perforation @ ~11,566 ft Perforation @ ~12,129 ft

Perforation @ ~14,578 ft Perforation @ ~13,884 ft

Different hole shapes from two technologies (ultrasonic on right and camera on left). Source: SPE 212322.

22 JPT | June 2023

 FEATURE | Fracture Imaging

Individual Perforation Area (Camera and Ultrasound)

by Cluster and Phase Bubble size represents perforation area (in.2)

6
Cluster Number

0° 60° 120° 180° 240° 300° 360°

Perforation Phase (0° = highside of wellbore)

Fig. 1—Individual perforation area measurements from ultrasound and camera sensors for Stage 37 of Well 1
demonstrating measurement differences and unmeasured perforations. Source: SPE 212322.

those trying to evaluate performance at the They show that these tools can deliver
cluster level. significantly different measures for some of the
“There is quite a bit of disagreement in them, holes. Fig. 1 shows multiple instances where only
with gaps of up to 100%, and many gaps of 25% one method can provide a usable measure.
or more,” said Tobben Tymons, visual analytics The paper offered explanations for the
director for EV, the company that pioneered differences with something engineers often
visual imaging. He made that observation when ask for and rarely get—a study offering a
he described the result of a two-well test where detailed look at the pros and cons of competing
EV partnered with Archer to measure entry holes diagnostic methods.
using both camera and ultrasound methods The conflicting numbers shown in the
(SPE 212322). EV‑Archer paper were in line with the results of
The paper presented at the 2023 SPE a previous side-by-side test by Chevron which
Hydraulic Fracturing Technology Conference and showed similar measurement differences
Exhibition (HFTC) included Fig. 1 comparing the (SPE 209122).
measurements using photos and ultrasound as At the conference, Hess and ConocoPhillips
pairs of colored dots within a stage in a side‑by‑side also offered papers on measurement differences.
well test. The red dots were based on a camera It’s a hot topic because bad data could lead
image of the entry holes in the casing; the yellow an operator to invest a lot of money and time
were based on ultrasound. on changes that don’t deliver the production

jpt.spe.org 23
 FEATURE | Fracture Imaging

expected based on the entry-hole measures in unusable measures for one method are frequently
test wells. not the same for the other.
There is agreement that the accuracy of In their two-well test data using both, more
these data matters. But on the question of which than 99% of the clusters were covered.
method is delivering accurate numbers, the advice This fact of life means that anyone selling two-
varied widely. technology measurements, beginning with EV and
The paper by Hess offered this advice: “The Archer, needs to create an evaluation method that
technology of perforation imaging has come a can efficiently decide which measure is correct on a
long way and drastically improved in recent years; hole-by-hole basis.
however, there are differences in the detail of the An early user for the service is Ovintiv. Dugan
images. The trends are very similar between the Hughes, a completion engineer for the oil company
compared technologies. The learning is to use one in the Permian which has relied on EV, said that
technology and consistently benchmark against it.” based on his side-by-side comparison, they offer
When asked about picking one method and “similar data sets.”
sticking with it, Tymons said he “strongly disagrees But he wants to continue collecting data from
with the approach.” Using one method avoids both methods for a project that represents a new
seeing the inconsistencies between the two use for entry-hole imaging—observing how these
technologies, but no matter which method is used, measurements change over time in a producing oil
“there are instances where it is simply wrong,” and gas well.
he said. Imaging runs using both methods, which he
When Dave Cramer saw similar gaps in a side- calls the stack, “gave us more confidence.”
by-side test, it motivated the senior engineering
fellow at ConocoPhillips to look for another Hole Size Matters
benchmark to judge whether the ultrasonic data Changes in the size of the entry holes that
he is getting from a provider the company has have been eroded during pressure pumping
often used, DarkVision, looks correct. offer measurable physical evidence of how
“If you just get conflicting data, what are you much, and how evenly, each entry hole has
validating?” said Cramer. His response was to use been stimulated.
data from a pressure test—stepdown testing—plus Before downhole imaging took off about
modeling to generate a set of post-fracture hole- 4 years ago, those spending millions of dollars
size estimates, which he compared with measures on fracturing had no way to directly observe the
with hole sizes from DarkVision, which often does impact of fracturing at the cluster level.
ultrasonic imaging for ConocoPhillips. But what was known back then strongly
The test result indicated the ultrasonic suggested fracturing designs were not working
measures are “good enough to tell us what we according to plan. Diagnostics, such as fiber
need to know.” optics, indicated that a disproportionate
Since the result did not include camera- share of the water and sand pumped were
based results, it was not designed to compare the flowing out of the first cluster reached at the
accuracy of the two methods. heel end of the stage, leaving many later clusters
Based on the two-technology test by EV and understimulated.
Archer, Tymons said the best option will be using When companies like EV began delivering
both technologies. His paper made a case that pictures and measurements to clients, users
visual and ultrasound methods used together are could clearly see inconsistent fracturing stimulation
better because issues that lead to inaccurate or was an issue that had to be addressed.

24 JPT | June 2023

 FEATURE | Fracture Imaging

That evidence led to a wave of experimentation Cramer is a man of strong, but changeable
by fracturing technology leaders, who went after it opinions. ConocoPhillips was an early EV customer.
two ways. Back then, Cramer believed the clear images they
They tried diverters—particles that sellers created looked superior to the fuzzier edges seen
said would limit the flow out of the holes likely to using ultrasound.
become dominant perforations. They also tested That changed when the project manager in
downhole designs that limited the number and charge of the fracturing of a ConocoPhillips well
size of the entry holes. The goal was to restrict in Canada hired a local company using ultrasound
the flow into the holes that were getting too much imaging—DarkVision.
stimulation, ensuring there was enough fluid and While ultrasound images will never look as
pressure to stimulate all the clusters. sharp as camera images, Cramer sees a certain
Based on presentations at the recent HFTC, inner beauty in them. He is focused on measuring
limited entry has been winning. When asked small differences inside perforations where the
about diverter testing, Ohm Lorwongngam, the flow erodes the entry hole from front to back.
completion advisor for Hess who presented at A small ridge inside an entry hole can have an
the conference, said they had tried many types outsized impact on the flow rate.
of diverters and found they are good at plugging “The dimension we care about is the minimum
holes, just not necessarily the right ones. diameter of the entry hole in the casing. We do
Along the way, ultrasound imaging not care as much about any other part of that
companies entered the business, giving users perforation,” Cramer said.
a competing option. While a camera can create far clearer images,
The competition led Hess and others to do he believes ultrasound is better at measuring the
imaging tests to evaluate the two methods, with 3D space because the returning sound waves
similarly inconclusive results. allow precise distance measures of features inside
Since then, they have stuck with camera the hole. Those can also be imaged using visual
imaging because of the high-resolution pictures imaging, but he said it is dependent on the lighting.
and the value of a database built using a consistent
measurement method. Better Together?
Tymons introduced the idea that two measurement
Getting Quantitative methods are better than one at HFTC.
No one interviewed for this story expects all the Both need to be better, because he said
perforations to be exactly the same. There are gathering two different data sets is likely to cost
too many variables to control when using shaped 20–30% more.
charges to perforate casing, which are then eroded The partners have created the downhole
by the flow of fluid and sand into an unpredictable hardware used to stack the cameras and
geologic environment. ultrasound equipment used for the two well tests
But their expectations have risen due to and for clients like Ovintiv.
the growing use of limited-entry designs that They also developed an editing method for
are evaluated using increasingly precise entry- choosing which measurements to use when two
hole measures. data sets are available. The method relies on both
Both Cramer and Hughes agreed that human judgment and automated evaluations,
differences of hundredths of an inch can result including tools using artificial intelligence,
in outsized differences in the fluid flow and Tymons said.
fracture growth.

jpt.spe.org 25
 FEATURE | Fracture Imaging

Percentage of Unmeasured Perforations

Well 1 Well 2

Camera 0.15% 15.97%

Ultrasound 6.93% 2.71%

Not Measured by 0.15% 0.63%

either sensor

Although 7% of perforations were unmeasured by the ultrasound sensor in Well 1 and 16% were unmeasured by the
camera sensors in Well 2, less than 1% of perforations were unmeasured overall in both wells as the alternate sensor
captured the missing perforation in almost all cases. Source: SPE 212322.

It is an outgrowth of the editing process for Both methods suffer if a sand bank on the
imaging methods that has always been part of this bottom of the casing covers the perforations. That
service, which has made them familiar with the has become less of an issue as more companies
pros and cons of each technology. shoot their perforations along the high end of
The common wisdom is that cloudy well the casing to create more-even hole sizes and
conditions generally favor ultrasound, while fluid distribution.
the cameras offer sharper images in wells with Sticking/slipping during the run is an issue more
clearer fluids. likely to affect ultrasound imaging. Tymons said it
“Our experience in the past has been with is not a problem for cameras which rapidly capture
cameras—we are lucky enough to have good 360-degree images as the tool moves through the well.
water quality to get good images,” said Hughes, Ultrasound, however, builds each image line
whose job description includes special projects by line. A sudden slip or stop in the middle of
and diagnostics. that process can stretch or compress the image.
But the EV-Archer paper emphasized that both The problem is conceptually similar to moving an
methods require good well cleanup to minimize the original image while it’s being scanned by a copy
sand and debris left behind after fracturing. machine, Tymons said.
While ultrasound imaging is less affected by Cramer recognizes the potential problems
murky water, it suffers when there is sand or and relies on DarkVision to limit the bad images.
debris in a hole. The EV-Archer study found that Stick/slip can be reduced by running the tool
80% of the time when perforations were missed by on coiled tubing instead of on a wireline or with
ultrasound, the problem was that the sound waves a tractor. It needs to move fast enough to limit
reflected off sand. Sand looks much like steel in sticking—around 30 to 45 ft per minute—but slow
the images because the sonic properties of those enough for ultrasound imaging.
materials—the acoustic impedance—are similar. Still, editing is required. While Cramer did not
A recent one-of-a-kind fracturing study by indicate that the number of entry holes edited out
Devon included a chart based on DarkVision data, of the report are an issue, it was a concern raised
where one of the design categories was missing by the EV-Archer report.
because it was “in the region that was not imaged” Their paper points out that unusable images
(SPE 212340). from a single method can lead to different

26 JPT | June 2023

 FEATURE | Fracture Imaging

interpretations than analysis using another of how much friction the water injected during
technology able to measure all the holes. the test encounters in the casing and in the near-
Based on a comparison of methods, when the wellbore fractures.
client used only one of the imaging methods, the He then used the data in modeling to isolate
number of unusable images could have changed the friction associated with the entry hole from the
some interpretations. effect of fractures near the wellbore. That data was
In the first well, ultrasound was unable to used to estimate the entry-hole sizes that would
measure nearly 7% of the perforations. In the present that amount of resistance.
second well, EV’s cameras passed through a ‘bank’ Cramer said when the entry-hole-size estimates
of proppant” near the bottom that covered the from the 12 stepdown tests were compared to
lenses with an “opaque substance.” As a result, the ultrasound measurements, they were “within
16% of the perforations were not measured. engineering accuracy levels,” and he “felt very good
But in nearly every entry hole, one technology using their entry-hole information” to calculate
or the other was able to generate a measure, so proppant distribution among clusters.
the client was provided data for more than 99% of But he warned those using the method that
the holes in the area surveyed. getting good data requires close attention to a lot of
The paper noted that the cluster analysis at details. The methods and the results were covered
the stage level could look significantly different if in two papers (SPE 205003 and SPE 212335).
some of the perforation measures are missing. As “There is a certain standard methodology that
completion engineers shift to clusters with fewer has to be carried out,” Cramer said. “It is a good
perforations—sometimes only one—the effect of validation if the stepdown is done right.”
missing images looms larger. The test requires pressure measurements from
“The more perforations you are missing, the the surface and a downhole pressure gauge. The
more you are jeopardizing your understanding of location of the downhole gauge and the entry holes
the fracturing,” Tymons said. figures in the calculations.
Timing also matters. “You have got to have
Trust, but Verify patience to wait out the water-hammer oscillation”
While customers have preferred providers, these before it is possible to accurately measure the
are not committed relationships for oil companies. pressure change.
The choice is normally made by the person The fact that a senior engineering advisor with
managing the asset, who varies from place to decades of fracturing experience felt the need to do
place, and may or may not be in line with a the data collection and calculations himself suggests
technical advisor’s point of view. this method may be hard for others to use.
While Cramer has come to accept the value Cramer hopes to engage other oil and service
of measures based on ultrasound, he had to get companies in figuring out better ways of gathering
used to relying on analysis from DarkVision’s better data.
“black box.” Ovintiv tried the two-technology imaging
Questions raised by side-by-side tests, method because it wants to ensure that accurate
including one done by ConocoPhillips, led him measuring of the entry holes begins with using
to create a method to test the entry-hole-size downhole imaging to observe how the holes
measures to use as a benchmark for imaging change during production.
measures, no matter which method was used. “When we run diagnostics, they tell a story.
The data were gathered from stepdown Ultimately, we need to see how they affect things
testing. The injection test provides a measure downhole,” Hughes said, adding, “This is the

jpt.spe.org 27
 FEATURE | Fracture Imaging

At this point, the company is not saying what

A step-by-step summary of a method where has been observed, though Hughes is thinking
ConocoPhillips used a stepdown test to about doing a paper on it and using both tools
estimate perforation sizes after fracturing. in the future on this project.
• Begin by establishing a stable treating He said they looked at each of the data
pressure at the maximum injection rate, sets “independently. The value of them is
as per design or by treating pressure slightly different.” JPT
limitations.
• Then, decrease the injection rate in several
FOR FURTHER READING
steps. After each step, establish a stable
pressure before advancing to the next SPE 212322 Combined Video and Ultrasonic
step. Measurements for Fracture Diagnostics—
• Stepdown tests culminate with termination Greater Than the Sum of the Parts
of injection (i.e., shut-in) for obtaining an by Tobben Tymons and Glyn Roberts, EV;
instantaneous shut-in pressure (ISIP). The Duncan Troup, Archer.
ISIP represents the average bottomhole SPE 209122 Assessment of Limited-Entry Cluster
fracturing pressure among intervals or Distribution Effectiveness and Impactful
clusters. Variables Using Perforation Erosion
• Pressures and rates are then evaluated in Measurements by Rick Eckdahl and Adam
a history-matching process using Bernoulli Vigrass, Chevron Canada Resources; Amit Singh
and tortuosity equations to generate the and Xinghui Liu, Chevron USA Inc; and
modeled pressure data. Larry Chrusch, Chevron Canada Resources.
Source: SPE 212335 SPE 212358 One Shot Wonder XLE Design:
A Continuous Improvement Case Study of
Developing XLE Design in the Bakken
by Apiwat Ohm Lorwongngam, Michael McKimmy,
first crack at tying the diagnostics and wellhead Evan Oughton, and Craig Cipolla,
production data together.” Hess Corporation.
Previous studies, such as a refracturing test by SPE 212335 Correlating Surface and Downhole
Devon, have observed how perforations can clog Perforation Entry-Hole Measurements Leads
over 10 years. The two-technology method would to Development of Improved Perforating
observe how perforations change, beginning after Systems by David Cramer, Matt White, and
6 months of production. Cody Douglas, ConocoPhillips Company.
Adding ultrasound data can help deal with the SPE 205003 Pressure-Based Diagnostics for
murkier conditions expected in production wells, Evaluating Treatment Confinement
while the camera images will be added to Ovintiv’s by David D. Cramer and Junjing Zhang,
large library of them. ConocoPhillips Company.

28 JPT | June 2023

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 FEATURE | Flood Management

Flood Management
Solving Conformance or Sweep
Efficiency Problems—Part 2:
Connecting Problems to Solutions
DAVID SMITH, President and Principal Advisor for Oilfield Conformance Consulting LLC

I
n Part 1 we discussed the process wheel and (i.e., near the wellbore or deeper in the reservoir).
the first two elements of that wheel, namely Although some problems can contain multiple
candidate selection and problem clarification. characteristics, the key is to define the most
In Part 2 we will focus on generating a dominant characteristic so it can be solved first.
connection between the problem types as outlined
in the conformance problem matrix and various Populating the Problem Matrix
methods of trying to solve these problems. Populating the matrix with every problem type
In this section we continue to utilize the that we face within the industry would create a very
conformance problem matrix outlined in Part 1 cluttered chart. One thing to recognize is that the
and incorporate various overlays on this matrix to wellbore is a VSC that we created to connect us to the
describe how elements of the conformance solution reservoir. Anytime we lose control of how fluid enters
continuum and the subsection of the continuum, the wellbore from the reservoir, we have a VSC.
i.e., existing wellbore interventions, can be used to Thus, we start by reviewing the more common
show how these solutions can be effectively applied. problems associated with losing control of the
wellbore such as casing leaks, packer leaks or
Defining the Problem Matrix plugs, mis-perforated intervals, cement channels,
Prior effort to classify conformance engineering perforated wrong interval, etc. These problems all
problems have used a linear view of grading fall in the upper left quadrant. Since they are strictly
problems from easiest to most difficult to control. void space or conduit flow, they are controlled
Probably the most quoted document in this effort totally at the wellbore.
is by Seright et al., SPE 84966. Although I don’t The next example helps us understand the
disagree with their ranking process, it really doesn’t importance of geologic controls and understanding.
help us to focus on the most appropriate solution. If we have a watered-out layer with no crossflow
A different way of classifying conformance between layers, this problem falls in the upper right
problems was developed, briefly described, and quadrant, since the flow problem is dominated by
presented in Part 1. The conformance problem permeable flow, but due to no crossflow between
matrix (Fig. 1) allows us to classify conformance layers, all the control exists at the wellbore.
problems based on two primary problem We then move to the more complex problem
characteristics: the dominant problem flow path of a watered out layer, but one with extensive
(i.e., a VSC [void-space conduit] or permeable crossflow between layers. This problem would fall
rock) and the location of prominent flow control in the lower right quadrant as the flow problem is

30 JPT | June 2023

 FEATURE | Flood Management

Problem flow is through Problem flow is through

void space or high-flow conduit permeable rock

at the wellbore
Casing hole connecting

le g,
s
thief zone off structure

er in
ak
ck ub
pa , t
Watered-out layer without

d ng
Perforated wrong crossflow between layers

an asi
interval
C
Flow control is dominated

or

Moving oil/water contact

n
es n

tio
r
tu a er

uc
Channel flow
ac rom lay

ng
od
behind pipe f r
d s f ed

i
sp
pr
ce ult -fill

cu
d
an u
d fa r
in al ate

or
in tur r w
–s

ng
ow na o ith

ni
le s

Fl up ifer er w s

Co
u t lay n layer
ho

u e d - o e e
aq e r t w nd p
Wat flow be
m

s t y a wee
or

o s i
Karsted layer flow cr ne l s
in the reservoir

o ge area
r
uid ete lled
nduct fl ir h ntro
u lt s that co c ti o n rv o o
s or fa prod u se y c
Fracture injection and Re trop
n
betwee iso
an

Fig. 1—Conformance problem matrix.

permeability related, but since there is extensive and highly conductive. An induced fracture will be
crossflow, there is really limited or no control at void-space flow, but to a limited extent, the control
the wellbore. is somewhat more accessible from the wellbore.
These last two problems exist as a continuous Karsted intervals (with connected vugular sections)
grade from the upper right quadrant to the lower are void-space flow problems, but their degree
right quadrant, depending on the level of crossflow of control is based on how connected they are to
between layers. vertical flow features (i.e., fractures or permeable
The lower right quadrant contains all issues rock) away from the wellbore. One other feature of
where reservoir permeability is very heterogeneous these deep reservoir VSCs is that they often change
and/or anisotropic. That is where permeability in their conductivity over time due to dissolution or
can change directionally as well as in magnitude. erosional enhancements.
Deltaic braided stream depositional environments In most problem scenarios, the ability to
can create this type of permeability variance. The properly characterize flow is the biggest limitation
key aspect of this problem is that this flow problem to designing the best solution. Engineers usually
is totally dominated by permeable flow and all equate any pressure drop over a region as a
control is located well away from the wellbore. function of Darcy’s law and permeable flow.
A reservoir that is highly faulted and fractured However, conduit flow (i.e., flow in large void-space
and where fluid can easily move through those features) might be better characterized by pipeline
features would fall in the lower left quadrant. The flow. The critical piece of this understanding relates
problem flow exists within the void-space feature to the nature and size of the void-space features.
of the fractures, but since there is extensive natural How we design solutions, or mixtures of materials
fracturing, the control is dominated deep in the to control these features, is closely related to the
reservoir. These features can vary from extremely flow mechanism’s size, shape, and overall extent
tight with limited transmissibility to very open within the wellbore and the formation.

jpt.spe.org 31
 FEATURE | Flood Management

Fig. 2—Range of solution options for conformance engineering problems.

True permeable flow in competent rock, even However, in most cases within the industry, we
up to several darcys, can be controlled by sufficient start with, and/or focus most of our time on,
volumes of very strong gels. However, larger existing wellbore interventions. Let’s look more
VSC features associated with enhanced faults or intently at existing wellbore Interventions.
fractures, karsts, large wormholes, etc. will require
a much stronger material, typically cements or Relating Solutions to the Problem Matrix
very strong preformed particle gels designed as Now that we have a populated matrix with a
void-space fillers. We will discuss this more when variety of problems, how does this help us relate
we focus on the solution overlay, but for now, to an appropriate solution? With existing wellbore
recognize that it is very important to properly intervention solutions, I think we would all agree
characterize the nature of the flow to generate that keeping to the simplest solution is often best.
effective solutions. In the case of several conformance issues, this
typically means mechanical solutions, bridge plugs,
Solution Types and Solution Continuum straddle packers, scab liners, etc.
Before we dive into the specifics about which However, we know that these solutions are
solutions might work best for a specific set of only effective in the upper half of this matrix.
characteristics, we must recognize that the In certain situations, mechanical solutions may
solution options for conformance engineering not be available due to the existing completion
problems range from a myriad of existing wellbore character. In those cases, we might be able to use
interventions to more extensive tailored solutions. cement or other void-space fillers (VSFs), and if the
This set of solutions can be represented by a problem is in the upper right quadrant, chemical
solution continuum (Fig. 2). solutions such as permeability blockers can
Distinguishing the best option within this be used.
continuum can be very difficult and often takes In the cases where the wellbore intersects
years of working on a given field or project another VSC and extends control away from
to identify the most cost-effective approach. the wellbore into the lower left quadrant of the

32 JPT | June 2023

 FEATURE | Flood Management

Problem flow is through Problem flow is through

void space or high-flow conduit permeable rock

at the wellbore
Thief zone off structure

le g,
s
er in
ak
ck ub
Perforated wrong

pa , t
d ng
interval
an asi
C
Watered-out layer without
Flow control is dominated

crossflow between layers

Moving oil/water contact

or er
es lay

g
r Channel flow

in
n
u
ct ter

tio

sp
fra wa behind pipe

uc

cu
in m od

or
o
ow fr
pr
l

ng
F lts
d

ni
u r wit
an

fa laye layers

Co
u t
–s

o n
red- twee nd p
Wate flow be y a wee
les

o s s i t
c r ne l s
ho
in the reservoir

Karsted layer flow o ge area

m

ter d
he rolle
or

r
W

lt i nt
e or fau n o
erv y co
Fractur and productio s
n in je c ti on Re trop
betwee iso
an

Fig. 3—Relationship between mechanical solutions, cements/VSFs, and chemical/sealant gel systems.

problem matrix we can use cement and other problems in one well or field. For example, we
VSFs. The key to creating effective solutions into have hydraulically fractured a well in a field with
the lower left quadrant is our ability to pump large significant permeability streaks. Perhaps we have
volumes of VSF materials that have the proper extended our fractured interval, thus connecting
strength to control that area. We can improve it to an aquifer. In some cases, we have karsted
our effectiveness in these types of solutions by intervals combined with extensive fracturing, either
tapering the strength of the materials we use. A induced or natural. In other situations, we have
great example of this is found in SPE 103044. When not controlled the wellbore connectivity to the void
we are limited to existing wellbore intervention space or conduit flow, thus limiting our overall
solutions, we can only generate effective solutions control (i.e., slotted liners, wire-wrapped screens,
for the lower right quadrant problems through or pre-packed liners). In addition, we also have
the utilization of deep permeability-penetrating problems that may have started out as limited flow,
solutions or extremely small nanoparticle but over the years these features get enhanced
systems. These are included in the chemical through additional rock dissolution or erosion. As
solutions. We can further see this relationship discussed in Part 1, understanding these problems
between mechanical solutions, cements/VSFs, and and their overall impact is critical to our ability to
chemical/sealant gel systems by using a graphical design effective solutions.
overlay image on the problem matrix (Fig. 3). Designing an effective solution must focus on
If this is all we had to do, the world of controlling, or at least aggressively influencing,
conformance engineering would be simple. the most dominant flow problem. In cases where
However, in many cases, we end up with multiple a VSC is involved, this will always be the dominant

jpt.spe.org 33
 FEATURE | Flood Management

Problem flow is through Problem flow is through

void space or high-flow conduit permeable rock
at the wellbore

Thief zone off

o structure

le g ,
s
e r in
ak
ck ub
Perforated wrong

Most Severe
pa , t

Commonly solved
interval with existing
d ng
an asi

wellbore interventions
C

without
Watered-out layer witho
hou
Flow control is dominated

contact
ontact
crossflow between layers
een la
or er
s
re lay

ng
n
u Channel
Ch
hannel
nnel flow
ct ter

oil/water c

pi
tio

fra wa

us
behind pipe
behin
uc

c
in m
od

or
o
ow fr
pr

Fl lts Most dominant

ng
Most common h

Moving oil/
nd

ni
u it Most Likely
fa problems, yer w

Co
problems, rs
sa

d - o ut la en laye
re e
–

not most prolific. Wate generallybetw nd p

y a ee
les

o w
ssfl
cromanaged eit l sw
by
ho
in the reservoir

n
Karsted layer flow ge area
ro
m

Demands improved ete olled

or

h
oir ntr
W

or fault
response flooding
Fracture d produ
ction erv co
s y
e n in jection an Re trop
we
betw i s o
an

Fig. 4—Interaction of the conformance solution continuum with the problem matrix.

feature. This is the one area where we have Returning to the problem matrix with the
lucked out. Our ability to control void-space flow solution overlay, none of these solution boundaries
is considerably better than our ability to design or problem placement locations are hard and fast.
and place solutions that gain significant control There are always gray areas within the problems
over permeable flow issues. Mechanical systems and the solutions that can alter their location to
are the easiest to place and usually the easiest some degree. In addition, remember that although
to remove if they don’t work. Cement and VSFs we may have done something to control one
are next, and our experience with remedial (or problem, many times multiple problems exist that
squeeze) cementing often comes with many reduce the overall benefit of the selected solution.
years of experience. The one significant problem The effect of economics can shift these boundaries,
with remedial cementing is that, for years, the as well as technological improvements and/or
industry has only focused on regaining control at physical limitations of the wellbore configuration.
or very near the wellbore, and today’s problems In addition, although chemical and/or gel systems
often demand that we influence these void-space can reach farther into the lower right quadrant,
conduits well beyond the wellbore. there are often times when many problems in
There are also situations when multiple this area lend themselves to better solutions from
solution techniques can be implemented at one pattern reconfiguration or designer wellbores,
time to gain synergy from the two solutions. One as discussed earlier. Fig. 4 provides a general
example is pumping gels, followed by cement, as in perspective on the interaction of the conformance
gas-shutoff cases documented at Prudhoe Bay. solution continuum with the problem matrix, along
In addition to the papers on Prudhoe and Anton with a severity vs. likeliness plot.
Irish, I recommend two papers on West Sak that The perspective shown in Fig. 4 is provided
utilize this technique and that show the progression not as a hard and fast relationship but more as a
of solutions that result from the performance general rule that has developed out of multiple
evaluation and problem understanding experiences, technical reviews, and learnings from
improvements (SPE 169073 and SPE 201302). others. It is my opinion that the greatest number

34 JPT | June 2023

 FEATURE | Flood Management

of conformance problems that exist in the industry problem understanding and the economics of
are related to permeability variance between zones the solutions applied.
that are significantly interconnected deep in the Part 3 will focus on making sure that we are
reservoir. These problems exist in the lower right properly accounting for the benefits received from
quadrant and are very difficult to access and control our diagnostic and solution efforts. JPT
from existing wellbores. These problems are not the
most severe in terms of rapid or massive injectant FOR FURTHER READING
cycling or breakthrough. The most severe problems
result from direct VSC problems and require some SPE 84966 A Strategy for Attacking Excess
form of physical intervention, or you lose the value Water Production by R.S. Seright, New Mexico
of the wells involved. Petroleum Recovery Research Center; R.H. Lane,
Over the years, the permeability variance Northstar Technologies Intl.; and R.D. Sydansk,
problems that exist in the lower right quadrant Syndansk Consulting Services.
have generally been solved through sidetracking, SPE 103044 The Successful Evolution of Anton Irish
custom pattern reconfigurations, injection/ Conformance Efforts by D.D. Smith, M.J. Giraud,
production rebalancing, etc. This is also the primary and C.C. Kemp, Occidental Petroleum, et al.
area where today’s application of big data analysis SPE 54596 Gel-Cement Combination Squeezes
tries to correct these conformance problems for Gas Shutoff by Q.J. Lai and A.J. Bond, ARCO
through rebalancing of fluids. Alaska Inc.; and T.W. Carpenter, ARCO AEPT, et al.
To get the most value out of your conformance SPE 169073 An Overview of Conformance Control
engineering efforts, you must continue to use the Efforts for the West Sak Field on the North
information you gain on each effort to learn even Slope of Alaska by J.W. Peirce, M.R. Hutcherson,
more about the problem and thus, formulate and M.D. Jensen, Conoco Phillips, et al.
the best potential solutions for the conformance SPE 201302 Case History of Conformance
problems you encounter. Remember Step 5 of the Solutions for West Sak Wormhole/Void
process wheel in Part 1. Space Conduit With a New Reassembling
To have the greatest success rate in Pre-Formed Particle Gel RPPG by G. Targac,
conformance problems you must revisit your C. Gallo, and D. Smith, ConocoPhillips, et al.

AUTHOR
David Smith, SPE, is currently water management for Halliburton and held
the president and principal several positions within ARCO that were associated
advisor for Oilfield with profile modification and sweep improvement.
Conformance Consulting LLC Smith has been an active SPE member for
and an adjunct professor more than 45 years. He was the technical
for Missouri University of program chairman for the 2014 SPE EOR/IOR
Science and Technology (MS&T). Conference in Tulsa, a past co-chairman of the
Prior to his current efforts and for SPE EOR/IOR TIG (Technical Interest Group), and
approximately 20 years, Smith was the global an SPE Distinguished Lecturer in 2019–2020. Smith
conformance engineering advisor for either holds a bachelor’s degree in geology from Pacific
ConocoPhillips or Occidental Petroleum. Prior to Lutheran University and an MS in petroleum
that he was a project manager in conformance engineering from Stanford University.

jpt.spe.org 35
 FEATURE | Gas Certification

Journey to an “A” Grade

Gas Certification
MIKE KYRYLOVYCH, P.Eng.

Source: Getty Images.

36 JPT | June 2023

 FEATURE | Gas Certification

T
he August 2022 issue of JPT featured an Roy Hartstein is an emissions subject matter
article on the most common voluntary expert, as well as founder and president of
certifications that have at least some Responsible Energy Solutions, an organization
kind of methane emissions-related that performs certification assessments and helps
requirements. Since then, MiQ appears to have companies prepare for certification. Hartstein and
become a certification framework of choice for his team have conducted over a dozen MiQ audits.
many industry players. According to Georges He talks about three aspects of value that motivate
Tijbosch, CEO of MiQ, as of January 2023, about natural gas producers to improve from a non-A
20% of US natural gas production has gone to an A grade: 1) possibility of earning a higher
through the MiQ process. Tijbosch noted that premium on the sold certified gas; 2) internal
most of the currently certified production received risk management across several avenues such as
grades A, B, or C. safety, identification of malfunctioning equipment,
While this is no high school, we naturally tend or early detection of operational inefficiencies;
to assume that getting an “A” is the ultimate goal of and 3) alleviating environmental concerns of the
getting certified. It might be true for some; however, investment community. He believes this advances a
as we all realize after graduating schools and long-term strategy to secure oil and gas’s potential
universities and upon entering the workforce, life is as part of the future energy mix.
quite often more about continuous improvement Regardless of the underlying motivation, most
over time vs. achieving the top grade as such. of us like to think we are straight-A students and
This article is aimed at exploring the MiQ don’t want to bring home a report card with a
grading framework in more detail and explaining lower grade. But at the time a company initiates
practical pathways for industry participants to the certification process, they may find they
achieve any desired MiQ grade. For simplicity, qualify for a lower (i.e., non-A) grade. What are
we will focus on the MiQ Standard—Onshore the potential implications of this?
Production, but the fundamental concepts are Let’s say you are a Permian producer with
applicable to other industry segments. legacy assets and an early gap analysis of methane
The MiQ Standard scores a facility based on intensity shows a likely D grade. Is it worth it
three broad categories. to go through the certification now and get a
• Methane-intensity quantitative metric D? According to Michael Rabbani, certification
• Monitoring technology deployment manager at MiQ, it absolutely is.
• Company practices related to the methane The baseline methane intensity depends
emissions management heavily on the region of operation. Publicly
available emissions data show that the Permian
Each of these categories is scored by an auditor Basin’s methane intensity baseline is multiple
accredited to conduct MiQ audits and who is an times higher than that of the Marcellus Shale.
independent subject matter expert in the fields of Peer-reviewed studies measuring the methane
methane mitigation, monitoring, and accounting. emissions of the Permian show that the basin as
The combined score across the three categories a whole might not even achieve an MiQ grade F.
results in a letter grade on the MiQ certificate So, being able to confirm even a grade of C or D in
issued for that facility’s production. Natural gas a high-emitting region positively differentiates an
buyers (typically utility companies or industrial operator’s performance and transparency.
users) then request certain volumes of certified gas Earning a non-A grade is a quite realistic
and, depending on the targeted end use and other outcome for an early adopter of the standard, so
factors, may specify a desired grade. what does the road map to improvement look like?

jpt.spe.org 37
 FEATURE | Gas Certification

The three pillars of

the MiQ Standard.
Source: MiQ.

*Source-level only.

The MiQ standards and auditor checklists outline have to do internal calculations to define what that
a simple framework to follow, with boxes to check threshold is for the assets it operates.
for technology deployment and company practices As well productivity declines over time, these
to move a company in the direction of a top grade. less-productive wells may negatively affect an
The purpose of the technology deployment pillar operator’s methane-intensity metric. The impact
is to verify the calculated methane intensity. The of these assets will likely be felt most by very
policies and procedures pillar is aimed at ensuring small operators where the ability to bring new
the operators are well-equipped to manage production year over year is rather limited, but will
their methane emissions up to the industry also be felt by larger operators if drilling activity
best practices. “With a goal to get your company slows, causing the methane intensity to increase
practices aligned with the standard, you’ll get there,” with time. Hartstein indicated that managing
said Hartstein. He added, “Implementing best methane intensity would require additional
practices required by the MiQ standard can lead emissions reductions or increases in production.
to certification, while adding advanced practices One potential solution might be shutting down
can lead to higher grades. Where you draw the uneconomic low-producing wells. Operators may
line economically answers where you can aim,” need to evaluate which of their wells should be
suggesting that a greater investment in control plugged and abandoned at the right time to take
technologies and other emissions improvements them off the asset inventory, possibly sooner than
can lead to higher grades in certification. typically assumed. Uniform plug and abandon
There might be an economic limit to methane- (P&A) rules across various jurisdictions would
reduction efforts. At some point, an incremental improve timeliness of P&A activity. Many states
dollar targeted at methane-abatement projects might have regulations that disincentivize operators to
bring more value (both monetary and environmental) clean up low-producing or shut-in wells which
if it was invested elsewhere. Each company will can lead to wells getting orphaned and continue

38 JPT | June 2023

 FEATURE | Gas Certification

emitting methane. The Canadian Province of It is important to keep in mind that the goal of
Alberta implemented liability management rating receiving a voluntary certification is to embark on
(LMR) to help regulators assess a company’s ability a journey of lowering the environmental impact of
to address its abandonment, remediation, and a company’s operations while satisfying society’s
reclamation obligations. LMR requirements have critical energy needs, especially in times of extreme
helped to prevent uneconomic wells from being geopolitical uncertainty. Research suggests people
orphaned due to sometimes questionable mergers tend to really like the stories about underdog
and acquisitions activities. characters. It is quite possible that continuous
It is important to some companies to show improvement in methane emissions-reduction
grade A for a variety of reasons. “The timeline to efforts showcased by the industry will have a
go from C to A doesn’t need to be a long one,” said similar effect. JPT
Hartstein. In most of the cases, it can take months
and not years. For example, if the training program With thanks to Sharon Paterson, Josh Etkind, and David Shackleton
(part of the company practices category) needs for their support and guidance. This article represents the author’s
personal views and does not necessarily reflect the opinion of or
improvement at the time the assessment is initiated,
endorsement from his current or past employers.
the company can make the required changes
and implement a new program by the time the
assessment is completed. Some companies choose AUTHOR
to pause the certification process, implement the
needed changes, and come back to the table ready Mike Kyrylovych, SPE, has
to receive a higher grade in less than 6 months. a combined 10 years of
A company that wants to be well-prepared in experience in the energy
advance of an assessment might engage in a “gap sector, business analysis,
assessment” to determine the specific policies, and data analytics. Having
procedures, or technology deployment that are worked at leading energy
needed prior to starting on certification. R&D, consulting and technology
Some operators are already engaged in firms, he has advised clients in
other voluntary initiatives and wonder whether the areas of enhanced hydrocarbon recovery,
or not certification is additive or contradictory infrastructure investment, M&A due diligence, and
to their current activities. A growing number regulatory compliance. In his previous role, he
of operators are joining the ranks of OGMP was an engineering analyst in a major Canadian
2.0 membership, a United Nations-managed oil and gas producing company where his duties
reporting framework focused on improving the were focused on leveraging digital technologies
accuracy and transparency of methane emissions to improve internal processes and operational
reporting in the oil and gas sector, and/or OGCI efficiencies. Currently, he works in the area of
Aiming for Zero Methane Emissions Initiative. GHG emission-reduction technologies.
These initiatives are in fact very compatible. The Kyrylovych has been an SPE member since
requirements for these initiatives are in most of 2010. He holds a BEng degree in petroleum
the cases complementary and when a company engineering from Ivano‑Frankivsk Oil and
engages with either body, the insights and practical Gas University, Ukraine, and an MSc degree
outcomes can be shared across all of them. Having in petroleum systems engineering from the
the right software to manage the data associated University of Regina, Saskatchewan, Canada. He is
with these frameworks can simplify and streamline a registered Professional Engineer in the province
the certification process. of Alberta and a Certified Business Analyst.

jpt.spe.org 39
 CASE STUDY

China Field Test of Dissolvable Collet

Demonstrates Time and Cost Savings
Jack Wang, Vertechs Group

O
ver the past few years, dissolvable frac using high-expansion dissolvable metal to create
plugs have been effective in addressing a collet structure with slip segments and a metal
unconventional completion challenges seal ring, eliminating the need for elastomers as a
by reducing the need for intervention sealing material.
and decreasing overall completion Compared to traditional frac plug designs, the
time and cost. However, the majority of dissolvable collet design is simpler and more robust, enabling
frac plugs on the market are made up of complex it to be run and pumped down at higher speed,
components, which increase their likelihood of eliminating issues accompanied with high annular
failing when run in hole, during stimulation, or not velocities, thereby increasing its running speed in
fully dissolving before cleanout. This has resulted the wellbore.
in skepticism and challenges with the older Since it uses less material for manufacturing,
generation of dissolvable plugs. it is lighter and easier to dissolve than traditional
To address these issues, Vertechs introduced frac plugs; for instance, the collet only weighs
a new dissolvable collet that can withstand high around 1.1 lb, which results in faster cleanout
and low temperatures (100–350°F), has a pressure runs, allowing the operators to produce their
rating of 10,000 psi, and is less than 2.5 in. in wells sooner. Many traditional frac plugs weigh
length (Fig. 1). around 11–13 lb.
The dissolvable collet combines anchoring
and sealing functions into a single component Field Test Results
An operator in China conducted a field test
on a four-well pad in an onshore, southwest
shale formation using traditional dissolvable
frac plugs in two wells and the new dissolvable
collets in the other two. The goal was to speed
up completion and minimize coiled tubing
operation spending. The results for plug-and-perf
and cleanout runs were compared between the
two types of plugs, and the new design showed
significant improvements.
When running conventional frac plugs into
the wellbore, the wireline crew adhered to the
line speed chart provided by the tool suppliers
Fig. 1—The dissolvable collet can withstand high and to minimize the impact of annular velocity on the
low temperatures (100–350°F) and has a pressure elastomers. To achieve this, the running speed was
rating of 10,000 psi.
maintained within a certain limit. Consequently,

40 JPT | June 2023

 CASE STUDY

Average Plug-and-Perf Time per Stage (mins)

Vertical Horizontal Set Plug Perforations POOH

200
180
15% Time saved
160
140
120
100
80
60 30

40 19
20 50
32
0
Traditional dissolvable plug Dissolvable collet

Fig. 2—Reduction in the average plug-and-perf time per stage by 15% when using dissolvable collets.

the average running time per stage in the vertical with Well 4 and conclude with Well 1, allowing
section was approximately 50 minutes, while the more time for the traditional dissolvable frac plugs
pumpdown time was about 30 minutes per stage in to dissolve. Fig. 3 illustrates the recorded drillout
the horizontal section. time per plug for each stage.
In contrast, the dissolvable collets were As depicted in Fig. 2, the dissolvable collets
deployed and pumped down at a higher speed utilized in Wells 3 and 4 exhibited little to no
due to their uncomplicated and sturdy structure, drillout time, in contrast to the traditional
leading to an average running time of 32 minutes dissolvable frac plugs utilized in Wells 1 and 2,
per stage in the vertical section and 19 minutes per which displayed a typical zig-zag drillout pattern.
stage in the horizontal section. Throughout the cleanout runs conducted in
While it is true that the pumpdown time in the Wells 1 and 2, several short trips were required
horizontal section decreases as the stages move to aid in the circulation of cuttings and debris.
from the toe to the heel, the average time per stage Conversely, no short trips were necessary in Wells
is used for easy comprehension and visualization. 3 and 4 as there were no cuttings or debris present
When combined with other aspects of the during the process.
plug-and-perf process, such as setting the plug,
perforating, and pull out of hole, it became Conclusion
apparent that significant time savings were In conclusion, due to the low total mass of
achieved during the running and pumpdown materials utilized, the dissolvable collets were
phases in both the vertical and horizontal sections capable of dissolving completely within a brief
of the well. This resulted in a 15% reduction in time period, thereby substantially reducing coiled tubing
spent per stage (Fig. 2). operation time by eliminating drillout and the need
Following the completion of the pad and a for short trips.
3-day well shut-in period, coiled tubing was rigged Overall, the dissolvable collet has proven to
up for the cleanout runs. The plan was to begin be a simpler, more robust, and efficient tool for

jpt.spe.org 41
 CASE STUDY

Drillout Time Per Stage by Well

24
22
20
18
16
Time (min)

14
12
10
8
6
4
2
0
32 31 30 29 28 27 26 25 24 23 22 21 20 19 18 17 16 15 14 13 12 11 10 9 8 7 6 5 4 3 2 1
Stage Count

Well 1 Traditional dissolvable plugs Well 2 Traditional dissolvable plugs

Well 3 Dissolvable collet Well 4 Dissolvable collet

Fig. 3—Comparison of the drillout time per stage for the four wells located on the same pad.

unconventional completions, addressing challenges

associated with traditional frac plugs and providing
AUTHOR
significant time and cost savings for operators in Jack Wang, technical
the industry. Although these savings may appear marketing specialist at
insignificant when considering just a few wells, Vertechs Group, began his
their impact can become more apparent and have career as a field engineer,
greater economic implications as they accumulate specializing in dissolvable
on a larger scale. JPT frac plug application and
troubleshooting. He developed
FOR FURTHER READING an interest in frac plugs over time
and took roles in R&D and testing programs
SPE 214278 New Dissolvable Isolation Tool centered around dissolvable frac plugs. His R&D
Eliminating Plug-and-Perf Operation contributions led to the acquisition of patents
Challenges and Reduce Completion Costs associated with frac plug components and related
by Jinlu Wang, Vertechs Group; Xusheng He and tools. He is currently dedicated to technical
Junyuan Wang, PetroChina Southwest Oil & Gas marketing efforts and providing comprehensive
Exploration, et al. training for new employees.

42 JPT | June 2023

 27 February – 1 March 2024
Kuala Lumpur, Malaysia

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 TECHNOLOGY FOCUS

Coiled Tubing
Pierre Ramondenc, SPE, Coiled Tubing Domain Head, SLB

N
eedless to say, the oil and gas industry their environmental footprint. Coiled tubing has
as a whole has been riding a rough a key role to play in those efforts, with strong
roller coaster over the past few years. arguments for itself: It is used throughout the life
The drop in activity felt at the end of of a well, from exploration to abandonment, and its
2019 was made much sharper by the COVID-19 flexibility of use, combined with recent technology
pandemic, which brought investment levels to developments in pipe materials, real-time
historic lows. This was followed by a recovery at downhole telemetry, and specialized downhole
least as abrupt, and many now believe that we tools—just to name a few—opens avenues to
are in for a strong multiyear upcycle. Although perform in a rigless manner many operations that
positive for our industry, this generates all sorts once required a rig and several service lines.
of challenges, including access to both the human It seems, however, that, like the rest of the
and equipment resources necessary to support well-intervention field, and despite a positive
that growth. outlook, coiled tubing still hits the same glass
The notion of cycles is not new to oil and ceiling in success rate and activity levels. How to
gas; however, the past 3 years have significantly break it was at the center of discussions during
transformed the mindset of most of its actors, the recent SPE/Intervention and Coiled Tubing
who are now chasing any opportunity to reduce Association (ICoTA) Conference in The Woodlands,
waste and increase efficiency of their operations Texas, which proposed to a record attendance a
while assessing how they can further reduce variety of case studies and new technologies and

PIERRE RAMONDENC, SPE, is the coiled tubing domain head at SLB,

with more than 15 years of oilfield experience. He is responsible for
the creation and implementation of new work flows, technical training
programs, tools, and the digital architecture of coiled tubing services
and several production-enhancement initiatives. Ramondenc has
authored more than 50 technical papers and patent applications
related to those topics. He holds MS and PhD degrees in civil and
environmental engineering from the Georgia Institute of Technology.
Ramondenc served as an SPE Distinguished Lecturer in 2017–18, is
Pierre Ramondenc a technical committee member of the SPE/ICoTA Well Intervention
Coiled Tubing Domain Head Conference and Exhibition, and is a member of the JPT Editorial
SLB
Review Board.

44 JPT | June 2023

 TECHNOLOGY FOCUS

a very dynamic operator roundtable. The technical

Recommended additional reading at OnePetro:
program confirmed a trend already noticed in
www.onepetro.org.
recent publications, with coiled tubing expanding
once again its operational envelope and proposing
new work flows addressing the industry’s wish for SPE 213666
efficiency, waste reduction, and digitalization. Coiled Tubing Drilling Advancement With
One such example is the rapid increase in Smallest Shaped Diamond Cutting Element
rigless coiled tubing drilling seen over the past by Syed M. Siddik, Baker Hughes, et al.
couple of years. The demand for new projects,
both onshore and offshore, is on the rise, with IPTC 23046
always more extreme downhole conditions of low Real-Time Rigless Intervention With a Catenary
pressure and high H2S content. Paper SPE 210978 Coiled Tubing System To Perforate the Long
provides a detailed review of the best practices Horizontal Section of a Well, Offshore Brunei
to take into consideration when planning and by Azemi Leong, Halliburton, et al.
executing such projects, which seem to be familiar
in the Middle East. Meanwhile, paper SPE 213666 SPE 212925
shows how bit design can play a key role in Subsea Well Annular Integrity Repair Using
facilitating deeper reach during coiled tubing Coiled Tubing and Pressure-Activated Sealant
drilling operations. by Joel E. Johns, Seal-Tite International, et al.
Another area of focus for the well-intervention
industry is offshore, where activity is expected to
grow significantly in the years to come. While our
industry still searches for ways to optimize costs
and minimize rig operations—which are costly
and time-consuming—papers SPE 212939 and
IPTC 23046 offer new avenues, with compelling
examples of how well-intervention vessels and and using the most advanced evaluation and
catenary operations can enable a wide range of intervention techniques. Both papers deal with
optimized rigless interventions while preserving the remediating well-integrity issues, but in very
use of key downhole technologies. different settings—as part of a fracturing campaign
Lastly, as a testimony to the versatility of for the former and to enable access to a subsea
coiled tubing, papers SPE 212933 and SPE 212925 tree for the latter. Yet they both demonstrate that
demonstrate how coiled tubing can capture a very coiled tubing often can be the cornerstone of much
large workscope in a single mobilization while larger work flows and be key in raising the success
reducing equipment and personnel footprint rate of well interventions across the globe. JPT

jpt.spe.org 45
 TECHNICAL PAPERS | Coiled Tubing

Engineering Approach Uses

Underbalanced Coiled-Tubing Drilling

Because of declining reservoir pressures in some The typical well completions, from top to
of its onshore gas carbonate fields, the operator bottom, include the following:
initiated a three-well underbalanced coiled-tubing • 5.5-in. tubing
drilling (UBCTD) campaign in its onshore Asab • 4.5-in. tubing
and Bab fields, with two wells to be drilled in Asab • 7-in. liner
and one in Bab. Because of the high hydrogen • 100 ft of 6-in. openhole
sulfide (H2S) content, a closed-loop system—the
first one successfully implemented in the Middle Project Objectives
East, according to the authors—was implemented. Because of safety and logistical constraints, the
The complete paper discusses the design and project would use a closed-loop system and
planning involved in the drilling of these three recirculate the drilling fluid, thus avoiding high
wells, the operational challenges encountered, water consumption. Also, the system needed to
and mitigations used. be designed to safely handle H2S in return fluids.
UBCTD using a closed-loop system has been
Introduction performed elsewhere but not in a high-H2S and
One of the operator’s main objectives was to high-CO2 environment.
increase production while safely maintaining
or minimizing operating costs. One method of Trajectory Design and Tubing Forces
achieving these goals is the use of coiled tubing Trajectory design is an important part of drilling
(CT) to drill formations in underbalanced mode. operations; reservoir targets given by geologists
The Asab and Bab fields are southwest of Abu and reservoir engineers must be met. To expose
Dhabi. Both fields have high H2S and CO2 content, more drilling footage in producing formations and
with a bottomhole temperature of approximately to increase overall productivity, the geologists
260–270°F. The candidate wells were drilled provide formation-top coordinates so that the
conventionally until the top of the reservoir section; drilling engineer knows how to proceed as drilling
then, the UBCTD package was moved to drill the progresses through the reservoir subunits.
reservoir section in underbalanced mode. When the well trajectory was designed in the
discussed case, the CT engineer input planned well
surveys into software so that the CT forces could
This article, written by JPT Technology Editor Chris Carpenter, be analyzed. Because these predrilled wells had
contains highlights of paper SPE 210978, “Novel Engineering
Approach Using Underbalanced Coiled-Tubing Drilling
Solutions for Tight Sour Gas Carbonate,” by Mohamed
For a limited time, the complete
Osama Abd El Meguid, Ayman El Shahat, and Ali
paper is free to SPE members
Sulaiman Bin Sumaida, ADNOC, et al. The paper has
at jpt.spe.org.
not been peer reviewed.

46 JPT | June 2023

 TECHNICAL PAPERS | Coiled Tubing

never had CT interventions, the friction coefficient projected openhole in 1,000-ft intervals. The
was unknown and the outcome of the software software considers CT pipe in the wellbore, which
could have been very different from that observed means that the software would provide theoretical
while drilling. production flow while drilling. This allowed the
Friction coefficients from other conventional analysis of additional gas contribution from
CT operations within the UAE, as well as those different formation sublayers and consideration
from other CT drilling operations in the region, of downhole condition changes when more
were reviewed and then used for analysis. With the openhole length was drilled and more gas added
lowest friction coefficient of 0.3 for open hole, the to the flow.
target drilling length could not be achieved. Project In addition to being run while drilling, the
planning required a solution to enable the lateral software was run for the condition in which
to meet the proposed objectives. the well was drilled to total depth and the CT
The following parameters were considered to pipe was removed from the wellbore; this
maximize the drilling reach: provided estimated production when the well
• The weight on bit (WOB) could be minimized began producing.
to enable the planned footage to be met.
Pushing too hard on the CT results in helical Hydraulics
buckling, which causes the contact of CT with When drilling the well with CT, a primary
the completion to be greater than desired. Two operational concern was well-cleanout efficiency.
types of devices are used to rotate the bit— Insufficient flow velocity to transport drilling
positive displacement motors and turbines. cuttings to surface could result in CT sticking. For
• The directional control is applied by a fixed this project, a hydraulic analysis was run using two
bent sub positioned below the motor or types of software, CoilCADE and Neotec WellFlo.
turbine. The azimuth and inclination can be The methodology of this process, and the factors
changed by adjusting the bent sub angle, with influencing it, are detailed in the complete paper.
the most common angle being 1–1.15°; this
gives 10° of dogleg severity (DLS). For this Equipment Selection
project, the bent sub angle was chosen to To meet the project’s objectives in terms of a
be 0.75°, resulting in a DLS of 7°, which, per maximum openhole length, the CT pipe had to
simulations, could give up to a 10% increase be designed to withstand all downhole forces
in lateral length. and reach the planned drilling depth. The 2⅜-in.
• The CT in the wellbore has a spiral shape and pipe was designed to reach at least 4,000 ft of
contacts the completion tubulars and openhole drilled open hole, taking into consideration friction
walls. To reduce friction and increase the coefficients taken from other locations in the
lateral reach, it was decided to use a metal-to- region. From extensive CT drilling experience in
metal friction reducer in the drilling mud. other locations with a 3.125-in. drilling bottomhole
assembly (BHA), it was determined that the same
Potential Production Analysis BHA system, which has proved its efficiency and
Once the pay zones are known, a production reliability over a number of years of CT drilling
analysis was performed to analyze potential operations, would be used.
productivity of the wells and to determine if the Because of its many components, the BHA
project could achieve production objectives. becomes relatively long—in this case, 77 ft. To
For this project, OLGA software was used. avoid potential issues related to BHA deployment
The software was run at different depths of the activities under pressure, a fit-for-purpose CT

jpt.spe.org 47
 TECHNICAL PAPERS | Coiled Tubing

Project Execution and Results

Several operational challenges had to be resolved
in the first well before continuing the operation.
The return flow lines and equipment were slightly
reconfigured and modified to handle H2S more
efficiently, with additional H2S-removal equipment
installed in the system.
The software simulations were important
for the project; all simulated parameters were
confirmed by actual operational data. The resulting
hydraulics analysis has proved cleanout efficiency.
Because of higher-than-expected gas flow from the
reservoir, the velocity, as well as cuttings transport,
was much better than simulated.
One benefit from higher production leading
Fig. 1—CT drilling tower.
to greater flow velocity was that the planned
frequency of wiper trips was reduced. Instead of
drilling tower was designed and manufactured for short wiper trips every 200 ft drilled, wiper trips
this project (Fig. 1). The height of the tower had were conducted every 300 ft. In addition, instead
to accommodate the entire drilling BHA length of conducting long wiper trips every second short
such that the drilling BHA could be deployed wiper trip, long wiper trips were performed after
as one section. During BHA deployment and three short wiper trips. The friction coefficient was
disengagement, well pressure is isolated by the calibrated during the wiper trips.
wellhead master valves such that the primary well-
control barriers and pressure-control-equipment Conclusions
stack are not exposed to pressure. As a result of the care taken with the planning and
preparation phases of the UBCTD project, two
Returns-Handling System wells were successfully drilled in the Asab field.
One of the main challenges of this project was Well-productivity results exceeded expectations
to design a returns-handling system capable of and proved the benefits of the technology and its
the following: applicability in the region.
• Removing the drilling cuttings from the process The production of the wells was higher
and collecting solids samples than that simulated by software because of
• Separating and measuring the flow rates of the difference between the provided reservoir
different fluids data, gleaned from overbalanced drilling wells,
• Neutralizing the high concentration of H2S and and the actual properties of formations drilled
treating the drilling fluid using UBCTD. The executed well operation has
• Maintaining underbalanced conditions been implemented for the first time in the oil
field where drilling fluids had to be managed in
A discussion of equipment selected to achieve a closed-loop circulation system in a well with
these objectives is included in the complete paper. high H2S content. JPT

48 JPT | June 2023

 TECHNICAL PAPERS | Coiled Tubing

Riser Allows Live-Well Intervention

With Coiled Tubing From Monohull Vessel

The complete paper describes the use of a vessel was engaged to expand the usable weather
riser for coiled tubing (CT) operations from a season and allow year-round RLWI operations.
monohull vessel already performing riserless well
interventions (RLWI). The project was developed Description and Application of
by the operator, an intervention-vessel company, Equipment and Processes
and several service providers. The solution covers To enable riser-based CT intervention in the NCS,
200- to 500-m water depths and converts back to the chosen option required more equipment and
riserless operation after CT operations. interfaces than were required when performing
RLWI. To conduct riser-based CT interventions in
Introduction live wells, a way to handle, deploy, and tension
The operator has more than 600 subsea wells the high-pressure riser was required, as was an
globally in multiple countries and more than 550 interface for both wireline and CT equipment in the
subsea wells on the Norwegian Continental Shelf vessel. A system to handle live-well returns from
(NCS), which accounts for more than 83% of all the well also was necessary.
subsea wells in the area. Successful interventions After many engineering iterations, the RLWI
here using RLWI vessels encouraged the operator vessel implemented a modular riser-handling
to investigate the possibilities of also performing CT package that could be installed and then removed
operations from a vessel. The best option was found when not needed.
to be a strategy that included a monohull vessel that On top of the surface flow tree, a custom CT
could perform both RLWI and CT operations. tension frame (CTTF) was developed for the CT and
The analysis of operations in rough-weather wireline stacks and pressure control equipment
conditions in the NCS showed that riser-based CT (PCE), each inside separate support frames within
operations from such a vessel could be performed the CTTF. With the CTTF connected to the riser,
in the summer season only. Thus, the operator each support frame could be skidded to the well
required a flexible solution such that the same center, eliminating the need for crane lifts while
RLWI vessel could cover both year-round RLWI changing between wireline and CT.
and summertime riser-based CT interventions
efficiently. The solution materialized when a larger CT Planning
Well Control and Barriers. Because of limited space
on the RLWI vessel, only one dual-ram blowout
This article, written by JPT Technology Editor Chris Carpenter,
contains highlights of paper SPE 212939, “A Proven and
Versatile Coiled Tubing Live-Well Intervention Solution From a
For a limited time, the complete
Monohull Vessel in the Norwegian Continental Shelf,” by Kjetil
paper is free to SPE members
Austbø and Stein Kristian Andersen, Equinor, and John
at jpt.spe.org.
Stuker, SPE, SLB, et al. The paper has not been peer reviewed.

jpt.spe.org 49
 TECHNICAL PAPERS | Coiled Tubing

preventer (BOP) would fit in the CT support-frame the vessel conversion from riserless to riser-based
cartridge within the CTTF. In addition to the dual operations. Over the course of 1 month, the vessel
strippers, the rest of the PCE requirement considered team upgraded the subsea-deployment, riser-
the subsea emergency disconnect package (EDP) tensioning, and riser-handling systems. The CT and
and lower riser package (LRP) to complete the well-return-recycling packages were installed, and
well-control equipment. The EDP and LRP included all systems were tested at the quayside. Once the
a safety head, a production isolation valve, and a vessel was outfitted for riser-based operations, a
retainer valve, all capable of cutting wireline and CT. successful sea trial was conducted.

Stuck-Pipe Contingency. In case of stuck CT pipe, Operational Summary

because of limited space inside the CTTF, the plan Three wells were selected for the first campaign. The
was to kill the well and hold the pipe in the CT BOP. main objective for all three was to restore wellbore
The CT injector head then would be lifted safely access. The first well had hard scale of barium and
within the CTTF to expose the CT pipe. After the strontium sulfate built up near the production
CT pipe was cut above the CT BOP, the CT injector intervals. Removal was achieved using a motor and a
head would be skidded to the side, allowing mill in combination with a multicycle circulating valve
wireline to rig up on the exposed CT pipe. Once the operated at high pumping rates. The high pump
wireline cut was completed downhole above the rates were achieved by pumping treated seawater
predetermined stuck point, the CT injector head with an environmentally friendly gel to work as a
could be skidded back over the well center and a hydraulic friction reducer. It took two CT runs to
spoolable CT connector would be made up to splice remove 2.4 tons of solids, cleaning a total of 270 m
the two CT pipes together to allow pipe retrieval. of fill. During the operation, a simplification was
implemented in bypassing the oil/water separator
Fluid Return and Recirculation. The three wells system after a management-of-change process that
planned for this campaign required CT cleanout allowed the maximum recirculating hydrocarbon
operations, two of them with a motor and a mill. It content to increase from 500 to 1,500 ppm.
was not permissible to take returns with significant During operations on the first well, two
amounts of solids to the subsea flowline, so a other important lessons were learned. First, the
fluid return and recirculation system on the vessel environmentally friendly product used as a friction
was necessary. reducer diminished after being circulated in and
Because one of the operations had to be out of the well. Second, while 99% of the summer
performed in overbalance with the PCE removed, weather was expected to create heave only below
the return system was modified such that the 2.5 m, the actual operation partly occurred during
degassing vessel would be used for monitoring the 1% of rough weather. The wave patterns
a closed active system and would have volume also were more complex than the metocean
control of the overbalance column. data suggested, with multiple wave systems that
Pumping nitrogen (N2) through the CT was reduced the benefit from the response amplitude
planned to decrease the bottomhole pressure operator of a large vessel.
(BHP) during the cleanout because of low BHP in For the second well, CT intervention was
one of the wells. preceded by 16 wireline fishing runs to remove
3000 m of wire left in the well since 2019. Because
Quayside Preparation of the low BHP in the well, fluid-loss-control
The operation began by mobilizing the vessel to a material was pumped and kill-weight brine was
shipyard that could facilitate all work required for used to perform the entire wireline operation

50 JPT | June 2023

 TECHNICAL PAPERS | Coiled Tubing

Fig. 1—Load relief frame.

in overbalance because the PCE had to be • Successful method developed for planning and
disconnected to remove the fishing BHA and the performing modifications and operations as
wireline bird nest. Upon completing the wireline one team
intervention successfully, CT was used to unload
the well with N2 and restore the well to production. Conclusion
One of the main challenges posed by the third Although most subsea intervention tasks in the
well was that the tree-top flange was too weak to NCS can be addressed by RLWI, an evaluation in
support the LRP. Thus, a load-relief frame designed 2018 and 2019 revealed a significant backlog and a
to be connected to the subsea template was need for CT interventions. The vessel proved to be
produced after extensive engineering (Fig. 1). This very stable. Although 99% of the summer weather
was preinstalled by an inspection, maintenance, was meant to be within the 2.5-m heave limit, some
and repair vessel. The well scope was then to of the operation fell during the other 1% rough-
remove sand and scale deposits along the highly weather time frame and heave above 4.3 m was
deviated upper completion section, the heel, and experienced. The CTTF safely allowed CT stabbing
into the horizontal production zone. This objective and BHA changes in up to 2.5-m vessel heave.
was achieved using the same downhole-tool According to the contract, the workover
configuration of motor and mill in combination stack, the riser, the CT, wireline, and flowback
with a multicycle circulating valve as in the first services were to be provided by separate vendors.
operation. This time, however, friction reduction Significant modification and verification work was
was achieved using a reducer that retained its done to ensure that all equipment would be fit
properties longer during the recirculation process. for purpose and that all systems and interfaces
The main results of the project included the would work together as planned. A considerable
following: part of this consisted of integrating each vendor’s
• One safety incident (a finger injury during well-control documents into one document and
tensioner commissioning at the yard) ensuring that the responsibilities, reporting
• Riser-based monohull intervention operation lines, and chain of command during operations
proven under NCS conditions were clear.
• Three successful well operations The three operations performed in summer 2022
• Clear efficiency improvements, assumed to be on three different fields all met CT objectives and
a result of the high focus on learning and quick proved the concept of riser-based CT intervention
implementation of improvements on a monohull RLWI vessel in the NCS. JPT

jpt.spe.org 51
 TECHNICAL PAPERS | Coiled Tubing

Casing Leak Repair Allows

Continued Hydraulic Fracturing

The authors introduce a successful alternative for (CIT) at 13,000 psi before the first fracturing
repairing casing failures on an unconventional pump. Maximum treatment pressure was kept
well that allows hydraulic fracture continuity to under the CIT pressure, with an acceptable
accomplish the original fracturing plan, considering safety factor margin maintaining the well with
well-integrity conditions throughout the entirety annular communication, and was continuously
of well production life as the main intervention pressure monitored.
objective. The resulting well production was higher Once the fracturing fleet finished the
than the expected estimated ultimate recovery intervention and left the pad, the engineering focus
(EUR) for the landing zone. of the completion was oriented to determine the
location and geometric characteristics of the casing
Introduction leak. It was decided to start from the simplest to
In December 2020, during the execution of most-complex diagnostics interventions.
hydraulic fracturing on a three-well pad in the Vaca The diagnostics interventions, and their results,
Muerta unconventional shale reservoir, an annular are detailed in the complete paper. A bullheading
communication suddenly occurred in one of the pumping test was executed, and an increase in
wells. This event took place during the execution Section B pressure was observed. This showed
of the ninth fracturing stage of 33 planned. clear communication between both sections.
After a thorough pressure analysis of this During circulation tests, it was observed that, by
event and verification that all pressure barriers reducing pressure in Section B, Section A pressure
were correct and in place, it was decided to stop response followed the pressure trend; opposite
fracturing treatments in this well and complete pressure changes in Section A, however, did not
pending fracturing stages in the other two wells reflect on Section B pressure changes.
of the pad until the problem was well understood Based on flow-test behavior, it was believed
and a solution was found. that a casing mechanical failure with a flow area
of 0.044 in.2, equivalent to a 0.23-in. orifice, was
Diagnostics the reason for the annular communication.
The initial good condition of the well barrier With the aid of a coiled tubing (CT) unit and a
was verified by a positive casing-integrity test bottomhole assembly (BHA) principally conformed
with a multiple-set mechanical packer, it was
possible to apply testing pressure below and
This article, written by JPT Technology Editor Chris Carpenter,
contains highlights of paper SPE 212933, “Casing Leak
Repair To Continue Hydraulic Fracture Stimulation,”
For a limited time, the complete
by Gaston Oscar Ciminari, Gonzalo Cabo, SPE, and
paper is free to SPE members
German Rimondi, Pluspetrol, et al. The paper has not
at jpt.spe.org.
been peer reviewed.

52 JPT | June 2023

 TECHNICAL PAPERS | Coiled Tubing

above the packer seals at different depths to

confirm the casing-leak position. A unique failure
was located in the zone between 998 and 1002 m.
A casing joint was located at 999.5 m; thus, it was
assumed that a mechanical problem existed on
this casing‑joint connection.
A wireline BHA composed of an injection-
logging tool and a temperature sensor was used
to reduce the zone of uncertainty. As a result of
this log, the failure zone was located between
999.4 and 1000.4 m. The failure evidently was
near the joint but not in it.
Immediately after well-fluid changeout, the
Fig. 1—Casing patch rig up.
real-time downhole camera was run on wireline
and showed what appeared to be a small hole
1 ft over the casing joint. Because of limited local experience with this
type of intervention, it was agreed to validate
Repair Alternatives casing-patch safety factors while performing finite-
Before review of potential repair alternatives was element analysis with the support of a recognized
conducted, it was agreed that the most immediate engineering consulting company to determine
need was to define the expected objectives of the if the technical proposal was feasible and would
repairing process. This process is detailed in the accomplish all safety goals required by the
complete paper. operator’s standards.
After multiple meetings with different
vendors and providers, a thorough discussion Interventions
was conducted of options (including the possible Repair intervention began with well preparation
combination of different solutions), safety before running the casing patch. This was achieved
considerations, equipment and tool capabilities, with the following steps:
and execution in previous experiences. Standard 1. An additional bridge plug was run and set on
CT service was selected to be the preferred wireline 50 m above the previous plugs.
intervention equipment to execute this job, and 2. A dissolvable fracturing plug without the ball
a casing patch was selected as the technology was precisely set on the wireline at 1020 m to allow
solution meeting the technical requirements. accurate depth correlation while running the casing
The selected casing patch consisted of an path on coil.
11.6-m-long metal pipe with four or five elastomer 3. The principal goal for running the casing
seals attached on each side, providing a 5-m patch was to ensure full casing drift. Thus, the
window between the inner seals, where the casing patch was run on CT using a BHA with a full
damage would be located for a correct pressure drift‑size watermelon mill and flow through an
seal. Internally, a hydraulically activated piston in‑line magnet.
travels upward, pushing a cone that deforms 4. Rigging up the CT and the casing-patch BHA
the casing-patch metal pipe. This permanent was a challenging task because of the length and
deformation applies compression stress to flexibility of the casing-patch BHA, which came
elastomer seals against the casing, providing assembled from the yard. It was necessary to make
anchoring and pressure-seal capabilities. a connection from the casing-patch running tool to

jpt.spe.org 53
 TECHNICAL PAPERS | Coiled Tubing

the CT string at a height of 18–20 m. To accomplish Hydraulic Fracturing Stages

that complex activity, the support of a lifting unit, After the successful repair intervention, 24 pending
a telescopic handler, and two cranes working fracturing stages were completed that featured
together was required to allow a successful tool high axial stresses caused by temperature changes.
connection (Fig. 1). High-pressure cycles of erosive fluid (mixed water
5. The casing patch was run and deployed. and sand) passed through the casing patch with the
plug-and-perf (P&P) wireline BHA. During fracturing
After rigging up and completing all function and execution, the annular pressure was monitored
pressure tests required at surface, the casing patch and a desirable isolation of the internal pressure
was run in hole until the reference plug previously was indicated. No restrictions or limitations were
set at 1020 m was tagged. observed during P&P runs.
The casing-patch deployment sequence had
the following steps: CT Cleanout
1. The casing patch was positioned at the After the fracturing stages were completed, a CT
casing leak. unit was rigged up for final well cleanout. This was
2. A ball was dropped from surface inside the performed without issues using a BHA reaching
CT string. the desired total depth connecting the new 24
3. The steel ball landed on the casing-patch fracturing stages with the nine previous stages
shoe, closing a hydraulic piston chamber. already finished.
4. Pressure was increased at low rates until
reaching 6,000 psi. Completion Run
5. CT tension was applied to verify casing-patch The lower completion assembly was run with a
anchorage to the casing. wireline unit without detecting any disturbances
6. Pumping was conducted at a low rate passing through the casing patch. The upper
(0.5–1 bbl/min) to increase pressure while picking completion assembly with a 2⅞-in. production tubing
up the CT string to surface. string was deployed successfully with a workover
7. Once the casing-path running tool passed unit, following the original completion plan.
through the last pressure seal, an instantaneous
pressure equalization and weight loss occurred. Conclusions
8. A pressure test was executed until 3,000-psi • Diagnostic interventions were key factors
wellhead pressure to confirm that the casing patch in determining the position and geometric
was positioned correctly over the casing damage. characteristics of the casing leak with a high
9. After setting the casing-patch system and degree of accuracy.
performing a positive pressure test, CT was rigged • Casing-patch intervention was executed
up and run using a BHA with a 3.98-in.-outer- according to plan with local service companies
diameter junk mill. and remote support in the context of a global
10. After retrieving CT out of the well, a pandemic without operational deviation or
12,000-psi pressure test was performed against health or safety incidents.
the bottom plugs and casing patch with positive • The remaining fracturing stages, CT cleanout,
results. and production-string installation were
11. Three composite plugs used as barriers executed successfully.
between the formation and the wellhead were • Well production, excluding the repair activity,
milled out using CT, and the entire casing was was higher than the EUR index for the landing
gauged up to the lower perforated interval. zone. JPT

54 JPT | June 2023

 TECHNOLOGY FOCUS

Acidizing
Imran Abbasy, SPE, Managing Director and CEO, Pakistan Petroleum Limited

T
he first acid job dates to 1895. Challenges
remain, however, when it comes to
“Completions can play a role
lithology, coverage, penetration, and in improving acid treatments.
management of reaction products. These Limited entry and the so-called
themes remain a focus for stimulation engineers.
In paper SPE 204879, for example, a novel
‘segmented and selective’
in-situ foam-generation system is introduced completions are at the
that provides effective diversion and leaves no forefront.”
residue. Field applications suggest significantly
better performance compared with other diversion
systems. In paper SPE 203985, the authors
present a 3D acid-fracturing model to calculate methods to achieve effective near-wellbore and
fracture geometry induced through multistage far-field bridging using a combination of solids
alternating injection of pad and acid fluids. and fiber-laden acid. For those wishing to delve
Alternating acid with high-viscosity polymer pad deeper into this subject, paper SPE 206255 makes
promotes nonuniform acid etching and viscous interesting reading.
fingering, which leads to longer and narrower Completions can play a role in improving acid
channels. Concurrently, investigators are studying treatments. Limited entry, as presented in paper

IMRAN ABBASY, SPE, has more than 35 years of global industry

experience with leading exploration and production (E&P) companies,
having held technical and leadership roles in production technology,
drilling, completion engineering, and operations. He has worked
in the North Sea, Middle East, Australia, Indonesia, Nigeria, and
Papua New Guinea, supporting completion design, artificial lift, well
integrity, and production optimization. In September 2022, Abbasy
was appointed managing director and CEO of Pakistan Petroleum
Limited (PPL), a listed public sector E&P company and a pioneer
Imran Abbasy
frontline player of Pakistan’s energy industry. He also heads PPL’s
Managing Director and CEO associated company overseeing operations in Offshore Block 5 in
Pakistan Petroleum Limited
the UAE. Abbasy has authored several SPE papers and participated
in SPE Applied Technology Workshops. He holds a bachelor’s degree
in mechanical engineering and a master’s degree in aerospace
engineering from George Washington University.

jpt.spe.org 55
 TECHNOLOGY FOCUS

SPE 211394, and the so-called “segmented and

Recommended additional reading at OnePetro:
selective” completions are at the forefront. Paper
www.onepetro.org.
IPTC 23003 introduces the concept of sweet spots,
which are then completed selectively with packers
and sliding sleeves. Paper SPE 213406 describes SPE 207514
a relatively complex architecture for a trilateral Subsea Multiwell High-Flow-Rate Riserless
TAML Level 2 well with openhole packers and Acid Stimulation Campaign With Two-Vessel
ball‑activated sleeves. Thus, it can be said that Approach: A Comparative Case Study
most enabling technology is out there. by Irma Kusumawati, ConocoPhillips, et al.
Lastly, engineers have begun to leverage
benefits that big data and artificial intelligence SPE 205599
potentially offer. Predicting an outcome of an A New Method of Carbonate Matrix
acid job remains hit-and-miss at best—a gap Stimulation Modeling and Optimization Using
engineers must bridge. In paper SPE 208172, the Field Experimental Data for Acid Efficiency
authors present a predictive model to estimate the Calibration and Case Studies in Kazakhstan
efficiency of acid-fracturing treatments in naturally by Ruslan Kalabayev, SLB, et al.
fractured reservoirs using an artificial neural
network. They report a predictability error of less SPE 209673
than 10%. This may be what we are looking for. Reducing Carbon Footprint of Matrix Acidizing
I hope you find the selections enlightening. JPT in Carbonate Formations: How Much Acid Do
We Really Need To Pump?
by Mahmoud T. Ali, Baker Hughes

56 JPT | June 2023

 TECHNICAL PAPERS | Acidizing

Simulator Aids Design, Analysis

of Acidizing Jobs With Fluoroboric Acid

Matrix acidizing with fluoroboric acid (HBF4) has precipitation may require fixing the average value
gained special attention because of its deeper of stoichiometric coefficients for reactions between
penetration of in-situ generated hydrofluoric HF/hexafluorosilicic acid (H2SiF6) and slow- and
(HF) acid and stabilization of formation fines by fast-reacting minerals. This becomes challenging to
binding them to the pore surface. While numerous do beforehand, especially when different types of
mathematical models exist in the literature for clays are present with relatively equal proportions
design and evaluation of conventional mud acid in the reservoir. Third, all resulting nondimensional
treatments, few attempts have been made in numbers can be estimated easily by measuring
developing a laboratory-validated model that can effluent acid concentration during coreflooding.
do so for fluoroboric acid treatments. The complete The following assumptions have been
paper presents a novel mathematical model incorporated into the model:
that has been developed that takes into account • The reservoir and core are assumed to be
the chemical kinetics and equilibrium aspects homogeneous and isotropic.
of important reactions and fluid flow inside the • Flow is assumed to be one-dimensional.
reservoir rock. • All fast-reacting minerals are grouped together
as a single fast-reacting mineral.
Mathematical Modeling • All slow-reacting minerals are grouped
Because the complete paper contains numerous together as single slow-reacting mineral.
equations, it is essential for understanding the • The reaction of HF with fast- and slow-reacting
authors’ description of their mathematical model. minerals is assumed to be first-order with
The authors identify three benefits of respect to HF.
their approach from a modeling point of view. • Changes in porosity are small and diffusion/
First, it reduces the total number of chemical gravity/thermal effects are neglected.
reactions taking place, which greatly simplifies
computational complexity while maintaining Laboratory Studies
reasonable accuracy. Second, the inclusion Laboratory studies were performed on sandstone
of separate chemical reactions for silica gel core samples from a prominent payzone in
northeastern India to generate data for model
validation. Core plugs of 1.5-in. diameter were
This article, written by JPT Technology Editor Chris Carpenter, taken from the same block to prevent mineralogical
contains highlights of paper SPE 205893, “Novel Simulator
for Design and Analysis of Matrix Acidizing Jobs With
Fluoroboric Acid in Sandstone Reservoirs,” by Mohammed
For a limited time, the complete
Qamruzzaman, SPE, Mandeep Khan, and Dhirendra
paper is free to SPE members
C. Roy, SPE, ONGC, et al. The paper has not been
at jpt.spe.org.
peer reviewed.

jpt.spe.org 57
 TECHNICAL PAPERS | Acidizing

heterogeneities. Samples were characterized Model Validation

with X-ray diffraction (XRD) analysis and porosity Before model validation, the model must be
measurements. calibrated with coreflooding experiments to
This payzone was selected because it consists determine the value of Damköhler and acid-
of a diverse range of minerals. Thus, a model capacity numbers under the test conditions.
that can be validated with the coreflooding from The calibration of the core-scale model was done
this sample could, in principle, apply to any other with effluent HBF4 concentration data generated
sandstone reservoir. during coreflooding. Results show that, once
calibrated, the developed model can predict
Coreflooding Experiments the consumption of HBF4 inside the core with
Coreflooding experiments were performed by the reasonable accuracy.
following steps: After validating the model through effluent
1. The core sample was saturated with 30 pore acid concentration, predicted permeability
volumes (PV) of 3% ammonium chloride (NH4Cl) response was compared with the measured values.
brine, and initial permeability was measured. Apart from the consumption of HBF4 in the core,
2. Carbonate content from the core was the calibrated model also can reasonably predict
removed by injecting 30 PV of 10% hydrochloric the changes in permeability during HBF4 injection.
acid (HCl) solution. The model was validated with effluent HBF4
3. Byproducts of HCl treatment were flushed concentration after providing a shut-in time of 3.5
by injecting 10 PV of 3% NH4Cl brine. hours after HBF4 injection. Once calibrated, the
4. The desired volume of HBF4 solution was model can predict changes in important variables
injected into the core and an effluent acid sample with reasonable accuracy both during matrix
was taken at the core outlet. acidizing and subsequent soaking with HBF4.
5. Changes in differential pressure were
measured throughout. Sensitivity Analysis
6. Steps 1 through 5 were repeated for each Simulation of HBF4 treatment at wellbore scale
core sample and injection rate. was carried out per a methodology described in
the complete paper. The wellbore-scale model also
Measurement of Effluent can be used to simulate the mud acid treatment by
HBF4 Concentration changing the boundary conditions and modifying
Effluent HBF4 concentration was measured by the the value of the acid-capacity number.
following steps: The effect of injected volume on normalized
1. The system was calibrated with 20, 50, concentrations of HBF4 during the treatment
and 100 mg/L of tetrafluoroborate-ion standard with a formulation described in Table 7 of the
solutions. complete paper has been compared with the
2. The peak of the tetrafluoroborate-ion normalized concentration of HF during treatment
solution was identified at 16 minutes with the with mud acid containing 3.0% HF. The normalized
described system configuration. concentration has been defined as the ratio of
3. The effluent samples were diluted concentration of HBF4 or HF at a point in the
1,000–2,000 times to make the concentration reservoir to that being pumped from the surface.
in the calibrated range. The injection rate was taken to be 2.0 STB/min.
4. The concentration of tetrafluoroborate ions Results showed that, while the penetration
in the effluent samples was calculated from the of live HF in the case of mud acid treatment is
area under the peak at 16 minutes. limited to 1 ft for 50 gal/ft of acid injection, the

58 JPT | June 2023

 TECHNICAL PAPERS | Acidizing

penetration of live HBF4 at the same injected volume of HBF4 formulation at 90°C. The higher
volume is approximately 3.3 ft in the reservoir. penetration of HBF4 in the reservoir does not
Although penetration of HBF4 was much larger compensate for its effect of low dissolving
compared with mud acid for the same amount power on skin factor. Thus, for formations with
of injected fluid, the permeability improvement reservoir temperatures less than 90°C, mud-acid-
achieved from the former was less. The reason based formulations should be preferred if no
is that the HBF4 solution has a lower acid- negative effects of mud acid are observed from
capacity number or mineral-dissolution capability coreflooding experiments. However, application
compared with the mud acid solution. The benefit of large volumes of mud acid may result in
of larger penetration was not translated into a sand unconsolidation.
corresponding increase in permeability. The authors found that the stimulation effect
More insights can be gained by looking at the becomes comparable to that of mud acid at 120°C.
changes in skin factor arising during acidizing Thus, for wells with greater reservoir temperatures,
treatments with HBF4, mud acid, and mud acid HBF4 can be used as an alternative stimulation
followed by HBF4. Simulation for mud acid fluid to mud acid without need of well shut in. This
followed by HBF4 was performed by modifying would be beneficial, because matrix acidizing of
boundary conditions as well as acid-capacity high-temperature reservoirs with mud acid usually
numbers and carrying forward the solution of is challenging because of precipitation issues.
mud acid at last timestep as the initial condition
for HBF4 treatment. The injection rate was taken Conclusions
to be 2.0 STB/min, and the initial concentration of The mathematical model presented in the
HF in mud acid was taken to be 3.0%. The results complete paper provides the following conclusions:
provided important conclusions. • Neglecting the equilibrium reactions during
First, a major reduction in skin factor with HBF4 hydrolysis of HBF4 greatly overestimates the
treatment occurs during pumping. Shutting the rate of spending of HBF4 in the reservoir.
well post-HBF4 treatment for 10 hours provides • Reservoir temperature; mineralogy; and job-
a smaller reduction in skin factor. The reason execution details are major factors affecting
is that, during injection, reaction products are the matrix-acidizing process with HBF4.
pushed away and fresh HBF4 arrives in the pore • Apart from HBF4 treatment, the model can be
space by convection. Collectively, the convection extended easily to analyze mud acid and mud
provides a constant supply of active HF to the acid followed by HBF4 treatment.
minerals, which react and clear the pore space. • For design of mud acid jobs, it may be
After shut in, the convection stops and HBF4 convenient to carry out coreflooding with
consumed by the minerals is not replenished. HBF4 instead of mud acid.
Thus, mineral dissolution occurs from the HF • Major reduction in skin factor with HBF4
generated by remaining HBF4 in the pore space, treatment occurs during pumping.
which is in smaller amounts compared with the • For reservoir temperatures lower than 90°C,
total free HF received earlier through convection. effects of deeper penetration of HBF4 on skin
The conventional practice of providing long shut-in factor are overshadowed by its poor dissolving
times after HBF4 treatment may not be beneficial capacity compared with that of mud acid.
from a stimulation point of view. • For wells with reservoir temperatures greater
Second, 100 gal/ft of mud acid formulation than 120°C, the stimulation effects offered
gives a better reduction in skin factor or an by HBF4 become comparable to those of
increase in well productivity than the same mud acid. JPT

jpt.spe.org 59
 TECHNICAL PAPERS | Acidizing

Study Investigates Ineffectiveness

of Acid Fracturing for Tight Reservoir Rock

The complete paper describes the analysis of The reservoir is a depletion-drive type where the
actual performance data for acid fracturing in a main natural energy is provided by gas in solution.
tight carbonate formation and the ineffectiveness Among the initial wells, only six were successful.
of the process as measured by the performance The field is very complex, based on stratigraphic
responses of the producing wells. An included and structural characteristics. The first horizontal
case study relates to a tight formation that is well was drilled during 2015–16 and was subjected
considered a reservoir rather than a source to seven-stage acid fracturing. This resulted in a
rock. The formation permeability is in the range substantial increase of well cumulative production
of 0.1–5 md. Development has been through compared with that of vertical wells.
numerous horizontal wells with limited multistage The development plan of this field was
acid stimulation. Analysis of performance data implemented with horizontal wells with laterals
for more than 30 wells indicates no fracture flow extending approximately 3,000 ft. Each well
and very limited stimulated production. was subjected to multistage acid fracturing.
Examination of performance data indicated that
Background producing wells suffered from rapid pressure
A category of tight conventional reservoir rocks depletion after a production period of 3–6 months.
exists that has not been subjected to horizontal Wells cease natural flow and cannot sustain
drilling and multistage fracturing. The objective of production even after what is considered acid
the authors’ study is to analyze the ineffectiveness fracturing without the help of artificial lift.
of treatment response under acid fracturing and Conventional production plots show that typical
explore the potential of implementing multistage performance begins with a high initial rate for a
fracturing for a tight reservoir rock using short duration followed by a sharp decline before
experience gained from unconventional resources. a stabilization period. To improve and recommend
The subject reservoir is a tight carbonate of a proper hydraulic fracture design, the authors
the Middle Cretaceous age with porosity ranges studied the effectiveness of current stimulation
between 15 and 19% and an average thickness of to develop alternative improvement procedures.
approximately 90 ft. Oil viscosity ranges between
2.06 and 2.54 cp and average oil gravity is 25° API. Methodology
The effectiveness of acid stimulation was analyzed
and evaluated by using historical production for
This article, written by JPT Technology Editor Chris Carpenter,
contains highlights of paper SPE 209264, “Ineffectiveness of
Acid Fracturing for Stimulating a Tight Fractured Reservoir
For a limited time, the complete
Rock: A Case Study,” by Huda R. Al-Enezi, Kuwait Oil
paper is free to SPE members
Company, and Iraj Ershaghi, SPE, University of Southern
at jpt.spe.org.
California. The paper has not been peer reviewed.

60 JPT | June 2023

 TECHNICAL PAPERS | Acidizing

4 years. To study the initial rates seen on these a few wells followed this phenomenon, indicating
horizontal wells, a productivity-prediction tool was limited fracture-dominated flow. Otherwise, it is
used to inversely compute the effective formation- difficult to detect linear flow in the performance
permeability responsible or the observed initial analysis of most wells. A rapid increase in slope of
production on these wells. Production data greater than 1 also was observed, with no evidence
were used to inversely calculate the geometrical of crossflow, confirming matrix flow rather than
averaged permeability from initial field-production fracture-dominated flow. One main observation of
data assuming that the initial conditions followed the authors is that the majority of the wells exhibit
a steady-state regime. variations in initial rates followed by radial flow.
Approximately 80% of the wells exhibited
Analysis and Observation limited to no fracture flow. Diagnostic plots
Transient Flow Analysis. The plotting of inverse for most wells showed radial flow followed by
flow rate with time on a log-log scale was used slopes of greater than 1 at early stages, signifying
as a diagnostic tool to explain the productivity the boundary effect or loss of productivity that
of the wells. Only a few wells showed limited- influenced the performance response. Because
and short-duration fracture flow, but a limited formation permeability ranges between 0.01 and
matrix-stimulation effect otherwise seemed to 5 md, faster recharge to the system is possible,
be the prevalent effect. The graphical trends which helps to sustain the production for some
were compared with typical performance from time, in contrast with very low permeability in
unconventional plays, highlighting the potential of unconventional formations where the system is
enhancing the response from the reservoir. If the totally under the influence of induced fractures.
induced fractures were present, they contributed It is important to point out that the primary
at the start. Hundreds of smaller fractures may concerns are the significant volumes of acid fluid
behave like the response of a single fracture needed to establish the channels (wormholes) and
depicting linear flow. the fracture surface.
In the case of the reservoir under study, the The limited fracture flow shows only localized
response of Well 18 showed a behavior similar to limited enhancing of formation hydraulic
that of a limited choked fracture (slope = 0.25) at conductivity and matrix stimulation. With confining
the beginning followed by fracture flow (slope = stress of greater than 5,000 psi, it is possible that
0.5) for approximately 1.5 years and then led to induced fracture closure occurs faster, especially
a slope of greater than 1, indicating a decrease in with the small fracture geometry resulting from
fracture network conductivity, in turn reflecting a small fracture-pad-fluid and acid volumes. A
deterioration of productivity and the observation lack of crossflow also was noted, illustrating the
of boundary effects. Well 18 is considered the well absence of fracturing and the poor quality of
with the highest cumulative oil of approximately stimulated stages.
1 million STB in the field, reflecting the importance
of limited fracture-dominated flow. Another well Acid System
showed a similar behavior of limited fracture To identify minerals and components that cause
effect for a shorter time. The radial flow and dissolution during acid-stimulation procedures,
strong matrix recharge were followed by limited X-ray diffraction was performed as a part of the
fracture flow for several months with slope = 0.5 petrological analysis to determine the mineralogy
and boundary appearance indicating the behavior of the formation. Formation samples from six
of a large network of localized small fractures depths indicated a dominant mineralogy of
among the stimulated lateral. As presented, only carbonates. The major component in all the

jpt.spe.org 61
 TECHNICAL PAPERS | Acidizing

Permeability-Enhancement Analysis
Productivity and overall geometrical permeability
analysis showed that the estimated geometric
averaged permeability for these wells did not
demonstrate significant increase or enhancement.
In acid fracturing, increasing acid volumes
will increase productivity. A proper treatment
(a) (b) volume should be used for optimal productivity.
The authors write that, for this formation with a
Fig. 1—Conductive channel-formation core from a permeability of approximately 5 md, minimum
depth of 7,575 ft with 15% ZCA at 110°F before test (a) acid volumes should be higher than 1,000 gal/ft;
and after test (b).
this is not the case, however, because the acid
volume used is approximately 240 gal/ft in most
samples was calcite, with trace amounts of of the tested wells. The authors anticipate that,
dolomite or ankerite, quartz, and halite with with the higher effective permeability considering
very low porosity and permeability, identifying only the early stage and with a higher initial
it as an acidization candidate. Acid-etch tests rate, production can increase substantially.
were performed using different acid types This illustrates that, at the time of study, the
[15% zonal coverage acid (ZCA), 5% ZCA, 28% permeability was only being enhanced within
carbonate stimulation acid (CSA), and 15% CSA]. the same order of magnitude.
Good conductivity values were provided by 15% Conceptually, the authors calculated the
hydrochloric acid (HCl) concentration with low predicted flow rate assuming better permeability
crushing and branched conductive channels values. Results showed that, with a small increase
(Fig. 1). Based on performance studies, these in K values of approximately 10 md, the cumulative
laboratory studies did not represent large- barrels can be increased threefold by only
scale treatments. doubling the initial rate and considering the
Two strategies have been applied to set the same decline.
volume of the injected acid: by horizontal length
(250 gal/ft) and by vertical thickness (550 gal/ft). Conclusions
Most wells have 12 stages and almost the same This paper demonstrates the ineffectiveness of
acid volume and recipe. Acid volumes used were using limited-scale acid fracturing in horizontal
in a range from 45,000 to 65,000 gal per stage. wells when dealing with tight carbonate reservoir
rocks. The current acid-fracturing methodology has
Chemical-Reaction Analysis been ineffective in unlocking the full potential of
To estimate the area of influence of the acid, an this reservoir. While the formation can benefit from
analysis was performed to investigate chemical acid fracturing because of higher rock dissolution
reactions resulting from acid stimulation and and closure stress ranging between 4,600 and
dissolution of carbonate affected by 15% HCl. 5,200 psi, this field potentially can produce
The actual influence of the acid can be estimated substantially more with regular fracturing fluids
to be approximately 2 ft. followed by proppants. JPT

62 JPT | June 2023

 TECHNICAL PAPERS | Acidizing

Multistage Acid Stimulation Uses

Straddle Packer, Real-Time Telemetry

The authors describe in the complete paper how fluid diversion during stimulation. Once the
the combination of a straddle-packer system and methodology was confirmed, the next step was to
a downhole real-time telemetry system was used identify the optimal bottomhole assembly (BHA)
to acid-stimulate up to 38 stages successfully with a packer element that could be set and unset
and monitor the behavior of the straddle packer 38 times in a single coiled tubing (CT) run. The
continuously during diversion of multistage final step in the feasibility study was to obtain
acid treatment of screens while maintaining real-time bottomhole data to ensure adherence to
packer-seal integrity and downhole pressure. In operational parameters during the interventions.
addition, the study also provides lessons learned More specifically, a casing collar locator (CCL)
from implementation of multistage packers with reading for depth accuracy, CT downhole pressure
real-time telemetry for successful diversion of for ensuring the packer-set value, and downhole
acid treatment uniformly across screens in a annular pressure to check pressure differences
horizontal well. along the packer elements were needed. This
required fiber-optic (FO)-enabled CT to acquire
Introduction real-time communication with downhole tools.
Use of inflow control devices (ICDs) is a preferred
completion technique in producing multilayer Methodology
reservoirs from a single well while allowing the The challenges associated with treatment of ICD
optimal production profile along the completed screens using a straddle-packer system to divert
intervals by managing the drawdown from the the treatment mechanically include successfully
reservoir to the wellbore. This study focuses on locating the ICD and placing it across the straddle-
controlled acid treatment of a high number of packer system, monitoring the pressures inside
ICDs in a single well. and outside the CT to confirm the treatment
Two options existed for achieving optimal affecting the targeted ICD, and not involving an
acid placement in the subject well with 38 ICDs already-treated ICD. In addition, when treating
during treatment, chemical and mechanical more than 38 ICDs in a well, maintaining the
diversion. Mechanical diversion is the preferred integrity of the straddle-packer elements is
option because it ensures the most-accurate necessary to reduce treatment time per stage
and maximize the number of stages that can be
treated in a run.
This article, written by JPT Technology Editor Chris Carpenter,
contains highlights of paper SPE 204830, “Multistage Acid
Stimulation for ICD Screens Completion Using Straddle
For a limited time, the complete
Packer and Real-Time Telemetry Coiled Tubing,” by Qadir
paper is free to SPE members
Looni, SPE, Malik M. Humood, SPE, and Ahmed A. Mousa,
at jpt.spe.org.
Saudi Aramco, et al. The paper has not been peer reviewed.

jpt.spe.org 63
 TECHNICAL PAPERS | Acidizing

The primary challenge in CT operations is

monitoring and controlling the downhole condition
of the job while relying on surface gauges. Actual
tool depth is monitored by the length of CT
running in the hole. Different methods are used
to determine the actual depth; however, these
techniques can be time-consuming and expensive.
Use of electric-line CT introduces limitations such
as pumping rate and fluid compatibility because
of the wireline cable. New FO cable manufacturing
and use of strong alloy downhole tools helped
(a) (b) (c) (d) (e) (f) (g)
overcome previous limitations and introduced
new possibilities for CT operations.
Fig. 1—Drift and well cleanout BHA: (a) FO connector The discussed system was designed with four
head and release sub; (b) pressure/temperature and
CCL sub; (c) TC sub, providing axial load readings; fibers protected by Inconel fiber carrier. Two of the
(d) motor-head assembly; (e) straddle-packer upper fibers were used for real-time telemetry with the
element; (f) pumping sub; and (g) straddle-packer
downhole tools. The third FO cable was used for
lower element.
distributed temperature sensing, and the fourth
cable was used as the backup. A 2-in. tapered CT
Another challenging aspect of mechanically string was pickled to install the FO carrier. The FO
treating the ICD screen is the CT reach. A common cable was anchored by a pressure bulkhead (PBH)
practice to extend CT pipe reach is selection of a from the reel manifold end. The PBH received
larger-diameter pipe, but, considering the weight and sent data through the FO cable from and to
capabilities of the rig crane, increasing the pipe size the tools attached to the CT from the other end.
proved problematic. The PBH also sent and received data from the CT
To reach the well’s total depth (TD), a specially control cabin.
designed, tapered 2-in. CT pipe was prepared The other end of the FO cable, called the CT
for the operation. In tapered CT strings, several head, will be installed after the CT connector. It
sections of CT with different wall thicknesses are will secure, seal, and terminate the FO cable. The
welded together. This tapered design reduced the CT head is attached to a pressure/temperature
overall weight of the CT string and helped improve tool, where it converts optical to electrical charges
CT reach during treatment. A second technique for operating the remaining tools and allows the
used to reduce overall CT weight is the drop-in- downhole battery to give power to the downhole
drum (DID) technique. DID allows the pipe to be system. The system will provide real-time pressure,
transported separately from the crash frame; the temperature, and CCL data. Tension compression
driving system is combined on location. Thus, the (TC) provides continuous treatment monitoring
size and length of the pipe that can be lifted by the while enabling operational decision-making.
offshore rig crane is maximized. The straddle packer was attached below the
real-time tools. The packer was set by pumping
BHA at minimum critical flow rate and unset by
This section of the complete paper details the BHA decreasing the rate below the critical flow rate.
used in both the CT well-conditioning run and the During the well-conditioning run, the straddle
main treatment run using the straddle packer packer was deployed without plugging the ball-
(Fig. 1). valve sub. Throughout the run, real-time pressure,

64 JPT | June 2023

 TECHNICAL PAPERS | Acidizing

temperature, and CCL parameters were acquired below the highest point reached. The observed
to confirm the position of the tool in real time. The pattern showed clearing of obstacles in the flow
TC sub reading was used in real time to identify any path of the ICD by the treatment fluid before
compression or tension affecting the tool. reaching the formation. Steady parameter reading
On the main treatment run, the straddle packer throughout the treatment confirmed the isolation
was deployed while the ball-valve sub was plugged and successful placement of treatment fluid at the
along with the real-time downhole monitoring tools targeted ICD.
to well TD. During running in hole (RIH), the TC At the end of the treatment, the TC real-time
real-time reading was monitored to highlight any reading was monitored to ensure the de-energizing
unexpected tensile or compression forces exerted of the element and that the weight was returned
on the tool. The CCL signal was monitored during to normal. Once the weight dropped, the straddle
RIH to provide a positive confirmation of the tool packer could be moved to the next stage, reducing
depth. Several measurements were taken during the waiting time between stages without exerting
RIH to correlate the depth of the CT BHA. Once the unnecessary force on the element that could
CT was at TD, the CCL was used to correlate the damage the seal and possibly reduce the maximum
depth and assure the placement of the targeted number of stages achieved in each run.
ICD port between the upper and lower elements By monitoring the downhole-pressure
of the straddle packer. response in real time, a decision can be taken on
Once the straddle packer was in place, the the spot to adjust the volume or the pumping time
elements were energized by pumping through the on each ICD screen to ensure the effective and
CT pipe. The CT downhole pumping pressure and uniform treatment of all ICDs.
the annular pumping pressure above the element
were used to provide positive confirmation that Conclusions
the packer elements were sealing and that the The use of FO, downhole telemetry-enabled CT
treatment fluid was diverted to the ICD port. As technology, from planning through execution,
soon as the element began sealing against the enabled the treatment of the all ICDs in the well
completion, the pressure increased, indicating safely and efficiently.
that the packer was fully energized. The combination of the straddle-packer system
By comparing the CT downhole pressure and along with real-time FO downhole telemetry
the downhole annular pressure, an increase in enabled the optimization of treatment time,
the CT pressure was observed while the reading eliminating any inaccuracy in the setting depth
remained steady in the CT-tubing annular above of the packer and unnecessary time waiting on
the upper element. This difference in pressure the packer to unset. Continuous monitoring of
indicated no communication between the downhole CT pressure and downhole annular
straddled section and the wellbore above the pressure provided confirmation of successful
packer, confirming the diversion of fluid into the mechanical diversion throughout the operation.
targeted ICD. Use of a downhole real-time TC sub proved
The pressure reading at the initial stage of the essential to success by preventing any unexpected
treatment showed a slight increase followed by a force caused by mature pipe movement before the
drop in pressure before it rose again to a pressure complete unsetting of the tool. JPT

jpt.spe.org 65
 TECHNOLOGY FOCUS

Hydraulic Fracturing Operations

Shahvir Pooniwala, SPE, Subject-Matter Expert, Saudi Aramco

W
ith the global normalization of fracturing equipment manufacturing, including
economies over the past 2 years electric, hybrid, and turbine-driven fracturing
after the pandemic, the demand for equipment spreads. We have also seen the
energy has only been increasing, application of automation and emissions
and all forecasts show this demand will continue to monitoring being widely adopted throughout
grow. In light of the current geopolitical situation the industry in an effort to lower the operational
globally, balancing the energy trilemma (ensuring carbon footprint.
energy security, energy equity, and environmental Fracture monitoring to optimize fluid
sustainability) is a key global challenge. volumes and designs remains a critical area of
With the ever-increasing energy demand, oil development. Research is ongoing with the focus
and gas remains a major component within the on combining different monitoring technologies
energy mix to address this challenge and to aid in including tracers, fiber optics, downhole cameras,
satisfying the growing demand. Hydraulic fracturing and microseismic monitoring. There also have
continues to be the main technology differentiator been innovations in using surface data to develop
that enables enhancing recovery from both green- cost-effective solutions to monitor fracture-
and brownfield reservoirs globally. geometry propagation. Nanotracers and low-cost
During the past few years, the industry has disposable fiber-optic cables have been areas
made great strides in reducing carbon emissions that have seen increasing deployments within
through the deployment of new technologies in the monitoring realm.

SHAHVIR POONIWALA, SPE, is a subject-matter expert for production

enhancement in the Gas Reservoir Management Department of
Saudi Aramco. In this role, he is responsible for hydraulic fracturing,
well completions, and implementation of new technologies, along
with training and developing young engineers. Pooniwala has close
to 15 years of industry experience. Before joining Saudi Aramco, he
worked with Baker Hughes globally in various regional roles such as
Middle East technical, sales, and commercial manager and Production
Enhancement Business Unit manager. Pooniwala has authored
Shahvir Pooniwala
Subject-Matter Expert
numerous SPE papers and has been on several SPE conference
Saudi Aramco committees and chaired several sessions. He is a member of the JPT
Editorial Review Board.

66 JPT | June 2023

 TECHNOLOGY FOCUS

Cluster efficiency and stage spacing is being

Recommended additional reading at OnePetro:
optimized in basins globally by studying perforation
www.onepetro.org.
erosion, fracture propagation, and performance
between various perforation strategies using
different gun configurations in both single clusters SPE 212342
and multiple clusters including extreme-limited- Overflush and Fracturing: Playing Poker With
entry applications. We have seen improvements Your Completion
in the pressure ratings of dissolvable and flow- by Martin Rylance, THREE60 Energy
through plugs with the aim of aiding in improving
turnaround efficiency in plug-and-perf wells. SPE 212749
Multistage hardware has seen enhancements Natural-Gas-Powered Direct-Drive Turbine
with new completion technologies such as Hydraulic Fracturing Technology Delivers
cemented ball-drop multistage fracturing systems High‑Power Density and Energy Transfer
and multistage openhole systems with sand- Efficiency for Environmental, Economic,
screens that require minimum intervention being and Operational Benefits
developed and deployed. by Guillermo Rodriguez, BJ Energy Solutions, et al.
Globally, we have observed increasing
application of lessons learned to revamp older SPE 212322
technologies and fracturing concepts such as the Combined Video and Ultrasonic Measurements
use of crosslinked gels, energized fluid systems, for Fracture Diagnostics—Greater Than the Sum
and tip screenout designs. of the Parts
In addition to conventional reservoirs, we also by Tobben Tymons, EV, et al.
are seeing a growing application of stimulation
and fracturing technologies being considered and SPE 209159
deployed for geothermal applications. Lessons Learned From the Large-Scale CO2
The recent technological developments and Stimulation of 11 Unconventional Wells in
deployments cement the fact that hydraulic the Williston Basin: A Practical Review of
fracturing will remain an important pillar to solving Operations, Logistics, Production Uplift,
the world’s energy requirements in the years and CO2 Storage
to come. JPT by Lionel Ribeiro, Equinor, et al.

jpt.spe.org 67
 TECHNICAL PAPERS | Hydraulic Fracturing Operations

Hydraulic Fracturing Unlocks

Potential of Europe’s Largest Reservoir

Greater Clair, Europe’s largest oil field, has distribution. Three main scales of fracture features
two existing platforms, Clair Phase 1 and Clair are observed in the core: fault-related, fracture
Ridge, on production with the potential for a corridors unrelated to large offsets, and lower-
third platform targeting the undeveloped Lower density joint-type networks. Open fracture density
Clair Group (LCG) to the South of Phase 1. In varies considerably by stratigraphy, with the
some areas, however, low matrix quality and highest densities in Units V and VI.
lack of natural fractures were the dominant
characteristics, resulting in lower production Field Development Phases. Exploration
rates. The authors write that fracturing technology Well 206/08-1A discovered Clair in 1977. Clair
brings opportunities to unlock poorer Phase 1 and underwent a protracted appraisal program before
Ridge reservoir areas. sanction of the Phase 1 development in 2001.
The commercial viability of the reservoir was not
Introduction confirmed until an extended well test in 1996
Reservoir Description. The Clair field is 75 km proved that oil rates from 15,000 to 20,000 BOPD
west of the Shetland Islands on the UK Continental could be sustained from long horizontal wells
Shelf within the extensional Faroe-Shetland Basin. targeting high-productivity fracture zones.
The Old Red Sandstone reservoir is divided into The scale and complexity of the reservoir drove
two lithostratigraphic units, the Upper and LCG. a phased multiplatform development. Phase 1
The LCG contains the bulk of the oil in place and began production with 20 producer and injector
underpins the Clair development. The reservoir wells coming online between 2005 and 2011.
is characterized by large variations in facies and Five additional wells drilled during 2016–2017
permeabilities. increased platform production by 70%. The
The LCG is subdivided into six units, I through second platform, Clair Ridge, came online in 2018,
VI, based on variations in sedimentary facies and the development wells drilled to date have
and heavy mineral assemblages. Development encountered varying degrees of natural fractures.
drilling preferentially targets the highest quality
reservoirs in Units V and III. The LCG is defined as Design and Characteristics
a dual-permeability system with a variable fracture of Well A23 for Hydraulic Fracturing
Candidate Well for Propped Fracturing.
Horizontal Well A23 was completed in March
This article, written by JPT Technology Editor Chris Carpenter,
contains highlights of paper SPE 205250, “Hydraulic
Fracturing at Clair: Unlocking the Potential of Europe’s
For a limited time, the complete
Largest Reservoir,” by Alistair M. Roy, SPE, Graeme H.
paper is free to SPE members
Allan, SPE, and Corrado Giuliani, SPE, BP, et al. The paper
at jpt.spe.org.
has not been peer reviewed.

68 JPT | June 2023

 TECHNICAL PAPERS | Hydraulic Fracturing Operations

2017. The lateral penetrated the low-permeability transverse fractures. A half-million lbm of proppant
unfractured Unit VI of the LCG in the Graben area per stage was selected as optimal to ensure
of Phase 1. It crosses the core/graben fault, which the standoff from the OWC while maximizing
is assumed to act as a baffle to communication well production.
between Zones 1 and 2 and Zones 3 and 4.
Well A23 was put on gas lift production in 2017, Fluid Design. A 35-lbm/1,000-gal guar polymer
producing approximately 1,300 BOPD. fluid with 2% potassium chloride base brine was
The well trajectory was designed to remain formulated to develop sufficient viscosity at a
40 m above the shale layer and to facilitate roughly bottomhole static temperature of 158°F using
transverse fractures within Unit VI Upper by drilling North Sea-approved additives. The low reservoir
perpendicularly to the maximum horizontal stress temperature required developing an atypical system
to overcome vertical drainage issues. for North Sea fields using a borate crosslinker
For this highly laminated reservoir, vertical while adjusting the pH with a short delay time of
propped fractures covering the entire Unit VI Upper approximately 30 seconds to minimize friction-
were recommended to improve vertical drainage pressure losses in surface lines and equipment.
without breaching the prognosed oil/water contact
(OWC) at 2,122 m vertical depth below mean sea Proppant Selection. Based on an estimated
level (TVDSS). closure pressure of 4,000 psi, a lightweight
The complete paper details completion design proppant with two mesh sizes was selected: the
(the difficulties encountered with the initial design finer 20/40 mesh to fill two-thirds of the fracture
and the decision to abandon the sleeve function while decreasing the risk of proppant bridging
for all zones and move to a plug-and-perf strategy at perforation, and 16/30 mesh on the final two
using tubing punches and composite bridge plugs stages to increase the fracture conductivity near
for all four propped fracture stages) and well- the wellbore.
intervention history. To minimize proppant flowback during
production, resin-coated proppant (RCP)
Preliminary Fracture Treatment Design was selected, using a dual-coat technology.
Pumping Schedule. The fracture simulation model With reservoir temperatures of 158°F, a low-
was based on the mechanical properties of LCG Unit temperature resin (LT RCP) was required.
VI Upper and Lower. The well trajectory intersects Production samples of LT RCP showed a
Unit VI with a minimum of 78 m standoff from the propensity for consolidation even when no stress
OWC prognosed at 2,122 m TVDSS in Unit VI Lower. was applied to the proppant sample. Therefore,
The fractures were designed to stay above the OWC it was decided to pump the 20/40 mesh RCP
to avoid water breakthrough. with the normal resin coat and a mix of normal
The prognosed OWC proximity became a key resin coat and low-temperature resin coat for the
design parameter. With limited Clair experience 16/30 mesh tail-in.
available, a 35% dirty fracture initiation and
propagation stage (PAD) percentage was assumed, Propped Fracture Treatment
with proppant stages initiating at a proppant Execution and Analysis
concentration of 0.5 lbm of proppant added Propped Fracturing Treatment for Stage 2.
(PPA) using the smallest 20/40 mesh proppant. Stage 2 was used as an example case to
A final 10-PPA concentration stage with 16/30 provide details of the methodology used for
mesh-size proppant was included to ensure the minifracturing analysis and the redesign of
good wellbore connectivity with the planned the main fracturing treatment.

jpt.spe.org 69
 TECHNICAL PAPERS | Hydraulic Fracturing Operations

Minifracturing Execution. The minifracturing and field experience was accumulated. Potential
treatment commenced with a hole fill by pumping exists to reduce the PAD stage to less than 20,000
linear gel into the well before any wellhead gal without significant risk of screenout.
pressure was observed. The annulus pressure
was increased to 1,000 psi before the breakdown Flowback and Production Results
treatment commenced. Formation breakdown After intervention was complete, Well A23 was
was observed at 6,782 psi. Thereafter, the planned put on gas-lifted production and flowed through
fracturing rate of 35 bbl/min was achieved. The a cleanup package. Minor issues with low
pumping rate was decreased in cyclical steps from temperatures and viscous crudes were observed
treatment rate to a minimum of 5 bbl/min. Finally, clogging the filters but, most importantly, fluid-
a hard shutdown was performed to conclude the compatibility testing was successful in eliminating
cyclic step-down test. plant-stability issues. During the flow period,
The calibration test was pumped, including approximately 1 ton of proppant was recovered
0.5-, 1.0-, and 1.5-PPA stages of 100 mesh sand while the well was beaned up to the maximum
slugs. Once the crosslinked fracturing fluid was at potential flow rate. Proppant returns quickly
the perforation, pumps were shut down. Then, the stopped, however, and the well has been proppant-
calibration injection test with crosslinked fluid was free for over 1 year. This is an important lesson for
pumped before a flush with linear gel. Clair regarding the use of RCP and should allow
The results of the minifracturing treatment for elimination of downhole proppant screens from
Stage 2 are detailed in the complete paper. future well completions.
Propped Fracturing Treatment Execution. The
execution of the Stage 2 main fracturing treatment Conclusions
on Well A23 commenced in June 2019. The rate was The Well A23 hydraulic fracturing results
brought up to 35 bbl/min to initiate the treatment, demonstrate that hydraulic fracturing, in
and treating pressure increased when the gel conjunction with horizontal wells, can be used in
reached the perforations. Following completion areas of low fracture density to provide vertical
of the PAD stage, the proppant concentration was connection over thicknesses greater than 300 ft.
incrementally increased from 0.5 to 10 PPA per Much larger and more-productive fractures
the design. The rate remained at 35 bbl/min until have been placed in Well A23 than were originally
it was decreased systematically during the flush proposed by focusing on solving the logistical
to carefully underdisplace the well by 5.1 bbl. This problems of working in a relatively remote area
resulted in 491,138 lbm of sand and proppant being instead of downgrading the fracture design to fit
pumped, with 487,541 lbm retained in the fracture. within conventional ideas of logistics.
Main Fracturing Treatment Execution. The A conservative fracture design was adopted for
performance of the 35-lbm/1,000-gal fracturing this first multistage fracture treatment in Clair, but
fluid onsite was as anticipated for all stages and post-job analysis clearly indicates that productivity
allowed successful placement of approximately enhancement can be achieved by reducing PAD
500,000 lbm of proppant per stage. Pressures and volume; increasing the proportion of 16/30 mesh
rates were as expected, and, despite appreciable proppant; or using larger proppant to tail in to
entry friction, sand and proppant slugs were enhance near-wellbore connectivity in the high-
used successfully to ensure no screenout took flux region of the fracture. Adopting channel-type
place. PAD volume was reduced from 60,000 fracturing and adding two or more fracturing
to 40,000 gal in Stages 3 and 4 as a minor net stages has been modeled and shows significantly
pressure increase was observed in Stages 1 and 2 improved production results and reduced costs. JPT

70 JPT | June 2023

 TECHNICAL PAPERS | Hydraulic Fracturing Operations

Advanced Diagnostics Aid Understanding

at Hydraulic Fracturing Test Site 2

The Hydraulic Fracturing Test Site 2 (HFTS-2) is was integrated and used to calibrate subsurface
a large collaborative field-based research and models and characterize fracture geometry and
development program in the Permian Delaware proppant distribution. Diagnostics and modeling
Basin funded by the US Department of Energy efforts enabled comprehensive calculations of
through the National Energy Technology hydraulic fracturing’s vertical and lateral extent and
Laboratory and the exploration and production production-depletion profiles and quantification
industry with support from academia. The project’s of fracture growth bias for child-well stages that
main objective is to improve the understanding overlapped parent wells.
of the hydraulic fracturing process through use of Results from the project culminated in
advanced diagnostics and collection of through- the development of a series of optimization
fracture cores to provide undisputable evidence procedures for increased drilling and completion
and attributes of created fractures. efficiency, reducing environmental footprint by
producing the reservoir from fewer well pads and
Project Background fracturing stages.
The HFTS-2 project provides the opportunity to
address the optimal development of a stacked Test Site
pay resource that requires simultaneous drilling The research well package consists of eight new
and completion of tens of thousands of wells producing wells, two existing parent wells, and
across multiple geologic horizons, also known as two new dedicated science and observation wells
cube development. drilled for this project. The new producing wells
The project consists of a series of coupled are landed in various Wolfcamp horizons and have
analytic and field experiments in which research- lateral lengths of approximately 7,500 ft. The lateral
quality data are acquired in dedicated research sections of the wells are spaced approximately 660
wells through full instrumentation at, and in ft apart. The two existing parent wells also are in
proximity to, hydraulically fractured wells. the Wolfcamp formation and have lateral lengths
Furthermore, the unique site design provides an of approximately 5,000 ft. The two new science
opportunity to understand the effect of reservoir wells were drilled from the same pad, positioned
depletion because many child-well stages overlap between laterals B3H and B4H. One science well is a
parent-well areas. The extensive data set acquired vertical pilot hole used to characterize the reservoir
through the collection of mud and drill-cutting

This article, written by JPT Technology Editor Chris Carpenter,

contains highlights of paper URTeC 2021-5514, “Overview
For a limited time, the complete
of Hydraulic Fracturing Test Site 2 in the Permian Delaware
paper is free to SPE members
Basin (HFTS-2),” by Jordan Ciezobka, SPE, GTI. The paper
at jpt.spe.org.
has not been peer reviewed.

jpt.spe.org 71
 TECHNICAL PAPERS | Hydraulic Fracturing Operations

samples, electric logs, and whole and sidewall the fracture plugs were drilled out, tubing was
cores. The well also was used to house diagnostic installed with BHP gauges, and all wells were put
instrumentation. The second science well is a slant on production. After a few months of production,
well drilled after all wells were stimulated and was the slant core well was drilled between the B3H
used to collect whole cores through the created and B4H wells and approximately 950 ft of core
fractures. The slant core well was instrumented was collected with the intention of capturing
with pressure and temperature gauges to monitor fractures from Well B3H. After the well was
reservoir depletion during production. drilled, 12 pressure gauges were installed. Project
The eight-horizontal-well package consisted of management, participation, and structure are
five new uncompleted horizontal test wells (T13H, detailed in the complete paper.
T14H, T15H, T16H, and B4H) drilled before project
commencement and three new horizontal test B5PH Pilot Hole
wells drilled beginning in the fourth quarter of The vertical pilot hole in Well B5PH was drilled to
2018 (B3H, B2H, and B4H) once the project began. the Wolfcamp B formation. Vertical core sections
Because the three new wells were drilled after the were taken from the Third Bone Springs formation
HFTS-2 project started, modification of the data- through the Wolfcamp B. Once the coring
acquisition program for these wells was possible, operations were completed, a variety of openhole
and thus openhole logs were acquired in each well, logs were run in the well. External fiber-optic cable
including quad combo and image logs. Permanent and eight pressure gauges were installed and
fiber-optic cables were installed in two of the three cemented in place.
horizontal wells. In Wells B3H and B4H, fiber-optic A formation-evaluation subcommittee
pressure gauges were included in the toe and heel developed an extensive core-testing, sampling,
section of the wells. All producing horizontal test and analysis program on the recovered whole core
wells, including the two parent wells, are landed in and sidewall rotary cores that took almost 2 years
the various horizons of the Wolfcamp formation. All to complete.
horizontal test wells are on production at the time
of writing and have been equipped with artificial lift Fiber-Optic Monitoring of Completions
(gas lift) and bottomhole-pressure (BHP) gauges. To assess perforation cluster performance of
Following the drilling and casing of all test various fracture designs, fiber-optic distributed
wells, a gyro survey was run in Wells B3H and B4H acoustic sensing (DAS) and distributed temperature
to reduce the chance of collision when drilling sensing (DTS) measurements were used. Good fluid
the slant core well, B6S. A cable-mapping log also coverage existed across most of the perforation
was run in the B3H and the B4H wells to locate clusters, with a couple of perforation clusters
the position of the fiber-optic cable on the outside becoming inactive for short periods of time
of the casing to allow orientation of perforating during fracturing.
away from the cable. To the authors’ knowledge, Fiber-optic-deployment geometry also
this is the first project that uses three wells fitted provided the ability to measure both vertical and
with fiber-optic cables, including a vertical and horizontal cross-well strain from propagating
horizontal well, to collect fiber-optic data. Next, a fractures emanating from adjacent wells while
diagnostic fracture-injection test was pumped in being fracture-stimulated. The cross-well strain
Wells B2H, T13H, T14H, and T15H. The wells then was recorded in Wells B3H, B4H, and B5PH wells
were fracture-stimulated, and fracture treatments during fracturing of Wells T16H, B1H, B2H, B3H,
were monitored using conventional microseismic and B4H. When a horizontal well instrumented with
tools and fiber-optic diagnostics. Post-fracturing, fiber optic cable was being fracture-stimulated,

72 JPT | June 2023

 TECHNICAL PAPERS | Hydraulic Fracturing Operations

that well could not be used for cross-well-strain

measurements and the strain data was recorded
on the other two wells with fiber-optic cables.
The completions from five treatment wells
(Wells T16H, B1H, B4H, B3H, and B2H) were
monitored using fiber-optic DAS microseismic
in three fiber-optic-instrumented wells. To the
Fig. 1—Layout of wells used in the PIT.
authors’ knowledge, this represents the first fiber-
optic DAS microseismic data collected in multiple
wells with fiber-optic cables, including a vertical in Q1 2020 using DAS and DTS data from multiple
and horizontal well. interrogator boxes connected to the multistrand
fiber-optic cable in Well B4H.
Slant Core Well The fiber-optic-based PIT was designed
To sample the created fractures and to monitor to identify connection points from the parent
reservoir depletion, a slant core well (Well B6S) was Bitterroot 1H well and the Boxwood 1H, 2H, and
drilled adjacent to the Well B3S horizontal producer 3H wells to the Boxwood 4H well. Fig. 1 shows
and was drilled from the same surface pad as the the general position of the wells used in the PIT
vertical pilot hole, the Boxwood 5PH well. relative to one another. The fiber-optic production
Well B6S was drilled though the created log test was designed to identify production
fracture network and was used to sample the results on a per-cluster basis with statistical
fractures by collecting a series of whole cores. nonuniqueness considered.
Ultimately, a total of 946 ft of core was recovered,
spanning approximately 167 vertical ft of Strain-Depletion-Profile Tests With
the reservoir. Distributed-Strain-Sensing Rayleigh-
A total of 1,261 fractures, including 500 Frequency Shift (DSS-RFS)
hydraulic fractures, was observed in the nine core During the first PIT, a new fiber-optic interrogator
sections. Hydraulic fractures are clustered, with box was used to collect distributed strain data
groups of up to five fractures spaced just a few based on the principle of Rayleigh light scattering
centimeters apart. and Rayleigh frequency shift during fiber
Once coring was complete, openhole shuttle deformation in Well B4H. The resulting data set
logs were run to measure rock properties, showed a notable strain response at the location
including a quad combo with dipole sonic and an of most perforation clusters. When this was
image log. These logs were then used to determine compared with the DAS hydraulic-fracture-profiling
locations for the swell-packer placement. The swell data set acquired during stimulation, a strong
packers were used to provide pressure-isolation correlation was observed. To validate these results,
redundancy to ensure pressure isolation once a second, more-focused PIT test was performed
pressure gauges were installed. Twelve pressure and additional DSS-RFS data were collected in all
gauges were installed in the slant core well. fiber wells. The second test confirmed the results
of the first test. These results showed that DSS-RFS
Production-Interference Test strain measurements are repeatable and can be
(PIT) and Production Log used to infer near-wellbore fracture geometry at a
Using the optical fiber and the fiber-optic toe perforation-cluster level. The results also showed
pressure gauge in the Boxwood 4H well, an fiber- that DSS-RFS strain measurement may be a proxy
optic-based PIT and production log was acquired for measuring pressure itself. JPT

jpt.spe.org 73
 TECHNICAL PAPERS | Hydraulic Fracturing Operations

Integrated Optimization System

Improves Hydraulic Fracturing Operations

In the complete paper, the authors demonstrate demonstrate the need for including effectiveness
the need to balance optimizing fracture efficiency considerations in any real-time fracture-
with effectiveness; present an integrated optimization algorithm.
system for fracturing optimization using real- The Completions Automation and Remote
time, historical data along with organizational Technology (CART) Center was set up in 2017 by
knowledge; and discuss the challenges and key the operator to monitor and optimize all shale-
considerations of setting up such a system, along fracturing operations remotely across multiple
with examples of large, untapped potential that basins. The Center is staffed by consultants
can be unlocked with data science. whose main role is to provide input directly to
the engineer on site to optimize each treatment.
Introduction Currently, this remote model relies on the
Currently, most third-party fracture-monitoring experience of the consultant to know when and
solutions do not provide a true fracture- where to provide the right input.
optimization platform that goes beyond fracture
monitoring and efficiency or cost analytics. Without Data Preprocessing
consideration for creating effective fracture Modularity is a key component of the authors’
geometries and good stimulation distribution, framework. The first step is to process new data,
this may lead to poor resource recovery. calculating important statistics used in historical
Integrated fiber-optic diagnostics data have analysis. Calculations to generate statistics
also shown that perforation-cluster screenout used within the models also are performed.
signatures sometimes can be observed in the Models can be applied sequentially within this
surface-treatment data. Historical analysis framework, posing no problems with regard to
of surface-treatment data has revealed that interdependency.
perforation-cluster screenout signatures are As data are fed into the framework, automated
widely observed in other basins (Fig. 1). Cluster analyses are performed to detect the start and
screenouts lead to severe nonuniformity in end of a stage in real time. Instead of opting for
stimulation distribution. These examples a complex deep-learning algorithm, the authors
implemented a simpler rule-based model to
improve operational efficiency of the tool. At each
This article, written by JPT Technology Editor Chris Carpenter, new time stamp, the injection rate and pressure
contains highlights of paper SPE 209127, “Efficiency and
Effectiveness—A Fine Balance: An Integrated System To
Improve Decisions in Real-Time Hydraulic Fracturing
For a limited time, the complete
Operations,” by Somnath Mondal, SPE, Ashan Garusinghe,
paper is free to SPE members
and Sebastian Ziman, Shell, et al. The paper has not been
at jpt.spe.org.
peer reviewed.

74 JPT | June 2023

 TECHNICAL PAPERS | Hydraulic Fracturing Operations

Cluster
Cluster
Screenout
Pressure Screenout

Chemical Concentration

Rate

Sand Concentration

Fig. 1—Example of cluster-screenout signature from surface-treatment data in a well. Integrated fiber-optic diagnostic
data from several basins have confirmed that such patterns are associated with perforation-cluster screenout.

are evaluated to determine if fracturing operations when the pressure begins to decrease while the
have commenced; should the flow rate fall back to injection rate remains constant or is increasing
near zero, the framework will reset itself if this was and then concludes the breakdown when the
simply a testing period of the stage or counts the pressure levels off. A post-processing step checks
stage as ended if the total sand pumped is more the breakdown to determine whether it was a
than the minimum required for the stage. true breakdown.

Easy or Hard Stage Optimization

A fracturing stage can be classified as “easy” or The authors present a full optimization routine
“hard” depending on how easily injectivity can be to minimize the cost structure. All optimizations
achieved and maintained. Engineers try to classify must be implemented manually, thus restricting
a stage as early as possible to decide how readily the routine to reasonable recommendations.
a stage will accept sand. The complete paper This effectively reduces the problem to a discrete
presents a work flow to assist engineers in the optimization problem. The authors instead
early classification of these stages. approach the problem by attempting to identify
potential optimization opportunities and then valid
Breakdown Detection optimizations at these times of opportunity. The
Breakdown identification is a key task for the potential operating states are constrained by a
onsite fracturing engineer and the CART Center set of hierarchical rules defined by subject-matter
as they try to spot signs of the subsurface rock experts, learnings from integrated diagnostics
fracturing and respond quickly. The authors pilots, and basin-specific engineer knowledge.
developed a method for identifying potential
breakdowns while they occur based on a physics- Pressure Prediction. To estimate the cost
based algorithm in collaboration with fracturing effect and understand the viability of potential
experts and completions engineers. The algorithm optimizations, the pressure response must be
indicates that a breakdown might be starting understood. The authors investigated two main

jpt.spe.org 75
 TECHNICAL PAPERS | Hydraulic Fracturing Operations

methods for pressure prediction, one using Model Implementation

a dynamic linear model and another using a A recommendation card is constructed that
supervised learning model. These models are includes the suggested change and contextual
detailed in the complete paper. information to assist the engineer, such as average
pressure, predicted pressure, and estimated
Optimization Routine. Opportunities for savings should the recommendation be adopted.
optimization must be identified. This is achieved The authors write that, for any optimization
by looking for points where sufficient pressure to be performed, the well must be in its plateau
headroom is available and pressure trends are phase. This maximizes the likelihood that the
favorable and sufficiently stable to be modeled. pressure is stable and can be adequately modeled
At a given timestep, all potential states are to make a prediction. The implementation currently
identified based on operating constraints using limits recommendations to either a sand or an
an exhaustive search method. The state space is injection rate change, but not both.
discretized, and the minimum change in a variable
that is reasonably achievable within mechanical Data-Engineering Model
limitations and the maximum implementable Wellsite-information transfer specification (WITS)
change is identified. These are used to discretize is a communications format used to transfer a
the state space into values within the maximum wide variety of wellsite data. The high-level model
change that differ by the minimum change. is implemented in the following process: from
For implementation, the authors only consider WITS data stream to model application to end user
optimizations of the injection rate and sand interface plus alert notifications.
concentration; however, this is readily extendable
to any set of independent variables. The pressure Conclusions
response is predicted for all these states. The authors demonstrate a platform to host and
Then, prior knowledge of the required total execute an ensemble of models and visualizations
sand and fluid for the stage is exploited to estimate that communicate actionable insights to an
the time to completion; the stage is then simulated operator within seconds of identifying an event.
under the assumption that the control variables do Specifically, the following conclusions are reached:
not change further for the duration of the stage. • An approach to real-time optimization is
The authors write that further work could presented using a combination of data-science
be done to improve this assumption of constant models constrained by physics-based rules,
behavior until the end of the stage. basin-specific organizational knowledge, and
learnings from integrated diagnostics trials of
Advanced Visualizations effective fracturing practices.
The authors also describe providing support for a • The authors acknowledge that fracture
series of advanced visualizations to give historical effectiveness has not been demonstrated in
context to current stage performance. This allows production, nor have they seen evidence the
engineers to compare performance across similar approach leads to fewer cluster screenouts.
wells and incorporate historical context into • Novel models and visualizations are presented
decision-making by automatically assigning each that can be constructed readily using only real-
upcoming stage with a list of similar historical time streaming data.
stages, called the historical subset. There, a series • A real-time streaming pipeline can be
of plots can be displayed to follow performance in implemented on a third-party source that
comparison with the selected historical stages. does not provide streaming endpoints. JPT

76 JPT | June 2023

 TECHNOLOGY FOCUS

EOR Operations
Soujatya Mukherjee, SPE, Senior Reservoir Engineer, Wintershall DEA

W
hile supply disruptions and price negating any chances of recovery, at least in the
volatility are not new to the oil short term.
and gas industry, the dramatic Concurrently, the rise in energy consumption
drop in oil prices because of the and increasing demand for energy security
COVID-19 pandemic severely affected global worldwide warrants the need to increase global
enhanced oil recovery (EOR) projects. To add hydrocarbon production. However, rising
fuel to the fire, the current geopolitical scenario environmental concerns with regard to greenhouse
leading to a surge in commodity prices and supply gas emissions, coupled with a decrease in the
chain disruptions exacerbated this situation by availability of easy-to-produce hydrocarbon

SOUJATYA MUKHERJEE, SPE, is a project manager and senior reservoir

engineer with Wintershall Dea. He has more than 15 years of
experience working on various EOR and enhanced gas recovery
projects in both conventional and unconventional oil and gas assets.
During his tenure, Mukherjee has worked in the areas of enhanced/
improved oil recovery, gas condensates, production optimization,
emulsions and phase behavior, petrophysics and fluid properties,
reservoir diagnostics, numerical simulations, well interventions, and
monitoring. He was a technical liaison and lead for joint-industry
Soujatya Mukherjee
projects on chemical EOR for heavy oils, microbial EOR, and low-
Senior Reservoir Engineer salinity waterflooding. In his current role as a project manager in
Wintershall DEA
the Digitalization and Technology team, Mukherjee is responsible
for deployment of technologies for risk mitigation of condensate
blockage and enhancing the gas and condensate production from gas
assets. He has authored more than 25 publications in various peer-
reviewed journals and conferences and has authored a chapter in
the book Recovery Improvement—Oil and Gas Chemistry Management
Series, Vol. III. Mukherjee has served as a member of several SPE
committees, including the 2022 OPES Technical Program Committee
and the 2021 steering committee for the SPE Workshop on EOR for
More Sustainable Future. He is a member of the JPT Editorial Review
Board and has been a mentor with the SPE eMentoring Program
since 2015. Mukherjee holds an MS degree in petroleum engineering
from Clausthal University of Technology and a petroleum engineering
certificate from Heriot-Watt University.

jpt.spe.org 77
 TECHNOLOGY FOCUS

resources, mandate the need for a gradual

Recommended additional reading at OnePetro:
shift toward optimized recovery strategy in a
www.onepetro.org.
sustainable and cost-efficient manner. As a result,
current circumstances dictate focusing on low-
cost and low-carbon EOR barrels to secure energy SPE 214268
supply in the shorter term while continuing to A Novel Approach To Combine Models
develop innovative technologies and strategies for To Evaluate Interwell Connectivity in a
enhancing production in the longer term. Waterflooded Reservoir With Limited
Energy consumption for mature waterfloods Injection History
increases sharply at higher water cuts primarily by Yanfidra Djanuar, Dragon Oil, et al.
because of the recirculation of water through the
existing swept pathways. Lower volumetric sweep SPE 210657
in reservoirs leads to excessive water production A Laboratory-to-Field Approach and
and less oil recovery. To curb the menace of excess Evaluation of Low-Salinity Waterflooding
water production, conventional EOR techniques Process for High‑Temperature/High-Pressure
such as polymerflooding or in-depth conformance- Carbonate Reservoirs
control techniques are mostly implemented. by Hemanta Kumar Sarma, University of Calgary,
Both methods have demonstrated cost savings et al.
because of reduced watercuts and reductions in
CO2 generation by lowering reinjection of produced IPTC 22733
water. Additional costs of injectants, transport, Like Cures Like Microbial Enhanced Oil
and topside facilities, however, contribute to Recovery in Biodegraded Crude
higher project costs. Early optimization measures by Thanapong Ketmalee, PTTEP, et al.
for existing waterfloods using machine-learning
(ML) approaches could enable optimal reservoir
management and production by delineating
reservoir heterogeneities more efficiently and
predicting more-effective interwell connectivity.
Furthermore, ML could contribute directly to the
optimization and surveillance of EOR applications,
which would subsequently affect the performance
and the cost of such projects, thereby supporting
the achievement of low-cost and low-carbon
EOR barrels. JPT

78 JPT | June 2023

 TECHNICAL PAPERS | EOR Operations

Data-Driven Virtual Viscosity Meter

Augments Inline, Laboratory Measurements

For polymer-based chemical flooding projects, uses pressure-drop and flow-rate measurements
controlling the viscosity of the injected polymer for the fluid flowing in a bypass line. Pressure drop
solution is critical because polymer cost is one is measured in the insulated coiled tube, while
of the more significant elements in project the flow rate is measured using a Coriolis-type
economics. The polymer viscosity is measured flowmeter. During operation, the polymer solution
routinely in the laboratory using fluid samples temperature and pressure drop at a fixed flow
taken manually at different sampling points. In the rate are measured continuously. The system then
case of large-scale projects, however, such viscosity calculates the viscosity of the polymer solution
monitoring becomes time-consuming and requires passing through the viscometer using the curve
a dedicated field staff. The complete paper extrapolated from the calibration points. Such a
introduces a data-driven virtual viscosity meter viscometer measures a wide range of polymer
(VVM) as a tool to augment inline and laboratory viscosity and could be used for both high-viscosity
viscosity measurements. and diluted solutions at low and high pressures.
Use of inline viscosity measurement, while
Introduction advantageous in many ways, comes with significant
In field conditions, proven ways to monitor polymer costs. An inline viscometer usually is installed
viscosity of the injected solution include laboratory on the foundation in a cabinet to protect it from
measurements using injector wellhead samples harsh weather conditions (Fig. 1). Additionally, the
and inline measurements using a viscometer. injection line upstream of the wellhead must be
In the former, injected chemical solution equipped with a bypass line and drainage system.
is sampled regularly to test its viscosity in the Maintenance activities could affect the uptime of
laboratory. This is a time- and labor-intensive the inline viscometer. This could become critical
method with safety and environmental risks during under field conditions, where problems with
sampling. The latter method is a way to monitor water treatment could translate into plugging
viscosity using inline viscosity-measurement of the viscometer filters, leading to erroneous
devices. Measuring the viscosity inline reduces measurements and eventual downtime for cleanup.
the risk of polymer degradation significantly and Such problems grow with the number of devices
provides more viscosity data. An inline viscometer in operation. Therefore, using a few viscometers
is often considered a compromise that comes
at the cost of less-effective viscosity monitoring.
This article, written by JPT Technology Editor Chris Carpenter,
contains highlights of paper SPE 211393, “Introducing
Data-Driven Virtual Viscosity Measurements,”
For a limited time, the complete
by Volodmir Karpan, Shell, and Samya Al Farsi and
paper is free to SPE members
Hanaa Al Sulaimani, SPE, Petroleum Development Oman,
at jpt.spe.org.
et al. The paper has not been peer reviewed.

jpt.spe.org 79
 TECHNICAL PAPERS | EOR Operations

polymer (ASP) floods. ML demonstrated potential

to leverage such data and provide high-accuracy
polymer-viscosity calculations by identifying
underlying trends between the injector-well data
and polymer-viscosity measurements.
The training data sets were presented to
several ML regressions with parameters that
were tuned experimentally to the task. This study
evaluated three methods: linear, polynomial, and
random forest (RF) regressions. RF was selected
after model evaluation by cross-validation showing
the best performance on the training data set with
high accuracy on the testing data set for all study
cases considered.

Study Cases
Three study cases were considered. Study Case 1
was based on data from the West Salym ASP pilot.
In this case, inline-viscometer and laboratory-
measured viscosity data were used to test the
performance of ML regressions with viscosity data
from different origins. In Study Case 2, data from
Fig. 1—Inline viscometer exterior and interior design. the Marmul Phase-1B ASP field trial was used.
In this project, no inline-viscometer data were
The authors address a solution to this problem available; still, an attempt was made to improve
wherein a machine-learning (ML) tool is proposed ML-regression performance by including more
to augment viscosity measurements by calculating available field data. Finally, Study Case 3 was based
the viscosity using field data for the periods when on field data from the Marmul polymer project.
no viscosity measurements are available. In this case, inline-viscometer and laboratory-
measured viscosity data were available. Inline-
ML Methods Used With VVM viscosity data originate from the inline-viscometer
In this study, the authors used ML methods to trial conducted on one of the polymer-injector
create a model of a VVM for calculating the viscosity wells of the Marmul polymer project. In this case
of the injected solution considering available study, an attempt was made not only to calculate
standard well data. the viscosity and compare it with the inline
The authors write that, to the best of their measurement but also to calculate the viscosity
knowledge, ML methods have not been applied for the periods when no such measurements were
to calculate polymer viscosity. Polymer viscosity conducted. All three study cases are detailed in the
depends on many parameters simultaneously, compete paper, while this synopsis concentrates
and the authors write that ML is a suitable tool for on the authors’ discussion of the results.
the problem. They collected field data and inline-
viscometer and laboratory measurements from VVM Applications
several small (pilot) and large (commercial-scale) The VVM application range depends on the range
projects in both polymer and alkaline/surfactant/ of parameters used to train the regression.

80 JPT | June 2023

 TECHNICAL PAPERS | EOR Operations

Therefore, selecting a wide range of parameters is ML to calculate the viscosity of an injected polymer
proposed. RF regression provides a good viscosity solution. The RF-regression algorithm was selected
evaluation. The quality of the calculation, however, as the most-suitable technique. To investigate the
depends on the quality of viscosity measurements. robustness of the approach to the data quality
This paper used two viscosity data sets obtained and test the limits of its application, the authors
from an inline viscometer and laboratory considered well data from several study cases.
measurements. The quality of laboratory-measured Despite overall good performance, the following
data is poorer than that from an inline viscometer issues were identified:
because of the higher risk of polymer degradation. • The study showed good performance of VVM
Thus, the calculation error of a VVM trained with when inline-viscometer data were used. A
laboratory viscosity was higher. poorer quality of viscosity calculation, however,
Despite the high risk of polymer degradation, was observed in the case of the laboratory-
a typical commercial polymer-injection project measured viscosity data.
relies on laboratory measurements to monitor • In the current model, the lack of some key
the injected solution viscosity. This seems to be a parameters was observed, which limited the
more-robust solution because implementing large- model performance. The authors argue that,
scale viscosity monitoring with inline viscometers because of the strong correlation between
is costly and complex. However, using an inline the injection pressure and the viscosity of
viscometer in combination with VVM could become the injected polymer solution, the missing
the solution to these problems. With VVM trained parameters characterize water quality and
on large-enough data sets, the number of required well injectivity.
viscosity measurements could be reduced. • The application range of VVM depends on
Moreover, the authors propose developing the data used for training the algorithm.
compact viscometers that can be transported RF regression should be trained on a wide
easily between injectors. A VVM trained on a range of parameters, and even chemical
large amount of well data could be used to compositions, to widen the application range.
evaluate viscosity across injectors with similar
injectivity and well design. The proposed approach Future work will be directed toward finding
would reduce the need for inline-viscometer a better correlation using discussed and new
measurements significantly. key parameters and training the algorithms on
Good viscosity monitoring is critical for polymer broader ranges for better viscosity calculation
projects operated under the operational lease of injected chemical solutions.
contract. Polymer injection is provided by the The proposed tool should be used in
contracting company to supply an operator with combination with existing inline or laboratory-
a solution of predetermined viscosity. Robust measured viscosity data to calculate viscosity
viscosity monitoring at the interface between during periods when such viscosity measurements
the operator and contractor is critical. An are unavailable. Using VVM should reduce
established VVM, combined with inline-viscosity the costs of viscosity monitoring. VVM allows
measurements, could be used to provide such viscosity calculation in real time with the
viscosity monitoring. resolution of input parameters. Integrating
such a tool with dynamic modeling also should
Conclusions improve prediction capability for polymerflood
The authors performed a proof-of-concept study performance because of a better understanding
and tested a developed work flow for a VVM using of polymer viscosity. JPT

jpt.spe.org 81
 TECHNICAL PAPERS | EOR Operations

Technique Evaluates Polymer Injectivity in

High-Salinity/High-Temperature Carbonates

The complete paper presents the interpretation injection, and crestal hydrocarbon gas injection in
of two polymer injectivity tests (PITs) performed in the gas cap.
two giant light-oil high-salinity/high-temperature The reservoirs have been developed through
(HS/HT) carbonate reservoirs onshore Abu long horizontal wells oriented into the lower
Dhabi. The detailed data acquired in both tests zones to allow a more-homogeneous sweep.
were used to evaluate both polymer injectivity However, the injected fluids in the lower zone
at representative field conditions and in-depth travel quickly through the upper zone not far
mobility reduction. The interpretation of the from the injection wells and around the producers
pressure transient analysis (PTA) of the pressure into the lower zone. This water or gas inverse
falloffs (PFOs) and the mechanistic 3D simulation coning results in bypassed oil in the lower
models of the two PITs confirmed the generation zone. To face this challenge, the operator has
of polymer banks and demonstrated effective investigated simultaneous injection of miscible
propagation of the polymer into the reservoirs at CO2 gas and polymer (SIMGAP) for reservoirs
target concentrations and representative rates of with an approximately 10-fold permeability
future interwell pilots. contrast between the lower and upper zones
and simultaneous injection of water and polymer
Introduction (SIWAP) for reservoirs with a permeability contrast
The reservoirs tested in the PITs can be described of 100-fold or greater between the lower and
as heterogeneous carbonate reservoirs divided upper zones. These techniques rely on reducing
into upper and lower zones. Upper-zone porosities mobility by polymer injection in the upper zone to
range between 20 and 30%; permeability ranges provide a pressure barrier and reduce crossflow
from 10 to 1000 md. In contrast, the lower zone of the higher-mobility fluid injected into the
has porosities and permeabilities ranging from lower zone.
10 to 30% and from 1 to 20 md, respectively. The
main production mechanisms in the reservoirs are PIT Simulation Model Setup
peripheral water injection, middip-pattern water A single-well radial simulation model was built
for PIT 1 to assess near-wellbore phenomena
by minimizing in-situ velocity and shear-rate
This article, written by JPT Technology Editor Chris Carpenter, calculation errors compared with Cartesian
contains highlights of paper SPE 211451, “Assessment of coordinate grids. For interpretation of PIT 2,
World-First Two-Polymer Injectivity Tests Performed in Two
Giant High-Salinity/High-Temperature Carbonate Reservoirs
Using Single-Well Simulation Models and Pressure-Falloff
For a limited time, the complete
Analysis,” by Juan M. Leon, Shehadeh K. Masalmeh, SPE,
paper is free to SPE members
and Ali M. Al-Sumaiti, SPE, ADNOC, et al. The paper has not
at jpt.spe.org.
been peer reviewed.

82 JPT | June 2023

 TECHNICAL PAPERS | EOR Operations

a mechanistic Cartesian 3D thermal black- Water-injection PFOs were modeled using PTA
oil simulation model was built by extracting a software with various well and reservoir models
subsector from the last available static geomodel, to obtain a reasonable match to the PFO data. The
preserving well architecture and grid resolution same models were used later to analyze polymer
in the extracted subsector. The radial simulation and chase-water PFOs.
model was found unsuitable for PIT 2 because When considering the PTA results and history
the injector well presented a very high deviated match for the multiple PFOs acquired at different
section in the target reservoir, while the long string dates for PITs 1 and 2, the representative injection
presented a long horizontal section. Therefore, the rates during the PFOs varied from 2,000 to
polymer injectivity and polymer bank propagation 5,500 B/D in both PITs.
in the upper reservoir might not be represented Most of the PFOs exhibited some interference
properly using a vertical well. associated with relatively large wellbore-storage
Different local-grid-refinement (LGR) levels signals. In addition, few pressure anomalies were
were implemented around the perforation length observed in the PFOs at the early time period
(upper zone), while the lower zone was in the root (0.15–1 hour). All PFO tests during both PITs were
grid. The minimum cell radius in the model was performed without downhole shut-in tools. Despite
determined to be 1.3 ft to avoid errors in well-index these challenges, the acquired PFO data during
calculations considering the well-flow model. Thus, PIT 2 were of a higher quality with less wellbore-
three LGR levels were applied. storage effect when compared with the PIT 1 PFOs.
PTA of the PFOs is consistent with the
PIT Injector-Well Characteristics assumptions used in the radial and mechanistic
The two PIT wells present similar configuration, simulation models. Moreover, the simulation model
having dual-string completions in the upper zone showed a reasonable match to both pressure and
[short string (SS)] and lower zone [long string (LS)]. derivative curves from PFO data for the middle- and
The SS features perforated intervals in the deviated late-time regions.
cased-hole section, while the LS has a horizontal
open hole. During the PIT, polymer solution was Polymer-Injection Parameter Design
injected into the SS while injection in the LS was Polymer-injection rates in the PITs were selected
temporarily halted. based on the planned SIMGAP and SIWAP interwell
The perforation strategy for the PITS differed pilots. The polymer will be injected in the upper
considering the larger permeability contrast zone using 2,000- to 3,000-ft-long horizontal
observed in the PIT 1 well. PIT 1 well perforations wells in the range of 2,500–10,000 B/D. Injectivity
were oriented in the middle of the upper zone to index in the slant wells (40°–70°) is expected to
reduce excessive crossflow into high-permeability be approximately 3.8–5.5 times lower than the
streaks in the top of the targeted layer. In contrast, horizontal pilot injector. The equivalent targeted
in PIT 2, well perforations covered most of the injection rate during the PIT would be in the range
upper zone. of 800–2,000 B/D.
Moreover, the polymer concentration range
Water-Injection Baseline was designed according to experimental data and
Special attention was taken during the water- the required effective polymer viscosity (8–10 times
injection baseline and the chase-water stages to higher than water viscosity) to derisk the SIWAP
calibrate the reservoir, adjust well parameters, and SIMGAP pilots. Therefore, the PIT was designed
and analyze injectivity behavior during and after to assess polymer-concentration requirements to
polymer injection. identify a resistance-factor (RF) range.

jpt.spe.org 83
 TECHNICAL PAPERS | EOR Operations

In-Situ Rheology Conclusions

In-situ rheology is one of the more challenging Interpretation of PITs performed in two giant
parameters to incorporate in the models because light‑oil HS/HT carbonate reservoirs onshore
the in-situ viscosities are highly affected by Abu Dhabi, together with extensive laboratory
different factors such as preshearing and the studies, aimed at derisking what the authors
presence of oil. Thus, the available in-situ rheology write will be the world’s first SIMGAP and SIWAP
curves were adapted to generate generic in-situ interwell pilots.
rheology curves based on thorough sensitivity Two mechanistic simulation models were
analysis. The analysis was structured using variable built to incorporate the information from
elongational effects and effective shear rates on polymer laboratory studies and to interpret the
polymer viscosity, which ultimately affect the onset large field-data sets during the PITs. Moreover,
of shear thickening and in-situ viscosity. Similar a sequence of multiple PFOs acquired during
in-situ rheology curves were implemented in both the PITs was assessed to obtain the required
simulation models. uncertainty parameter ranges for the history-
matching exercise. Lessons learned from PIT 1
Polymer-Injection PFO Tests allowed optimization of the PIT 2 design program
Various PFO tests were conducted during the and achievement of a better understanding of
two PITs after each main polymer-injection stage. polymer characteristics.
The PFOs could not differentiate between the The primary conclusions of the PIT
relative contributions of polymer viscosity and interpretation results included the following:
residual resistance factor (RRF) to the polymer RF. • The two PITs confirmed the polymer-
Therefore, additional tests were acquired during concentration range identified in the laboratory
the chase waterflood in both PITs. and required to achieve target RFs during the
The polymer RF increased as the polymer polymer-based interwell pilots.
concentration in the expanding polymer bank • The PITs demonstrated that the qualified
increased, and preshear levels reduced in both PITs. polymer can be injected without preshearing.
All PFO matches were based on comparison • Both simulation models matched all water
to the baseline. The skin value during PIT 1 was and polymer PFOs and found no evidence of
varied from –1 initially to 6.4 at the end of the contribution of induced fractures to injectivity.
PIT and progressively reduced to 2 during chase • Simulation models and PTAs of the PFOs show
water. In contrast, the skin was assumed constant that additional viscosity degradation might take
(–2) during the entirety of PIT 2. Moreover, the place beyond the shear device.
assumptions made during the first PIT on the RRF • An RRF vs. permeability function was developed
and shear-thickening effects were amended in based on laboratory measurements and results
PIT 2, confirming that no injection impairments were incorporated into the simulation model;
occurred because of the polymer but rather these RRF value ranges were later confirmed by
because of water-makeup quality. PTA of the PFOs during the chase-water periods
PFO data and the history-matched analytical in both PITs.
model were compared with the PFO generated from • PIT-interpretation results will contribute to
the mechanistic simulation model and reasonable improved reliability of the sector and full-field
agreement was found on transmissibility, mobility, simulation models to assess polymer-based
and skin assumption. (A comprehensive assisted enhanced oil recovery schemes and to unlock
history-matching methodology was implemented in further development opportunities in other
both PITs and is detailed in the complete paper.) reservoirs with similar characteristics. JPT

84 JPT | June 2023

 TECHNICAL PAPERS | EOR Operations

Efforts Lead to Formulation

of High-Performance ASP

Mangala is a large low-salinity, high-quality Immediately after the field’s appraisal stage,
fluvial oil field in India with stock-tank oil initially work to identify the most suitable EOR process
in place (STOIIP) of more than 1 billion bbl of began. First, a polymerflooding pilot was conducted
waxy and moderately viscous crude. Aqueous- during 2011–12. The encouraging results led to full-
based chemical enhanced oil recovery (EOR) has field polymerflooding implementation in November
been identified as the most suitable technique 2014. The ASP pilot performed well; incremental oil
to improve recovery over waterflooding. The recovery over polymerflooding was estimated to be
objective of the complete paper is to describe in the range of 20–25% of the pilot STOIIP.
alkaline/surfactant/polymer (ASP) formulation The initial development plan involved
development for Mangala, which involved more implementing a hot waterflooding production
than 30 corefloods at the time of writing, with startup to maintain reservoir pressure and effective
formulation design changing over time. sweep. The Upper Fatehgarh FM1 and FM2 units
were developed with inverted nine-spot patterns,
Field Background while the more-homogeneous lower Fatehgarh (FM3
The Mangala field has been regarded as an and FM4) were developed with downdip injectors
excellent chemical EOR candidate since its and updip horizontal producers. The Mangala field
discovery in 2004. The main reservoir unit is began producing under a hot waterflood in 2009,
divided into the Lower and Upper Fatehgarh with the injected water heated to approximately
formations. These units are subdivided into five 80–85°C to avoid wax deposition. Injection was
reservoir units, FM1 to FM5 from top to bottom. started within a few months of first production.
Mangala contains waxy sweet crude oil with At the time of writing, the field is under
gravity ranging from 20 °API near the oil/water polymerflooding, with results largely in line
contact to 28 °API in the oil column. The crude has with expectations. The field, which has already
in-situ viscosity of 9–17 cp. The crude has good produced approximately 37% of the STOIIP, is
napthenic acid content and reacts with alkali to on a declining production trend, and large-scale
produce in-situ soap. ASP flooding is being considered as the next
development initiative to arrest production decline
and increase overall recovery.
This article, written by JPT Technology Editor Chris Carpenter, The complete paper discusses EOR screening
contains highlights of paper IPTC 22729, “ASP Formulation studies; ASP formulations, including the initial
Development Journey: Optimization, Validation, and
Quality Control for Mangala Field,” by Nitish Koduru,
Dhruva Prasad, SPE, and Amitabh Pandey, SPE, Cairn
For a limited time, the complete
Oil and Gas. The paper has not been peer reviewed.
paper is free to SPE members
Copyright 2023 International Petroleum Technology
at jpt.spe.org.
Conference. Reproduced by permission.

jpt.spe.org 85
 TECHNICAL PAPERS | EOR Operations

formulation; the method adopted for selection of of ASP flooding. Thus, the ASP formulation was
chemical suppliers for the pilot test; optimization revisited in an attempt to decrease injection alkali
of ASP formulations tested in the pilot; validation in all phases (ASP, polymer drives) and surfactant
of the developed formulation to other layers of the concentrations.
field; and planned quality-control processes to be Ultimately, the optimization study helped in
used during procurement of chemicals for larger reducing alkali concentration from 3.0 wt% to
applications of ASP floods in the field. This synopsis 2.5 wt% and surfactant concentration from 0.3 wt%
concentrates on the last three of these factors, to 0.25 wt% without losing the efficacy of the
rather than the formulations considered, which, formulation in recovering oil.
in addition to the initial formulation, included
the following: Validation for Other Mangala Layers
• Formula 2: ASP formulation with a sacrificial Most laboratory studies until 2020 were focused
surfactant on development of ASP formulations for the FM1
• Formula 3: ASP formulation with a single layer. The lower Fatehgarh layers of Mangala
surfactant (FM3 and FM4) bear high initial volumes of oil and
• Formula 4: Formulation with a highly have slightly higher reservoir temperatures. The
hydrophilic, large-hydrophobe surfactant properties of crude in the lower layers are not
very different from the crude in the upper layers
Mangala ASP Pilot Test (FM1 and FM2). The authors sought to verify the
Performance of the ASP formulation in the Mangala performance of the existing ASP formulation
pilot is impressive. From the water-cut trend, it [0.18% tristyrylphenol (TSP) + 0.12% alkylbenzene
is evident that the surfactants have mobilized a sulfonate (ABS)] for the lower layers of Mangala at
significant volume of oil from the targeted area. reservoir conditions.
Production trends of oil and emulsion suggest that Dead-oil phase-behavior experiments were
favorable mobility is maintained throughout the conducted with an optimized formulation with FM4
flood. Severe production separation issues were crude. Observing good performance, live-oil phase
not observed. Post-pilot cores taken using sponge behavior experiments were performed with FM4
coring in the pilot area indicate a remaining oil crude. The formulation was tested on reservoir
saturation of 5–10% in the ASP-flooded sand. corefloods under high-pressure conditions. The
first coreflood (live oil) was performed using FM4
ASP Formulation Optimization core plugs and the FM4 oil with coreflood design
After the pilot’s success, another laboratory study and procedures very similar to several previous
was performed to find adjustments to the chemical corefloods using upper Fatehgarh materials.
formulation to optimize performance. For larger Following a short polymer flood and tapering,
applications of ASP flooding, the operating cost a 0.4‑pore volume (PV) ASP slug with a 0.3-wt%
of chemicals is the most important factor driving surfactant slug was injected followed by a polymer
project economics. The ASP formulation used drive. Following the polymer preflood, a 0.4-PV ASP
in the pilot had 3.0 wt% of soda ash. Preparing slug was injected at 2 ft/D followed by approximately
3.0 wt% of alkali brine would, for large scale, 3-PV polymer drive until no more oil was recovered.
require hundreds of tons of alkali consumption per Residual oil saturation was reduced from 34% to less
day. Transporting such huge volumes of alkali may than 1%, resulting in an incremental recovery of 99%.
itself become challenging. Apart from economics, A second live-oil coreflood was performed to
transportation logistics must be investigated optimize the ASP design by reducing the amount of
to avoid major hurdles during implementation chemical injected, which entailed injecting a 0.3‑PV

86 JPT | June 2023

 TECHNICAL PAPERS | EOR Operations

ASP slug instead of a 0.4-PV slug. The purpose of of potential surfactants was screened based
using a 0.3-PV ASP slug was to improve salinity on phase-behavior experiments. Promising
gradient and lower retention. The results of the formulations were selected and further developed
test were good; again, oil saturation reduced to to improve robustness and efficacy. In addition
approximately 1%. The injected alkali mass was to identifying high-performance formulations, the
enough to satisfy consumption. The surfactant laboratory worked on an in-house development
retention measured 0.12 mg/g rock. program that helped in providing more options for
The ASP formulation and flooding design selection of high-performance surfactants.
developed for the Mangala upper Fatehgarh Surfactant mixing in the laboratory should
appears to be as effective for the lower Fatehgarh. be carefully scaled to field-mixing conditions
The surfactant phase behavior is very similar in designing facilities. In this case, because the
to that of the FM4 oil samples with regard to surfactant design changed after facility fabrication
optimal salinity and interfacial tension. The live-oil was complete, mixing issues were observed.
corefloods demonstrated that the ASP design with Careful laboratory evaluation led to identification
a 0.3-PV ASP slug is as effective in recovering oil in of facilities modifications that resolved most
the lower Fatehgarh as in the upper Fatehgarh. issues. The design of the ASP facility generally
is linked to the type of surfactants planned for
Quality Control of Surfactants use. Formulations generally evolve with time as
in Chemical Shipments further experimentation increases understanding
Quality-control laboratory studies are an important of the crude. It is advisable to make the slight
step to check produced samples before shipping. modifications required to accommodate changes in
A program with two types of quality checks was formulations because it pays off in recovering more
designed. Generally, aqueous stability tests oil with a more-robust formulation. A selection
do not take much time, but phase-behavior process should be in place to select the chemical
experiments with crude require approximately supplier whose actual sample performs per quality-
15 days of equilibration time. However, chemical control specifications.
manufacturers may not be able to hold large The authors found the performance of the
volumes of chemicals for such a long period. A quick ASP formulation in the Mangala ASP pilot to be
phase-behavior test was designed by enhancing a impressive. From the water-cut trend, it is evident
mixture of chemical solution with brine and crude that the surfactants have mobilized significant
by constant gentle mixing on a mechanical mixer. volumes of oil from the targeted area. Production
This helps in making qualitative observations within trends of oil and emulsion suggest that favorable
48 hours. Once the aqueous stability test and mobility is maintained throughout the flood.
quick phase-behavior test is given approval by the Optimization studies helped reduce chemical
laboratory, the chemicals are ready to be shipped. concentrations in the ASP formulation. Validation
Detailed phase-behavior tests, monitored for 30 of efficacy of the formulation in other layers of the
days, can be used for quality-checking purposes field helped reinforce the confidence in formulation
while accepting the shipment at site. performance. Having one ASP formulation for
multiple ASP applications in one field reduces
Conclusions complexities in production-side surface-facility
Once screening studies identified chemical operations. Quality-control laboratory studies are
methods to be best-suited for EOR, detailed an important step in checking produced samples
laboratory studies were initiated to identify high- before shipping. These studies reduce the tedious
performance ASP formulations. A large range process of returning rejected sample batches. JPT

jpt.spe.org 87
 TECHNICAL PAPERS

SPE Technical Papers Available for Download

SPE technical papers synopsized in each monthly issue of  JPT are available for download
for SPE members for 2 months. These May and June papers are available now.
You’ll also find links to the technical papers at the bottom of each synopsis.

MAY 2023 JUNE 2023

(available here through 30 June) (available here through 31 July)

DEEPWATER FIELDS COILED TUBING

Successful Implementation of Geomechanics Novel Engineering Approach Using Underbalanced Coiled
in a Deepwater Setting: A Case Study From Tubing Drilling Solutions for Tight Sour Gas Carbonate
KG Offshore, India A Proven and Versatile Coiled Tubing Live-Well
Intelligent Deepwater Advanced Solutions Hub Intervention Solution From a Monohull Vessel in the
for Value Maximization Throughout Asset Life Cycle Norwegian Continental Shelf
One Innovative Intelligent Completion Intermediate Casing Leak Repair To Continue Hydraulic Fractures
String Design for Deepwater Gas Well Completions: Stimulation
The Installation Case Study From L Gas Field, China
ACIDIZING
INTELLIGENT OPERATIONS Novel Simulator for Design and Analysis of Matrix
Dual Heuristic Dynamic Programming in the Oil and Gas Acidizing Jobs With Fluoroboric Acid in Sandstone
Industry for Trajectory Tracking Control Reservoirs
IBTIKAR Digital Laboratory: A Collaborative Approach Ineffectiveness of Acid Fracturing for Stimulating a Tight
Toward Research and Development Challenges Fractured Reservoir Rock: A Case Study
in Oil and Gas Upstream Multistage Acid Stimulation for ICD Screens Completion
A Digital Oilfield Comprehensive Study: Automated Using Straddle Packer and Real-Time Telemetry Coiled
Intelligent Production Network Optimization Tubing

EXTENDED-REACH AND COMPLEX WELLS HYDRAULIC FRACTURING OPERATIONS

Constructing Deep Closed-Loop Geothermal Wells Hydraulic Fracturing at Clair: Unlocking the Potential of
for Globally Scalable Energy Production by Leveraging Europe’s Largest Reservoir
Oil and Gas ERD and HP/HT Well-Construction Expertise Overview of Hydraulic Fracturing Test Site 2 in the
Breaking ERD Records With Optimized Engineering and Permian Delaware Basin (HFTS-2)
Practices: Making the Impossible Possible Efficiency and Effectiveness—A Fine Balance: An
Maximizing Reserves Value Using Multilateral Wells: Integrated System To Improve Decisions in Real-Time
A Decision-Support Tool and Key Applications Hydraulic Fracturing Operations

CEMENTING AND ZONAL ISOLATION EOR OPERATIONS

Expandable Geopolymers for Improved Zonal Isolation Introducing Data-Driven Virtual Viscosity Measurements
and Plugging Assessment of World-First Two-Polymer Injectivity Tests
Quantifying the Sealing Performance of Plug and Performed in Two Giant High-Temperature/High-Salinity
Abandonment Cement Systems Under Downhole Carbonate Reservoirs Using Single-Well Simulation
Conditions Models and PFO Analysis
ASP Formulation Development Journey, Optimization,
Validation, and Quality Control for Mangala Field

TOPICS COMING UP IN JULY

Reservoir Simulation | Wellbore Tubulars | Unconventional and Tight Reservoirs | Decarbonization

88 JPT | June 2023

 SPE NEWS

DOE Awards SPE and Consortium Partners

$165 Million Grant To Advance Geothermal
The US Department of Energy (DOE) has awarded Over the next 5 years, the consortium will
a $165 million “Geothermal Energy from Oil and address four key facets: technology transfer,
Gas Demonstrated Engineering” (GEODE) grant to a demonstration and deployment, barriers to
consortium formed by Project Innerspace, Society expansion, and workforce adoption. Within those
of Petroleum Engineers International (SPE), and facets, the consortium will focus on a variety of
Geothermal Rising (GR). pain points constraining geothermal growth,
The cross-industry collaboration formed by the including research and development gaps and
consortium will engage with oil and gas experts, roadmapping, stakeholder engagement, funding
geothermal startups, and other stakeholders for keystone projects, and consensus building
to build consensus around strategies and among ecosystem stakeholders.
opportunities for geothermal innovation. “It is exciting for Geothermal Rising and its
The consortium will leverage the oil and expansive membership to play a role in convening
gas industry’s 100+ years of experience and communities who, working together, hold the
technological developments in drilling and solution to our climate crisis through heat and
subsurface engineering to address and overcome electricity decarbonization,” said Bryant Jones,
challenges currently constraining geothermal executive director of GR. “We really can use the
development. earth to save the Earth if we work together to
The grant will provide $10 million in the first make it happen.”
year, which will fund the consortium members, in Accomplishing these goals will significantly
collaboration with more than 100 partner entities, contribute to achieving the cost targets outlined
to develop a roadmap to accelerate geothermal in the DOE’s recently announced geothermal
energy’s growth and development. From the EarthShot, bringing down the costs of enhanced
second year onward, the DOE will provide up geothermal systems by 90%. The consortium’s
to $155 million in additional funds to finance ultimate objective is to place geothermal into
execution of the plan. its proper and central role as the “go-to” secure,
“We look forward to advancing our collective reliable, safe, and clean energy source of
vision for the role geothermal will play in the future the future.
of energy through this powerful partnership,” “Geothermal provides oil and gas professionals
said Jamie Beard, founder and executive director, an opportunity to leverage our collective expertise
Project Innerspace. “This is the geothermal decade. and resources to drive sustainable growth in
By 2030, with focused concerted action, we can the energy sector,” said John Boden of SPE. “We
catalyze geothermal into exponential growth. The believe that geothermal energy has the potential
key to achieving this is building consensus and to become a key part of the global energy mix,
forging forward-looking collaborations between the and the oil and gas industry has significant
oil and gas and geothermal industries, and we will contributions it can make toward achieving
get that work done through this partnership. All that goal. We are excited to be part of this
hands on deck.” groundbreaking collaboration.”

jpt.spe.org 89
 SPE NEWS

SPE CEO Mark Rubin Retires

With more than 40 years in during an industry downturn. Rubin became
the oil and gas industry Executive Director (later CEO) of SPE in September
and more than 21 years 2001. SPE at the time was a community of 47,835
leading SPE, Mark Rubin professional members, of which 25,917 were based
will be retiring in June. in the US, and 5,190 student members.
Rubin began his career in Rubin soon realized that there were untapped
the field, working for Unocal. opportunities for SPE through the continued
Following a downturn, he began globalization of membership and services, especially
working in the standards group at the American
Petroleum Institute (API), moving through several
roles to Upstream General Manager at API. I have known Mark since we were in the student
Rubin joined SPE in 1979 while he was a chapter at A&M and through a lifetime of
petroleum engineering student at Texas A&M SPE service. My years on the Board and as
University. He could not have imagined then that President were a pleasure because of Mark’s
he would one day lead this organization that leadership and stewardship of our entire global
helped him throughout his career as a student, a community. I was proud to serve with him.
young engineer responsible for oil and gas fields —Janeen Judah, 2017 SPE President
in East Texas, and as an unemployed engineer

SPE ACHIEVEMENTS DURING MARK RUBIN’S LEADERSHIP

ATCE 2001—Mark joined SPE
2003—Opened SPE office in Dubai
2003—Began offering free dues to student members, supported through corporate sponsorship
2004–2005—Significant investment in supporting young professionals, including YP workshops and programs
2005—Inaugural issue of The Way Ahead magazine
2005—Launched International Petroleum Technology Conference in conjunction with AAPG, SEG, and EAGE,
as a major annual event to rotate between the Middle East and Asia Pacific
2006—Pilot program launched in Abu Dhabi for an SPE-sponsored Petroleum Professional Certification
2006—First technical section (Wellbore Positioning) is created
2007—First SPE President from the Middle East
2007—OnePetro multisociety library launched
2007—Opened SPE Moscow office
2009—SPE completes merger with Petroleum Society of Canada; adds Calgary office
2010—ATCE was held outside the US for the first time (Florence, Italy) ; subsequent ATCEs held
in Amsterdam, Dubai, and Calgary
2012—PetroWiki pilot (on Drilling) was launched as a free resource based on the
Petroleum Engineering Handbook

90 JPT | June 2023

 SPE NEWS

in the Middle East and Asia. He worked with the SPE

Board of Directors to develop initiatives that would
vastly expand SPE’s reach. SPE’s 2002 President,
Steve Holditch, proposed establishing an office in
the Middle East, and in 2003, SPE followed through
in opening the Dubai office, offering more events
and programs in the region. SPE expanded member
services through its existing London and Kuala
Lumpur offices, and then opened a Moscow office in
2007 and a Calgary office in 2009 (resulting from the
merger with the Petroleum Society of Canada). 2022
SPE President Kamel Ben-Naceur observed “Since I Mark with staff from the Richardson Chamber of
first met Mark Rubin at an SPE workshop more than Commerce and 2013 President Egbert Imomoh (right) at
the official headquarters reopening in Richardson, Texas.
15 years ago, he has been extremely supportive
of ideas to expand SPE to new geographical and
technical areas. He was a strong driver behind The growth in student members was the result
the international expansion of SPE, with many of another major initiative Rubin encouraged–
new sections and student chapters created under expanded focus on young members as the future
his leadership.” By the time SPE held its first of our industry. During the period 2003–2005,
ATCE outside the US in 2010 (in Florence, Italy), Halliburton provided the first sponsorship to
membership had grown to 71,191 professionals enable free student membership. 2005 SPE
and 26,000 students, an increase of 83% from when President Giovanni Paccaloni had a passion for
Rubin joined SPE. young professionals, and Rubin worked with him to

2012—First time SPE topped 100,000 professional and student members (104,762)
2012—Enhanced member services for the Projects, Facilities, and Construction discipline, including creation
of Oil and Gas Facilities magazine
2013—First SPE President from Africa
2013—Created SPE Connect online community
2013—Joined with AAPG and SEG to launch the Unconventional Resources Technology Conference
2013—Reopening of Richardson office building after a year-long renovation
2016—Drilling and Completions discipline split to better serve both communities
2017—Created online publication HSE Now to serve members in that discipline
2017—Senior Professional group was created for members age 55 and older
2019—Strategic focus on serving data science professionals, including creation of online publication
Data Science and Digital Engineering
2020–2021—Global pandemic fast-tracked SPE’s digital transformation through the creation of virtual events
and new SPE Live broadcasts to engage members online; also, the decision to retain staff helped SPE
rebound quickly post-pandemic
2022—SPE Energy Stream multimedia platform created
2022—Four new technical sections were initiated, bringing the total to 21

jpt.spe.org 91
 SPE NEWS

develop new programs to ensure SPE’s relevance

to a new generation, including the launch of I was struck by two things in the years I worked
The Way Ahead, SPE’s magazine written by and for with Mark:
young professionals, in 2005. In the ensuing years, •H
 e saw each SPE member as a customer
SPE has created many additional engagement who needed to be provided quality service
opportunities for students and early- to mid-career wherever he or she was a resident. This
professionals to sustain this important group of drove the plans to strengthen the various
future industry leaders. regional offices.
Rubin also recognized that technology was •H
 e was conscious of the global nature
the key to serving a global membership, so he SPE had assumed over the years, and he
advocated for making more of SPE’s resources sought to protect and nurture this in all
readily available and searchable online for SPE activities.
members. When he proposed to bring together —Egbert Imomoh, 2013 SPE President
our papers and other resources with those of other
societies serving the industry, OnePetro was born.
A few years later, Rubin pushed to convert the Rubin recognized the importance of members
Petroleum Engineering Handbook into an electronic finding their community within SPE and leaned into
form, resulting in the creation of PetroWiki, thanks a discipline focus. This led to several magazines
to a generous sponsorship from Apache. During the focused on specific disciplines, expanded online
COVID-19 pandemic, the popular SPE Live series communities, and the creation of Technical Sections
was launched to provide timely topics and diverse during his tenure. Bringing together these technical
viewpoints, and help members remain connected to resources to help members find the information
the SPE community. With the growth in multimedia they need within our large, diverse Society has also
content, he encouraged the creation of Energy contributed to SPE’s membership growth.
Stream as an addition to this slate of highly valuable A final key area of focus during Rubin’s tenure
online resources for students, practicing engineers, has been the staff. He understood that creating a
and their companies. positive staff culture and professionalizing SPE’s
When Rubin joined SPE in 2001, Technical approach to human resources was essential to
Directors were just being added to SPE’s Board to making SPE successful and delivering the types of
represent the disciplines within our membership. experiences that SPE members expect. Working
for an organization that relies on volunteers, Rubin
encouraged staff to volunteer in their communities.
During the industry downturn that began in 2015,
SPE faced significant challenges and he had to make
tough decisions, including SPE’s first-ever staff layoff
in 2015 and a second layoff the following year.
Despite these difficult circumstances, Rubin’s strong
leadership and the staff’s unwavering commitment
allowed SPE to weather the storm.
When the pandemic struck, weekly messages
from Rubin to the global staff kept everyone
connected and confident that SPE would make it
Mark with former SPE Executive Director Dan Adamson
at 2012 ATCE. through. As the pandemic lingered, members were
eager to get back to in-person events. Rubin made

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 SPE NEWS

the difficult decision to retain event staff during

the pandemic so that we would be able to rebound
quickly to deliver the high-quality events members
expect from SPE. That decision has served SPE well
over the past year.
2004 SPE President Kate Baker had the
opportunity to observe Rubin’s leadership
throughout his SPE tenure. She noted, “Mark
had big shoes to fill succeeding Dan Adamson.
And he did, taking SPE more truly international
and embracing and expanding offerings in the
related technical diversity the business had always
used and required, though perhaps less visibly
displayed, than its core engineering competencies.
In deliberating new elements or expansions, he
always asked foremost how these might support Mark visited the Great Wall of China while attending a
conference in Beijing in 2006.
or detract from SPE’s mission. SPE remains the
preeminent professional organization in oil and
gas largely because of Mark’s insight, leadership, persons are attracted and enabled by competent
and frontline efforts. SPE is well positioned and graceful leadership, leadership that welcomes
to disseminate technical knowledge useful in new opportunities and the richness of possibility,
exploring for, developing, and producing energy while at the same time honoring the past and
resources beyond oil and gas to achieve a safe, seeking to learn deeply from collective experience.”
secure, and sustainable future.” Throughout the ups and downs of 21 years of
Baker continued, “I am sure Mark would be leadership, Rubin was guided by the words of US
quick to note that success also has depended President Harry S. Truman: “It is amazing what you
upon a superbly talented and motivated staff can accomplish if you do not care who gets the
and volunteers. Yet I credit Mark here, too. Such credit.” In forming partnerships with other industry
associations, whether for events such as IPTC and
URTeC, or other activities, it was always about
Mark is the consummate professional, always serving the members, not who got credit for the
approachable and always keeping the best idea or the result.
interests of membership and staff in mind. He Being CEO of a global organization means a
combines an easy-going leadership style with lot of travel, and one of the things Rubin is looking
a strong backbone when required to make the forward to is more time with his wife, Linda, and
difficult decisions. His robust understanding their daughters. Rubin is an avid skier, and he
of the macro factors of our industry and their looks forward to having more time to spend on
influence on membership and programs led the slopes. In warmer weather, hiking and other
to significant growth in the Society. Finally, the outdoor activities are also a passion he will finally
respect SPE now commands within our industry have time to indulge after his retirement. JPT
can be attributed to Mark’s leadership and
his foresight. Officially retiring in a few weeks, Rubin has been
—Jeff Spath, 2014 SPE President supporting the transition and onboarding of his
successor, Simon Seaton, who takes over in mid-July.

jpt.spe.org 93
 SPE NEWS

Newly Expanded SPE Journal Delivers

Broadened View of Subsurface
as an Asset Now and in the Future
Birol Dindoruk, Editor in Chief, SPE Peer-Reviewed Journals

At the January 2023 SPE Board Meeting, a proposal associate editors. All current editors will continue
to consolidate SPE’s peer-reviewed journals into to serve under the new journal. Existing technical
one all-encompassing journal was approved for disciplines—drilling, completion, production,
implementation. With its first issue set to publish operations, reservoir engineering, and formation
in January 2024, the newly expanded SPE Journal evaluation—will be covered along with new
will include the theoretical research for which and emerging concepts that include but are not
it has been historically known, the application limited to energy transition, sustainability, and
aspects of petroleum engineering formerly data science.
covered by SPE Drilling & Completion, SPE Production SPE Journal is not stepping away from
& Operations, and SPE Reservoir Evaluation & traditional oil and gas research, but we are
Engineering, and expanded topics related to expanding the scope to include new ideas.
associated sciences and emerging technologies. Further, the single journal platform will reduce
This is an exciting advancement that will provide redundancies and competition between journals
SPE the opportunity to continue its mission of and allow for growth with the industry as changes
disseminating technical information across a global occur in the research landscape. Other benefits
community while remaining open to new and include simplified access to SPE’s complete range
expanding developments in all aspects of the oil of technical content (including special issues) on
and gas industry. OnePetro, elevated reputation within scholarly
Since its inception in 1996, SPE Journal has publishing, faster time to publication with monthly
grown into SPE’s flagship journal. It has the issues, and increased opportunities for authors to
highest impact factor (currently 3.602) and highest publish under the expanded scope of the journal
volume of papers of the four journals, publishing and introduction of special article types. We will
between 30 and 50 papers on a bimonthly basis. publish 40–45 papers per month in the new journal
While our current journal portfolio has served as and expect that number to grow. Overall, there will
a foundational resource for the SPE community not be any impact on the content that is covered
for decades, advances in digital publication and an currently in our peer-reviewed journal portfolio.
improved reader experience on OnePetro make The new SPE Journal will cover the fundamental
this the right time to build a single, robust journal research and practical aspects of subsurface
footprint that will provide ease of access to both energy resources for sustainable oil and gas
authors and readers and catapult the journal to exploration and production while broadening
next-level impact. its focus on circular carbon economy, energy
Under the expanded journal, the existing transition, and alternative/renewable energy
editorial boards from each journal will combine sources. It will involve novel theories, emerging
into one editorial board with an editor in chief, concepts, fundamental/applied research and
seven executive editors, and more than 100 development, invited review papers, case

94 JPT | June 2023

 SPE NEWS

histories, and field application studies spanning other special topics of current interest. With
across all domains of petroleum/subsurface this broadened view, we will look at the entire
science and engineering. In addition to the subsurface as an asset that can be utilized for
existing technical disciplines (reservoir, drilling, multiple purposes currently and in the future.
production and facilities, data science and SPE has already begun the consolidation
engineering analytics, etc.), the journal will cover process. Members, subscribers, and authors are
rock physics, geology, geophysics, geochemistry, encouraged to visit the Journal Consolidation page
geomechanics, numerical simulation and to learn more about the process and receive
modeling, injection/production facilities, oilfield up‑to-date information on the steps that are being
chemistry, water treatment, carbon capture, taken to achieve this goal. SPE is committed to
utilization, and storage (CCUS), hydrogen transport maintaining the historical integrity of its peer-
and storage, geothermal energy, digitalization, reviewed journals while ensuring that all authors
artificial intelligence, data analytics, economics, are provided with an inclusive, fair, and positive
health, safety, environment, sustainability, and experience in peer review.

AUTHOR
Birol Dindoruk, SPE, is the engineering from Technical University of Istanbul,
editor in chief of SPE’s journals. an MSc degree in petroleum engineering from
He is currently the American The University of Alabama, a PhD in petroleum
Association of Drilling engineering and mathematics from Stanford
Engineers Endowed Professor University, and an MBA from the University
of Petroleum Engineering at of Houston. His technical contributions have
the University of Houston, having been acknowledged with many awards during
previously been the chief scientist of his career, including SPE Lester C. Uren Award
reservoir physics and the principal technical expert (2014), Cedric K. Ferguson Medal (1994), and
of reservoir engineering at Shell. SPE Distinguished Membership. In 2017, he was
He is well-known for his extensive work elected as a member of the National Academy
on thermodynamics of phase behavior/EOS of Engineering for his significant theoretical
development and experimental work, interaction and practical contributions to enhanced oil
of phase behavior and flow in porous media, recovery and CO2 sequestration. He was
enhanced oil recovery and CO2 sequestration, and an SPE Distinguished Lecturer during the
correlative methodologies. Recently, he has also 2010–2011 season, served as SPE Data Science
been working on data analytics, artificial intelligence, and Engineering Analytics technical director,
and machine learning, with a focus on effective and served as a member of the Advisory
incorporation of data sciences into oil and natural Committee of the SPE Reservoir Dynamics
gas industry practices and energy systems. and Description technical discipline. He has
Dindoruk has 28 years of industrial been active in various editorial positions
experience. He holds a BSc degree in petroleum with SPE and editor in chief positions in Elsevier.

jpt.spe.org 95
 SPE EVENTS Visit www.spe.org/events for a complete list.

Events 24–25 July | Kuala Lumpur

Managing Reserves and Resources in a
Changing Energy Landscape, Realigning
5–8 June | Vienna
Towards a Low Carbon Future
SPE EuropEC—Europe Energy Conference
Featured at the 84th EAGE Annual Conference 8–9 August | Westminster, Colorado
& Exhibition Fiber-Optic Sensing Applications for Well,
Reservoir, and Asset Management
13–15 June | Denver
SPE/AAPG/SEG Unconventional Resources 14–15 August | Denver
Technology Conference Refracturing: A Proven Strategy to Maximize
Economic Recovery
14–15 June | Port of Spain
SPE Latin American and Caribbean Petroleum 15–16 August | Galveston
Engineering Conference Reservoir Aspects of Geothermal Systems

28–29 June | The Woodlands

SPE International Conference on Oilfield
Chemistry
Call for Papers
IADC/SPE International Drilling Conference
8–10 August | Galveston
and Exhibition
SPE Subsea Well Intervention Symposium
Deadline: 8 June
22–23 August | Houston
International Petroleum Technology Conference
SPE Energy Transition Symposium
Deadline: 12 June
5–8 September | Aberdeen
SPE Thermal Well Integrity and Production
SPE Offshore Europe
Symposium

Workshops
Deadline: 12 June

SPE International Conference and Exhibition

on Formation Damage Control
12–13 June | Bali
Deadline: 11 July
Brownfield Solutions—Achieving Balance and
Momentum in Asia Pacific

Sales
19–20 June | Kuala Lumpur
Managed Pressure Drilling (MPD) and
Underbalanced Drilling (UBD)
Mike Buckley Lara Estephan
20–21 June | Kuala Lumpur Media Accounts Manager Media Accounts Manager
Integrated Reservoir Characterisation, (Companies A–L) (Companies M–Z)
Surveillance and Management: Advances Tel: +1.713.457.6828 Tel: +1.713.457.6311
and Challenges mbuckley@spe.org lestephan@spe.org
26–27 June | Kuala Lumpur Danny Foster
Joint Industry Solutions Series—Offshore Associate Director, Americas
Operations and Business Continuity During Tel: +1.713.457.6312
Monsoon Season dfoster@spe.org

96 JPT | June 2023