First Break April 2024 - Underground Storage and Passive Seismic

SPECIAL TOPIC

EAGE NEWS Sneak preview of Annual’s Technical Programme

TECHNICAL ARTICLE Photosphere-based atlas of a high Arctic geo-landscape

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FIRST BREAK ®

An EAGE Publication

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Damian Arnold (arnolddamian@googlemail.com)

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Philippe Caprioli, SLB (caprioli0@slb.com)

Satinder Chopra, SamiGeo (satinder.chopra@samigeo.com)

• Anthony Day, PGS (anthony.day@pgs.com)

• Peter Dromgoole, Retired Geophysicist (peterdromgoole@gmail.com)

• Kara English, University College Dublin (kara.english@ucd.ie)

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• Hamidreza Hamdi, University of Calgary (hhamdi@ucalgary.ca)

Clément Kostov, Freelance Geophysicist (cvkostov@icloud.com)

Martin Riviere, Retired Geophysicist (martinriviere@btinternet.com)

• Angelika-Maria Wulff, Consultant (gp.awulff@gmail.com)

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ISSN 0263-5046 (print) / ISSN 1365-2397 (online)

63

Deferring flood damage in coastal lowlands: assessing surface uplift by geo-engineered CO2-sequestration with easy-to-use land-uplift model

Editorial Contents

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15 Personal Record Interview — Sebastien Lacaze

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18

21

Technical Articles

35 VRSvalbard – a photosphere-based atlas of a high Arctic geo-landscape

Rafael Kenji Horota, Kim Senger, Aleksandra Smyrak-Sikora, Mark Furze, Mike Retelle, Marie Annette Vander Kloet and Marius O. Jonassen.

43 The impact of marine-streamer acquisition technology on broadband time-lapse (4D) seismic data

Patrick Smith, Paul Glenister, Daniel Fischer, Hanna M. Blekastad and Ingrid Selle Østgård.

Special Topic: Underground Storage and Passive Seismic

49 How large should microseismic monitoring networks be for CO2 injection? Case study review

Zuzana Jechumtálová, Leo Eisner and Thomas Finkbeiner

55 Impact of injection rate for CO2 storage within sedimentary basins, a multidisciplinary analysis of focused fluid flow

James R Johnson, Reinier van Noort, Jamil Rahman, Lawrence HongLiang Wang and Viktoriya Yarushina

63 Deferring flood damage in coastal lowlands: assessing surface uplift by geo-engineered CO2-sequestration with easy-to-use land-uplift model Ruud Weijermars

71 Unveiling the depths by deploying Low-Frequency Seismic (LFS) in the Paradise Field area, Australia, to assess the hydrocarbon potential. Roy P Bitrus, Vasilii Ryzhov, Adel Milin, Dmitrii Ryzhov, Ilshat Sharapov, Sergey Feofilov, Evgeny Smirnov, Ivan Starostin, Marion Croft, Frank Glass, Helen Debenham and Simon Molyneux

79 Comprehensive measurement, monitoring, verification planning enables safe CO2 storage, risk reduction, and operating cost optimisation Valeria Di Filippo, Colleen Barton and Pramit Basu

86 Calendar

cover: Digital earthquake wave with circle vibration.

European Association of Geoscientists & Engineers

Board 2023-2024

Near Surface Geoscience Circle

Esther Bloem Chair

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Catherine Truffert Industry Liaison

Mark Vardy Editor in Chief Near Surface Geophysics

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Oil & Gas Geoscience Circle

Yohaney Gomez Galarza Chair

Johannes Wendebourg Vice-Chair

Lucy Slater Immediate Past Chair

Wiebke Athmer Member

Tijmen Jan Moser Editor-in-Chief Geophysical Prospecting

Adeline Parent WGE & DET SIC liaison

Matteo Ravasi YP Liaison

Jonathan Redfern Editor-in-Chief Petroleum Geoscience

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Aart-Jan van Wijngaarden Technical Programme Officer

Sustainable Energy Circle

Carla Martín-Clavé Chair

Giovanni Sosio Vice-Chair

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Laura Valentina Socco Vice-President

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EAGE Annual 2024 Technical Programme to feature more energy transition topics

As the 85th EAGE Annual Conference in Oslo approaches, delegates can look forward to an exceptional Technical Programme showcasing the latest advances in geoscience and engineering. This year saw a significant increase in the abstract submissions with close to 1800 papers being submitted for the event (up from the 1200 abstracts submitted in 2023).

Following the selection processes, the committee has finalised the main Technical Programme, with over 845 oral presentations and close to 250 poster presentations covering a diverse array of topics.

Reflecting on this year’s Technical Programme, Aart-Jan van Wijngaarden, Technical Programme Officer for EAGE, anticipates a large attendance in Oslo. ‘It is clear that people want to share and discuss new technologies and applications in a physical conference. The effectiveness of face-to-face discussions and networking is being recognised, after two years with many virtual meetings. We see an increase both in case studies describing applications of technology and in new technologies being developed in research. Another trend is the integration of AI and ML into the established subsurface disciplines. Therefore we did not make a separate AI and ML theme but integrated this in the existing session themes.

Due to high number of submissions, we had to select approximately 60% best papers based on technical quality and impact for the conference attendees. Some people will be disappointed that their

paper is not selected, but it will ensure a high-value technical programme, with 17 parallel sessions to choose from.

The Technical Programme offers a broad diversity, from detailed seismic processing, advanced geological modelling or dynamic reservoir modelling to regulations for CO2 storage and geohazard monitoring. Sharing and learning across established technical communities is one of the great benefits of such a broad geoscience conference.’

In addition to the submitted abstracts, the Local Advisory Committee and EAGE technical communities have put together a list of over 15 dedicated sessions featuring emerging themes in geoscience, including natural hydrogen, critical minerals, and CCS. Engineering topics are also emphasised, with dedicated sessions focusing on reservoir and petroleum engineering.

Norway has emerged as one of the world’s leading energy hubs and a key area for the development and pioneering of new technologies and low-carbon solutions. With a significant growth in Norwegian-based presenters, our international community will benefit from the strong

showcase of Norway’s innovation and technology leadership. Presentations from leading operators in Norway including Equinor, AkerBP, Vår Energi, Wintershall Dea, OMV and TotalEnergies, will further underscore the nation’s influential role in the industry.

For more details on the Technical Programme and how to participate in the EAGE Annual 2024, please visit eageannual.org.

What’s coming to GET2024 10

Indian students into geoscience

Oslo will feature 250 posters.

Check out the Community Programme at the EAGE Annual

Here are three reasons to participate in the Community Programme at the EAGE Annual in Oslo this June.

First, you’ll connect with high-profile speakers that may broaden your perspectives on technology, energy, and sustainability.

The Women in Geoscience and Engineering Community will host the session ‘Future-Proofing Energy: Empowering Diverse Talent in a Tech-Driven World’, underscoring the indispensable role of diversity in the evolving landscape of geosciences and engineering. Dr Anna Lim, chair of the WGE Community, explains: ‘This one-hour moderated panel discussion will incorporate live polling to foster interactive dialogue. It reflects our commitment to fostering an ecosystem where

diversity enriches our strategies and solutions, recognising the critical need to address biases and cultivate an inclusive culture for ground-breaking ideas and sustainable outcomes.’

Similarly, the Young Professionals Community will host the session ‘Attracting and Retaining Talent’ which will set the spotlight on the career opportunities available in new technologies and game-changing applications in the energy industry. Dr Brij Singh, chair of the YP Community, says: ‘New unconventional domains have emerged, creating a lot of uncertainty among young talent. The session will focus on educating them about the challenges and opportunities these domains provide to inspire them to join the industry’.

Both sessions will be featured in the Strategic Programme on Thursday, 13 June.

Second, with our Artificial Intelligence Technical Community you can get up to speed with the latest trends in machine learning for the energy transition and generative AI. Nicole Grobys, AI Committee member, emphasises: ‘The application of AI for finding solutions to geoscience and engineering challenges including the most important – the energy transition – is a key topic for us.’

On Sunday 9 and Monday 10 June, you can challenge yourself by signing up for the Hackathon on ‘Coding to Net-Zero: AI for Energy-Efficient Future’. Sign up as a team or as an individual (and form a team at the event) at eageannual.org. Great prizes and the chance to showcase solutions to a broader audience await the winning teams.

You are also invited to pass by the Digital Transformation Area on Wednesday 12 June, to participate in ‘Tips and Tricks with ChatGPT, for Geoscientists and Engineers’, an informal presentation (including demos) on how to effectively use applications of large language models, such as ChatGPT, for geoscience and engineering challenges.

Third, Local Chapters Oslo and Stavanger will have the pleasure of introducing you to some of the hidden gems of Norway, followed by some excellent networking time. The session ‘Geosecrets of Norway’ at the EAGE Community Hub on Tuesday 11 June is where you will find the answers to questions such as: What secrets lie beneath the waves off Norway’s coast, where the earth split apart millions of years ago? What very rare mineral treasures lie beneath Norway’s rugged landscape? Why is Norway a prime location for understanding the Earth’s climate past and future?

There is even a bonus! Our Career Advice Centre returns with activities dedicated to helping you stand out from the crowd, e.g., create a strong CV by receiving advice from HR experts and get a professional portrait photo; discuss career development at our Speed Mentoring, and learn how to transfer your knowledge and skills to energy transition-related roles at the ‘Interactive Session: Skills for the Energy Transition’.

Mark the AGMM in your agenda

The Annual General Meeting for Members (AGMM) in Oslo is the time in the year that you can meet the EAGE Board that you elected to oversee the running of the Association. We therefore encourage members to make a note of the

meeting on Wednesday 12 June (13:30 to 14:30).

In addition to the Board presenting reports on the previous year’s activities, the meeting is a valuable opportunity for members to express their views and ideas

for the future direction of the Association. For the Board and the Business Office, the meeting is also invaluable as a chance to meet members direct and hear your views. Visit www.eage.org/about_eage/agmm for more information.

Broaden your perspectives around the dynamic nexus between technology, energy, and sustainability at the EAGE Annual Community Programme.

Imagine producing a better subsurface image, ready for interpretation, in weeks, not months. Using superior physics, DUG Multi-parameter FWI Imaging replaces the traditional processing and imaging workflow, making all that possible now. Don't wait another day to ask us how.

Help build our professional skills map for energy transition

tool is aimed

Every member’s career journey is unique, yet seldom travelled alone. Collaboration and support in finding the right skills, transferring or repurposing them, are intrinsic to the process, just like for knowledge-sharing within the scientific community. This is especially true during periods of transition. For these reasons the EAGE Decarbonization and Energy Transition Community, in collaboration with the Education Committee, are working on creating a tool aimed at delineating the requisite skills for successfully navigating a career in the evolving energy landscape. We are hoping that members will help refine the concept by taking part in a brief survey.

Dr Maximilian Haas, DET Committee member, explains: ‘The tool has the potential to revolutionise our members’ career development. It is not just a tool; it is a catalyst for transformative career development. By addressing the challenges of today

and anticipating the needs of tomorrow, it is poised to become an invaluable asset for our members, ensuring they are wellequipped to thrive in the ever-evolving energy sector.’

The objective of the initiative is to offer a comprehensive learning path, encompassing both technical and non-technical proficiencies, thereby aiding our members in navigating their personal energy transition journeys. DET Committee member, Dr Adeline Parent, notes that ‘as the tool revolves around individuals’ technical skills, and considering that every person has a unique career trajectory, we want to understand what defines you and the competences required for your current role. Together, as a talented and competent workforce, we can successfully tackle the ambitious goal of achieving Net Zero by 2050’.

Maren Kleemeyer, EAGE Education Officer and Education Committee chair, adds: ‘This tool not only identifies skill gaps for a new role but also offers practical guidance on how to address those gaps by connecting relevant skills to the short courses and educational resources provided by EAGE.’

In order to ensure that the insights provided by this tool align closely with the needs of our members, we would like to invite you to participate in a short survey: replies are anonymous and will help us improve the skills mapping as well as identify additional areas where geoscientists and engineers can play a role for the energy transition.

Fill in the survey

EAGE Online Education Calendar

START AT ANY TIME

START AT ANY TIME

START AT ANY TIME

11-12

VELOCITIES, IMAGING, AND WAVEFORM INVERSION - THE EVOLUTION OF CHARACTERIZING THE EARTH’S SUBSURFACE, BY I.F. JONES (ONLINE EET)

SELF PACED COURSE 6 CHAPTERS OF 1 HR

GEOSTATISTICAL RESERVOIR MODELING, BY D. GRANA SELF PACED COURSE 8 CHAPTERS OF 1 HR

CARBONATE RESERVOIR CHARACTERIZATION, BY L. GALLUCIO

PACED COURSE 8

* EXTENSIVE SELF PACED MATERIALS AND INTERACTIVE SESSIONS WITH THE INSTRUCTORS: CHECK SCHEDULE OF EACH COURSE FOR DATES AND TIMES OF LIVE SESSIONS

The

at delineating the requisite skills for successfully navigating a career in the evolving energy landscape.

Why land seismic data often needs to be cleaned up

For its February technical lecture, Local Chapter London together with Local Chapter Houston had the pleasure to host Christof Stork and learn about the wide benefits of producing realistic yet synthetic data which mimics land noise and how it can improve both seismic acquisition and processing of reflection data.

Stork started his presentation with an explanation of the differences between land and marine seismic data, specifical-

ly the challenges of noise contamination and its origins in the presence of near surface heterogeneities associated with land data. He then showed some real data examples depicting distorted refraction multiples (refraction reverberations) before demonstrating his simulations of synthetic data. This focused on scattering and refraction multiples and its impact on signal quality in acoustic and elastic medium. Various approaches of processing were discussed coupled with several

acquisition geometries varying from an ultra-high trace density to digitally created arrays and their effects in the final image.

According to Stork, there are numerous benefits of data modelling, e.g., understanding the physics of the noise, testing the existing processing capabilities and developing new methods, optimising acquisition patterns to name a few.

The presentation was followed by a Q&A session with many interesting questions and discussion from the global audience spanning two continents: those who missed it will be able to find a recording in the EAGE YouTube channel.

EAGE LC London acknowledges Christof Stork for sharing his expertise with the audience; Celina Giersz of Stryde, Lisl Lewis of SLB, Artem Kashubin of Saudi Aramco for hosting and moderating the event. Special thanks to Allan Willis from the EAGE LC Houston for co-hosting and the whole community for joining in!

Secret of teaching a good course is our latest ‘How-to’ video

EAGE continues to be at the forefront of empowering its members with essential skills through its innovative initiatives. One such initiative is the latest addition to its repertoire: the How-to video series, with its latest focus on How to Teach a Good Course, featuring advice from the EAGE Education Committee members: Maren Kleemeyer (chair), Henry Debens, Claudio Bagaini, Ivanka Bekkevold, and Sergey Fomel.

Designed to equip geoscience professionals with the expertise needed to develop impactful courses, this series covers the intricacies of creating compelling content that resonates with learners. It

is the natural follow up to our previous series How to Submit a good abstract, How to get published, and How to present to a live audience, all of which serve as invaluable resources for acquiring useful skills.

Accessible to all EAGE members through the Learning Geoscience platform, the videos provide a wealth of knowledge at no cost, underscoring EAGE’s dedication to accessible education. Along with other free e-learning content such as E-lectures and the Distinguished Lecturer Programme (DLP) webinars, members have access to a comprehensive suite of resources curated to enrich their under-

standing of geosciences and foster professional connections.

Explore the new How to teach a good course series

EAGE offers a wide range of free-learning material to boost your skills.

LC Paris reviews role of minerals in energy transition

We are indeed living in a fascinating era of rapid technological evolution and shifting energy paradigms. Our generation is witnessing the transition from a fuel-based energy system to a mineral-based energy system. With the dramatic change in the demand for critical minerals, supply is becoming a potential source of vulnerabilities for our modern societies as we head towards these cleaner energy systems. Price volatility due to geopolitics changes may complicate and even compromise the industrial development of these crucial technologies.

To get a grasp of the current projects being implemented worldwide, the EAGE Local Chapter Paris arranged a dedicated event ‘Minerals for the Energy Transition’. The event took place at the auditorium at Société Géologique de France, Paris (and was also transmitted online worldwide). Speakers from different companies and institutions were invited to give an overview of their current activities. The event was organised in collaboration with SPE France, a collaboration that continues to bring great value to our community and shows the importance of chapters unifying their effort to provide the best debates for its members.

The first speaker Emmanuelle Robins (Pole Avenia) discussed the aLINA territorial programme, a European initiative that explores the supply chain of

critical raw materials for the industries of the future, through responsible mining but also the recycling of mineral resources such as lithium. Romain Millot (Lithium de France) also spoke about this mineral’s uses, demand and impacts. He presented a case study on geothermal brines and lithium extraction in the French Region of Alsace (Upper Rhine Graben). Lithium

the ambient seismic signals to monitor underground changes once they occur. This could play a crucial role with a minimal disturbance in the ground and make mining operations safer and more environmentally responsible.

Later, Christian Polak shared Orano’s experience with uranium mining cycle operations. A quick overview of Orano’s mining activities in Kazakhstan, Niger and Canada was presented. Polak also went through Orano’s innovative technics in mining uranium such as freezing, jet boring, box hole boring, in-situ recovery, and the SABRE mining system. Finally, uranium forecasts for the next ten years were also shown, highlighting the role of nuclear energy as (at least) a transitional energy to a cleaner future.

Lastly, Lipsa Nag as representation of the French climate tech venture studio Marble explained the goals of the company in the energy transition.

de France is working on the ecology, economics and sovereignty challenges and issues that come with the development of a geothermal lithium industry ecosystem in France.

One solution to the many issues that we tend to encounter in the mining sector was proposed by Jean Charles Ferran, co-founder and president of Geolinks. He showed how innovative passive seismic (monitoring) can mitigate risk in mining exploitation. The technique uses

Marble’s process consists of three steps: finding the best idea, turning the idea into a new company, and finally taking the startup in to the world. The founders-in-residence intend to work on ‘hard climate problems’ later with the Marble teams in order to build ventures with massive impact potential.

For more details on each presentation, join the EAGE YouTube channel where the entire technical presentation has been uploaded there.

EAGE and SPE organisers with the speakers.

Emmanuelle Robins (Pole Avenia) presented the EU-funded aLINA programme.

Virtual and physical field trips offered in Oman naturally fractured rocks

Pascal Richard

Marseille University &

Thomas Finkbeiner

and François Civet

extend an invitation for a one-day excursion on 5 October 2024 in the Oman mountains, offering exceptional outcropping conditions. This expedition is part of the Fifth EAGE Workshop on Naturally Fractured Rocks (6-8 October 2024), with registration fees covering all field trip expenses.

The focal point of our visit will be Jebel Madar, a salt core anticline formed during the Tertiary era due to the collision of the Arabian and Eurasian plates, influencing the current geometry of the Oman Mountains. Notably, we will explore carbonate formations like Natih and Shuaiba, which are important reservoirs for Oman.

Our excursion has two-fold objectives. Firstly, we will observe fault and fracture

corridors within carbonates, with a strong focus on geometry, development timing, and mechanical stratigraphy impact. Discussions will integrate field observations with known regional deformation phases. Secondly, participants will experience collaborative virtual geology from the same outcrop utilising state of the art 3D visualisation tools. This provides an opportunity to trial the added value of virtual field trips after having seen the real fractured rocks in the field.

In the field, we will study fault patterns, e.g., normal faults, transtensional faults, grabens; and natural fractures, e.g., layer bound fractures and fracture corridors that deformed the carbonates. During the day, we will switch from large-scale faults down to small fractures. In combination with the virtual field, we will understand their 3D geometry and imbrication, the relationship to the mechanical stratigraphy and the timing of deformation. This synthesis of field and virtual geology aids in up-scaling for reservoir-size geological models.

The virtual field trip, facilitated by VR-Explorer software from VR2Planets, allows participants to explore Jebel Madar from their locations, providing immersive pre-field trip sessions in September. Beyond introducing the field trip, the software offers access to other remarkable locations on the Djebel, otherwise inaccessible in a single-day physical trip. Participants can revisit these outcrops at their convenience before and during the workshop, maximizing learning opportunities.

Real-time, passive seismic phased

Self contained, autonomous 3C for sustained

(PRgeology), Juliette Lamarche (Aix

CEREGE),

(KAUST),

(VR2Planets)

Jebel Madar South West corner overview from drone survey (picture courtesy of KAUST).

Small scale fracture corridor on pavement.

Pavement and section observations (picture from drone survey, courtesy of KAUST).

How four concurrent conferences will combine to frame the global energy transition technology challenge

Since its inception, the EAGE Global Energy Transition (GET) Conference & Exhibition has mirrored the role of geoscience and engineering in the energy transition. At GET 2024 in Rotterdam from 4-7 November 2024, we will continue the process by proving an unprecedented platform to share the latest developments.

We will be staging specialised sub-conferences on Offshore Wind Energy, Carbon Capture and Storage, Geothermal Energy, and Hydrogen and Energy Storage, highlighting the multi-disciplinary approach needed to tackle energy transition challenges. The four-day meeting will be packed with a range of activities including a conference, an expansive exhibition,

workshops, short courses, field trips, as well as community and student initiatives.

We are currently inviting abstract submissions across all four sub-conferences with a deadline for submissions of 30 June 2024.

Visit eageget.org to learn more.

This is what the GET2024 event will be featuring

Carbon Capture and Storage Conference

Rotterdam’s emergence as one of the world’s inaugural operational Carbon Capture and Storage (CCS) hubs, marked by numerous projects approaching or achieving Final Investment Decision (FID), makes it an ideal location for discussions on the future of CCS. The conference will deliver an extensive programme with the intention of going beyond mere technical discussions by incorporating strategic sessions that tackle the prevailing challenges in expanding the CCS business case. As we move forward, the integration of various stakeholders, including policymakers, industry repre-

sentatives, researchers, NGOs, civil society, and investors, becomes increasingly crucial to bring CCS projects to fruition.

‘The next five years are crucial for the nascent CCUS business in the world and particularly in Europe, with the deployment and operation of the first real CO2 storage projects at scale,’ say conference chairs Ben Dewever (senior geoscientist, carbon capture and storage capability team, Shell) and Mike Branston (new energy domain lead, SLB). ‘The conference will focus on technological progress in areas such as reservoir characterisation, risk assessment, geophysical monitoring of CO2 plumes, and the seamless integration of technical

planning with commercial operations for CCUS ventures, alongside sharing insights from ongoing CO2 injection projects.’

The conference dedicated sessions will bring together high-level speakers from industry, academia, regulatory bodies and other CCUS stakeholders to offer in-depth analyses on specific topics. The technical programme will cover nine main topics and over 25 subtopics, offering a wide range of subjects for exploration and discussion. We invite professionals, researchers, and enthusiasts from the CCUS domain to contribute to this pivotal gathering by submitting your abstracts and joining the technical lineup.

Geothermal Energy Conference GET 2024 proudly announces the first stand-alone Geothermal Energy Conference, set to become Europe’s largest technical congress dedicated to geothermal energy highlighting current progress and the innovative approaches necessary for the upscaling of geothermal energy production.

Our co-chairs, Gehrig Schultz (COO, Geoscience, EPI Group) and Saba Keynejad (environmental data scientist, energy transition and environment, CGG), state: ‘This is an excellent opportunity to be part of a movement that is shaping the geothermal landscape, driving progress, and influencing the path forward. The conference provides the optimal platform to evaluate new technologies, cost-reduction strategies, modelling advancements, and more. Equally important will be the panel discussions led by international experts on policies, incentives, and cross-border collaborations critical to accelerate geothermal deployment internationally.’

The event will feature panels for in-depth discussions on geothermal advancements and practical experiences on pertinent geothermal topics. So, we encourage specialists and researchers to share their findings and perspectives on geothermal energy’s diverse applications, highlighting industry developments, best practices, and existing challenges. The technical programme will cover three main topics, with over 10 subtopics to choose from, ensuring a comprehensive exploration of the geothermal energy field. Participation is particularly encouraged from professionals in the geothermal sector, geoscientists aiming to pivot their expertise to geothermal energy, and community leaders and public officials interested in sustainable energy solutions.

Hydrogen and Energy Storage Conference

Conference chairs Karin de Borst (hydrogen storage lead, Shell) and Marcin Glegola (energy storage specialist, Shell) want to highlight the significance of the geosciences in this evolving landscape – ‘The increasing shift from fossil-based energy sources to intermittent renewable energy sources creates an enormous demand for energy storage solutions. The geosciences will be critical to develop and deploy these solutions. Only the subsurface offers capacities in the GWh to TWh range which will be critical for buffering of weekly to seasonal fluctuations; and it holds the rare minerals that battery storage depends on.’

We are uniting a diverse range of specialists - geoscientists, geologists, engineers, and other relevant professionals – to share knowledge and expertise on projects and research involving hydrogen and energy storage. Attendees will have the opportunity to understand the latest trends, research, and commercial projects in these domains.

Offshore Wind Energy Conference

Conference chairs Gwenaëlle Salaün (senior lead geophysicist, Ørsted) and

Sanket Bhattacharya (seismic business development manager, Fugro), emphasise the critical role of geoscience in the offshore wind sector. They point out that the IEA and IRENA’s projections for achieving 1.5°C global temperature control and net zero by 2050 requires a substantial increase in offshore wind capacity, with the expectation of reaching nearly 500 GW by 2030. This growth necessitates advances in cost-efficiency, time-saving, and supply capabilities. The conference aims to address these challenges by discussing innovative seabed and subsurface analysis methods, geophysical acquisition, seismic imaging, and AI applications, and by fostering a multi-disciplinary dialogue to navigate the industry’s regulatory and environmental considerations.

We aim to bring together a diverse group of professionals, including geophysicists, geologists, hydrographers, geotechnical engineers, and environmental and numerical specialists from both the industry and academia. We encourage you to explore the range of topics, which include six main topics and over 20 subtopics offering a comprehensive overview of the field. Learn more and take an active role by submitting your abstracts.

OUR JOURNALS THIS MONTH

Near Surface Geophysics (NSG) is an international journal for the publication of research and developments in geophysics applied to the near surface. The emphasis lies on shallow land and marine geophysical investigations addressing challenges in various geoscientific fields. A new edition (Volume 22, Issue 2) will be published in April, featuring 11 articles. This is a Special Issue on ‘Ground Penetrating Radar (GPR) numerical modelling research and practice’.

Editor’s Choice article:

• Realistic simulation of GPR for landmine and IED detection including antenna models, soil dispersion and heterogeneity — S. Stadler et al.

Basin Research (BR) is an international journal which aims to publish original, high impact research papers on sedimentary basin systems. A new edition (Volume 36, Issue 2) will be published in April.

CHECK OUT THE LATEST JOURNALS

EAGE and SBGf joint conference in Rio to discuss roadmap to low carbon emissions in Brazil

In an era marked by the pressing need to search for more sustainable and clean energies, the upcoming First EAGE/SBGf Conference on the Roadmap to Low Carbon Emissions in Brazil stands as a significant event. Scheduled to take place from 26-28 November in Rio de Janeiro, the conference represents a milestone for stakeholders within Brazil’s energy landscape. Organised jointly by EAGE and the Sociedade Brasileira de Geofísica (SBGf), this collaboration underscores a shared commitment to addressing one of the most critical challenges of our time.

Central to the success of the conference is the ground-breaking partnership between EAGE and SBGf. The collaboration marks the beginning of a new era in the Brazilian geoscience community, leveraging collective expertise and resources to drive knowledge exchange, technical advancement, and professional growth. The cooperation agreement between the two associations aims to empower the next generation of geoscientists, providing them with the tools and opportunities needed to excel in their careers and make a tangible impact in the field. Through the partnership, students and professionals

The conference aims to facilitate inter-disciplinary dialogue and collaboration to develop a comprehensive roadmap for achieving substantial reductions in carbon emissions within Brazil. The threeday event will feature a rich programme comprising keynote presentations, technical sessions, panel discussions, and workshops. Respected specialists and thought leaders from academia, industry, and government will lead discussions on research, innovative technologies, and best practices.

alike will have access to opportunities for networking, mentorship, and skill development.

As we embark on this journey of learning, innovation, and collaboration, we invite stakeholders from across the geoscience community to join us at this special occasion. Together, we can shape the future of geoscience and pave the way for a more sustainable and resilient tomorrow.

Classic view of Rio.

Unveiling the passion behind a chapter in India

Students at the Indian Institute of Petroleum and Energy (IIPE) in Visakhapatnam tell how they lean towards geoscience.

Embarking on the geoscience journey at the Indian Institute of Petroleum and Energy (IIPE) in Visakhapatnam, our Chapter finds itself fuelled by an unbridled passion for exploration and innovation. The chapter’s formation represents more than just a formality - it symbolises a shared commitment to learning more about the fascinating field of petroleum engineering.

Beyond the academic realm, the initiative is seen as an opportunity to contribute meaningfully to the evolving field of geoscience. The possibility of being featured and promoted in EAGE publications offers an opportunity to establish connections with the international geoscience community. The question of focus looms large – the dilemma is not

just theoretical musing; it’s about aligning academic pursuits with the pressing challenges faced by the industry.

In the pursuit of sustainability, environmental geophysics emerges as a compelling avenue. As petroleum engineering enthusiasts, the Chapter recognises the importance of responsible resource extraction and minimising environmental impact. The aim is to adopt practices that can shape a greener, more sustainable future for the industry, including initiatives like green hydrogen production, promoting net zero emission strategies in India, exploring CO2 storage solutions, and adopting other green technologies.

The digital wave sweeping through geoscience also captures the attention of engineering students. Drawn to the possibilities that data analytics, artificial intelligence, and machine learning bring to the table, the prospect of redefining

traditional practices and ushering in a new era of efficiency and precision in exploration and production is undeniablyexciting.

Finally, the Chapter at IIPE, Visakhapatnam, serves as a proclamation of dedication to improving the state of petroleum engineering. The objective is clear: to set out on an exciting journey of exploration and discovery and invite other engineering enthusiasts to join in influencing the future of geoscience, regardless of whether the inclination is toward environmental geophysics or digital applications.

Members of the EAGE Student Chapter at IIPE.

First row (L-R): Priyanshu Kumar Singh, Sthitadhi Maitra, Abhinav Bhosale. Second row (L-R): Kumar Saurav, Pranjal L. Pachbiye, Shivam Nath.

Chapter members attended the Energy Environment Summit held in July 2023.

Chapter members attended the HERO (Hydrogen Energy Resources and Opportunities) Summit 2023.

EAGE invites the student community to compete in the Online GeoQuiz 2024

We extend a warm invitation to all EAGE Student Chapters that have successfully renewed their membership for the year 2024 to join our EAGE Online GeoQuiz.

As part of our commitment to fostering knowledge exchange and academic excellence, we are excited to announce the Online Geo Quiz, a virtual event scheduled for 10 April 2024.

This is an opportunity to engage and challenge students in the field of geoscience, providing a platform for intellectual growth and friendly competition. We encourage all eligible EAGE Student Chapters to participate in this exciting event, which promises to be both educational and entertaining. The event will take place in an online format on 10 April 2024 with a deadline for registration of 8 April 2024.

The Online GeoQuiz tests participants’ knowledge across various aspects of geoscience, offering a chance to showcase their expertise in a virtual environment. We believe this event will not only be a source of academic stimulation but also an avenue for networking and collaboration among student communities.

will each be awarded three complimentary registrations to attend our Annual Conference and Exhibition, taking place in Oslo, Norway, from 10 to 13 June 2024.

How to participate? Interested student chapters can register for the Online Geo Quiz until 8 April 2024. Scan the QR code to register and find more details about the event. For any additional information or queries, feel free to reach out to us at students@eage.org.

We look forward to your active participation in the Online GeoQuiz 2024. Let’s come together virtually to celebrate knowledge, camaraderie, and the spirit of exploration in geoscience!

The EAGE Student Fund supports student activities that help students bridge the gap between university and professional environments. This is only possible with the support from the EAGE community. If you want to support the next generation of geoscientists and engineers, go to donate.eagestudentfund.org or simply scan the QR code. Many thanks for your donation in advance!

A geoscientist in transition Personal Record Interview

A serial entrepreneur, Sebastien Lacaze last July launched an energy transition consultancy called LookUp, a logical progression from Eliis, an innovative seismic interpretation company he co-founded 15 years ago. Influenced by family, fascination with geoscience began early in life. He worked first as a seismologist in Nepal, before landing an oil industry job with Techsia in his home town of Montpellier, where he has been based ever since.

Early life in Montpellier

My parents, a psychiatrist and psychologist, shaped my vision of teamwork and openness. They also took my sister and I along the limestone paths dotted with holm oaks in the Mediterranean hinterland. We were fascinated by the traces of the earth’s history, we observed the strata, the outcrops with curiosity, we already loved the beauty of the ground. The little flame started to light and never went out!

‘Damascus’ moment

My uncle Alain Gavignet, a physicist whom I idolised, played a decisive role in my life. When I was just nine years old, he took me to the Schlumberger Research Centre in Cambridge where he worked and showed me how they were engineering logging tools. I ‘discovered’ his profession, how it pushed forward the limits.

Student studies

My interest, indeed, my passion for geosciences grew steadily over the years. I studied geophysics at the University of Montpellier, then Brest and finally Paris. I met some fantastic teachers like Pierre Andrieux in Paris, an associate professor also working for CGG. He introduced me to applied geophysics in the industry. I was also lucky enough to go to New Caledonia to prepare a Masters thesis using marine geophysical data to better understand plate tectonics in the Fiji region of SE Asia.

Formative experience in Nepal

My first professional assignment was in Nepal, on an international cooperation

project for the Department of Mines and Geology focused on developing seismic signal processing tools applied to seismology and geodesy. It was a real shock! The culture, the customs, the environment... everything changed. I was seduced. I learned the language, immersed myself in the values of the country and discovered a fascinating world. I was also learning the basics of the job with the geophysics laboratory of the French Atomic Energy Commission to which I used to report.

Early years in O&G

In 2004, I was hired by Techsia, a Montpellier-based company specializing in software development for well log analysis, later acquired by Schlumberger. The work did not really suit my skill set. I found that the subsurface analysis offered to customers, based on a few geological maps, still lacked accuracy. A much more detailed model was needed. The idea seemed obvious and inspired my first company.

The Eliis story

With the experience of Techsia behind me, I teamed up with my colleague, Fabien Pauget, the best expert in image processing I know, to start a company called Eliis (Elite Image Software). We first began in the medical sector, working in neuroradiology analysing brain aneurysms from 3D scan and MRI.

But our shared passion soon caught up with us. We decided to concentrate our efforts on our preferred field, geoscience, and more specifically applications in oil and gas exploration. The seismic interpre-

tation software PaleoScan we developed did well and the company now employs around 70 people.

Energy transition start-up

I was convinced that geoscience is an essential discipline for the energy transition and revolution. The subsurface conceals sources of renewable energy that are still poorly understood or insufficiently exploited, such as geothermal energy and natural hydrogen. We need to be innovative to face all the environmental challenges.

I decided to create LookUp, a new company to bring together open-minded people so that by working together and sharing information we can harness the power of geoscience to accelerate the transition.

Advice for start-up beginners?

The most important thing: do not be guided by your fears, pursue your idea, and believe in yourself!

Beach volleyball diversion

I’ve been playing volleyball since the age of 14 and I live by the sea: two good reasons to become president of Montpellier Beach Volley club, the biggest in France! The sport combines values that are essential to my life as an entrepreneur: the importance of teamwork, respecting and listening to one’s teammates, a sense of effort and the joy of succeeding. This discipline has two final assets that are quite rare in the sporting world: it features almost perfect gender equality and low CO2 emissions. All you need is a ball and a net!

Sebastien

3rd

3rd EAGE Workshop on EOR Deadline: 15 May

1st EAGE Workshop on The Role of AI in FWI Deadline: 22 May

8th EAGE High Performance Computing Workshop Deadline: 22 May

1st EAGE Conference on Energy Opportunities in

Caribbean Deadline: 30 May

MORE TO EXPLORE

CROSSTALK

BY ANDREW M c BARNET

BUSINESS • PEOPLE • TECHNOLOGY

What drives a supermajor

If one was to hazard a guess, ExxonMobil probably earns top spot among the anti-oil industry lobby as the arch villain, accused among other things, of making obscene profits at the expense of the environment, harbouring a well-documented history of denial and misinformation about climate change and making only miserly investments in energy transition technology.

None of the supermajors are immune from some of the same or similar accusations, but rarely do we get a full-on response.

Step up Darren Woods, CEO of ExxonMobil. In a recent 45-minute video interview with Fortune magazine editors, Woods expanded on views previously aired since he took over leadership of the company in 2017. He delivered as plausible a rationale as you are likely to hear of how his particular company with its history regard its role and responsibility in the energy mix, adding some home truths. There were of course some notable omissions in the narrative (no mention of size of profits or amount returned to shareholders) nevertheless the message is salutary particularly his insistence that the time has come to base energy transition on more than aspiration.

Woods maintained the company had moved on from its past history with climate change, recognised the challenge of decarbonisation and was set on leveraging some core competencies ‘to solve what we can’. However, he insisted that communities around the world are not prepared to pay the true price of energy transition. ‘The dirty secret nobody talks about is how much all this is going to cost and who’s willing to pay for it,’ he said. ‘The people who are generating those emissions need to be aware of and pay the price for generating those emissions. That is ultimately how you solve the problem.’

he supported carbon tax and has been encouraged by the Biden Administration’s 2022 Inflation Reduction Act which included subsidies in the US for developing climate change mitigation and energy innovation. But he referred to government intervention as only a bridge to the future, arguing that in the end market forces will have to take over. Building a business on government subsidy was not a long-term sustainable strategy.

As a company he said ExxonMobil was focused on investing in the development of new solutions, such as CCS and hydrogen, so how much it has spent on energies such as wind and solar compared, for example, with European peers, was false. The company did not bring any special competencies to that space ‘other than a cheque book’ and would not be able to deliver ‘above average returns to our investors’. ExxonMobil’s strategy leaned towards starting businesses from scratch, and those opportunities took time to develop.

‘World not prepared to pay true price of energy transition.’

If Woods had hoped that the response to his remarks would help his stated mission to promote better understanding of the company’s perspective, he was probably disappointed. Reporting the interview, The Guardian newspaper, something of an eco warrior in the UK press, tacked on quotes to its report on the interview from among others Gernot Wagner, a climate economist at Columbia Business School. ‘It’s like a drug lord blaming everyone but himself for drug problems. I hate to tell you, but you’re the chief executive of the largest publicly traded oil company, you have influence, you make decisions that matter. Exxon are at the mercy of markets but they are also shaping them, they are shaping policy. So no, you can’t blame the public for the failure to fix climate change.’

He also warned that we are not on the path to net zero by 2050, ‘objective analysis will tell you that’ and that existing technology will not get us there. In his view the cost of transition to a lower carbon economy has to be made explicit, and governments know that their constituents have a problem with that. Woods said

Ironically ExxonMobil is currently flexing its musles in its core oil and gas business, for which Woods makes no apology. Last October it launched a $59.5 billion takeover of Pioneer Natural Resources creating what it described as the industry’s leading high-quality undeveloped US unconventional inventory

position. Together, the companies will have an estimated 16 billion barrels of oil equivalent resource in the Permian. At close, ExxonMobil’s Permian production volume would more than double to 1.3 million barrels of oil equivalent per day (moebd), based on 2023 volumes, and is expected to increase to approximately 2 moebd in 2027. The company has stated that it plans to accelerate Pioneer’s net zero Permian ambition from 2050 to 2035. The acquisition, the biggest since Shell acquired BG in 2016, comes at a time when US crude oil production in 2023 headed global oil production for a sixth straight year, with a record breaking average production of 12.9 million b/d, according to the US Energy Information Administration (EIA),

Now ExxonMobil is locked in a commercial battle with rival US supermajor Chevron headed by CEO Mike Wirth, who has also repeatedly been clear about the continuing need to focus on producing more hydrocarbons for the world in the energy transition era. ExxonMobil has put a spanner in the works of Chevron’s $53 billion recent bid for Hess oil corporation. A big attraction of the proposed takeover for Chevron is the 30% stake in the Guyana consortium held by Hess. This massive prospect has already yielded more than 11 billion barrels of discovered oil in the Stabroek offshore block, with estimated recoverable reserves of more than of 20 billion barrels. ExxonMobil has an existing 45% stake in the consortium and argues that it has right of first refusal regarding any sale of partner assets. At this stage it is unclear whether there can be a negotiated settlement or the whole deal will be nixed. An obvious takeaway is that competition in the industry is intense as ever and no inch is being given in the drive for recoverable reserves in favourable environments.

against Hamas in the Gaza strip and oil supplies from the Gulf states are being put in jeopardy by attacks on cargo shipments.

It is just as well that these days the old connection between oil price and oil company investment sentiment is generally thought to have been severed. Otherwise the signals from the market would be considered confusing in the extreme. In January Saudi Arabia ordered Aramco to cap its maximum sustainable capacity to 12 million b/d instead of a planned 13 million b/d. Such action would imply some disenchantment with future oil demand worldwide.

‘Supermajors are heading back into deep water exploration.’

Meanwhile in March Reuters reported that according to its research OPEC and the International Energy Agency (IEA) are further apart than they have been for at least 16 years in their views on oil demand in 2024.

IEA believes that demand will rise by 1.22 million b/d this year, while OPEC suggests 2.25 million b/d, a difference of about 1% of world demand. According to Reuters this is about differing perspectives on the market for oil in 2024, but also on the speed of the world’s transition to cleaner fuels where OPEC clearly takes a more sceptical view. There have been mutterings elsewhere that peak oil demand would max out later than 2030, a previously popular projection.

The mega mergers themselves do not come as a particular surprise because Big Oil has been recording huge profits for its stakeholders, generating plenty of cash in recent years. In 2022 ExxonMobil, Shell, Chevron,TotalEnergies and BP reported some $200 billion in profits of which ExxonMobil’s share alone was $59 billion. Also the argument for adding reserves through acquisition rather than through the drillbit has always been persuasive if the price is right.

Consolidation has implications. It potentially affects the total spend on exploration and development that service companies can expect as a result of a more concentrated customer base and possible re-evaluation of reserves replacement strategy. As it happens the industry as reflected by the supermajors continues to be based on the analysts’ favourite term, capital discipline, to which you can add risk aversion in a period of geopolitical turmoil. The market has had to adjust to a market profoundly shaken by the Covid epidemic followed by Russia’s incursion into Ukraine and threat to Europe’s natural gas supplies. Now the Middle East region is on a knife edge as Israel continues its military action

Oil companies have sustained themselves in the last ten years by confining much of their reserves investment to infrastructure-led exploration, thereby producing more oil in a low risk environment during major economic uncertaintly worldwide. For geoscience-related companies serving the industry, this made for a troubled decade decimating the global marine seismic vessel fleet dependent upon oil company exploration budgets. The only upside has been the development of a credible seabed seismic capacity to meet oil company 4D and other reservoir characterisation requirements at an acceptable cost.

We are now witnessing change in that the supermajors are heading back into deepwater exploration, hence the scrap between ExxonMobil and Chevron over the Guyana oil riches. The reordering of budget priorities is seemingly based on the calculation that the current minimal risk E&P strategy will not deliver sufficient reserves to meet demand in the years to come.

In a review of trends for 2024 S&P Global noted the search led by global IOCs is on for ‘sizeable prospects where the potential return is large enough to ensure profitability in lower oil-price environments (particularly for frontier areas without existing infrastructure). These companies are betting big on offshore areas in the Eastern Mediterranean, Southern Africa (Namibia and South Africa), as well as Angola, Brazil, Guyana and Suriname because of favourable resource characteristics and investment conditions.

How this all affects future seismic business is a moot question, but the omens are surely favourable.

Cost Revolution in Mineral Exploration

Ambient noise surface wave tomography allows us to resolve the deep (800-1000 m) cover contact, as well as peek beneath. These sort of wide area, low resolution images can be obtained relatively cheaply : a recent survey over 5,000 km² cost <US $60/km²

less than aero grav

about 1/3 the price of MT

1% cost of reflection seismics

Thanks to SISPROBE for providing the data.

INDUSTRY NEWS

UK launches consultation on seismic data for carbon storage

The UK North Sea Transition Authority (NSTA) has launched a consultation to determine what data relating to CO2 storage should be made public and when.

Information gained from geophysical surveys, well data, and injection tests will be among the wealth of information that could be obtained and used in planning and future decision-making.

‘Once in place the easy access to data will encourage new entrants into the industry and help to cement the UK’s position as an international leader in the sector which is vital in the drive to reach net zero greenhouse gas emissions,’ said the NSTA.

The UK National Data Repository already houses more than one petabyte of freely-available information gleaned from more than 60 years of activity. ‘Originally set up to support the oil and gas industry, it is increasingly used by companies, academics and individuals working in carbon storage, offshore wind and hydrogen, and it is expected that this new information will make a significant addition to that resource,’ said the NSTA.

There are currently 27 carbon storage licences in place in UK offshore waters. Twenty-one were awarded last year in the UK’s first-ever carbon storage licensing round. Early progress is being made on them, said the NSTA. The UK government has included some of these in the four Track 1 and Track 2 clusters, selected to speed up

the growth of the industry and encourage first injection as soon as possible.

The four CCUS clusters are expected to contribute to the target of capturing and storing 20-30 million tonnes per annum (Mtpa) of CO2 by 2030.

The UK published its ‘Carbon Capture Usage and Storage Vision’ in December 2023, pledging up to £20 billion investment in the sector to create a competitive market in carbon capture, usage and storage (CCUS) by 2035.

scheme has received more than £1 billion from the UK government. It has allocated a record £800 million for offshore wind, four times more than was made available to offshore wind in the previous round, helping to deliver the UK’s ambition of up to 50GW of offshore wind by 2030, including up to 5GW of floating offshore wind. The CfD scheme gives renewable energy projects a guaranteed price for the electricity they generate.

Nic Granger, NSTA director of corporate, said: ‘Access to this data will enable users to identify potential carbon storage locations and assist decision making in this growing sector.’

Meanwhile, Britain’s flagship Contracts for Difference (CfD) renewables

Some £120 million was allocated for established technologies such as onshore wind and solar and £105 million for emerging technologies such as floating offshore wind and geothermal.

Companies can bid for contracts in the sixth CfD auction.

Seismic shows gas find in Tanzania

PGS shoots survey offshore Egypt

Bangladesh launches licensing round

Archive / Illustration / Courtesy of North Sea Transition Authority (NSTA).

CGG publishes carbon capture study for Indonesia, Malaysia, Thailand and Vietnam

CGG has released the Southeast Asia Carbon Storage Study to support and accelerate the screening process for all players in the region’s fast-growing CCUS market.

The study ranks and prioritises opportunities across 58 basins in Indonesia, Malaysia, Thailand and Vietnam, covering a total

surface area of more than 6 million km2, to help streamline the process for identifying the best basins and plays for potential carbon storage. The study and its associated data are available to licence now.

The Southeast Asia Carbon Storage Study is a new addition to CGG’s GeoVerse Carbon Storage portfolio which already includes studies for the North Sea and US Gulf of Mexico. Developed by experts from CGG’s Carbon Storage, Geology and Data Hub teams, the studies provide an assessment of storage potential based on a proprietary quantitative and qualitative criteria-based screening methodology which assesses deep subsurface features and the above-ground context.

Dechun Lin, EVP Earth Data, CGG, said: ‘The release of this carbon storage screening study comes at a time of accelerated growth in the Southeast Asia CCUS market and will provide operators with accurate and critical subsurface information for rapid insight and decision-making. With this strategic addition to our growing portfolio of carbon storage screening studies, CGG is expanding its footprint and experience in all active CCUS hubs around the globe.’

EMGS wins multi-client survey in the North Sea

EMGS has won a contract from Equinor for a fully prefunded multi-client survey in the North Sea. The survey is expected to have a contract value of approximately $2 million. The fully prefunded survey was expected to start in early March 2024.

Meanwhile, the company has reported fourth quarter 2023 revenues of $1.1 million, down from $15.2 million in the fourth quarter of 2022 and down from $1.6 million in the third quarter of 2023. Adjusted EBITDA (including capitalised multi-client expenses and vessel and office lease expenses) was a loss of 1.7 million, down from a profit of $8.2 million in the fourth quarter of 2022.

Free cash decreased to $10.3 million at quarter end.

Overview of basins covered by the Southeast Asia Carbon Storage Study and snapshot of storage play segmentation (image courtesy of CGG Earth Data).

PGS makes Southern North Sea data available

PGS has made data available from the SNS Vision project targeting exploration potential in the mature Southern North Sea gas province.

The final data supports exploration both for post-salt CO2 storage potential in the Triassic Bunter sand formation and nearfield exploration targets.

SNS Vision covers open exploration acreage, as well as eight recently awarded CCS licences. It provides reliable and consistent depth-migrated regional data for screening and evaluation of the carbon storage site.

Twenty-six datasets included in the project have benefited from imaging reprocessing, including a 2 millisecond broadband processing, modern deghosting, complex demultiple flow that is optimised for shallow water, and depth migration based on full waveform inversion (FWI).

This resulted in a seamless seismic data volume with improved resolution over approximately 12,000 km2 that is suitable for both conventional exploration and CCS projects from shallow to deep.

Imaging of complex geology and salt tectonics has been effectively addressed through depth velocity model building (VMB), tomography, FWI updates, and Kirchhoff prestack depth migration (KPSDM). FWI has successfully resolved shallow features, and revealed shallow salt and cap rock details.

An accurate depth velocity model, with well control coming from 31 wells spread over the entire project area, was crucial for achieving high-quality seismic imaging of the Southern North Sea gas province.

After the SNS Vision seismic reprocessing effort, PGS performed an automatic regional horizon interpretation to rapidly interpret the volume and particularly the CO2 storage horizons, namely the Bunter Sand Formation interval.

Using an Eliis PaleoScan relative geological time (RGT) model, PGS rapidly generated detailed horizon stacks. It then

derived inversion data, seismic facies volumes, spectral decomposition and visualised these at a chronostratigraphic level (an example is shown on the data library tile below). In less than one month, this method allowed it to interpret a significant area of around 12,000 km2 without much a-priori seismic interpretation.

Quantitative interpretation (QI) characterisation of this dataset has included petrophysics and rock physics analysis, well-toseismic calibration, seismic stack(s) optimisation or conditioning prior to seismic inversion for elastic property estimation, transform to reservoir properties (porosity), and integration of the above with the detailed high-resolution seismic interpretation. These results are also available.

To establish a proper reservoir understanding, first developed a rock physics understanding by creating a rockAVO product. To this end, it screened 25 of the two thousand wells in the area. The wells used were selected based on log data availability, length, and quality. Porosity estimation was then performed for the BSF interval at regional scale, with use of the 25 rockAVO wells for the calibration and establishment of the transform between the elastic properties and the target property (porosity).

Meanwhile, Norway’s Halten and Dønna Terrace is revealed in unprecedented multi-azimuth detail by PGS’ final GeoStreamer X Norwegian Sea data.

Full stack depth imaging is now available for the first 7000 km2 tranche of GeoStreamer X Norwegian Sea, over of the Halten/Donna Terrace.

The final subsurface images provided by GeoStreamer X Norwegian Sea reveal structure and stratigraphy in unprecedented detail in both shallow and deep settings.

‘The detail on our final GeoStreamer X data is so sharp, it makes our interpreters’ fingers itch. It’s a new level of understanding the traps and plays, allowing your team to reassess new and missed exploration opportunities and volumetrics on the Halten-Dønna Terrace,’ said Sónia Pereira, VP of Data Sales Europe at PGS.

Shearwater wins UK CCS data contract

Shearwater GeoServices has won a contract from Spirit Energy for advancing carbon capture and storage (CCS) capabilities in the UK. The six-week project in the Morecambe Bay in the northwest of the UK is scheduled for the summer of 2024 and will be Shearwater’s fifth CCS survey in the last two years.

It relates to Spirit Energy’s recent carbon storage licence award by the UK’s North Sea Transition Authority (NSTA). The licence is a key step forward in transforming the North and South Morecambe gas fields into permanent, safe, and secure carbon storage, supporting the UK’s Net Zero ambition to capture and

store over 50 million tonnes of CO2 per year by 2035.

Tanya Herwanger, SVP strategy and new markets at Shearwater, said: ‘By applying our innovative data collection and imaging technology to help operators gain a better understanding of their storage sites we support deployment of CCS at scale.’

Meanwhile, Shearwater has won a contract from India’s Oil and Natural Gas Corporation Limited (ONGC) for a survey in the Cauvery Basin, off the east coast of India.

Set to begin in the early months of 2024, the project will cover a 4600 km² area in the Bay of Bengal, utilising the vessel SW Empress Vessel SW Empress.

Seismic interpretation indicates large gas find in Tanzania

Tanzania-based oil company Aminex has completed seismic interpretation of the recently acquired 338 km2 3D seismic dataset over the Ruvuma PSA, which indicates potentially the largest onshore gas discovery in East Africa.

The data indicates improved in-place volumetrics for the Ntorya gas discovery onshore Tanzania and revealed a significantly higher resource potential in the wider licence area than previously identified on the existing sparse 2D database.

The interpretation of the 3D seismic has been completed by the Ruvuma PSA operator, ARA Petroleum Tanzania (APT). Seismic inversion geomodelling, undertaken in collaboration with Ikon Science, has defined a high confidence area with a revised in-place volumetric estimate for the Ntorya gas discovery. A most-likely (approximating to P50) estimate of 3.45 trillion cubic feet (Tcf) of Gas Initially In Place (GIIP) is now believed to be potentially connected to the reservoir sandstones encountered in the Ntorya-1 (NT-1) and Ntorya-2 (NT-2) discovery wells. This revised Ntorya volume represents a substantial increase to the published P50 GIIP of 1.64 Tcf estimated by RPS Energy (RPS) in February 2018.

Furthermore, the new 3D seismic data images a possibly even larger area of gas charged reservoir sandstones, beyond the high confidence area established by the new seismic inversion modelling. This provides for potential additional prospective

gas volumes associated with the Cretaceous age sand units tested in NT-1 and NT-2 (Units 1 and 2) and for the possible existence of an as yet undrilled shallower sand unit (Unit 3), to be tested by the forthcoming Chikumbi-1 (CH-1) appraisal well later in the year. An upside aggregated GIIP volume for the Ntorya accumulation based on a success case in multiple stacked sands at CH-1, is estimated by APT to be up to 7.95 Tcf (approximated to a mean unrisked P10 GIIP).

RPS has been engaged to undertake a revision of its 2018 study to support the initial Field Development Plan. The study is likely to focus on a much narrower area of the reservoir, surrounding the two existing wells and CH-1 location that will be targeted for initial production, with the aim of defining preliminary 1P and 2P reserve estimates. These reserve estimates are expected to increase substantially as phased development and project maturation progresses in light of the results of the newly reported APT interpretation studies.

The 3D dataset has also revealed, for the first time, considerable undrilled exploration potential within the broader licence area. Multiple undrilled structural and stratigraphic plays spanning a range of geological intervals are estimated by APT to contain a total Pmean unrisked GIIP potential of 8.43 Tcf (excluding Ntorya). These new plays and prospectivity currently identified to date contain a risked Pmean GIIP exploration potential

of ca 2.2 Tcf. Continuing work, including advanced seismic imaging and reinterpretation of existing wells, is being undertaken to reduce geological uncertainty and mature the new exploration portfolio. The new volumetric studies result in a total updated unrisked GIIP volume for the Mtwara Licence of 16.38 Tcf.

Charles Santos, executive chairman of Aminex said: ‘The quality of the new 3D seismic dataset was excellent giving the JV partners the ability to map in detail the Ntorya gas discovery, refine volumetric estimates and provide the basis to locate future appraisal and development drilling targets. We are particularly excited by the significant potential gas volumes now identified in other untested structures within the licence area. To place these volumes in context, the Ntorya accumulation is potentially the largest onshore gas discovery in East Africa and, with the sizeable new exploration targets, should be much less expensive to exploit than offshore resources.’

TGS adds new US carbon storage datasets

TGS has expanded the coverage of its CO2 storage assessment datasets by adding eight additional US onshore basins. Gulf Coast Onshore, Permian, Illinois, Michigan, Appalachia, North Dakota, Sacramento-San Joaquin and DJ, include interpretation on more than 43,000 wells across 378 million acres.

‘Our CO2 storage assessment offers a comprehensive geologic assessment of saline aquifer storage potential by leveraging our vast subsurface library of seismic, well, and geologic data,’ said TGS in a statement.

The subsurface assessment for carbon storage in saline aquifers considers the geologic structure, reservoir characteristics, fluid dynamics and caprock integrity to provide insights when identifying the most promising subsurface formations for carbon sequestration.

TGS added that the expansion of its CO2 storage assessment is supported by industry funding and the individual basin assessments will be released as they are completed throughout 2024 and 2025.

ENERGY TRANSITION BRIEFS

Chevron is developing a 5-megawatt hydrogen production project in California’s Central Valley. The project aims to create lower carbon energy by utilising solar power, land, and non-potable produced water from Chevron’s existing assets at the Lost Hills Oil Field in Kern County. The facility will produce two tons of LCI hydrogen per day, with the goal of supporting an expanding hydrogen refuelling network.

New York State Energy Research and Development Authority (NYSERDA) has announced Equinor’s Empire Wind 1 project, one of the conditional winners in its fourth offshore wind solicitation round. The project will deliver 810MW of renewable energy to New York.

CO280 Solutions and a leading pulp and paper company have awarded a carbon capture test campaign to Aker Carbon Capture for an undisclosed site on the Gulf Coast in the US. It will enable the full-scale implementation of multiple Just Catch 400 modular capture facilities with permanent storage, and the creation of carbon removal credits.

The UK has announced more than £21 million of funding for hydrogen production plants. Suffolk Hydrogen, run by Hydrab Power, will make green hydrogen for low carbon service vehicles at the Sizewell C nuclear site. Tees Valley Hydrogen, run by Exolum, will build a new hydrogen refuelling station to help supply the local transport sector.

Norway has invited applications on two areas in the North Sea for CO2 injection and storage on the Norwegian Continental Shelf. Several commercial companies have made inquiries to the Ministry of Energy regarding one or more storage areas. These inquiries form the basis for the areas now being announced.

Ørsted has agreed with Incheon Metropolitan City, Korea, to cooperate on developing an offshore wind power industry in the region driven by Ørsted’s 1.6 GW offshore wind project off the coast of Incheon.

TGS launches well data app

TGS has launched the FMB Cloud app, marking a fundamental enhancement to its Facies Map Browser (FMB) platform, which provides geoscientists with a standardised and interpreted well dataset.

FMB Cloud provides comprehensive access to well-based stratigraphic interpretation and sequence-constrained facies maps. It enables the user to perform a range of visualisation, manipulation and data analysis techniques, resulting in increased levels of geologic knowledge and accelerated regional hydrocarbon and carbon storage assessments.

TGS said in a statement: ‘The well data suite utilises digital wireline logs, scanned image files, drilling reports, lithology and biostratigraphic information to provide high-quality log data coupled with expert geological interpretation. The result is a standardised, workstation-ready and geologically consistent dataset that reduces risks and accelerates exploration.’

Meanwhile, TGS has also announced a strategic partnership with Entertel to deliver an integrated solution to empower operators with seamless access to TGS licensed well data through Enertel’s QuantumCast software platform.

The partnership will grant Enertel direct access to a customer’s entitled TGS well data, including the utilisation of TGS Application Programming Interfaces (APIs) embedded directly within QuantumCast, facilitating enhanced operational efficiency and decision making.

The well data provided by TGS within Enertel’s analytical platforms encompasses a range of information, including well headers, formation tops, logs, as well as production and completion data.

Fred Enochs, co-founder and CEO of Enertel said, ‘Through the partnership with TGS Well Data, we are able to provide a comprehensive analytics platform for rapid forecasting, asset evaluation, and basin analytics.

CGG reports fourth quarter operating loss of $11 million

CGG has reported an operating loss of $11 million and a group net loss of $15 million on fourth quarter revenues of $265 million compared with an operating profit of $84 million and a group net loss of $49 million in Q4 2002.

Full-year operating profit was $119 million with a group profit of $16 million on revenues of $1.075 billion compared to operating profit of $182 million and group profit of $48 million on revenues of £927 million in 2022.

Fourth quarter Data, Digital and Energy Transition revenue was $201 million, down from $205 million in Q4 2022. Geoscience revenue was $98 million, up 41% year-onyear driven by delivery of large processing projects. ‘Activity remains solid worldwide with Elastic TLFWI technology continuing to prove its value and receiving recognition from clients,’ said CGG. However, Earth Data after-sales were $41 million, down 47% year-on-year mainly due to delayed licensing rounds in Brazil and in the GoM.

Sensing and Monitoring Revenue of $119 million was up from 104 million in Q4 2022.

Looking ahead for the next two years CGG anticipates market demand for its core businesses to continue to grow at yearly mid-single digit through 2026 sustained by offshore international activity and the Middle East, and selected exploration in key basins. In new businesses it is more optimistic. ‘CGG is strongly positioned to address the critical needs of new markets in low carbon (CCUS and minerals and mining), high performance computing (HPC) and structural health monitoring (SHM). These three businesses are expected to develop rapidly at above 30% during the period 2024-2026.

Sophie Zurquiyah, CGG CEO, said: ‘In 2023, CGG significantly strengthened its financial performance, and I am pleased to see that we returned to positive organic cash flow generation, while continuing to invest in our new businesses.’

PGS reports fourth quarter operating profit of $83 million

PGS has reported a fourth quarter operating profit of $83 million and net income of $60 million on revenues of $265 million compared to an operating profit of $46 million and a net loss of $5 million on revenues of $217 million in Q4 2022.

Rune Olav Pedersen, president and chief executive officer, said: ‘It was reassuring to experience a doubling of Q4 multi-client late sales, compared to the average of the three first quarters of 2023.

In Q4 most of our late sales came from Europe and West Africa. We worked on highly pre-funded multi-client projects in Brazil and Malaysia in the quarter, and in addition we recorded significant sales from surveys in the processing phase contributing to a strong pre-funding level of 148% of the capitalised multi-client cash investment.

Profitability of our contract projects in Q4 were level with the summer season. We are experiencing lower acquisition activity over the winter season. At the same time the value of contract leads continues to grow. In addition, we see increasing opportunities for new multi-client programs and anticipate a more robust summer season market.

‘For the full year 2023 we benefited from an improving data acquisition market with a high pre-funding level on our multi-client projects and increasing profitability

for contract work. Despite this, revenues declined compared to 2022 owing to unexpected scheduling and operational challenges, and lower than expected multi-client late sales.’

In its outlook, PGS said: ‘Offshore energy investments are expected to continue to increase in 2024. The seismic acquisition market benefits from the higher spending level and a limited supply of seismic vessels. PGS New Energy is expected to benefit from an increasing tendering activity for offshore wind site characterization projects.’

Capital expenditures for 2024 is expected to be approximately $125 million, including capex to expand the offshore wind activities and some 2023 streamer capex delayed into 2024.

The order book amounted to $366 million on December 31, 2023. On September 30, 2023, and December 31, 2022, the order book was $437 million and $416 million, respectively.

Meanwhile, PGS is supporting Papau New Guinea’s Department of Petroleum and Energy to digitalise it’s access to data.

PGS is supporting the digitalization of DPE archives by providing a wide-format scanner and essential archive supplies.

In 2022, the DPE relocated to newly built offices in Waigani (central Port Mores-

by), which highlighted the need for modernisation of its document archives. The DPE currently stores hundreds of archive boxes containing paper reports and logs, along with other data on various physical media such as CDs and exabyte tapes. Digitalisation will make access to valuable data easier for companies exploring and developing new energy projects. The new scanner provided by PGS can do image-totext conversion for paper reports and can also scan long paper logs.

There is renewed interest in PNG’s energy sector as the government continues to stabilise its investment and development policies, said PGS. Access to reliable data supports this trend, it added.

The highly prospective Gulf of Papua is covered by two large multi-client 3D surveys, mapped by PGS. The 2011 Solwara MC3D and the 2020 Painimaut MC3D datasets benefit from modern demultiple techniques, full-waveform inversion (FWI), and pre-stack depth migration (PSDM). These surveys reveal numerous prospects in multiple play types over open acreage, and farm-in opportunities are available over the Solwara MC3D survey area. PGS has exclusive marketing rights for the Solwara and Painimaut MC3D surveys until 2029.

CGG ramps up offshore geothermal technology

CGG has released has published a paper outlining the potential of offshore geothermal energy as a green energy resource of global significance and setting out a framework for its responsible development.

Research by CGG scientists strongly indicates the existence of vast, untapped geothermal resources along the magmatically active ocean floor spreading centres and adjacent flooded rift systems occurring in all the world’s major oceans. These offshore areas could be optimal locations to harvest geothermal resources for power in conjunction with the co-production of freshwater, Green Hydrogen, and ammonia, collectively creating an alternative set of

rapidly scalable green energy solutions. CGG has been granted a patent for a novel combination of geological, geophysical, and engineering technologies to support research into and the exploration, development and monitoring of offshore geothermal resources.

Peter Whiting, EVP Geoscience, CGG, said: ‘The opportunity offshore geothermal resources presents could be a game-changer in supporting the United Nations Development Programme’s 2023 Sustainable Development Goals including clean energy, climate action, and partnerships for sustainable development. While the award of the patent recognises the exceptional work of our geothermal

experts, our motivation for seeking it is to ensure that there can be rapid, responsible, and equitable development of these resource of this important global resource.’

Schematic showing offshore geothermal resource exploration and development adjacent to sea floor spreading centres. (image © CGG).

Shell reaches 60% of its 2030 emissions reduction target

Royal Dutch Shell has reached 60% of its target to halve emissions from its operations (Scope 1 and 2) by 2030, compared to 2016.

Publishing its first energy transition update since the launch of its Powering Progress strategy in 2021, the company also reduced the net carbon intensity of the energy products it sells by 6.3% compared with 2016, the third consecutive year it hit its target. In 2023 it achieved 0.05% methane emissions intensity, significantly below our target of 0.2%

Meanwhile, the company has set a new target to reduce customer emissions from the use of its oil products by

15-20% by 2030 compared with 2021 (Scope 3, Category 11) as a contribution to the decarbonisation of the transport sector.

Shell has also confirmed that it will invest $10-15 billion between 2023 and

the end of 2025 in low-carbon energy solutions. It will focus on renewable power projects in Australia, Europe, India and the USA, Shell said.

‘Our target to achieve net-zero emissions by 2050 across all our operations and energy products is transforming our business. We believe this target supports the more ambitious goal of the Paris Agreement to limit global warming to 1.5°C above pre-industrial levels. Shell’s strategy supports a balanced and orderly transition away from fossil fuels to low-carbon energy solutions to maintain secure and affordable energy supplies.’

TGS reports fourth quarter operating profit of $47 million

TGS has reported an operating profit of $47 million and a net loss of $9 million on POC revenues of $206 million compared with an operating profit of $74 million and a net income of $43 million on

POC revenues of $227 million in Q4 2022.

Full-year operating profit was $179 million with a net income of $22 million on POC revenues of $968 million.

Early Q4 sales of $59 million were nearly double those of $31 million in Q4 2022. However, late sales of £59 million compared with $137 million in Q4 2022.

TGS said it expects multi-client investments of $300-350 million and a POC early sales rate of more than 85%.

Kristian Johansen, TGS CEO, said: ‘While we are pleased to deliver proforma annual revenue growth of 14% in 2023, we are disappointed with late

Oil majors results round-up

Equinor has announced adjusted earnings fourth quarter of $8.68 billion and $1.88 billion after tax in the fourth quarter of 2023. Net operating income was $8.75 billion and net income was $2.61 billion.

ExxonMobil has reported 2023 fourth quarter earnings of $7.63 billion, a 40% drop from £12.75 billion reported in Q4 2022.

TotalEnergies reported adjusted fourth quarter net income of $5.2 bil-

lion and cash flow of $8.5 billion. The company reported full-year adjusted net income of $23.2 billion and cash flow of $36 billion.

Shell reported adjusted fourth quarter earnings of $3.5 billion as a result of strong gas trading. Focus on disciplined spending led to 2023 cash capex of $24.4 billion; 2024 cash capex outlook is $22-25 billion.

bp has announced better than expected fourth quarter 2023 underlying replace-

sales in Q4. We did not see the normal seasonal late sales uptick, as customers’ year-end funds were limited by high cost inflation, increased spending on drilling and new seismic data acquisition and delayed licensing rounds. On a positive note, we saw good order inflow and positive momentum in our Acquisition business and strong development in the Digital Energy Solutions business. I’m increasingly optimistic for 2024, based on positive signals from our customers. Our POC contract backlog going into 2024 is 21% higher than a year earlier and the pipeline of further business opportunities looks promising.’

ment cost profit of $3 billion, compared with $3.3 billion for the previous quarter. Reported profit for the quarter was $0.4 billion, compared with $4.9 billion for the third quarter of 2023. Operating cash flow was $32 billion and net debt was reduced to £20.9 billion.

Chevron has reported fourth quarter earnings of $2.3 billion, compared with $6.4 billion in Q4 2022 and $6.5 billion in Q3 2023.

Kristian Johansen, TGS CEO.

BRIEFS

Petronas has signed production sharing contracts for two Discovered Resource Opportunities (DRO) clusters, situated off the coast of Peninsular Malaysia.   The BIGST Cluster was awarded to PETRONAS Carigali, and JX Nippon Oil & Gas Exploration (BIGST), with 50% cent participating interest each. Meanwhile, Tembakau Cluster was awarded to IPC Malaysia and IPC SEA Holding, with 90% and 10% participating interest, respectively.

Seabird Exploration has reported fourth quarter revenues of $8.5 million and EBITDA of £1.7 million. Net interest-bearing debt was $13.9 million. Utilisation was 76%.

Partners in Israel’s Tamar natural gas field have agreed to expand production at the offshore site, which is a major energy source for Israel and also supplies Egypt and Jordan. Field operator Chevron said the move will increase Tamar’s production capacity to up to 1.6 billion cubic feet per day, from a current 1 billion cubic feet, according to a Reuters report.

The US Bureau of Ocean Energy Management (BOEM) has completed its environmental review of the proposed New England Wind project offshore Massachusetts. BOEM estimates that the proposed project would generate up to 2600 megawatts (MW) of electricity.

Five applicants have been approved for the auction round for Sørlige Nordsjø II offshore wind projects on the Norwegian Continental Shelf. They are, Aker Offshore Wind, BP og Statkraft; Equinor og RWE; Norseman Wind (Energie Baden-Württemberg AG); Shell, Lyse og Eviny; Ventyr (Parkwind og Ingka).

The US Bureau of Ocean Energy Management (BOEM) has announced the two final Wind Energy Areas (WEAs) offshore Oregon. The Coos Bay WEA is 61,204 acres and is located 32 miles from shore.

The Brookings WEA is 133,808 acres and is about 18 miles from shore.

Bangladesh launches licensing round

The Bangladeshi government has issued an invitation to international oil and gas companies offering 15 deepwater blocks and nine shallow-sea blocks for exploration in its first bid round since 2012.

The deep-sea licenses available for bidding are DS-08, 09, 10, 11, 12, 13, 14, 15, 16, 17, 18, 19, 20, 21 and 22. The shallow-water ones are SS-01, 02, 03, 05, 06, 07, 08, 10 and 11.

TGS, in partnership with SLB and the national oil company Petrobangla, has acquired a 2D multi-client seismic data survey encompassing over 75,000 km across all 24 blocks on offer. Acquisition of the 12,636 km 2D seismic survey was completed in April 2023. Final PSTM-processed products are available now, and final PSDM products will be available in May 2024.

David Hajovsky, executive vice-president of multi-client at TGS, said: ‘The Bengal Fan is one of the world’s largest deep-water fans with significant evidence of working petroleum systems. It is widely considered one of the most extensively underexplored frontier regions. With limited existing offshore Bangladesh data, this new high-quality seismic, combined with the revised Production Sharing Contract 2023 (PSC), is a critical component for companies to evaluate and submit competitive bids.’

The country is offering several tax exemptions with contractor’s corporate income tax liability borne by the Petrobangia. Machinery imported for petroleum operations will not be taxed, it added. Contractors will also be allowed to repatriate 100% of their profit.

To qualify for bidding, a company must have an offshore daily production of

at least 15,000 barrels of oil or 150 million cubic feet of gas in operated assets. Companies have until September 9 to submit bids to Petrobangla.

‘Bidders must have global experience (other than their home country) in oil and gas exploration and production,’ the notice added.

The initial contract period lasts six years, which can be extended by three, according to the offshore production sharing contract (PSC) model that Petrobangla announced last year.

Contractors must provide a bank guarantee of $3 million for the initial exploration period of six years. After four years it must commit to drilling an exploration well backed by a further bank guarantee of $20 million for the remaining two years. If it wishes to avail of the threeyear extension, it must provide another bank guarantee of $20 million.

‘At the end of the initial exploration period, the contractor will have an option to relinquish the entire area after completion of the minimum work program or to proceed to the subsequent exploration period, relinquishing 50% of the contract area in a single portion,’ stated the offshore PSC framework. ‘The contractor shall relinquish all of the contract area if it does not commit to drill an exploration well after completion of the geological and geophysical survey during the four years of the initial exploration period’.

In the event of no discovery the contractor shall bear all losses without liability to the state.

If a contractor secures a commercial discovery it is assured of a 20-year production contract for an oil field and a 25-year contract for a gas field.

Fifteen deepwater and shallow water blocks are available to bid on. Bangladesh has launched a new production sharing contract. Credit: Arvind Vallabh on Unsplash.

Oil and gas round-up

BlueNord has made a final investment decision on the Harald East Middle Jurassic well in the Danish sector of the North Sea, operated by the Danish Underground Consortium (DUC), a JV between TotalEnergies (43,2%), BlueNord (36,8%) and Nordsøfonden (20%) The HEMJ well will be drilled close to the Norwegian border and if successful deliver production by end of 2024. The expected gain from the well is up to 8 mmboe net to BlueNord of which ca 80% is gas. This well is drilled into the Jurassic with good reservoir properties.

Shell has taken a final investment decision (FID) on the Victory gas field in the UK North Sea, approx. 47 km north-west of the Shetland Islands. Once onstream, the field will help to maintain domestically produced gas for Britain’s homes, businesses and power generation. The development will feature a single subsea well which will be tied back to existing infrastructure of the Greater Laggan Area system, using a new 16 km pipeline.

Afrentra has been selected for two blocks in Angola’s 2023 onshore bid round. As part of the 2023 Public Tender process launched by ANPG, Afentra submitted bids for Blocks KON15 (1000 km2) and KON19 (900 km2) in the Kwanza onshore Basin as a non-operating partner. The onshore Kwanza basin, covering

25,000 km2 is an under-exploited proven hydrocarbon basin and has numerous oil fields and discoveries dating back to 1955. Both KON15 and KON19 blocks were high-graded by Afentra as they have good signs of a working petroleum system and contain wells that were drilled on salt structures with light oil recovered to surface in one and oil shows in others from post and pre-salt reservoirs. There is limited 2D seismic data.

Serinus Energy has been selected as a preferred bidder on the KON-13 block in the onshore Kwanza basin in the Republic of Angola. The Kwanza basin is a large proven hydrocarbon basin extending over 25,000 km2. The basin has existing oil discoveries dating back over 70 years. The KON-13 block has an aerial extent of 1011 km2 with one exploration well drilled in 1969 and 136 km of legacy 2D seismic. The Kwanza basin is located both on and offshore Angola. It extends from Luanda, located in the north, to Cape Santa Maria farther south. The company sees this basin as an under-explored and under-exploited basin.

Aker BP and Equinor have discovered oil in well 30/12-3 S in the North Sea. The wells were drilled about 40 km south of Osberg. The licence is part of the Munin field. Between 0.15 and 0.55 million Sm3 of recoverable oil equivalent

(o.e.) was proven in well 30/12-3 S. Well 30/12-3 S encountered a 3.5-m oil column in the Tarbert Formation, in a sandstone reservoir with moderate reservoir quality. The Tarbert Formation was 195 m thick, 97 m of which was sandstone rocks with moderate-good reservoir quality. The oil/ water contact was encountered 3110 m below sea level. The Ness Formation was about 163 m thick, 19 m of which was a sandstone reservoir with moderate reservoir quality. Well 30/12-3 A encountered the Tarbert Formation with a thickness of about 216 m, 19 m of which was sandstone rocks with poor reservoir quality. The Ness Formation was 50 m thick, 11 m of which was a sandstone reservoir with moderate reservoir quality. Data acquisition was undertaken.

BlueNord's targets in the Danish North Sea.

VRSvalbard – a photosphere-based atlas of a high Arctic geo-landscape

Rafael Kenji Horota 1,2,*, Kim Senger1, Aleksandra Smyrak-Sikora1,3, Mark Furze1, Mike Retelle1, Marie Annette Vander Kloet1,2 and Marius O. Jonassen1

Abstract

Recent technological advances provide opportunities to enhance students’ learning. Field-based geoscience education is no exception. Traditional pedagogy of field teaching, although invaluable, sometimes struggles to provide students with the depth and breadth of real-world examples to foster a deep understanding of geoscientific landforms and processes. These methods rely on complex landscape features examined in a field activity to exemplify the learning content, while teaching staff typically ground students’ understanding with supplementary printouts of figures, diagrams, and sketches.

In this paper we present VRSvalbard, an interactive web-GIS platform currently populated with 129 virtual field tours of the High Arctic Archipelago of Svalbard. The virtual field tours are built around 1481 aerial photospheres, systematically acquired largely during drone-based data acquisition campaigns as part of the overarching Svalbox project including a database of digital outcrop models. The virtual field tours offer interactive digital field experiences in desktop and virtual reality mode. Selected tours also integrate 3D datasets, digital outcrop models, digital elevation models, interactive map layers, satellite imagery, published figures, photos, audios, videos, and text resources. These elements are presented within a detailed and realistic 3D digital globe that allows students to virtually explore field sites before and after field excursions. In addition, we provide an overview of the motivation behind VRSvalbard, the technical framework of the platform and a summary of using the VRSvalbard platform during education, research and field excursions for the petroleum industry.

Keywords. Svalbard; field-based education; digital learning; drones; digital twin

Introduction

Geoscience education plays a pivotal role in shaping students’ understanding of the Earth’s complex and dynamic processes. It is a field that inherently demands field-based education, where students step out of the traditional classroom and into the natural environment to directly observe and interpret geoscientific phenomena.

In the Norwegian high Arctic Archipelago of Svalbard (Figure 1), with its remote and extreme environments, the University Centre in Svalbard (UNIS) conducts year-round field-based geoscience education. The field conditions are often challenging, including sub-zero temperatures, high winds, snowdrift, and limited or no daylight during the polar night from October to February. Additionally, the fragile Arctic environment demands adherence to strict environmental regulations to minimise human impact and reduce the environmental footprint of fieldwork. Logistic complexities related to planning, permit acquisition, and necessary safety measures also need to be considered (Senger et al., 2021; Horota et al., 2023). At the same time, Svalbard’s

geological diversity and the complex weather variations in the circum-Arctic offer valuable learning opportunities for fieldbased geoscience education.

Svalbard comprises all islands between 15-35°E and 74-81°N, including the largest island Spitsbergen. Geologically, Svalbard is the emergent part of the Barents Shelf and offers a nearly continuous sedimentary record from the Devonian to the Paleogene (Olaussen et al., 2024). The diverse lithologies along with recorded tectono-thermal events including compressional and extensional tectonics and large-scale magmatism make Svalbard an invaluable place to study and teach a wide variety of geoscience courses. Importantly, recent global climate change is more pronounced in the high Arctic (Rantanen et al., 2022), and Svalbard is one of the world’s most rapidly warming places (Isaksen et al., 2022) where students can experience it and therefore gain a deeper understanding of this process.

As technology continues to reshape the educational landscape, there is a pressing need for innovative solutions to bridge the gap between traditional field-based learning and contemporary pedagogical methods (Cliffe, 2017). In this context, virtual field experiences and digital outcrop models of field environments emerge as powerful tools which address these field educational

1 The University Centre in Svalbard | 2 University of Bergen | 3 Norwegian University of Science and Technology

* Corresponding author, E-mail: rafaelh@unis.no

DOI: 10.3997/1365-2397.fb2024029

challenges and offer educators the means to create immersive and engaging learning experiences (Horota et al., 2023). Virtual field experiences improve 3D thinking and the positive perceptions of learning (Pugsley et al., 2022). While digital outcrops have been around for the past 30 years (Buckley et al., 2008), it was during the global Covid-19 pandemic when their usefulness became apparent to a larger teaching community (Bond & Cawood, 2020; Senger et al., 2021).

In this paper we introduce VRSvalbard (https://vrsvalbard. com/), a tool to support field-based learning experiences for students, researchers and industry professionals. We present the technical framework of VRSvalbard and our strategy for systematic and sustainable data acquisition. Finally, we provide case studies of how VRSvalbard is used in several UNIS courses and outline how such digital tools complement traditional field teaching.

VRSvalbard: motivation, technical framework, and data acquisition

Motivation

The development of VRSvalbard commenced with an analysis of the educational needs and goals related to UNIS geoscience courses’ field components. UNIS offers courses in Arctic Geology, Arctic Geophysics, Arctic Biology and Arctic Technology and all courses include a mandatory field component utilising the natural laboratory offered by Svalbard. The harsh and extremely

seasonally dependent field conditions often require adjustments to planned field activities. In this context, digital tools like VRSvalbard and Svalbox (www.svalbox.no/map; Betlem et al., 2023) offer an opportunity to support students’ learning if an actual field experience must be adapted and to make more efficient use of fieldwork that is undertaken as planned. Since 2016 UNIS has been systematically acquiring digital outcrop models (DOMs) and openly sharing them through the Svalbox database (Senger et al., 2022; Betlem et al., 2023). While DOMs allow quantitative geoscientific work, they only cover single outcrops/mountainsides and their acquisition and processing take time. In recent years DOMs are almost exclusively acquired using drones, many of which are also capable of taking photospheres (i.e. 360° panoramic images derived from automatically stitching together multiple photographs taken around a single nodal point) as a complementary qualitative dataset. Photospheres are ideal for placing DOMs in a regional context and providing different perspectives of the field sites. As photospheres can be acquired very quickly, they can be taken in parallel with field activities and thus provide a digital representation of the specific conditions (snow cover, weather etc.) of the field day.

During our analyses of UNIS’ field activities, we identified that field sites frequently had to be changed on short notice due to harsh weather conditions or polar bear encounters. Keeping the site and changing fieldwork dates and/or rearranging bookings of transport (typically boats or snowmobiles) would in many cases

Figure 1 A) Location of the Svalbard archipelago (inset map, based on IBCAO; Jakobsson et al, 2008) and the available Virtual Field Tours on www.vrsvalbard.com/map. B) Geological map from Dallmann, (2015) and the Norwegian Polar Institute (2016). C) Meteorology fieldwork in Adventdalen (January 2021). D) Geology fieldwork at Kapp Linne (April 2023). E) Geology fieldwork at Borebukta (September 2022).

have been preferable but were often not possible due to logistical constraints. Changing field sites, or cancelling the field day, were frequently the only viable options. These factors led us to acquire visual datasets with a better overview of Svalbard’s landscape (in the sunlight and/or with less snow cover) and the frequent rescheduling and cancelling of fieldwork gave us the idea to develop virtual field tours (VFT) for key field sites around the archipelago.

Technical framework

VRSvalbard comprises seven backend and six front end user-interface components hosted externally using a web-hosting provider (Figure 2; Table 1). It is developed in WordPress, where the HTML5 package output from the Pano2VR software is uploaded via the Garden Gnome Package plugin for each of the localities in individual webpages. These pages are linked to markers displayed over an interactive map, that is built using the open-source Leaflet Map Plugin JavaScript library in the VRSvalbard.com/ map tab. Geographical coordinates are attributed to each marker which automatically gets placed and clustered over the interactive

map through shortcodes, small code snippets that display a specific function or content in WordPress.

VRSvalbard currently hosts 129 VFTs from localities all over Svalbard (Figure 1A). They are also shown in separate interactive maps in the VRSvalbard.com/courses tab displaying field teaching localities for specific UNIS courses.

The HTML5 packages output for the VFT were built using Garden Gnome’s Pano2VR - Panorama Tour Builder software to upload, orient and link photospheres and Sketchfab 3D models links, photos, videos, and text as supplementary content. The software exports it as an HTML5 package for each project field location. The whole customisation and export process takes up to 30 minutes for each VFT (± 10 photospheres) to be ready for upload to VRSvalbard (Figure 3).

The platform also hosts interactive 3D geospatial presentations as thematic virtual field guides (VFGs) of Svalbard’s geology (Figure 4). VFGs are developed using the Cesium ion 3D geospatial platform that creates and hosts 3D content in the cloud. It allows 3D data upload to create 3D tiles that can be combined with high-resolution terrain, satellite imagery, and map layers for

Figure 2 Technical framework – Back-end and front-end, map and marker implementation, funding projects and feedback questionnaires.

Table 1 Back end components of

global coverage and shows where data fits in the digital world. The 3D geospatial assets and presentations are stored in a Cesium ion account and are imported to a VFG page in VRSvalbard as an iFrame embedded link.

Data acquisition

The images of the field sites were collected to provide a virtual 3D perspective of the learning sites. We acquired both overlapping images for Structure-from-Motion (SfM) reconstruction (Westoby et al., 2012; Betlem et al., 2023), and photospheres. We used consumer drones, particularly DJI’s Mavic 2 Pro (Hasselblad 1” CMOS sensor 20 Mp) and Mavic 3 (Hasselblad 4/3” CMOS sensor 20 Mp) models. Systematic acquisition was conducted during dedicated Svalbox field campaigns, but also carried out as opportunistic field activities (field excursions as part of UNIS courses, near-town day trips around Longyearbyen, or on multi-day expeditions farther afield; Table 2).

Some preexisting data, including photospheres (Betlem et al., 2022) and DOMs from the Svalbox database (Senger et al., 2021; Betlem et al., 2023) were integrated in the VRSvalbard.

VRSvalbard: visualisation, data integration, and case studies

In the platform, the VFTs are a sequence of panoramic images that are spatially merged to create a virtual experience. Once created, the viewer can virtually experience local and remote field sites. VFTs can be experienced through desktop computers, laptops, tablets, mobile devices, and even in an immersive view mode with head-mounted displays.

VFGs, on the other hand, are interactive, digital experiences that provide users with a thematic storytelling exploration of a field area. In essence, they capture the real-world environment of a specific location or region through a variety of multimedia content, including images, videos, maps, and 3D models to teach. VFG experiences are only visualised via desktop or mobile devices.

Table

Synthesis of major field campaigns contributing data to VRSvalbard. Small boat is RV Clione with four scientists onboard. Medium boat is Ulla Rinmann with 11 scientists onboard.

Data integration and storytelling

The photosphere selection provides a virtual experience of motion by approaching a given landscape feature of study in the digital space. Interactive elements like popups, photo hotspots, directional sound, images, video, and text can be added as informational content to selected photospheres to highlight landscape features, and display 3D model pop-up windows from the Svalbox.no web portal. The datasets are linked together in Pano2VR software while developing the VFT (Figure 3).

The photosphere image transitions are limited to illustrate details over a specific real-like landscape location. To facilitate

the integration of photospheres with complementary data like digital outcrop models, geological maps and regional terrain models, a full 3D visualisation platform is required. These are provided by VRSvalbard’s thematic virtual field guides (VFGs; Figure 4).

To complement storytelling for teaching, 3D datasets were also added to Cesium Ion as assets and displayed in VRSvalbard as a Cesium story presentation. One example is the VFG of the Neogene-Quaternary Volcanism and Thermal Springs that seamlessly integrates map layers, digital outcrop models, digital elevation models and geological maps that facilitate storytelling by being all in the same context. The VFGs are supplemented with text, figures,

Figure 3 Schematic figure displaying how visual photospheres are spatially merged and how dataset is integrated in selected photospheres in the Pano2VR software. Data is exported as .html packages and uploaded to a VRSvalbard page accessible through a marker in an interactive map.

Figure 4 Data integration and storytelling as a virtual field guide QRcode to URL https://vrsvalbard.com/neogene-quaternary-volcanism-and-thermal-springs/). Integration of ArcticDEM, Bing Satellite, Sverrefjellet DOM, geological map layer of Svalbard, text box and clickable link to the virtual field trip of Sverrefjellet displayed in the upper-right corner, accessible through the QRcode to URL https://vrsvalbard.com/Sverrefjellet/.

and clickable links that bridge this fully digital 3D learning tool with the VFT on a side bar to provide context (Figure 4).

Case studies

VRSvalbard has been implemented as a teaching tool in several Arctic Geophysics (AGF), and Arctic Geology (AG) courses at UNIS: AGF-213, AGF-351/851, AG-209, AG-210, AG-220, AG-222, AG-336/836, and AG-351/851 (Figure 5; Table 2). It has been used for various purposes in the courses including:

• as a demonstration tool in lectures and in-class activities (All courses),

• fieldwork planning (All courses),

• orientation and navigation (AGF-213, AGF-351/851, AG-210),

• health and safety briefings (All courses),

• detecting changes in the landscape (AG-210, AG-220),

• guaranteed virtual access to field sites in daylight and good visibility (AG-209, AG-222),

• post-fieldwork analysis (All courses),

• students’ term projects (AG-209, AG-210, AG-222, AG-351/851),

• as a resource for course assessments and activities (All courses),

The use of VRSvalbard in UNIS courses has provided invaluable feedback on the experiences of instructors and students; this

feedback is being actively and continuously collected through short informal interviews (with instructional staff) and in-class discussion and surveys (with students). The full extent of each course field component highlighting the unique use of VRSvalbard and feedback related to specific courses can be found at https://vrsvalbard.com/purposes-of-use/.

Research campaigns

Photospheres are also acquired during research campaigns in both spring and summer (Table 2), providing an exponentially expanding photosphere database that also benefits teaching. In these campaigns the main aim is focused on more traditional geological field work, for instance collection of dolerites (intrusive igneous rock of basaltic composition) samples of the High Arctic Large Igneous Province (HALIP) for geochronology and geochemical analyses. Digital techniques are highly complementary and at UNIS we aim to include a two-person team dedicated to droning on all research campaigns to complement the more traditional scientific objectives. Data collected includes both digital outcrop models (for placing the sampled locations in context of the igneous plumbing system and quantitative analyses for the HALIP example) and photospheres (for seeing the overall setting and detailed examples of outcrops).

Industry campaigns

Svalbard has always attracted field excursions of petroleum companies interested in understanding the geological devel-

Figure 5 Field locations of all courses. BSc course = 200-level course code, MSc course = 300-level course code, PhD course = 800-level course code. Courses: AGF-213 (Polar Meteorology and Climate), AGF-350/850 (The Arctic Atmospheric Boundary Layer and Local Climate Processes), AG-209 (The Tectonic and Sedimentary History of Svalbard), AG-210 (Quaternary and Glacial Geology of Svalbard), AG-220 (Environmental Change in the high Arctic Landscape of Svalbard), AG-222 (Integrated Geological Methods: From Outcrop to Geomodel), AG-351/851 (Arctic Tectonics and Volcanism), AG-336/836 (Rift Basin Reservoir: From outcrop to model).

opment of the greater Barents Shelf. Svalbard is its exposed part and offers insights into the petroleum systems of the hydrocarbon provinces in the SE Barents Sea (Olaussen et al., 2024). Such field excursions often include a multi-disciplinary team (geoscientists, petroleum engineers etc.) from either a single company or a licensed group, with a specific target in mind. Field excursions are most often organised with a chartered boat with overnight stay, ranging from a few days in the Isfjorden area to a week-long circumnavigation of Spitsbergen. UNIS leads these campaigns and provides both scientific and technical guides. Existing data on the Svalbox and VRSvalbard platforms facilitate pre-field work workshops with the field trip participants, highlighting the regional context of the sites that are planned to be visited. These data allow the participants to revisit the field locations back in the office, also allowing colleagues who were not able to attend the actual field trip to join geoscientific discussions.

Discussion

From the ground to the air: drone-based photospheres Photospheres are used in many applications, for instance virtual tours of museums (Schulmeister and Edwards, 2020), the Global Seed Vault in Svalbard (https://seedvaultvirtualtour.com/), tourism (Sukardani et al., 2023), or in biology (Eidesen & Hjelle, 2023). Most people have been exposed to photospheres through Google Street View (Anguelov et al., 2010). The emergence of affordable small drones with high-quality cameras provides geoscientists with an aerial view of their field sites (e.g., Jordan 2015). Drones have proven instrumental in efficiently collecting a wide array of geospatial data, including high-resolution imagery and topographic information, even in remote and challenging terrains (Pina & Vieira., 2022). Leveraging the wealth of data obtained through drone-based surveys, researchers have begun to harness this information to construct immersive and non-immersive virtual field trips and exercises (Cheng & Tsai., 2019; Horota et al., 2022; Whitmeyer and Dordevic 2021). These guides offer a dynamic platform for students, scientists, and enthusiasts to virtually explore and analyse geological features and environmental changes (Pugsley et al., 2022).

Teaching and learning opportunities of photospherebased platforms.

VRSvalbard is becoming an important instructional tool frequently used in numerous courses at UNIS. Unpredictable field conditions require use of supplementary resources to ensure that students have the possibility to achieve learning outcomes for field courses. In this context, the benefits of using VRSvalbard are clearly identified by both instructors and students alike. Instructors use VRSvalbard during the design of field activities (pre-fieldwork preparation tasks, field assessment, etc.) and students use VRSvalbard to support their learning in the course. Photosphere-based platforms may be key in addressing emerging needs in geoscience education including fostering greater accessibility (e.g., in relation to expense, obstacles to travel, physical accessibility for students or teachers with disabilities; Carabajal et al., 2017; Carabajal & Atchison, 2020; Kingsbury et al., 2020), enhancing design for online and blended virtual

field learning (Pugsley et al., 2022) and responding to needs for emergency remote teaching. The photosphere-based platforms provide high-quality materials with useable data rather than static and limited digital resources (e.g., image banks on websites) that have been critiqued as inadequate substitutes for field learning (Carabajal et al., 2020). The uses of VRSvalbard in teaching at UNIS suggests that use of photosphere-based platforms do not risk reducing the quality of field work but strengthens and expands what has been traditionally possible. We anticipate that web-GIS platforms like VRSvalbard, along with other similarly designed materials could be used in collaborative online international learning programs in geoscience education to support open higher education broadly.

Conclusions

In this contribution we have presented the VRSvalbard web-GIS platform offering photosphere-based access to field sites in the High Arctic archipelago of Svalbard. VRSvalbard leverages the use of bird’s-eye view photospheres and SfM-based digital outcrop models to provide geoscience students and researchers with photorealistic virtual field experiences. The platform is freely and openly available to everyone but is mostly used in courses at UNIS. We conclude by summarising the advantages of the platform:

• A growing number of photospheres from Svalbard are freely available.

• Photospheres are thematically linked to field campaigns visited as part of UNIS courses (virtual field tours).

• Photospheres are integrated with digital outcrop model and complementary geoscientific data in thematic virtual field guides.

• The platform makes fieldwork more efficient by facilitating pre-fieldwork planning and post-field work analyses.

• In cases where field sites cannot be visited the platform allows an alternative and engaging way of accessing field sites digitally.

Data availability

Photospheres are available through the Svalbox platform, hosted on the Zenodo repository (Betlem et al., 2022a; Betlem et al., 2022b; Betlem et al., 2022c; Betlem et al., 2023a).

Acknowledgements

We sincerely appreciate the data acquisition, technical discussions, and field assistance from many colleagues at UNIS, notably Peter Betlem, Nil Rodes, Anna Sartell and Tereza Mosočiová.

PhD funding to RKH was provided by iEarth and the Norwegian Ministry of Education. VRSvalbard is a sub-project of the Svalbox project, funded by the University of the Arctic (UArctic), the Svalbard Science Forum/Research Council of Norway (through Arctic Field Grants and a Svalbard Strategic Grant), iEarth seed funding and UNIS itself. Equinor financially supported the 2023 Svalbox summer field campaigns.

Academic licences for developing virtual field guides and 3D geospatial data visualisation were made available by GardenGnome (Pano2VR) and Cesium ion, respectively.

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The impact of marine-streamer acquisition technology on broadband time-lapse (4D)

seismic data

Patrick Smith1*, Paul Glenister1, Daniel Fischer 2, Hanna M. Blekastad2 and Ingrid Selle Østgård2.

Abstract

Modern marine-streamer time-lapse (4D) seismic projects generally use broadband processing flows that compensate source and receiver ghost effects. They are mostly very successful, but it can occasionally be difficult to achieve an accurate match between the surveys at low frequencies. A test project using data from the Heidrun field, offshore Norway, suggested that broadband processing can exacerbate minor issues that are typically insignificant for nonbroadband flows. Seismic surveys acquired with multisensor marine streamer systems tend to undergo wavefield separation and other processing during acquisition, with different acquisition contractors using differing workflows. This can cause discrepancies between the surveys that the 4D processing contractor cannot compensate. Similarly, ancillary datasets, such as farfield signatures, may be generated inconsistently. We recommend that time-lapse seismic processing begin with raw measurements wherever possible so that identical processing flows may be used for each survey. Even then, it may not be possible to completely compensate the impact of differing acquisition systems.

Introduction

Modern marine-streamer time-lapse (4D) seismic projects generally use broadband processing flows that compensate source and receiver ghost effects. They are mostly very successful, but it can occasionally be difficult to accurately match the surveys at low frequencies. We investigated this issue using data from the Heidrun field, offshore Norway.

The Heidrun long-term time-lapse seismic processing project

Heidrun is an oil and gas field in the Norwegian Sea north-west of Trondheim, in about 350 m water depth. Operated by Equinor, it started production in 1995 from Lower and Middle Jurassic sand-

stones at about 2300 m depth. The reservoir is heavily faulted and reflection seismic data in this area is strongly contaminated by water-layer multiples. Eight monitor surveys have been acquired since 2001, with processing performed under long-term contracts with Equinor (Fischer et al., 2013, Halland et al., 2019). The first six surveys were acquired with Q-Marine hydrophone-only (H) acquisition hardware. The 2018 and 2021 surveys used the IsoMetrix multisensor (PZ) system. IsoMetrix provides complementary pressure (P) and vertical acceleration (Z) measurements that enable separation of the up- and down-going wavefields recorded at the receivers. Wavefield separation of the 2018 data used SLB’s Optimum Deghosting (ODG) software, described in Caprioli et al., 2012, whereas the 2021 data used the acquisition

1 SLB |

2 Equinor

* Corresponding author, E-mail: psmith11@slb.com

DOI: 10.3997/1365-2397.fb2024030

Figure 1 Maps of source-receiver repetition accuracy for the 2018 PZ survey versus the 2008 H survey for near and far offsets.

contractor’s algorithm. Shot-by-shot farfield signatures, derived from nearfield hydrophone (NFH) measurements, were available for all surveys. The remaining acquisition parameters for the H and PZ surveys were otherwise identical (Table 1) with excellent survey repetition accuracy (Figure 1).

A modern non-broadband 4D processing flow was developed in 2014 using four of the H surveys. When available, the up- and down-going wavefields of the 2018 PZ data were recombined at the

years 2001, 2004, 2006, 2008, 2011, 2014 2018, 2021

9-m receiver datum of the H acquisition to create a reghosted dataset comparable with the earlier surveys, and the previously derived processing flow was applied. A very satisfactory match was achieved.

The original broadband processing flow was derived in early 2021 using H datasets from 2008, 2011 and 2014, and using the up-going wavefield from the 2018 PZ survey. Adaptive deghosting (Rickett et al., 2014) was used for source and receiver deghosting of the H datasets and for source deghosting

Table 1 Acquisition parameters for the H and PZ surveys.

Figure 2 A portion of an inline section through the 2011 H 3D stack cube, plus corresponding 4D differences between H datasets, between PZ datasets, and between PZ and H surveys.

of the PZ data. The remainder of the flow was quite standard for time-lapse surveys in this area, with 3D SRME (Dragoset et al., 2008) being the main tool used to attenuate water layer multiples. Global match operators were applied at two points in the flow to compensate wavelet differences between the surveys. This flow was applied to the 2021 data when it became available. Figure 2 shows part of an inline section through the 2011 (H) final stack cube plus three 4D seismic difference panels. The first difference panel compares H datasets from 2011 and 2014. It exhibits very low residual noise levels – the display gain is four times higher than that of the stack panel. There is, however, little evidence of reservoir changes at this location over this time interval. The second 4D difference panel compares the two PZ datasets. We observe increased coherent residual background energy, but this has little impact on the interpretability of the 4D signal that is present in the centre of the image. The last panel compares the 2018 PZ survey with the 2014 H data. The background residual is noticeably higher and obscures the likely production effect that had been observed on the non-broadband comparison over this time interval, particularly after inversion to relative acoustic impedance. Much of the residual energy has a low dominant frequency and seems related to residual water-layer multiples or other sources of ringing. Despite these issues, it was clear that the lower sidelobe energy associated with the broadband seismic significantly simplified interpretation of reservoir changes (Figure 3). We therefore

instigated a test project to understand how we might improve the broadband 4D comparisons.

The test reprocessing project

In this area, the 4D difference quality at early stages of the processing flow is insufficient to allow detection of the subtle issues targeted by the test project. 4D repeatability attributes are also of little assistance. We therefore processed a 3-km wide swathe of data from the 2014, 2018 and 2021 surveys to enable creation of 3D migrated single inline sections from which high-quality 4D differences could be computed. Many tests from wavefield separation onwards were processed through the previously derived demultiple and imaging workflow prior to evaluation. Testing highlighted several potential deficiencies in the previously used broadband processing flow, as described below.

Wavefield separation of PZ datasets

The up- and down-going wavefields for the 2018 survey were generated from the P and Z measurements using SLB’s ODG algorithm (Caprioli et al., 2012), whereas the 2021 data had been wavefield-separated using the acquisition contractor’s approach. The wavefield separation workflows contained a significant number of non-identical processing steps in addition to the wavefield separation itself. We reprocessed the raw 2021 measurements using ODG and demonstrated that using identical workflows gave a much-improved PZ-PZ comparison (Figure 4). We would

Figure 3 A portion of the 3D stack for the PZ (2018) data together with relative acoustic impedance 4D differences (2018-2014) computed from the 2018 non-broadband flow and from the original 2021 broadband flow.

Figure 4 Part of an inline section from the 2021 PZ stack, plus relative acoustic impedance 4D difference sections between the 2018 and 2021 PZ datasets. The middle panel used different PZ wavefield separation workflows for the two surveys. The right-hand panel used identical workflows.

presumably have achieved similar results had both surveys been wavefield-separated using the contractor’s method.

Farfield signature handling

Nearfield-hydrophone-based shot-by-shot farfield signatures were available for the H and PZ surveys. Those of the H surveys had a maximum record time of 1024 ms whereas those of the PZ surveys were 1998-ms long. Careful tapering of the H signatures was needed to prevent truncation artifacts being visible after deghosting. Truncating and tapering the PZ survey signatures identically to those of the H surveys improved the similarity of the final images even though the truncation resulted in reduced attenuation of bubble energy on the PZ data.

The data quality at early stages in the flow is such that the effectiveness of the designature and debubble can only be evaluated near the water bottom reflection. Synthetic testing suggested that designature with the vertical farfield signature gave imperfect attenuation of bubble energy for take-off angles beyond about 20 degrees which, for the water bottom reflection, corresponds to offsets of about 250 m. This residual bubble energy is visible on the near offsets of the deghosted seismic data and gives the impression that the designature has not achieved its aim. But the take-off angle corresponding to the maximum available offset at reservoir level is only about 20 degrees, suggesting that designature with the vertical farfield signature is adequate for the reservoir. Evaluation of 4D differences after processing through the full workflow confirmed that the variation in take-off angle for reservoir reflections was insufficient to warrant full angular designature.

Deghosting workflow

The revised processing flow used Adaptive Deghosting (Rickett et al., 2014) to remove the receiver ghost from the H data, with parameters chosen to optimise the match with the upgoing wavefield of the PZ data. Source deghosting used the same algorithm applied in a separate pass, with identical parameters for all surveys. The deghosting matched the amplitude spectra of the PZ and H datasets very satisfactorily but frequency-variant water-bottom reflection-alignment histograms (Figure 5) suggested that a small residual phase difference remained between the H and PZ datasets. 4D QCs, including phase spectral differences, produced at this point in the flow suggested that this error was present over the entire time range of the data. However, QCs produced after applying the full workflow showed no indication of a phase error at reservoir. It seems that the phase error is close to zero at vertical incidence and increases with take-off angle. 4D QCs produced early in the flow appear to be unreliable due to contamination by scattered noise and multiple reflections that have relatively high take-off angles.

3D Surface-related multiple elimination

3D surface-related multiple elimination (Dragoset et al., 2008) relies on Kirchhoff summation of all possible surface-multiple raypaths to generate multiple predictions for each trace. A large aperture is required to create accurate multiple predictions at low frequencies. Increasing the aperture from 500 m to 1500 m improved the multiple predictions in the 0-8 Hz band.

Figure 5 Histograms of near-offset timing differences between band-limited and full-bandwidth near-offset water-bottom reflection times, computed over equivalent areas of the two surveys. The left-hand panel shows results for the 2008 H survey and the right panel shows results for the 2018 PZ survey.

Figure 6 Part of an inline section from the 2018 PZ 3D stack, plus relative acoustic impedance 4D difference sections between the 2014 H and 2018 PZ datasets. The middle panel used the original broadband flow, and the right panel used the revised flow.

Final processing flow

Figure 6 shows the impact of the revised broadband processing flow on the H versus PZ comparison. A 4D hardening signal, previously identified on the non-broadband data, is clearly visible on the revised result, whereas it is obscured by background noise on the original broadband dataset. However the hardening signal is followed by a spurious apparent softening related to interaction of residual sidelobe energy with the remaining low frequency background noise, emphasising that the quality of the revised result is still inferior to that of the H vs H or revised PZ vs PZ comparisons.

Discussion

The test reprocessing identified deficiencies in the original broadband flow. Similar issues were present in the non-broadband processing flow but did not cause obvious problems. The deficiencies are also present in the broadband H - H comparison in Figure 2 and the revised PZ - PZ comparison in Figure 3. They seem of little consequence for broadband 4D processing when identical acquisition systems are used. The poorer PZ - H comparisons appear to either be due to inadequate compensation of the differences between the acquisition systems or that the broadband processing flow responds inconsistently at low frequencies to the differences in the acquired datasets. We currently suspect the latter because the 2018 non-broadband processing was minimally affected by these issues, and because the residual energy seems associated with residual multiples (the primary reflections are well matched). Broadband processing boosts low-amplitude low-frequency signal that is potentially more affected by differing noise content and other characteristics of the acquisition systems, and this may well cause inconsistent behaviour of the more data-adaptive components of the processing flow such as demultiple. Even so, broadband 4D seismic data tend to have lower sidelobe energy, improved definition of 4D time shifts and to give improved 4D inversion (e.g., Trinh et al., 2022) and reverting to non-broadband processing is undesirable.

Evaluation of these subtle issues is extremely difficult at early stages in the processing flow. Their effects may be obscured by noise and multiple energy, and 4D QC attributes may be misleading. On this dataset, reliable judgments could only be made after applying the entire demultiple and imaging flow. Project plans should include the resources required to do this.

Care must be taken when evaluating processing steps that apparently address this low-frequency residual energy. Some 4D processing algorithms jointly process base and monitor surveys to create a common component and deviations about that common component (e.g., Shadrina et al., 2019, Zhao et al., 2023). The base and monitor are then reconstructed by combining the deviations with the common component. But, if the deviations are band-limited either explicitly or implicitly during their derivation, the reconstructed datasets will contain no 4D information outside that bandwidth. The 4D differences may no longer exhibit the low-frequency 4D noise, but they no longer contain low-frequency 4D signal either.

It currently seems that some degree of mismatch is inevitable when different acquisition systems are used.

Summary

Broadband 4D seismic processing seems especially sensitive to differences in the acquired datasets and to minor imperfections in the processing flow. Differences in processing applied during acquisition of the data, including wavefield separation and generation of far-field signatures, cannot necessarily be corrected by subsequent algorithms. Software upgrades can mean that even identical hardware systems generate different results over time. We therefore recommend that processing starts from raw measurements to ensure consistency. Differing data characteristics may cause aspects of the subsequent seismic processing flow to operate inconsistently, even when identically parameterised. The choice of acquisition hardware for a new monitor survey is often dominated by logistical and other issues. The potential impact of these choices on 4D seismic data quality should be considered during pre-survey planning.

Acknowledgements

We thank Equinor and Heidrun partners (ConocoPhillips Skandinavia AS, Vår Energi ASA, Petoro AS) for permission to publish these results.

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Halland, K.S., Blekastad, H.M., Torset, S., Haug, S.G., Lippard, J.M. and Antal, A. [2019]. The Use of 4D Seismic Data on the Heidrun Field. 81st EAGE Conference & Exhibition, Extended Abstracts, We_R07_01.

Rickett, J.E., van Manen, D.J., Loganathan, P. and Seymour, N. [2014]. Slanted-streamer Data-adaptive Deghosting with Local Plane Waves, 76th EAGE Conference & Exhibition, Extended Abstracts, Th. ELI1 15.

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Special Topic UNDERGROUND STORAGE AND PASSIVE SEISMIC

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Large-scale exploration of shale oil and gas, in America in particular, has driven innovation in the passive seismic characterisation of unconventional reservoirs over the years. Such techniques are proving to be extremely useful in assessing the suitability of former oil and gas reservoirs for underground storage of carbon dioxide. A range of techniques for characterising CO2 storage reservoirs are now under development, including geomechanical modelling and analogue and numerical modelling in combination with seismic analysis. Important work is also being done on injection rates in preparation for largescale adaption of carbon storage to help meet the planet’s carbon reduction goals.

Zuzana Jechumtálová et al show that long-term CO2 sequestration leads to induced seismicity at distances exceeding kilometres from the injection well.

James R. Johnson et al utilise analogue and numerical modelling in combination with seismic analysis to identify potential areas of further research on injection rates for CO2 storage.

Ruud Weijermars highlights how a novel geomechanical model can help to identify suitable CO2-storage capacity in the subsurface of coastal regions by computing what pressure buildup in the reservoir will result in geo-engineered surface uplift that nullifies the adverse effects of relative sea level rise for the region under flood threat.

Roy P. Bitrus et al present a survey that has mapped the hydrocarbon presence probability to identify and derisk the presence of hydrocarbons in the survey area.

Valeria Di Filippo et al demonstrate proper planning facilitates for safe, durable injection of CO2 in a nearshore depleted reservoir for long-term storage.

It is also possible to submit a Technical Article to First Break. Technical Articles are subject to a peer review process and should be submitted via EAGE’s ScholarOne website: http://mc.manuscriptcentral.com/fb

You can find the First Break author guidelines online at www.firstbreak.org/guidelines.

Special Topic overview

How large should microseismic monitoring networks be for CO2 injection?

Zuzana Jechumtálová1*, Leo Eisner1 and Thomas Finkbeiner2 show that long-term CO2 sequestration leads to induced seismicity at distances exceeding kilometres from the injection well.

Introduction

We review published literature of induced seismicity resulting from CO2 sequestration in geological formations. We explain why these processes are related and explain various hazard levels associated with this practice. We also discuss why the depth of induced seismicity is a crucial parameter when evaluating risks for caprock failure and triggered (felt) earthquakes in the basement as well as characterise the reservoir (i.e., formation used for sequestration).

Several case studies observe induced seismicity, mostly associated with basement activated faults. Only one case of induced seismicity suggests seal failure resulting from CO2 sequestration. However, our review also documents an apparent lack of adequate monitoring arrays installed to capture induced seismicity. We found a large number of case studies where no induced seismicity has been detected – most likely due to the seismic monitoring network physical limitations.

Despite the limited number of reported cases, we find a weak positive correlation between seismic magnitude and the volume of injected CO2. Furthermore, and perhaps more importantly for microseismic monitoring network design, we show strong evidence that long-term CO2 sequestration leads to induced seismicity at distances exceeding kilometres from the injection well. We discuss this observation is similar to salt-water disposal induced seismicity.

Background and objectives

Geologic carbon storage is a valuable strategy for reducing atmospheric CO2 emissions while minimising the economic disruption of de-carbonising the world’s energy supply (International Energy Agency, 2010; Pacala and Socolow, 2004). However, the sequestration process can create a number of environmental and safety hazards that must be understood and addressed. These include the potential for injection-induced earthquakes, which result from altering pore-pressure and the present day in situ state-of-stress conditions in the subsurface. To date, measured seismicity due to CO2 injection into geological storages has been limited to microseismicity; although a few stronger events have been felt (see Table 1). There are important similarities between CO2 injection and other energy-related subsurface operations that have induced significant earthquake

events — e.g., geothermal systems, waste-fluid injection, hydrocarbon extraction, etc. (National Research Council, 2012). That said, there exist important distinctions among these processes that should be discussed in the context of inherent seismic risk (IEAGHG, 2013).

This study reviews observed induced seismicity resulting from CO2 injection into geological formations in the context of geologic carbon storage (GCS) and CO2-enhanced oil recovery (CO2-EOR). A promising outcome is that for any given development project the risks of induced seismicity can be lowered using a mix of mitigation and remediation strategies.

In the context of Carbon Capture & Underground Storage (CCUS), the workflow should start with a clear understanding of risk. We employ the general definition that risk consists of three parts (Kaplan and Garrick, 1981):

1. one or more scenarios of concern;

2. the probability of a given scenario occurring;

3. and the damage that would result (i.e., the consequence of the scenario).

Thus, a quantitative measure of risk must encompass both the probability of an event to occur and the severity of its impact. The term hazard is used to refer to components 1 and 2 alone — i.e. just the probability of occurrence, without the measure of damage.

The first step in a risk assessment is to identify all plausible scenarios that may be considered as, and lead to, damage. For a CO2 injection project, four scenarios related to fault reactivation and induced seismicity are a primary concern and considered damage:

1. property damage;

2. a public nuisance (see discussion below);

3. brine-contaminated drinking water;

4. CO2-contaminated drinking water.

The first scenario (property damage) is analogous to the risk associated with natural seismicity, though here building and infrastructure damage results from induced events. The second scenario captures the notion that felt earthquakes will bother people in the local vicinity – even without the occurrence of property damage. Here, we use the common terminology ‘nuisance’ to

1 Seismik s.r.o. | 2 King Abdullah University of Science & Technology

* Corresponding author, E-mail: zuzana@seismik.cz

DOI: 10.3997/1365-2397.fb2024031

define this risk, although the meaning of this word may falsely convey that it is a minor problem. In fact, its consequences should not be underestimated: public backlash can lead to entire projects being shut down (Deichmann and Giardini, 2009); this influences public opinion and spreads scepticism that geologic carbon storage is an unsafe process of dealing with CO2 (Singleton et al., 2009). Scenarios 3 and 4 result from the observation that slip along faults or fault zone can alter subsurface fluid flow patterns, potentially creating or reactivating leakage pathways (Zoback and Gorelick, 2012, 2015; Juanes et al., 2012; Vilarrasa and Carrera, 2015a,b). It is helpful, however, to make a distinction between brine and CO2 leakage. While they may occur together, they have different physical behaviour, occurrence probabilities, and impact on ground water security. In the case that other in situ fluids are present — e.g. oil or gas — additional scenarios need to be added to the list. Indeed, the enumeration of risks above is not meant to be exhaustive, and additional risk may be important at a given site. Thus, the four scenarios listed above, though, are key priorities for all onshore storage operations. Also, while the intrinsic damage potential at offshore CO2 storage sites may be much lower, fault reactivation and induced seismicity are nonetheless highly undesirable.

Given these four scenarios above, we focus our attention in this study on monitoring strategies. Ultimately, mitigation techniques can be applied to address the following two aspects:

(i) lower the likelihood of significant seismicity to occur and (2) minimise damage should earthquakes occur. While it is desirable to avoid induced seismicity in the first place, the inherent complexity of subsurface systems make this a challenging task – especially when considering large scale (i.e., high volume) field developments. Selection of sites having favourable formation characteristics and adequate operational procedures can lower this likelihood. However, a remaining (i.e., non-zero) probability of inducing larger earthquakes will always exist (see also more discussion in Zoback and Gorelick (2015). In light of this, it is pragmatic to always choose sites and engineering safeguards such that consequences are likely to be low (even if unwanted events occur).

Case study review on seismicity (or lack of) induced by CO2 sequestration

Based on our literature search, we summarise below the most publicly reported CO2 sequestration projects with emphasis on the induced seismicity. In each case, we provide a brief description of the monitoring array deployed and the seismicity recorded:

• Sleipner, North Sea (CO2-EOR): No seismicity has been reported at the Sleipner field to date. However, there is no local seismic monitoring network and the regional network will only register events greater than 3.4. Therefore, it is impossible to rule out that small-scale seismicity has occurred and is occurring. However, because the Utsira Sandstone storage formation is very large with very few barriers to flow and porous (average porosity of 35-40%, total pore volume is estimated at 6x1011 m3), injection has caused only very small pressure increases. This fact results in a very low probability to induce seismicity in the specific case of Sleipner (Verdon et al., 2013).

• Snøhvit, North Sea (CO2-EOR): The Snøhvit Field is located in an elongated E-W trending fault block system located in the western Barents Sea, some 150 km north of the coast of Norway. Much like Sleipner, no local seismic monitoring network has been deployed to date, so only events greater than 3.4 can be detected. However, unlike Sleipner, pore pressures increased substantially during initial injection phase into the Tubåen Formation (White et al., 2018); this fact necessitated a change in injection strategy, using the shallower Stø Formation instead. However, it is not known whether the pore pressure increases in the Tubåen Formation triggered any earthquakes; the regional seismic network (the closest station is onshore, i.e. more than 150 km away) has so far not detected any seismicity from the field.

• Cogdell, USA (CO2-EOR): Injection of CO2 to enhance recovery began in 2001, although with negligible injection rates. Since 2004 monthly gas injection volumes (including CO2) have markedly increased exceeding 85 million m3/ month (Gan and Frohlich, 2013). For the entire Cogdell site combined gas injection rates were about 113 million m3/month between 2004 and 2012; a temporary increase to more than 225 million m3/month occurred in August of 2006 just as the first earthquake in the 2006-2011 sequence was detected. The magnitudes of these events ranged from 1.6 to 4.4, included 18 events with magnitudes exceeding 3, and an Mw 4.4 earthquake that occurred September 11, 2011. The ensuing events were all located within 2 km of actively injecting wells. Thus, gas injection most probably contributed to triggering the earthquake sequence, but it has not been shown. The event depths were fixed at 5 km because USArray station spacing (∼70 km) is too large to allow determining meaningful depths. The recent seismic activity provides strong evidence for the activation of preexisting subsurface faults. This was followed by a 24-year interval quiescence with no earthquakes detected. We utilise this information to estimate total volume of injection in the summary below.

• Aquistore, Canada (GCS): CO2 injection at the storage site began in April 2015 with the purpose of storing liquid CO2 deep underground (Roach et al., 2017). A monitoring array of 650 geophones was deployed to monitor microseismicity at the Aquistore site. These geophones were buried to depths of 20 m on a 2.5x2.5 km regular grid, and form part of a large seismic network primarily for repeat seismic reflection surveys. During a 3-year period (2015-2017) of monitoring, no microseismic events have been detected, although only a small fraction (less than 1%) of the planned volume has been injected. Recently, it has reached the milestone of permanently storing 0.5 million tonnes of CO2.

• Cranfield, USA (CO2-EOR): A seismic monitoring array was deployed consisting of six instruments buried in shallow boreholes 100 m deep situated in a circular fashion approximately 3 km from the injection well; this array monitors large-scale CO2 injection with annual injection rates of more than 1 million tonnes. The monitoring started on December 15, 2011 and finished on February 19, 2015. If the microseismic events occur at the reservoir depth just beneath the monitoring station, the minimum detectable magnitude is estimated to be Mw -0.5.

Further, the monitoring network can detect as low as Mw 0.0 if the events occur within the site (distance of 6 km). No induced/ triggered seismic events were detected (Hovorka et al., 2013).

• In Salah, Algeria (CO2-EOR): Seismic monitoring at In Salah started only five years after CO2 injection started but the monitoring ‘network’ was limited to a single geophone in a shallow borehole (Verdon et al., 2015). More than 6000 (micro-)seismic events were detected during the monitoring period, the largest of which had a magnitude of Mw 1.7.

• Weyburn, Canada, (CO2-EOR): A downhole microseismic monitoring array of eight geophones was installed to monitor a small part of the whole field. Approximately 200 events were recorded over a six-year period, all with magnitudes less than M w 0. Verdon et al. (2011) used these events to constrain a geomechanical model of the field. Event hypocentres indicate that most of the microseismicity is located around nearby horizontal production wells, and not around the injection well as anticipated. Although the errors in vertical location are large, it appears that many events are located in the overburden. Overall, the low rate of seismicity suggests either that the rock deformation is very small, or deformation is generally occurring aseismically. Verdon et al. (2011) have generated a representative numerical geomechanical model of the Weyburn reservoir and surrounding units coupling together an industry standard fluid-flow simulator with a finite element mechanical solver. The initial model uses material properties based on core sample rock physics measurements. This does not match the microseismic observations well. The most likely reason is that reservoir stiffness has been overestimated. Reducing reservoir stiffness by an order of magnitude, the revised model does predict that microseismic events will occur around the producing wells and in the overburden above the producers.

• Aneth, USA, (CO2-EOR): A downhole array of 60 geophones (prev. 23 geophones) was deployed to monitor CO2-EOR at the Aneth Field. Produced water from the field was also injected into an underlying aquifer. No seismicity was detected associated with the CO2 injection, but the underlying produced water disposal generated approximately 1400 events (two fault-like clusters) over the course of a year, with the largest event having a magnitude of 1.2 (Rutledge, 2010).

• Decatur, USA (GCS): Two separate monitoring arrays were installed to monitor the Illinois Basin-Decatur Project: a downhole micro-seismic monitoring array consisting of 34

multicomponent geophones in two deep boreholes (Bauer et al., 2016), and a secondary array consisting of 13 broadband seismic instruments at the surface and four accelerometers deployed in 150 m-deep boreholes (Kaven et al., 2015). The downhole microseismic array detected a total of 4747 events over a three-year period during CO2 injection with a peak magnitude of 0.9. The surface monitoring array has detected 179 events, with magnitudes ranging from 1.1 to 1.3 (Williams-Stroud et al., 2020). Multiple fault-like clusters were created and post-injection seismicity was observed.

• Lacq-Rousse, France (CO2-EOR): Three types of seismic monitoring arrays were installed to monitor CO2 storage at the Lacq-Rousse field. The first consisting of one surface seismometer (0.5-50 Hz), the second in seven shallow borehole arrays of four geophones (10-1000 Hz) each buried to depths of approximately 200 m, and the third being a deep downhole array of three accelerometers (1-800 Hz). The entire network detected over 2500 reservoir-related microseismic events during a three-year period, all of which had magnitudes less than 0 (Payre et al., 2014).

• Otway, Australia (GCS): At the beginning microseismic monitoring at the site relied on three shallow boreholes (<100 m) with broadband seismometers. These detected no seismic events that could be directly attributed to the injection. Later, a downhole distributed acoustic sensing (DAS) monitoring array consisting of five wells was deployed. These nearly vertical wells reached depths up to 1750 m drilled from 2 pads (Shashkin et al., 2022). The recorded data were used to build a 3D velocity model to detect and monitor the CO2 plume over time. The first dozens of induced events were detected with a maximum moment magnitude MW ~ -0.5 (Glubokovskikh et al., 2023). The weakest detected events have magnitudes -1.5. The first cluster of microseismic events occurred between the pre-mapped faults. However, two strong events occurred to the north from the Well Pad B two months after the end of the CO2 injection.

The observed seismicity resulting from CO2 sequestration from the various projects described above is summarised in Table 1 below. From the information, we extracted maximum earthquake magnitude and plotted this as a function of cumulative injected volume (Figure 1). We observe a weak positive dependency of maximum induced event magnitude with cumulative injected volume. However, we do not wish to generalise these observations

Figure 1 Observed maximum magnitudes and injected volume of CO2

Monitoring array Project name, Country Type Observed magnitudes Observation period, number of events Injected volumes [M tonnes]

Regional array

Surface array

Sleipner Norway CO2-EOR aquifer storage no seismic events have been detected since 1996 0.85-1 per year

Snøhvit Norway CO2-EOR aquifer storage no seismic events have been detected since 2008 total 7

Cogdell Texas, USA CO2-EOR oil field 1.6 to 4.4 over a 6 year period (2006-2011) in time of M4.4 ~10

Decatour Illinois, USA GCS dedicated storage

Lacq-Rousse France

Shallow boreholes array Aquistore Saskatchewan, Canada

Cranfield Mississippi, USA

Lacq-Rousse France

Saskatchewan, Canada

Paradox Basin Utah, USA

Lacq-Rousse France

Decatour Illinois, USA

to 1.3 179 events 1 (2011–2014) 1.8 (2017-2020) total 2.8

events over 3 years 0.051

GCS dedicated storage no seismic events have been detected 3 years (2015-2017) 0.0004-0.0006 per day, total 0.036

CO2-EOR dedicated storage no seismic events have been detected Dec 2011 – Feb 2015 >1 per year total 11.6

than 1 event over month

located events

events over 7 years 200+ located events

per year or more

events over 1 month

events over 3 years 1 (2011–2014)

(2017-2020) total 2.8 Downhole

events over 13 months

due to the limited number of events. Table 2 also summarises the epicentral distance of induced seismicity from injection of CO2 illustrating the size of activated area. We note that four of the seven case studies with induced seismicity events occurred at distances exceeding 1 km from the injection wells. For the remaining three case studies, where induced seismicity is observed within 1 km from the injection well, the CO2 injections represent relatively small and short injection (Lacq-Rouse), or poor monitoring network (Wayburn and in Salah).

Discussion and conclusions

The majority of the CO2 field sequestration cases studied did induce seismicity. However, only the Cogdell field had an appre-

ciable magnitude of 4.4. The rest did not reach magnitude 2 and some in fact not even magnitude 1. In addition, we notice that in five cases no induced seismicity was detected during sequestration. This may be explained by the fact that a significant portion of these lack adequate microseismic monitoring networks. Thus, the assumption that only low magnitude or even no seismicity is induced by CO2 sequestrations is probably incorrect. Therefore, we propose that national regulators or/and governments should mandate adequate (micro-)seismic and other monitoring strategies to properly inform operators in real time of the hazards and risks occurring during operations. Retro-active mitigation (i.e., only after induced seismicity occurs) is not considered a proper response.

Table 1 Summary of observed seismicity induced by a CO2 sequestration.

Generally, the above discussed induced seismicity occurs during or after the injection of CO2 However, the lack of preexisting seismicity may again result from the lack of observation networks. It is generally advisable to start to monitor at least with the CO2 injection, if not possible before. Only monitoring during the injection can provide adequate warning if activation of unwanted seismicity occurs.

Based on the above documented distances of induced seismicity from the CO2 sequestration injection wells, we conclude that the microseismic monitoring arrays need to monitor areas reaching to units of kilometres away from the injection borehole(s).

The above review documents how relatively weak seismic events have been observed up to today. This may imply that in the projects up to today induced seismicity by CO2 sequestration is probably not triggering deep basement faults (with the exception of Cogdell and perhaps Decatour). Monitoring and preventing such seismicity requires detection of relatively strong events, probably enough with moment magnitudes greater or equal to 1. However, monitoring of microseismicity related to reservoir or even seal breakage requires detection of much weaker events – based on observations from Decatour we may generalise that we need to detect events greater than magnitude 0.

Summarising the required size and distances of microseismicity, we see the fundamental problem of network design for CO2 sequestration is that a detection of very weak microseismic events (below moment magnitude 1) requires downhole monitoring which has only limited reach of detection from the monitoring well. However, long-term CO2 sequestration induces events at significant distances from the injection well. Furthermore, the differentiation between basement, reservoir and seal events requires achieving depth resolution to differentiate between different scenarios of the risk. However, the depth resolution decreases with increasing distance from the monitoring array. Even for the borehole monitoring arrays the depth resolution requires very long borehole monitoring ideally spanning the reservoirs. Thus, we conclude that downhole monitoring arrays are generally not suitable for monitoring of the seismicity induced by the CO2 sequestration and recommend use of multiple surface or shallow borehole monitoring seismic arrays to monitor and verify seismicity. While such arrays will not detect weak events as the

downhole arrays, they provide sufficient coverage and robustness needed for mitigation of risks associated with seismicity induced by the CO2 sequestration. Distributed acoustic sensing (DAS) systems have great potential to become an alternative suitable monitoring tool. Downhole-deployed DAS provides a relatively inexpensive receiver array that is sensitive to the microearthquakes in a wide frequency range, as is evident from applications to enhanced geothermal systems or stimulation of unconventional reservoirs. The DAS array has sensitivity sufficient for detection and location of induced events with Mw −2, which occurred up to 1500 m away from a monitoring borehole (Glubokovskikh et al., 2023).

Acknowledgements

The authors are grateful to King Abdullh University of Science and Technology for sponsoring this study under research grant ORA-CRG2021-4671.

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Impact of injection rate for CO2 storage within sedimentary basins, a multidisciplinary analysis of focused fluid flow

James R Johnson1*, Reinier van Noort1, Jamil Rahman2, Lawrence HongLiang Wang1 and Viktoriya Yarushina1 utilise analogue and numerical modelling in combination with seismic analysis to identify potential areas of further research on injection rates for CO2 storage.

Abstract

Carbon sequestration within sedimentary basins (e.g., sandstone reservoirs, saline aquifers) is one of the promising solutions for reducing GHG emissions. However, this will require the current rate of CO2 injection to be increased by several orders of magnitude. In practice this will be a shift from a scattered set of pilot projects worldwide e.g. Sleipner, Quest) to large-scale, regional CO2 injection across a range of sedimentary basins. As a result, there will be a large variety of different ‘CO2 systems’, with critical and sometimes challenging variations in both the reservoir and caprock conditions, both locally and regionally. As the CCUS industry scales it will become increasingly important to understand how the simultaneous injection of CO2 across extensive clustered sites will impact overpressure. Research on naturally occurring fluid migration systems shows that when critical boundaries are crossed for regional overpressure, release of gases can occur from the subsurface via different physical mechanisms. To enhance our understanding of this, we utilise analogue and numerical modelling in combination with seismic analysis to identify potential areas of further research within this previously largely unexplored risk category.

Introduction

Increasingly carbon capture, utilisation, and storage (CCUS) is being compared to waste management. This is perhaps the most apt description of it, as it involves the collection of an undesired product (i.e. CO2) emissions of which could be reduced, reused, or recycled, but must be disposed of in cases where it is not. Carbon credits, both voluntary and mandated, will determine how profitable this segment of waste management becomes. Mandated carbon credits for a number of jurisdictions (e.g. European Union, Canada) are set to reach roughly $130/tonne (GOC, 2024; EU, 2024) while voluntary markets have paid several times that in some cases already.

Given potential profitability, a number of technologies have been developed to manage CO2 waste in a comparatively short timeframe. Currently, some of the most popular methods include carbon utilisation short-term (CUST) (e.g. biofuel, food carbon-

1 Institute for Energy Technology

| 2 University of Bergen

* Corresponding author, E-mail: james.johnson@ife.no

DOI: 10.3997/1365-2397.fb2024032

ation) and carbon utilisation long-term (CULT) (e.g. concrete, steel), biological methods (e.g. biochar, microalgae, macroalgae), and geological methods (e.g. reservoir storage, carbon mineralisation) (van Noort et al., 2013; Kelemen et al., 2019; Gayathri et al., 2021; Onyeaka et al., 2021; DOE, 2024; IEA, 2024). Carbon sequestration in sedimentary basins has a substantial lead in understanding the necessary technologies due to similarities with hydrocarbon exploration, while also providing significant storage space (i.e. est. 5 Gt/year by 2050, 2-6 Pt total capacity) (Benson et al., 2005; Kelemen et al., 2019; IEA, 2024). Such volumes are projected to be enough storage space for CO2 in order to reach IEA Development Goals beyond the year 2100 (Kelemen et al., 2019; IEA, 2024).

In addition to profitability, safety considerations are essential for establishing CO2 storage within sedimentary basins as a business. Successful pilot projects (e.g. Sleipner, Quest) have accelerated growth and enthusiasm for the technology, while other projects have created learning opportunities (e.g. In Salah, Weyburn, Decatur) sometimes at a cost to public engagement and support. Experience from these projects, in addition to other injection-based industries (e.g. geothermal) have shown that there can be issues with subsurface mechanical behaviour (e.g. induced seismicity, fault reactivation) related to geological uncertainty (Michael et al., 2010; Rutqvist, 2012; Yarushina et al., 2022). Moreover, seal capacity has been shown to be influenced by injection rate in combination with the properties of the reservoir they are emplaced within (Gasda et al., 2017; Johnson et al., 2022a). As development of carbon sequestration in sedimentary basins scales up, such issues will become more critical. Our ability to understand and manage these impacts (e.g. water production to limit overpressure) is a challenge to this sector of CO2 waste management. Fault activation, fracturing of seals, and the formation of flow paths that could lead to CO2 leakage are just a few mechanical behaviours that will become more difficult to manage as the industry shifts towards basin-scale development. Here we explore the expected behaviour, both locally and regionally, of the subsurface under different mechanical conditions as a parameter of injection rate of CO2. Specifically, we highlight the need to

think about the impact of the rate of injection as a spectrum, presenting naturally occurring phenomena (e.g. gas chimneys, pockmarks) on high-resolution seismic alongside analogue and numerical modelling of porosity waves as a case study in order to prevent early accidents that could be detrimental to public engagement and support.

Pockmark and Chimney Formation – A model for CO2 leakage?

Pockmarks and their chimney structures are a common occurrence within sedimentary basins, and their structural parameter have been studied using seismic (Figure 1). Pockmarks are circular indentations on the seafloor with a characteristic M-shape when viewed in cross section. They form as a result of gas seepage (e.g. CH4, CO2) through the seafloor, and are potentially associated with porosity waves (Hovland and Judd, 1988; Rass et al., 2018; Connolly et al., 2022; Yarushina et al., 2022).

It is commonly accepted that reservoir overpressure is the main driver leading to gas seepage and the formation of chimney structures. In gas reservoirs, overpressure can form as a result of one or a combination of several different factors including but not limited to high sedimentation rates, hydrocarbon generation, alterations in PT regime associated with diagenetic reactions, or glaciation/deglaciation cycles (Portnov et al., 2016; Wangen, 2020; Johnson et al., 2022b; Yarushina et al., 2022). In the case of subsurface storage of CO2, the overpressure can be created locally through rapid injection, or on the basin scale from improper modelling and management of a network of CO2 injection wells within a given region.

Regardless, the mechanisms behind how the formation of chimney structures occurs is debated within the literature. While it has been proposed that it could be the result of extensive vertical hydraulic fracturing (Wangen, 2020; Robinson et al., 2021), other proponents have modelled how it could be related to porosity waves (Rass et al., 2018; Yarushina et al., 2020).

Porosity waves would be expected to form in ductile deformable formations at lower fluid pressures than those associated with brittle stress behaviour (i.e., fractures) (Rass et al., 2018; Yarushina et al., 2022). Conversely, porosity waves should

occur at higher fluid pressures than is seen when solely diffusion occurs. Within this narrow range of conditions, porosity waves are associated with pore dilation caused by viscoplastic deformation of the pore space (Yarushina et al., 2022). When combined with flow localisation, this produces elongated cylindrical conduits (Figure 1) with an approximately circular cross-section (Rass et al., 2018).

Numerical modelling has shown that key parameters controlling the formation and dimensions of porosity waves are compaction length (L - m) (Equation 1) and compaction time (T - s) (Equation 2) (Yarushina et al., 2022). Compaction length describes the drainage area required for each chimney to grow and can be imaged for a given area utilising seismic (Figure 1).

(1)

Where η is bulk viscosity of the rock (Pa s), μ is fluid viscosity (Pa s), and K is background permeability (m2). Collating average geometry characteristics of chimneys for a said area (e.g. Figure 1) could assist in understanding any uncertainties associated with their inputs. Compaction time describes how quickly a porosity wave will form a chimney structure.

(2)

Which depends on the difference between solid and fluid densities (Δρ – kg/m3), bulk viscosity (η), compaction length (L), and gravitational acceleration constant, g (m2/s). The inverse relationship between compaction length and time (Equation 2) suggests that larger chimney structures should form faster. Furthermore, Yarushina et al., (2022) shows that chimney formation and resulting seal failure can occur incredibly rapidly (c. 1-2 years).

Since brittle failure of potential caprocks is well documented as a result of shale exploitation (Heinemann and Mittermeir, 2012; Johnson, 2017; Uzun et al., 2017) injectors will have to consider both modes of failure. Within the brittle regime, fracturing is expected to occur when fluid pressure increases beyond the minimum horizontal stress (Zoback, 2007). Such fracturing typically creates planar structures connected to the original reservoir,

Figure 1 (a) High resolution post stock seismic showing the presence of a pockmark in cross-section with a zoom-in of pockmark in the white box. (b) Seismic attribute variance was applied in order to pull out the residual signal from the gas chimney, with a zoom-in showing more clearly the vertical striations of the chimney wall.

that follow the orientation of maximum principal stress (Zoback, 2017). However, locally they are also influenced by other factors including rock fabric, composition, historical principal stress orientation, etc. (Johnson et al., 2022a; Johnson et al., 2022b).

Extensive analogue modelling has been carried out investigating brittle behaviour utilising Hele-Shaw cells (Li et al., 2020; Johnson et al., 2022b, Oye et al., 2022). Li et al., (2020) showed that injection of fluids will follow the direction of principal stress. Subsequent research has shown that fracture patterns also depend on rock fabric and composition, highlighting how vertical fracture formation, important for fluid migration, is possible when the minimum principal stress is vertical (Johnson et al., 2022b). However, there are limited examples of analogue modelling of viscoelastoplastic regimes wherein porosity waves can occur.

Methodology for analogue modelling

Here, we are performing analogue modelling experiments in a transparent Hele-Shaw cell in order to better understand the flow mechanisms that lead to chimney formation. In these experiments, water is injected into the base of our quasi 2D Hele-Shaw cell utilising a ISCO 260D pump. Within the HeleShaw cell a column of saturated, granular hydrogel, simulating the mechanical behaviour of a sedimentary basin, sits underneath a short column of water. The suitability of hydrogel to represent the rheology of the subsurface for poroviscouselastic experiments was established by MacMinn et al., (2015). In the experiments shown here, a blue dye was added to the injected water to contrast this fluid from (colourless) interpore water saturation. Behind the Hele-Shaw cell sits an opaque sheet of Plexiglass utilised as a light diffuser for the LED light source beyond that. A camera, Olympus E-5, is set to take pictures every 2 minutes with the data being logged on a PC .

Image analysis was used to quantify the results utilising ThermoFisher’s Avizo, paying particular attention to how injection rate impacts the creation of a plume within this environment. Furthermore, the ascent and changing geometry of the plume are analysed. The analysis of the plume is then used to better understand the impact it has on the subsurface. The parameters analysed were area (A – m2), Crofton perimeter (Cp - m), symmetry (s – unitless), shape (SAP - unitless), orientation (O – degrees), and elongation (E - unitless).

The Crofton Perimeter computes the perimeter utilising the intercept count (Gel’find and Graev, 1991), through a discrete summation of the distance between any two points on a grid within the given shape (Equation 3).

(3)

Where, N0, N90 and N α represent the intercept counts in the horizontal and vertical directions, and for a given diagonal direction, α, respectively. Parameters a, b, and c are the distances between the horizontal, vertical, and diagonal lines. While symmetry and shape were both used to investigate how the plume changes geometry as it ascends, the two parameters explore different aspects. Symmetry explores the invariance of the plume geometry under certain transformations, and is calculated using Equation 4. When s=1 the shape is perfectly

symmetrical. Shape measures how closely the plume resembles a perfect circle (Equation 5) where SAP =1 is considered ideal.

(4)

Here, ϴmin is the minimum value operator between 0 degrees and π along the shortest axis, and Rmin and R max describe the geometry of said axis.

(5)

Similar to shape, elongation is used to analyse how eolotropic the shape of the plume is. This is calculated based on an inertia matrix (Equation 6). The shape is then characterised by E which is calculated from the two eigenvalues along the longest (λ1) and shortest (λ2) axes respectively (Equation 7). Values closer to 0 are more eolotropic.

(6)

(7)

Orientation is usually, but not always, an indicator of direction (Matthews et al., 1999). In the case of a plume experiencing buoyant forces, the orientation can appear to change depending on the amount of force applied downwards upon it. Orientation, which can vary between -90o and 90o, in this case is most representative of plume flattening which is dependent upon compaction length (Equation 1) and compaction time (Equation 2). Together these geometry parameters can be used to quantify the impact of a porosity wave as it migrates upward, in order to understand more about how a gas chimney is created both naturally and in the case of CO2 injection for subsurface storage.

Results

The generation of a focused fluid flow, due to the injection of CO2 within a subsurface reservoir, based on the analogue modelling carried out here, can be broken up into six phases characterised by large shifts in a combination of the parameters identified (i.e. area. Crofton perimeter, symmetry, shape). Phase I: Channelisation is characterised by the creation of a near-vertical channel up out of the overpressure focal point (i.e. injection site), that can be characterised as a thin, symmetric intrusion (Figure 2a). Geometry analysis shows that Phase I – Channelisation is marked by a small total area and Crofton Perimeter (Figure 3a). Furthermore, the symmetry is the highest that it will be for the duration of the experiment while the shape is also the most eolotropic that it will be (Figure 3b and 3c).

Phase II: Plume Growth sees the plume expand in area while not greatly further penetrating upwards through the poroviscoelastic medium (Figure 2b). Mode II fracture growth is interpreted to be created allowing the expansion of the plume, and is represented by a white halo around the plume wave (Figure 2b). There is slow growth in area and Crofton Perimeter which can be visualised by the shape becoming significantly more circular, reaching a plateau before plume flattening occurs (Figure 3b);

this is correlated with an increase in elongation value (i.e. less eolotropic). Due to the small size and proximity to injection site, the plume is the most asymmetrical that it will ever be during this

phase (Figure 3b). The orientation shifts from almost vertical (i.e. -90o) towards horizontal (i.e. 0o) as it approaches the next phase (Figure 3c).

Phase III: Plume Detachment is marked by upwards movement of the plume, releasing it from the injection site (Figure 2c). Focused fluid flow occurs in the region interpreted to be fractured, while intrusion of the porosity wave results in further creation of mode II fractures as a white halo around the plume (Figure 2c). Simultaneously, the plume head experiences a significant amount of flattening as it interacts with the medium above resulting in the plume to be the widest it will be during the experiment. There is still slow growth of area and Crofton Perimeter during this phase (Figure 3a). Symmetry finishes plateauing and starts to decrease, while the shape parameter remains close to its minimum (Figure 3b). Orientation, however, has now shifted to being roughly horizontal as the plume head flattens (Figure 2c and 3c).

Phase IV: Plume Rise shows the plume moving upwards in the column while also becoming more circular (Figure 2d). Again, a halo of mode II fracturing is seen around the plume as it rises (Figure 2d). The area and Crofton Perimeter experience a significant surge during this phase. This is visible to the naked eye (Figure 2c and 2d) and correlates to an increase in slope for growth of both of these parameters (Figure 3a). Symmetry becomes variable, while the plume becomes increasingly circular (Figure 3b). Orientation remains constant during this period, suggesting that the plume is still more flat than it is high (Figure 3c).

Phase V: Final Acceleration sees further plume extension as it gets ready to break through the poroviscoelastic media-water interface (Figure 2e). An increase in pressure at the plume edge is highlighted by a darker blue, while a whiter region is caught in the image analysis as a small hole suggesting separation and the possible presence of a disparate plume (Figure 2e). There is a slight bump downwards in area and Crofton perimeter growth as the plume interacts with the surface (Figure 2e and 3a), suggesting initial leakage of the plume is occurring. Note,

Figure 2 Analogue modelling of CO2 injection into the subsurface, where it is possible to see (a) initial injection, (b) plume growth, (c) plume flattening and detachment from source, (d) plume rise and shape/symmetry fluctuation, (e) plume acceleration towards surface, and (f) plume breakthrough characterised by channel creation.

Figure 3 Forty equally distributed datapoints in time were selected to show general trends for the six parameters studied here. (a) Area vs. Time (red) and Crofton Perimeter vs. Time (blue) (b) Shape vs. Time (yellow) and Symmetry vs. Time (green) (c) Orientation vs. Time (black) and Elongation vs. Time (grey). Circles pinpoint the beginning of each new phase.

at this point a characteristic M-shape of a pockmark is visible at the media-water interface. Symmetry and shape have found a new plateau during this phase (Figure 3b). Orientation remains unchanged until it rapidly shifts to becoming roughly vertical again (Figure 3c).

Phase VI: Plume Breakthrough shows the establishment of a chimney and the following stream of porosity waves (i.e. green and yellow in Figure 2f), in addition to a collection of blue fluid at the top of the water surface (Figure 2f). This occurs as the result of surficial blowout and liquefaction of the solid (Figure 2f). The collection of blue fluid at the top of the water surface (Figure 2f) is partially representative of gas (e.g. CO2) that has made its way through the marine-water column into the atmosphere. Here, gel that is associated with the blue fluid is representative of particulate that is pushed up into the column by the porosity wave and would settle out on the seafloor enhancing the characteristic M-shape seen in seismic (Figure 1). Due to the creation of multiple plumes now streaming upwards through the much thinner channel that has been created (Figure 2f) this portion of the porosity wave development was not characterised utilising geometry parameters.

The formation of one or the other phases depends on the injection pressure, injection rate and permeability of the formation. In the case of moderate injection rate, a prolonged Phase I: Channelisation can be expected. This phase is characterised by the localised pulsating fluid upward propagation in the form of porosity waves.

Comparison with numerical modelling

Numerical modelling was conducted, in part, to compare with the analogue modelling. Figure 4 illustrates the outcome highlighting the progression of porosity waves in an idealised system. The model domain is 10x20 with a numerical resolution of 100x200. The length unit L is the compaction length (Equation 1) of the two-phase system, while the time is scaled by compaction time, T, (Equation 2) (Yarushina et al., 2022). These two properties, as discussed depend upon the properties of the rock and the fluid it contains. The fluid injected at the bottom midpoint starts at T=0 with the subsequent creation of porosity waves. Further numerical modelling is detailed by Wang et al., (2022).

The numerical model does a good job of showing the changes that occur to the subsurface as a result of the porosity waves ascent. At the beginning an increase in porosity, alongside a pressure effect can be seen (Figure 4a). On the leading edge of an upward-flowing fluid, one can observe a decrease in effective pressure, succeeded by an area where the effective pressure surpasses that of the surrounding subsurface. As the porosity wave ascends, you can see an undulation in the plume walls suggesting following porosity waves. This is marked by changes in both porosity and effective pressure (Figure 4b). In addition to this a radiating pressure effect from the injection site is seen on either side of the ascending plume (Figure 4b-d). Greater separation between the leading plume and the attached plumes following are noted in Figure 4c. Finally, a channel is created showing a significantly more uniform pattern in porosity, while the pressure differences also become more subdued (Figure 4d).

Both models start with growth in the leading edge prior to ascent (Figure s 2a-b and 4a-b) that could be interpreted as channelisation. Another clear similarity in the two models is a wider initial ascending porosity wave resulting in a more uniform, narrower final channel (Figure s 2f and 4d) that has resulted in the fundamental alteration of the properties of the medium. While other similarities likely exist, further experiments are required to more adequately explore them.

Relationship with CO2 storage and geophysical monitoring

The mechanical behaviour of the subsurface upon a change in pore fluid pressure or effective stress depends on both the properties of the rock (e.g. permeability, Young’s modulus, creep parameters) and those of the fluid(s) they contain (e.g. fluid density, viscosity). In the case of CO2 storage, injection rate plays a critical role, both locally and at a basin-scale (Figure 5). Under ideal circumstances, the injection of CO2 will result in flow near the injection site, followed by diffusion through the pore-space at the edges accumulating until maximum capacity less any pressure difference for safety is reached (Figure 5a). From this point, the CO2 will hopefully be held there by a combination of the following mechanisms (1) structural and stratigraphic trapping, (2) residual CO2 trapping, (3) solubility trapping, and/or (4) mineral trapping (Benson et al., 2005; Keleman et al., 2019; Ringrose et al., 2020). Due in part to shale hydrocarbon exploitation (Heinemann and Mittermeir, 2012; Johnson, 2017; Uzun et al., 2017), the industry is ubiquitously aware of the impact that a high injection rate can have on a brittle system, where ‘fracking’, results in a series of complex fracture patterns. In a ‘CO2 system’ stress-induced fracturing could result in failure of the primary caprock (Benson et al., 2005; Rutqvist, 2012; Ringrose et al., 2020) through stress-induced fracturing (Figure 5c). Rutqvist (2012) expounds on common failure types within this regime highlighting (1) caprock fracturing/failing, (2) fault reactivation (e.g. seismic and aseismic slip), and (3) surface deformation (i.e. uplift followed by subsidence). Diffusion and brittle failure are two end-member possibilities resulting from injection of CO2, that are often considered the only probable outcomes (Rutqvist, 2012; Ringrose 2020). However, at least one more possibility exists within this spectrum as demonstrated by the presence of gas chimneys on active seismic (Figure 2). Specifically, failure through porosity waves (Figure 5b) as shown previously by numerical modelling (Yarushina et al., 2020; Yarushina et al., 2022) and confirmed by both the analogue and numerical modelling here.

The deliberate formation of porosity waves isn’t always undesirable. In the case of reservoirs containing intraformational flow barriers, porosity waves might alleviate reservoir compartmentalization, enhancing injectivity and storage capacity (Yarushina et al., 2021). However, it’s crucial to prevent their propagation into the caprock. The analog and numerical modelling presented here provides insight from a first-principles perspective that injecting CO2 into a poroviscoelastic medium can lead to the emergence of porosity waves in the subsurface (see Figures 2 and 4). The movement of these waves through the column fundamentally alters the structure of the medium (Figure 2), producing similar patterns resembling chimneys and pockmark geometry observed in seismic data (Figure 1). Furthermore, experiments demonstrate

that the initial plume’s geometry can be substantially wider (approximately 2.5 times wider here) than the subsequent channel formed (Figure 2). Ultimately, the alteration in rock properties facilitates a more accessible conduit for fluid flow towards the surface thereafter (Figure 2f).

Furthermore, conditions under which they would occur for CO2 subsurface storage systems require further research (Wangen et al., 2020; Yarushina et al., 2022). However, it is clear that locally injection rate is a critical factor to understand. At a regional scale it is important to consider a basin-wide CO2 injection strategy that takes into account overpressure for the entire geological system (Figure 5). Currently, further analogue and numerical modelling is required to compare different

injection rates and how this impacts plume growth and failure of the overburden.

When considering the role passive and active seismic should take in the monitoring of CO2 injection, passive monitoring is occasionally utilised to justify longer time periods between the deployment of active 4D seismic, as well as the deployment of fit-for-purpose seismic (e.g. multicomponent, wide azimuth) (Davis et al., 2019). While it may be possible to detect porosity waves utilising passive methods (Yarushina et al., 2022), especially during initial channel creation (Figure 2a, Phase I), the reality is that the difference in signature that would be given compared to brittle failure is not yet understood. Conversely, active methods have been shown capable of tracking fluid

Figure 4 Numerical modelling of injection creating a localised porosity wave at time steps (a) 0.52, (b) 3.31, (c) 6.52, and (d) 9.47. Changes in porosity and effective pressure are shown as the porosity wave makes its way towards the boundary interface.

Figure 5 Sketch of three different possible mechanical interactions between the subsurface and the injected fluid (i.e. CO2) as it relates to increasing injection, with (a) ideal diffusion, (b) porosity waves, and (c) brittle failure.

injection (e.g. CO2, SAGD for heavy oil recovery) (White, 2013; Davis et al., 2019), as well as chimneys that may be the result of naturally occurring porosity waves (Figure 1). The value of multicomponent data for CO2 injection cannot be understated, as it would allow for full geomechanical characterisation of the subsurface, and a better separation of what signal is resulting from the rock compared to injected fluid (i.e. CO2) (Davis et al., 2019). Nonetheless, further studies comparing the use of all active and passive methods (e.g. Berkhout and Verschuur, 2011; Johnson, 2017; Davis et al., 2019) may allow for greater utilisation of passive methods in the future.

Conclusion

Decades of research have been invested into better understanding sedimentary CCS with notable real world pilot project successes (e.g. Sleipner, Quest) and some notable failures (e.g. In-Salah). Despite this, there are still components of the ‘CO2 system’ that we do not fully understand. It has been shown that when injecting CO2 into the subsurface it is important to think of mechanical behaviour as a spectrum, including the possibility for porosity waves and potentially other phenomena, as opposed to two end-member behaviours (i.e. diffusion, brittle failure). Various facets of hydrocarbon exploration, especially unconventionals (e.g. shale exploitation, oil sands) have provided a good framework for beginning to understand subsurface fluid migration and the tools that can help us further investigate this. Nonetheless, the development of large-scale CCS fields is the greatest subsurface challenge we have yet to face as an industry. Understanding the first principles of how injection rates and injection pressure will impact CO2 propagation on both a local and regional scale is necessary, and moreover it is critical to exploring what monitoring methods will ensure early warning of any possible failure.

Acknowledgements

We would like to acknowledge Forskningsrådet for grant #331644 (NCS2030) for their support.

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Deferring flood damage in coastal lowlands: assessing surface uplift by geo-engineered CO2sequestration with easy-to-use land-uplift model

Ruud Weijermars1,2,3,4* highlights how a novel geomechanical model can help to identify suitable CO2-storage capacity in the subsurface of coastal regions by computing what pressure buildup in the reservoir will result in geo-engineered surface uplift that nullifies the adverse effects of relative sea level rise for the region under flood threat.

Abstract

Mitigating flood risk of heavily urbanised coastal regions by geo-engineered surface uplift via CO2-sequestration may help to create commercially viable storage opportunities for greenhouse gases like CO2. Recent projections for increased global flood risk due to sea level rise induced by rising CO2-emissions are briefly reviewed. Next, a practical geo-mechanical model is presented, suitable for quick technical assessments of the key physical parameters that contribute most to achieving a specific surface uplift rate required to outpace the projected relative sea level rise for a certain region at risk. The model allows for probabilistic inputs to (1) capture the uncertainty in the value of key input parameters, and (2) link and rank the sensitivity of the surface uplift, to the individual input parameters (in tornado and spider graphs). Three uplift scenarios are given to demonstrate the feasibility of flood mitigation with CO2-sequestration. Finally, a discussion places the emergence of CO2-injection projects in a historic perspective, and highlights the critical key factors in the future screening of any CO2-injection prospects. These factors include the evaluation of technical challenges, potential risks, stakeholder management, public education and perception management.

Introduction

This study argues that the identification of regions under threat of increased flood risk with suitable CO2-storage capacity in the subsurface could mitigate the risk via geo-engineered surface uplift at appropriate rates. The value of global assets under increased threat of flooding due to sea-level rise was estimated at $3 trillion in 2005 (then corresponding to around 5% of global GDP) and would reach $35 trillion by the 2070s (OECD, 2007). Offsetting the tremendous cost of flood damage to buildings and infrastructure, and the looming loss of entire coastal regions to permanent inundation, may become a key factor for economic sustenance of CO2-sequestration projects. The global framework for classifying and quantifying proved CO2-storage capacity is provided by the CO2 Storage Resources Management System

1 Department of Petroleum Engineering

3 College of Petroleum Engineering and Geosciences

* Corresponding author, E-mail: ruud.weijermars@kfupm.edu.sa

DOI: 10.3997/1365-2397.fb2024033

(SRMS, 2017), which mirrors the now well-established Petroleum Resources Management System (PRMS, 2018). The world’s prospective CO2-storage capacity in subsurface formations can only be speedily matured into proved capacity if we can generate more commercially viable projects by turning technically suitable storage volumes into proved storage reserves that can be monetised with a profitable return on investment.

Geo-engineered solutions are increasingly suggested to help mitigate the adverse impact of man-made changes to the natural environment. Man-made distortions of the equilibrium state of natural processes are omnipresent and increasingly result in unintended and costly side-effects. The devastation can be expressed in terms of habitat destruction, reduction of biodiversity, and wilderness loss, while the anthropogenic emission of carbon dioxide has resulted in global warming and sea level rise. Sea-level rise threatens to have a particularly costly impact on coastal communities around the world, because of the increased risk of episodic flooding and eventual permanent loss to the sea.

CO2-sequestration is increasingly seen as a possible geo-engineered solution to mitigate climate change. The petroleum industry has vast technical experience with CO2-injection programs, which traditionally were economically linked to hydrocarbon extraction projects. However, CO2-sequestration projects not linked to petroleum extraction projects presently require public funding allocation to break the vicious cycle of more greenhouse gases being emitted into the atmosphere resulting in higher sea levels. Exclusively relying on public funding may provide a bottleneck for the rapid upscaling of CO2-sequestration projects. A new approach, first advocated here, is to target coastal regions under threat of increased flood risk with suitable conditions for CO2-sequestration, because these regions provide increased potential for finding financing options via public-private partnerships.

This study first briefly summarises the latest scenarios for global sea-level rise related to melting ice caps consequent to global warming due to increases in anthropogenic CO2-emissions. Next, a geomechanical model considered most suitable for quick

technical screening is outlined, with particular emphasis on a sensitivity analysis of physical parameters controlling the surface uplift rate in a CO2-sequestration project. The model is then applied in a synthetic case study to demonstrate the workings of the probabilistic approach. The discussion places the proposed solution in broader perspective, highlighting key factors that must be considered in prospect screening.

Data guidance

Historic trends of both sea level rise (Figure 1a), and increase of carbon dioxide concentrations in the atmosphere (Figure 1b) are accelerating. Both processes have been attributed to anthropogenic CO2-emission sources (Figure 2). The mechanisms, assumptions and implications behind each of the three graphs merit further explanation.

Sweet et al. (2022) incorporated low-confidence ice-sheet processes and high emission pathways with global warming approaching 5°C by 2100, resulting in model projections of global mean sea level (GMSL) rise exceeding 100 cm, 150 cm, or 200 cm, which corresponds to 50%, 20%, and 10% confidence levels, respectively (Figure 1a). Such rises of the global mean sea level are a direct effect of climate change, leading to thermal expansion of warming ocean waters and adding water mass to the ocean, largely via the melting of ice from glaciers and ice sheets (Sweet et al., 2022). If the melting of the Antarctic Ice Sheet at

Figure 1 (a) Global mean sea level rise scenarios, according to Sweet et al. (2022). Numbers on curves are GMSL rise in metres for the year 2100.

(b) Atmospheric CO2-concentration increases, historic (1900-2015) and forward growth scenarios (2015-2100), according to socio-economic pathways assumed in Cheng et al. (2022). The numbers at the curves are the magnitude of radiative forcing in W m -2

the South Pole accelerates, the GMSL will very likely reach 2 m by the year 2100.

Separately, the various forward curves for greenhouse gas accumulation in Figure 1b were generated using radiative forcing levels varying between 3.4 and 8.5 W m-2 (Cheng et al., 2022), which reflect the possible socio-economic pathways (scenarios) of how we manage our CO2-emissions in the future.

Separately, many coastal delta regions − in addition to GMSL − experience vertical land motion (VLM) such as local subsidence in delta regions due to sediment loading and compaction (Dokka, 2011). Such VLM subsidence will exacerbate the effects of sea level rise, because the relative sea level rise (RSL) will exceed the GMSL according to: RSL=GMSL+|VLM|. For example, the region of New Orleans subsides with VLM rates of -10 mm/y as was inferred from satellite data (Deltares, 2023). This means over the next 50 years, New Orleans may see a further RSL rise of about 1 m, due to the combined effects of VLM and GMSL (using the 50% likelihood curve of Figure 1a). Many coastal regions experience similar accelerated RSL due to the combined impacts of local land subsidence (VML) and GMSL.

Beefing up flood defence systems in coastal regions with high RSL rise rates is very costly. For example, mitigation measures against an RSL of 1 m in the Netherlands was estimated at €30 billion (Kok et al., 2008; Jonkman et al., 2013). The mitigation package included dyke heightening, storm surge barrier adaptation and sand supplication to natural coastal dunes. However, at today’s unit cost, the price would quickly escalate to well over €100 billion, which has led Dutch planners to start thinking of new concepts like floating cities, essentially conceding to non-sustenance of limitlessly strengthening artificial flood defences in the long term. More likely a variety of solutions will be needed to alleviate the effects of RSL, in scenarios mirrored in many coastal regions around the globe.

The actual rate of GMSL rise itself is also subject to uncertainty, as is apparent from the wide range of scenarios (Figure 1a), which reflect the uncertainty in the future accumulation rate of greenhouse gases (Figure 1b). Importantly, the uncertainty is not a modelling limitation, but a consequence of the unknown human behaviour and policies for adopting meaningful measures to curb greenhouse gas emissions. Obviously, the steeper rising GMSL curves of Figure 1a are correlated with the higher increases of atmospheric CO2-concentrations of Figure 1b. The low growth scenarios of Figure 1b are subject to emission curbing policy

Figure 2 Historic growth of annual Mt CO2 emissions split out in sources. Combustion of coal and oil still accounts for 70% of the emission. From https:// sealevel.info/carbon/).

measures being successful. However, CO2-concentrations have already increased from pre-industrial revolution values of 278 ppm, last seen in 1870, to 424 ppm in 2023. Eye-popping and recommended are the animated CO2-curves of NOAA (2022) and the ultra-high resolution animations of modern CO2-plume emission sources for the years 2006 and 2015, respectively, generated by NASA (GSF, 2014) and the CO2 Human Emissions (CHE) Project (Figure 3). These results do not bode well for the future.

The principal cause of the historic atmospheric CO2-concentration increase (Figure 1b) is the steep rise in CO2-emissions of anthropogenic origin since the start of the industrial revolution (Figure 2). This anthropogenic load piggybacks on the natural carbon cycle which emits CO2 into the atmosphere by natural processes (respiration and decay, forest fires and volcanic eruptions). However, the natural emission sources were historically balanced because of absorption of the same amount of CO2 by the Earth’s oceans, land and plants. Clearly, mankind is well-advised trying to curb the unbalanced growth of anthropogenic greenhouse gas emissions, not only because of seasonal rise, but also because of its overall devastation of life on Earth.

Model development

The historic CO2-emission pattern of Figure 2 is directly responsible for the historic increase in atmospheric CO2-concentrations

Figure 3 Screen shot from CO2-plume emission source animation in 2015, the year of the Paris Climate Accord. Screen still is for 20 May 2015, which shows CO2-concentrations beginning to spike in the northern hemisphere; these seasonal spikes shift to the southern hemisphere when summer reaches there in December. From the CHE Project (ECMWF, 2020).

(Figure 1b). Depending on which emission level will develop in the future (Figure 1b), considerable rise in the global mean sea level is expected to occur (Figure 1a). Coastal regions are already becoming more prone to flood risk, which requires costly measures to defer flood damage. Mitigating the flood risk of heavily urbanised regions by geo-engineered surface uplift via projects funded in public–private partnerships may be a cost-effective way to counter the adverse impacts of sea level rise induced by global warming.

To quickly screen technical viability, an easy-to-use land uplift model considering the force balance in fluid withdrawal as well as in CO2-sequestration projects, is presented here. The model was recently developed to history-match the surface-subsidence rates and uplift rates due to pressure changes occurring in hydrocarbon extraction projects. A case study of the Groningen Gas extraction project demonstrated the model’s capacity to accurately match the historic subsidence rates (Weijermars, 2023). In another case study, the model reverted to an uplift model, considering the pressure increases due to CO2-injection in the Snyder Field, Scurry County, West Texas. The results affirmed the observed maximum surface uplift of 10 cm, over a period of four years, above the Kelly-Snyder oil field was due to the enhanced oil recovery with CO2-injection.

The geomechanical model of surface uplift couples the effects of reservoir pressure change and elastic buckling of

Figure 4 Pressure change-buckling model: Faultbound reservoir section with change in reservoir pressure, ΔP, causing instantaneous elastic change in the reservoir thickness, ΔhR , which then induces a vertical stress, ΔσvR , at the base of the overburden of the reservoir. In case such stress is due to reservoir pressure increase, surface uplift occurs by upward buckling of the elastic overburden by a maximum amount of w = Δh o at x =0. When the stress at the base of the overburden decreases due to fluid extraction, surface subsidence occurs (after Weijermars, 2023).

its overburden, while assuming the pressure changes occur in a confined reservoir space with an impermeable overburden (Figure 4). The series of equations are both simple and powerful at the same time. The earlier model of Weijermars (2023) is here modified to include poro-elasticity and presented with emphasis on uplift modelling and uplift-rate quantification; the closed-form solutions make a sensitivity analysis feasible.

The maximum change in vertical strain in the reservoir, , caused by the uplift, , is:

(1)

with initial reservoir thickness hR, and the cause of change in height attributed to the pressure increase of the reservoir with total compressibility CR (made up of pore and fluid compressibility) and considering poro-elasticity, with Biot’s coefficient, a

In the case of reservoir pressure increase, the overburden above the reservoir will buckle upward. The stress change, ΔσvR, induced by the pressure rise in the reservoir will be proportional to the increase of its load-bearing capacity, which is given by a constitutive equation:

(2)

Equation (2) becomes case-specific when one uses the Young’s modulus, ER, and Poisson ratio, R, of the rocks in the particular reservoir space of interest. One may also substitute Equation (1) into Equation (2), and assume temporal changes in the reservoir pressure, :

(3)

Equation (3) is now a time-dependent solution controlled by the temporal changes in the reservoir pressure, . The rise in reservoir pressure during injection will be controlled by the amount of injected CO2 added to the reservoir formation fluid:

(4)

The actual volume change in the reservoir will be affected by the change in CO2-density as it travels via the wellbore to the reservoir, which requires computation of phase behaviour using an equation of state (Goeijenbier, 2023). In the present study, follows an assumed linear path which applies to high permeability finite reservoirs in boundary dominated flow. The principal focus will be on a sensitivity study aimed at finding a pressure build-up path required to achieve the surface uplift that will match or outpace the local rate of relative sea level rise, given the geomechanical properties and dimensions of the injected reservoir.

The full profile of land-uplift w(t) above the injection site across the uplift region of total length, L, can be computed for any location x relative to the highest point of uplift (Figure 4), using a buckling function for an elastic plate:

The maximum uplift occurs at the origin of the coordinate system, (Figure 4):

(6)

with given by Equation (3) and the flexural rigidity, D, of the overburden determined by:

(7)

with a representative Young’s modulus, , and Poisson ratio, , for the overburden strata, with total thickness, A single uplift expression can be obtained by substitution of Equations (3), (6) and (7) into Equation (5):

(8)

(5)

for x=0 we get a concise expression for :

(9)

Evaluation of Equations (8) and (9) for specific cases can be done relatively fast, both deterministic and probabilistic, because of the closed-form solution format. The workflow for history-matching known uplift with given pressure changes in the reservoir by determining the unknown Young’s modulus of the overburden, as was applied in Weijermars (2023), is given in Appendix A.

Sensitivity analysis

Part of the strength of the land-uplift model used here is its simple analytical nature, which allows for quick sensitivity analysis. In this study, a spreadsheet augmented with probability density functions and the Monte-Carlo simulation tool of Palisades@Risk (a plug-in for MS Excel) was used. A range of possible values was selected for all input parameters, which reveal how these affect the resulting surface uplift rate.

A synthetic case is adopted with realistic ranges of input parameters as detailed in Table 1, together with the type of probability distribution function used in the modelling. Because there is no clustering of data in any of the parameters used, a uniform distribution assumption was deemed most appropriate. The pressure range assumed was 3-30 MPa, which corresponds to 25-250 bar or 363-3630 psi, representing technically feasible pressures from a practical operations perspective. The pressure range was initially assumed to be built up over a 10-year injection program with final , and the uplift rate for intermediate times was computed according to:

(10)

The output’s probabilistic sensitivity to the input parameters is visualised in the tornado-graph of Figure 5a, which quickly reveals that (1) the thickness of the overburden, and (2) the horizontal dimension of the reservoir utilised for the sequestration are the prime factors controlling the uplift efficiency. The Young’s moduli of the overburden and reservoir play a lesser role, while variations in the compressibility, Poisson’s ratio and Biot’s coefficient have no discernable impact on the amount of uplift. Separately, the normalised spider-graph of Figure 5b reveals the non-linearity of the impact of variations in the most relevant parameters.

With the knowledge of the sensitivity analysis in hand, it is now feasible to fix the compressibility, Biot’s coefficient and Poisson’s ratios at commonly used representative values for rocks (0.0001 for compressibility, 0.9 for Biot and 0.25 for Poisson) and focus on time series showing how surface uplift rates are affected by the four critical system parameters (i.e., the two Young moduli of the reservoir and overburden, the typical horizontal dimension of the reservoir, and the thickness of overburden), while pressure is an engineering quantity build up by injection volume as required by the system to achieve the uplift nullifying RSL.

Uplift scenarios

The uplift profiles for specific parameter choices were modelled in detail, considering three scenario cases. Table 2 gives the

parameters used in these scenarios. The pressures given are the ones achieved at the end of a decade since the start of injection, and a linear pressure buildup is assumed in each of the three scenarios considered here. The reservoir height is included in Table 2, because the stress due to the pressure induced strain in the reservoir needs to be balanced by the stress on the base of the buckling overburden, which is ensured in the model for each of the three scenarios. The maximum uplift rates for each scenario (Table 2) are steady over the 10-year period and are included in Table 2. The associated maximum stress increase at the base of the overburden builds up linearly as indicated in Figure 6. The progressive uplift of the land surface above the reservoirs for each scenario is portrayed in Figure 7.

Discussion

Traditionally, the injection of CO2 in subsurface formations was linked to petroleum extraction projects, which has given industry the technology solutions. A new approach advocated here is to target for CO2-injection, regions with subsurface storage prospects that will economically benefit by mitigating the risk of flood damage due to sea level rise. Such regions will have more at stake if already developed and hosting cities, rather than being remote and empty lowlands. Mitigating the flood risk of urbanised regions by geo-engineered surface uplift via projects funded in public–private partnerships may be a cost-effective way to counter the adverse impacts of sea level rise induced by global warming.

Such a bold proposition certainly raises questions and concerns, while offering opportunities to be realised and

Table 1 Key parameters used in the sensitivity analysis.

Figure 5 Sensitivity analysis. (a) Tornado graph ranking prime parameters affecting uplift rate. (b) Spider graph showing non-linearity in impact of individual parameters.

challenges to be solved. This brief article can only address a few key aspects, as follows:

Uplift feasibility: The model examples of Figure 7 were deliberately limited to conservative uplift rates of 1-3 cm/y. The most aggressive case (Scenario 3) would result in a 90 cm land surface uplift over 30-year project period. The maximum uplift is at the apex of the bulging overburden. Figure 8 shows that for the 30-year case, the land up to 5.5 km from the centre will still be uplifted at least 45 cm or more over a 2x5.5 km wide region. Assuming the uplift region extends 10 km in orthogonal direction to the cross-sectional view, an area of 27,181 acres will have been created with elevations ranging between 45 and 90 cm. Such uplift would be large and fast enough to outpace both tectonic VLM and climate change-induced changes of the GMSL of most coastal regions.

Seismic hazards: Fluid injection in the subsurface is known to reduce normal stress on natural faults, which may consequently slip and cause earth tremors. Numerous well-known case studies exist (not cited for brevity), but the magnitude of such injection-triggered seismicity is not known to have resulted in any human casualties or building collapses. By far the most tenuous case is the Groningen Gas extraction project (which builds up stresses similar to those occurring in fluid injection cases), which ceased due to societal unrest and concerns about production-related pressure-depletion triggering fault slip (see sources cited in Weijermars, 2023).

However, from a technical viewpoint the seismicity was very minor and public information arguably was rather poorly managed. Due to potential fault-slip, the geo-engineering of surface uplift by CO2-sequestration is not immediately recommended for subsiding regions with known faults, such as is the case, for example, in the greater New Orleans region where numerous growth faults occur in the subsurface (McLindon, 2021). However, with proper monitoring and modern modelling capacity, fault behavior is well understood and can be contained and technically managed, in principle. Generally, the management of public perceptions is commonly ignored initially, and started too late when technical issues arise, resulting in premature failure of potentially viable geo-engineering projects.

Seal integrity: The injection of gas and liquids in the subsurface is not a new technology and is widely used for storage of strategic oil reserves and seasonal storage of natural gas and other fluids (hydrogen etc.). Ensuring seal integrity is a standard element in the geotechnical assessment of such projects.

Technical challenges: While the petroleum industry has vast experience with CO2-injection projects of various magnitudes, there are still technical challenges in certain projects.

Figure 6 Maximum stress buildup, over the first 10 years, at the base of the overburden of the reservoirs used for the CO2-sequestration in each of the three scenarios considered.

Table 2 Key parameters used in the scenario cases; the shaded cells show mutating values.

years of failures and delays, the project is being re-engineered. Meanwhile, the regional government’s monetary fines for the Gorgon’s joint venture partners are escalating, adding pressure to quicken the re-engineering of the previously agreed injection schedule.

Opportunities: This paper is the first to propose geo-engineered surface uplift as a viable means to counter the adverse impacts of sea level rise induced by global warming. Threatened coastal communities may find a possible solution path to mitigate the increased risk of flood damage and avert eventual permanent inundation via CO2-sequestration projects funded in public–private partnerships. Separately, the creation of artificial islands currently done by sand replenishment projects (using suction dredges to scoop up sediment from the shallow seafloor nearby), may be replaced by raising the land instead by CO2-subsurface storage in a cost-effective way.

Disclaimer: The land-uplift models presented here were generated with fast, analytical solution methods based on sound geomechanical principles, while stripping down the problem solution to the minimum required using essential physics. This approach enables the rapid sensitivity analysis presented in this study. More advanced modelling tools exist (see citations in Weijermars, 2023, and Jun et al., 2023), but these have other limitations, such as complexity of use and excessive computing time, making such models too expensive for initial project screening. Of course, when the initial assessment of an actual project option gains traction and appears promising, the entire suite of advanced modelling tools shall be used to bring such projects to maturation.

Acknowledgements

For example, the world’s largest CO2-sequestration project hitherto is tied to a natural gas production project in the Gorgon Field (offshore Australia). The extracted natural gas is extremely sour (with 30% CO2) due to which the injection of extraordinary large volumes of CO2 below Barrow Island was mandated by the North Western Australian government and conditional for Gorgon’s natural gas extraction approval. But the CO2-storage program has been marred by a range of technical setbacks (Trupp et al., 2021), leading to a 10-fold escalation of the original budget from $300 million to $3 billion. After 10

The author acknowledges the generous support provided by the College of Petroleum Engineering & Geosciences (CPG) at King Fahd University of Petroleum & Minerals (KFUPM).

Appendix A - Modelling workflow

The stress at the base of the overburden in the model of Figure 4 needs to be balanced, and is computed separately for the uplift due to elastic buckling and the uplift due to the pressure change in the storage reservoir. Several workflows are possible. For example, in Weijermars (2023) the focus was on history matching

Figure 7 Progressive uplift of the land surface above the reservoirs for each scenario over a 10-year period since the start of the CO2-injection program. Numbers on curves indicate the years required to reach a given elevation profile.

Figure 8 Progressive uplift of the land surface above the reservoir for Scenario 3 over a 30-year period since the start of the CO2-sequestration program. Uplift curves are spaced for 1-year interval since onset of the CO2-injection.

using known subsidence/uplifts and known pressure changes. Then the recommended workflow steps are as follows:

A) Reservoir dynamics

1. Use compressibility, , and a given time series of the change in reservoir pressure,

2. Compute the strain changes in the reservoir layer from and

3. Compute the stress from the strain, using constitutive scalars and

4. Uplift/subsidence VLM in the reservoir layer given by the product of strain, , and the initial reservoir thickness, hR

B) Overburden dynamics:

1. Input elastic properties and thickness of the overburden to compute the flexural rigidity, D

2. Match the obtained in Step A4.

3. The strain induced in the reservoir can be computed from VLM/ hR

4. Stress is computed from the strain of Step B3, using the elastic moduli, of which the overburden’s Young’s modulus was adjusted if needed to ensure stress balance.

5. For a given reservoir with horizontal dimension, L, the follows, and should be equal to the VLM of Step A4.

6. Next, the VLM profiles at different times since the start of the pressure increases in the reservoir can be fully captured with Equation (8).

For workflow in the present paper, the starting point was not the history matching of known uplift. Instead, various pressure buildup scenarios were assumed to explore what would be the consequent uplift. Three arbitrary scenarios were modelled varying the shaded parameters in Table 2, with the coupled model constraint that the stresses at the base of the overburden must be balanced.

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Unveiling the depths by deploying Low-Frequency Seismic (LFS) in the Paradise Field area, Australia, to assess the hydrocarbon potential

Roy P Bitrus1*, Vasilii Ryzhov1, Adel Milin, Dmitrii Ryzhov1, Ilshat Sharapov1, Sergey Feofilov1, Evgeny Smirnov1, Ivan Starostin1, Marion Croft2, Frank Glass2, Helen Debenham2 and Simon Molyneux3 present a survey that has mapped the hydrocarbon presence probability to identify and derisk the presence of hydrocarbons in the survey area.

Executive summary

Low-frequency Seismic technology (LFS) survey was conducted in the area of the Paradise Field in the Canning Basin of Western Australia. The purpose of the project was to assess the hydrocarbons potential of the Winifred Shale Grant Fm sediments. The project was carried out in the following stages: field data acquisition, analysis and evaluation of the quality of the acquired field data and data processing and interpretation.

The project was supported by Buru Energy Ltd (Buru) as operator of the EP 428 petroleum exploration permit and by partners Origin Energy West Pty Ltd (Origin) and was co-funded under the Energy Analysis Program of the Exploration Incentive Scheme (EIS) administered by the Western Australia Government’s Department of Mines, Industry Regulation and Safety (DMIRS) to improve the understanding of petroleum systems in Western Australia.

The deliverable from the survey was a map of hydrocarbon presence probability to identify and derisk the presence of hydrocarbons in the survey area. The result correlated well with the interpretation of the 2D reflection seismic survey over the Paradise area.

Introduction

Passive Low Frequency Seismic (LFS) exploration aims to characterise the geological attributes of the earth’s interior, particularly targeting formations with anomalous absorption and reduced velocities, typical of hydrocarbon deposits. By detecting abnormal absorption resulting from hydrocarbon friction during wave passage, LFS enables the identification of potential reservoirs through additional reflections and resonance phenomena (Quintal et al., 2009, Brillinger, 2000). This method, applied in various geological engineering and seismology contexts, has gained traction in the oil and gas industry for exploration, production, and enhanced oil recovery (EOR/IOR) projects, offering a means to reduce drilling risks and locate hydrocarbon accumulations accurately (Al Jadani, 2015, Arutyunov and Kuznetsov, 1993, Birialtsev et al., 2009). LFS technology

1 TenzorGEO Ltd | 2 Buru Energy | 3 Molyneux Advisors

* Corresponding author, E-mail: roy.bitrus@tenzorgeo.co.uk

DOI: 10.3997/1365-2397.fb2024034

analyses the spectral response of natural Low-Frequency Seismic background (Rapoport et al., 2004), effectively forecasting oil and gas prospects (Sharapov et al., 2016), delineating reservoirs, detecting hydrocarbon accumulation in non-structural traps, identifying bypassed oil, and pinpointing drilling sweet spots with a success rate of 85% based on extensive field applications since 2005.

This article presents findings from a Low-Frequency Seismic (LFS) survey conducted in the Paradise field area of the Canning Basin, Western Australia, approximately 120 km southeast of Derby, aimed at assessing the hydrocarbon potential of the Winifred Shale Grant Formation sediments. Despite only one well, Paradise-1, on-site, Downhole Sampling Tool (DST) results indicated the presence of water with traces of oil in the Winifred Shale Grant Formation.

The LFS method’s workflow encompassed field data acquisition, analysis of data quality, and subsequent processing and interpretation. Data acquisition was conducted by Buru Energy staff and interpretation performed on an active seismic survey undertaken by Terrex at the same time with final processing and interpretation of passive seismic data completed by TenzorGEO between February and August 2022.

The Paradise Field

The survey site is situated in the northern region of Western Australia, approximately 120 km northwest of Derby and 15 km north of the Great Northern Highway, which connects Perth with the port of Wyndham. LFS observation points were established along existing pastoral dirt tracks and unsealed roads in the area.

The lithology and stratigraphy of the area reveal a complex geological history, with sedimentary deposits ranging from Ordovician clastic and carbonate units to Mesozoic and Recent alluvium. Notable formations include the Winifred Shale Grant Fm and the Anderson Formation, which contain potential source rock facies and sandstone reservoirs (Buru Energy, 2014, 2016).

The Paradise-1 well penetrated various formations, including sandstones, claystones, and limestones, providing insight into the

geological composition of the region. The stratigraphic sequence highlights depositional environments ranging from deepwater marine to fluvio-deltaic, with distinct lithological characteristics observed throughout the Permian to Carboniferous periods.

Additionally, the presence of sandstones, shales, and dolomites suggests a diverse depositional history influenced by rift-infilling and transgressive-regressive cycles.

In the Paradise field of the Canning Basin, seismic exploration, initially conducted by WAPET in the late 1950s and 1960s focused on the Lennard shelf and adjacent areas primarily through surface mapping and a limited number of exploration wells, with seismic techniques gaining prominence only in the 1980s (Buru Energy, 2014, 2016).

The Paradise structure in the Canning Basin was initially identified based on reconnaissance seismic lines acquired in the early 1980s, with subsequent seismic surveys revealing fairto-good data quality but showing variations in parameters and vintage years.

Drilling activities in the region, spanning from shallow wells drilled in the early 20th century to more recent efforts targeting diverse hydrocarbon systems, have provided valuable insights, including oil and gas shows in various formations such as the Grant and Laurel Formations.

Recent drilling endeavours, such as the Valhalla and Paradise wells, have encountered significant oil and gas shows, indicating the presence of basin-centered hydrocarbon systems in the area, particularly within the Laurel Formation.

Rheology of hydrocarbon-saturated reservoirs

When employing LFS technology, it is crucial to comprehend that the rheology of hydrocarbon-saturated reservoirs displays abnormal reflection of low-frequency waves due to multiple factors:

• Acoustic Impedance: Hydrocarbon-saturated reservoirs demonstrate lower acoustic impedance compared to water due to oil’s higher compressibility under reservoir conditions, leading to enhanced contrast (Tetelmin, 2009).

• Viscosity: Oil’s viscosity, significantly higher than that of water and surrounding rocks, contributes to increased absorption in the medium, augmenting the reflection coefficient modulus (Gibson, 2008).

• Fluid Displacement Mechanisms: Fluid displacement within saturated or fractured areas, such as gas-and-fluid mixtures inside the formation structure, leads to energy dissipation and enhanced absorption (Quintal et. al., 2009, Cole and Cole, 1941 , Goloshubin et al., 2006). This results in velocity dispersion and increased reflection coefficients.

• Experimental Evidence: Theoretical research indicates that a thin layer with attenuation due to gas-and-fluid displacement within the formation structure exhibits a notable increase in reflection coefficient (Figure 1), approximately 10%, around a frequency of 6.5 Hz (Brillinger, 2000). This phenomenon applies to various combinations of water/oil, oil/gas, and water/gas. The frequency dependence of P-wave velocity (Vp) and Q-factor (Q) in thin layer models confirms enhanced absorption of elastic energy and a drop in compressional wave velocity in the frequency range of 0.5 to 10 Hz, resulting in a significant rise in the reflection coefficient modulus.

• Impulse Response: The impulse response describes the complex nature of seismic wave propagation in a real geo-medium, involving various types of waves and their transformations. Unlike standing waves, traveling waves carry energy and can propagate freely. Standing waves, on the other hand, do not carry energy but facilitate spatial energy transfer. The frequency content of vertical P-waves is influenced by the geo-medium’s bedding structure, acting as a filter. A hydrocarbon-saturated

Figure 1 The shape of a compressional wave reflected from a thin layer with lower wave impedance without absorption (top) and with absorption (bottom).

Figure 2 Results of the laboratory seismic reflection experiment using ultrasonic frequencies (where 1k Hz = 1 Hz) (courtesy of Goloshubin et al., 2006).

reservoir, being a significant heterogeneity, alters the amplitude-frequency response of the geological medium, especially in the low-frequency range due to higher wave reflection coefficients. The impulse responseparameter h (t),

characterises the amplitude-frequency response of the geo-medium, which can be calculated through numerical simulations of wave propagation processes.

• Numerical Simulations: Numerical simulations demonstrate that absorption within the layer alters the reflected wave’s shape due to the presence of the reflection coefficient’s imaginary part, while increasing the amplitude of the reflected wave. Consequently, hydrocarbon-saturated reservoirs exhibit significant reflection due to the absorption of low-frequency compressional waves.

• Resolution: The resolution of LFS technology is determined by the spectral characteristics of impulse responses in homogeneous media with thin layers of lower impedance, which exhibit a modal spectrum structure. Depth resolution (dy) in LFS interpretation depends on the modes (n) in the spectrum, typically ranging from 1 to 4 due to industrial noise interference. Vertical resolution is estimated based on the condition that differentiates between spectral peak positions and must exceed a certain threshold (∆f/4), where ∆f is a frequency difference between two adjacent modes. Performing simple calculations results in an analytical dependence. Analytically, vertical resolution is expressed as dy/depth=1/4n. Horizontal resolution (dx) is determined by the depth of heterogeneity and mode number (n), accounting for lateral diffusion of wave amplitude. This relationship is given by dx/depth=1/√2πn.

In summary, the technical description elucidates the underlying mechanisms contributing to the anomalous reflection of low-fre-

quency waves in hydrocarbon-saturated reservoirs, highlighting their significance in seismic analysis and exploration efforts.

Data acquisition

The survey site, situated in northern Western Australia, is characterised by flat terrain with absolute relief ranging from +60m to +75m. The area experiences a hot and dry climate, with average temperatures around 30°C, peaking in October and dropping to 24°C in June. January sees the most rainfall, while August is the driest month, with an average annual rainfall of 732 mm. The landscape is dominated by spinifex grasslands, low-level shrubs, and occasional Boab trees, with observation points for Low Frequency Seismic (LFS) scattered along existing pastoral dirt tracks and unsealed roads. Passive seismic recordings were conducted at the Paradise structure site using the LFS method along five profiles, although the original plan for 100 observation points was adjusted due to installation constraints at 13 specific locations (Figure 3). Fieldwork, managed by Buru Energy staff, was carried out in 22 days with observation points spaced at 300 m intervals along each profile. Topography and geodesy procedures followed surveying guidelines, involving tasks such as positioning planned observation points and establishing areal and elevation references using GPS navigation sensors. Coordinates collected in the field were transferred to a computer for processing and interpretation, ensuring accurate spatial data for the survey area. Sensor Acquisition Equipment: The field data acquisition employed seismic sensors from SmartSolo (Figure 3), featuring IGU-16HR 3C recorders and DT-HP305V/305H geophones, designed to capture vertical and horizontal seismic vibrations digitally and accurately. With specifications suitable for high-resolution seismic monitoring, the equipment facilitates studying variations in seismic background intensity and spectral composition. Operating in challenging field conditions, the sensors record microseismic signals on three components at a sampling frequency of 500 Hz, synchronised precisely via GPS for accurate

Figure 3 Layout of the planned and actual observation points. Insert: Nodal seismic data acquisition system ‘SmartSolo’.

time reference. Provided free of charge by ANSIR through a joint usage application by Buru Energy and ANU, Buru Energy covered shipping costs and insurance during usage and transit. The quality assessment of field data records involved five stages:

1. File Conversion: Data files were converted from SEGD format to 00 format with a sampling frequency of 50 Hz to prepare for further analysis using LFS technology, with frequencies above 25 Hz excluded.

2. Reverse Filtering: Reverse filters were applied to the 00 format files to flatten the amplitude-frequency characteristic, particularly for analysis in the low-frequency range of 0.55 Hz, enhancing the spectrum shape.

3. Average spectrum level calculation: The average spectrum level for each 6-hour record was calculated by slicing the record into frames, constructing Fourier amplitude spectra, and averaging the amplitudes in the frequency range of

1-6 Hz. The quietest areas were identified to estimate the average amplitude level.

4. Histogram construction: A histogram of the average levels of spectrum amplitudes from all records was constructed to identify the noisiest (high level) and defective (low level) records, with values below 10 indicating potential issues, such as failure of the Z component.

The criterion for assessing the quality of field data include absence of noises and the duration of the background recording. This rigorous assessment process ensures the reliability and accuracy of the field data records, crucial for subsequent analysis and interpretation.

5. Harnessing Machine Learning for Automatic Noise Analysis and Quiet Interval Detection in All Records: Field record quality was evaluated using machine learning models trained beforehand. These models analyse spectrogram structures to determine probabilities of various noise types. A lack of noise signifies a superior background record. The analysis revealed intervals with wind and industrial noise, missing components in the record, and signal value surpassing permissible limits. A minimum of 2 hours of noise-free background recording is necessary for processing and interpretation using LFS technology in the surveyed area. Given a profile-based survey, the duration of noise-free background recording should ideally be at least 8 hours to gather adequate statistics. The range of noise-free background recording varied from 3.33 to 106 hours, with an average of 45 hours.

Data processing and interpretation

The processing and interpretation of LFS data involves stages such as velocity model preparation, numerical simulation, noise

Figure 4 Impulse and frequency characteristics of the reverse filter.

Figure 5 The histogram of the average levels of spectrum amplitudes of the Z component for all records of the survey area.

Figure 6 Comparison of Spectrogram from observations points.

filtering, well data analysis, spectra features recognition, sensitivity analysis to velocity model accuracy, and assessment of oil presence probability at Winifred Shale Grant Fm deposits.

1. Velocity Model Preparation: The velocity model preparation involves utilising VSP and conventional seismic results to construct a model necessary for numerical simulation. This simulation aims to generate spectra of responses with and without a hydrocarbon-saturated reservoir to detect interpretable signs within the survey area’s spectra. Buru Energy provided TWT and Depth maps for main reflecting horizons based on BP21 seismic survey interpretation and vintage data, facilitating the calculation of interval longitudinal velocities for each LFS observation point. For Paradise 1 VSP data lacking longitudinal velocity Vp for the upper section, seismic data was used for model construction. The basement depth in the work area was set at approximately 12 km based on regional geophysical data, with a corresponding velocity of 6500 m/s in the crystalline basement.

2. Numerical simulation: The 1D numerical simulation of the vertical component of media responses involved constructing a velocity model for each observation point, simulating two scenarios (with and without a hydrocarbon layer), and analysing model spectra for interpretation. A source shot-point generated short-time pulses, recording vertical displacement velocity at the model’s top. Model spectra indicated distinct peaks in the presence of hydrocarbons, varying in position due to depth changes. Transitioning to a mode scale allowed for uniform spectral analysis, aiding in focusing on the target horizon and calculating double travel time and distance between resonance maxima. Focusing procedures enhanced clarity between ‘empty’ and ‘oil’ models, and analytical calculations determined the horizontal resolution map for the target horizon.

3. Noise Filtering:

a. Filtering of strong surface wave noise from non-moving surface sources: Surface wave noise originating from non-moving surface sources is effectively filtered using the linear prediction algorithm, which considers the correlation

between vertical and horizontal components of the microseismic record. This algorithm removes the correlated portion of surface noise from the vertical component of the record. Examples of spectrograms and accumulated spectra for observation point 12810, along with results of filtering using the linear prediction algorithm, are illustrated in Figures 8a and 8c respectively, with an additional example of the inverse filter for observation point 12810 depicted in Figure 8b.

b. Filtering of quasi-harmonic noise: Filtering of quasi-harmonic noise is performed to exclude narrowband components caused by monochromatic vibrations of close surface technogenic sources from the recorded signal.

c. Filtering of an ambient background surface noise (omnidirectional surface waves): The filtering process for ambient background omnidirectional surface noise involves several steps. Initially, cross-correlation functions between vertical and radial components of simultaneous observation records are calculated. These functions are then transformed into radial and transversal components, with transversal components not utilised further. Cross-correlations are combined into virtual shot gathers (VSG) for radial components, and pairs of sensors meeting specific criteria are included in the VSG. The ZR and RZ gathers are averaged to suppress Rayleigh waves, followed by antisymmetrisation to enhance P-waves’ visibility. Hilbert transform and phase correction are applied for visualisation, and noisy cross-correlation functions are removed based on RMS comparison. After rejection by RMS, moving average filtering is applied, followed by FK filtering to remove slopes and smooth the virtual shot gather. Finally, cross-correlation functions are averaged across different VSGs corresponding to the same pair of sensors.

4. Well data analysis: The analysis of well data, specifically oil depths and oil-filled thickness (net pay), focuses on the Paradise 1 well within the survey area. After removing surface wave noise, the real spectrum from the well exhibits a prominent peak at low frequencies due to the nature of

Figure 7 Comparison of velocity characteristics in the area of the Paradise 1 well (from 1 observation point 81013).

natural longitudinal vertically directed waves. Standardising the spectrum involves aligning the envelope of the real spectrum with that of the model spectra, revealing similarities and differences in shape. Focused spectra show good distinction between model ‘oil’ and ‘empty’ spectra, with the actual spectrum closely resembling the ‘empty’ model spectrum in the 0-2 modes range. However, due to detecting only water with traces of oil during DST work, the Paradise 1 well cannot serve as a reference for constructing correlation maps, as it cannot be definitively categorised as oil-bearing or empty.

5. Spectra features recognition: The process involves comparing model spectra with the spectral characteristics of wells with known hydrocarbon saturation, assessing morphological similarity, and constructing correlation maps. Pearson’s linear correlation coefficient is calculated to evaluate similarity, with maps indicating zones of high and low similarity. Adjusting actual spectra to model envelopes allows for accurate comparison. The range of modes is refined based on objective function maximisation, with maps revealing variations in similarity coefficients across profiles. Morphological similarity maps for both oil and absence of oil cases are generated, with normalised coefficients aiding in unequivocal spectrum assignment.

These maps highlight areas with high correlation to model spectra, aiding in geological interpretation.

6. Sensitivity analysis of the LFS interpretation results in comparison to the Velocity Model: The analysis evaluates the sensitivity of results from Low-Frequency Seismic (LFS) interpretation to variations in the velocity model. Two experiments were conducted: adding a second oil layer to the model and altering velocity characteristics. When adding a second oil layer, the model spectra showed changes, particularly in the presence of additional spectral peaks. Focusing the spectra minimised these changes, maintaining the overall similarity between models with one and two oil layers. Altering velocity characteristics affected the entire spectrum, causing changes in both ‘empty’ and ‘oil’ spectra. However, focusing preserved the shape of the spectra, maintaining the overall forecast for the survey site. The experiments revealed minimal deviations in similarity coefficients, with some slight variations observed in certain observation points. Overall, changes in velocity characteristics had a more significant impact on results compared to adding a second oil layer.

7. Assessment of the probability of oil at the Winifred Shale Grant Fm deposits: The assessment of oil presence probability at Winifred Shale Grant Formation deposits

Figure 8 a. An example of raw data, observation point 12810, b, An example of filtering using inverse filter, observation point 12810. c, An example of filtering using the linear prediction algorithm, observation point 12810.

involves constructing a final map based on normalised similarity coefficients, well data analysis, and real spectra. Due to the absence of wells with clearly identified hydrocarbon content at the Paradise field, the analysis relied solely on model spectra. Considering the historic success rate of LFS technology, probability levels were set based on normalised correlation coefficients: 85% for maximum

probability, 50% for mid-level, and 0% for minimum. Areas with probability values below 50% are deemed unpromising. The resulting probability map mirrors the pattern of normalised similarity coefficients, indicating higher probabilities on the dome and its eastern slope. Recommendations include conducting areal LFS surveys in areas with increased probability values, particularly on the

Figure 9 a, Similarity map of focused spectra for the case of absence of oil content in the section. b, Similarity map of focused spectra for the case of presence of oil content in the Sakmarian Winifred Member of the Grant Formation. c, Map of normalised similarity coefficients of focused spectra.

Figure 10 Hydrocarbon presence probability map at Winifred Shale Grant Fm.

crest of the Paradise structure, with suggested observation network spacing and the importance of obtaining spectra from wells for enhanced reliability.

Conclusion

This article summarises the findings and methodology of LFS (Low-Frequency Seismic) works conducted at the Paradise structure survey site. Despite encountering challenges such as missing observation points and the need for data filtering, analysis proceeded with accepted recordings from 85 observation points. Model spectra were created to analyse oil presence, focusing on the 0-2 modes range for consistency. However, actual well data indicated only water with traces of oil, necessitating reliance on model spectra for further analysis. The stability of LFS forecasts was demonstrated through experiments involving changes in the velocity model. A hydrocarbon presence probability map for Winifred Shale Grant Formation deposits was constructed based on normalised similarity coefficients, showing higher probabilities in specific areas of the Paradise structure. Recommendations include conducting further surveys in high probability areas, accompanied by obtaining well spectra for enhanced reliability.

References

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Comprehensive measurement, monitoring, verification planning enables safe CO2 storage, risk reduction, and operating cost optimisation

Valeria Di Filippo1*, Colleen Barton1 and Pramit Basu1 demonstrate proper planning facilitates for safe, durable injection

of CO2 in a nearshore depleted reservoir.

Abstract

A Measurement, Monitoring and Verification (MMV) plan is a requirement for subsurface CO2 injection and storage, and developing an appropriate plan requires holistic assessment. A complete MMV plan must take into account the features of the structure, including geology and mineralogy. It must consider how the CO2 will be introduced to the storage space, the potential for plume movement within the containment area, and a well-defined approach to monitoring over time. The plan also must address risk management, including the potential impact if containment is compromised, how it will be controlled, and the extent to which control measures will be effective.

This study explains how experts developed an MMV plan to manage CO2 produced as associated gas from hydrocarbon production. The project design includes a plan for transporting CO2 in dense phase from an onshore facility to offshore platforms for injection into depleted reservoirs. The study details the development of a site-specific MMV plan that considers geological features, identifies operational challenges, and anticipates conditions that could develop over 15 years of CO2 injection. Identified site specific risks are directly tied to the selection of suitable monitoring technologies.

Introduction

Developing an MMV plan is a complex process that requires input from many stakeholders, including the Carbon Capture and Storage (CCS) site operator, partners, agencies, and a broad representation of project managers, domain analysts, and subject matter experts. The MMV plan considers the reservoir location, depth, type, target disposal volume, and time requirement in addition to site characteristics, the integrity of the storage complex, wells, and specific geologic features. The plan also must conform to governing compliance regulations, guidelines, and mandates.

There are multiple monitoring targets for site-specific variables at each phase of the project — pre-injection, injection, and site closure. Each monitoring technology in turn has a corresponding performance target and characteristic trigger event, control response option, and contingency plan.

The operational monitoring component of the MMV plan includes technical verification to determine within acceptable uncertainty that the pressures and volumes inside the storage site are consistent with forecasts. Baseline and early monitoring are critical because they enable trigger elements that could lead to severe containment failure to be identified so timely, preventive, corrective action can be taken.

The MMV plan development process presented here was created for an operator conforming to a ‘no emissions’ policy. The project encompassed moving excess CO2 to an onshore facility for treatment and then to a depleted nearshore oil and gas reservoir for storage. Aquifer zones in the proposed reservoir and additional potential candidate fields were considered for use as secondary CO2 storage sites when the depleted zones in the primary reservoir are fully utilised.

Methodology

A comprehensive, risk-based MMV plan anticipates unwanted CO2 migration and is designed to accommodate monitoring changes or expansion as the CO2 storage process gets underway. The plan must demonstrate that objectives have been achieved, support strategic planning and field development, and help decision-makers distinguish among alternative courses of action, a effect informed choices, and prioritise activities. Finally, the plan accounts for uncertainty, the nature of the uncertainty, and how the uncertainty can be addressed.

Design principles governing development ensure the MMV plan is (after Dean and Tucker, 2017):

• Risk based: The MMV plan is founded on a thorough subsurface risk assessment that considers an array of conditions that could affect containment and conformance if not properly mitigated.

• Site specific: Monitoring technology selection allows for containment verification based on the outcome of site-specific feasibility assessments.

• Adaptive: Site-specific plan designs have the flexibility to adapt as new information emerges about the performance of the storage complex and selected monitoring technologies.

1 Baker Hughes

* Corresponding author, E-mail: Valeria.DiFilippo@bakerhughes.com

DOI: 10.3997/1365-2397.fb2024035

• Performance-based: Well-defined key performance indicators (KPIs) are provided in sufficient detail to allow the MMV plan to be used as a working guide for operations.

• Compliant with governing regulations: The MMV plan is designed to current regulatory requirements with the capacity to adapt as regulations evolve.

The MMV Plan operates within an Area of Review (AoR) — the area of influence where there is potential for impacts from CO2 storage — which encompasses four environmental domains:

• Geosphere: Below underground sources of drinking water.

• Hydrosphere: The interconnected system of water bodies on Earth, encompassing oceans, rivers, lakes, groundwater, and atmospheric water vapour, that form a crucial component for supporting life and various geological processes.

• Biosphere: The domain containing ecosystems where living organisms exist.

• Atmosphere: The domain composed of a layer of gases surrounding the Earth which plays a crucial role in sustaining life by providing oxygen, regulating temperature, and protecting against harmful radiation.

The initial AoR, derived from preliminary reservoir dynamic modelling prior to injection, is updated periodically based on observed storage performance during and after injection operations. MMV activities are adapted over time as the project progresses from the pre-injection phase, to injection, to post-injection, and finally, to site closure.

Regulatory compliance

Every stage of MMV plan development must conform to regulatory requirements for CO2 injection and storage. These regulations have evolved over the past decade as have the monitoring technologies that ensure CO2 containment and regulatory compliance.

The US Environmental Protection Agency (EPA) Class VI Rule, finalised in 2010, sets the federal minimum technical requirements for Class VI injection wells (approved for CO2 injection for the purposes of geological storage) with the

objective of protecting underground sources of drinking water (USDWs), as provided in the US Code of Federal Regulations (CFR) [40 CFR 146.81 et seq.]. In addition, the EPA Greenhouse Gas Reporting Program (GHGRP) requires facilities that conduct geological storage of CO2 to submit a monitoring, reporting, and verification (MRV) plan as provided in 40 CFR 98.440 et seq

The more recent 2017 publication of the British Standards institution Carbon Dioxide Capture, Transportation and Geological Storage — Geological storage Section 6 Risk management (BS ISO 27914:2017), provides recommendations for safe and effective CO2 storage in subsurface geologic formations through all phases of a storage project. BSI ISO regulations are incorporated into and augmented by the California Air Resources Board – Carbon Capture and Sequestration Protocol under the Low Carbon Fuel Standard (CA LCFS 2018) by including spatial and temporal boundaries of a CO2 storage operation. Each of these standards defines regulations for:

• Environmental protection

• Leak detection

• Baseline measurements

• Corrective action

• Environmental impact.

The BSI ISO, EPA GHGRP and CA LCFS standards further define standards for:

• Storage performance

• Leak attribution

• Quantifying CO2

• Management systems.

These are internationally referenced standards that have become the blueprint for CO2 geological storage regulation development around the world.

MMV plan stages

The MMV plan is developed throughout the site characterisation work, with the first risk assessment carried out and initial safeguards identified through site selection, site appraisal, and engineering concept selections.

Figure 1 MMV plan process flow.

The plan consists of three main stages (Figure 1): baseline, injection, and post injection.

The Baseline plan development stage establishes site-specific, risk-based monitoring targets, delineates associated monitoring tasks, and defines site-specific geologic (e.g. passive) safeguards. It also sets out the engineered (e.g. active) safeguards for assuring the expected storage performance and if necessary, triggering appropriate control measures.

The baseline MMV plan can be broken down into three substages: the concept stage, the feasibility stage, and the define stage.

The purpose of each substage is to build the foundation for the next. The activities for each can be summarised as follows:

Concept stage

• Identify site-specific storage risks and potentially endangered area

• Identify geologic (e.g. passive) and engineering (e.g. active) safeguards to storage risks

• Rank identified storage risks

• Perform qualitative and quantitative risk analysis of identified storage risks

• Determine monitoring requirements and targets

• Match and rank monitoring technologies to risk scenarios

• Carry out cost-benefit analysis of monitoring technologies

• Produce conceptual monitoring plan deployment timeline for the storage site life cycle.

Feasibility stage

• Determine performance metrics for each selected monitoring technology

• Delineate control response options for each selected monitoring technology.

Define stage

• Establish contingency monitoring plans

• Develop operating procedures in response to monitoring trigger events

• Identify remediation strategies, including reassessment of risk scenarios, monitoring programs, and operations

• Produce full MMV baseline procedures for pre-injection, injection, and closure.

During the injection operations stage, the baseline plan is closely monitored to ensure performance criteria are met. Periodic performance reviews during injection provide a continuation of the risk management process to support plan revisions, if needed, as new data are acquired.

The post-injection MMV plan constitutes the final part of the plan and supports long-term stewardship of the storage site. This stage includes periodic revisions and data acquisition as the plume reaches equilibrium after injection activities have ceased.

Technology selection

Monitoring tasks are determined based on the site characterisation and local regulatory requirements. Monitoring technologies are screened and evaluated for effectiveness for individual tasks based on systematic evidence-based analysis (Dean and Tucker,

2017). The performance metrics for each technology must be assessed against pre-defined operational metrics to determine the degree to which the technology can reduce the specific risks associated with each monitoring task.

The next step is to perform a cost-benefit analysis, where the total cost estimates for each technology are measured against the lifecycle benefits that the technology will deliver in terms of risk reduction. This allows the technologies to be ranked for effectiveness for the specific site.

Risk assessment and the Probability Model

Qualitative and quantitative risk analysis are integral to the MMV plan. The Bowtie Method approach used by Shell Global Solutions for the Peterhead Goldeneye CCS project (Dean and Tucker, 2017 and Shell Canada Energy for the Quest CCS Project [2011]) is the framework for a systematic, qualitative risk assessment of events with the potential to affect storage performance. The bowtie shows the relationship among key elements, how a risk might arise, and how safeguards can be used to provide effective protection against the risk. Preventive safeguards decrease the likelihood of a threat leading to the top event, while corrective safeguards decrease the likelihood of significant consequences if a top event should occur.

The qualitative risk analysis presented as a bowtie plot (Figure 2) provides a summary of the overall risk mitigation plan that helps to effectively communicate site-specific risks and their consequences among the stakeholders. Illustrating preventive and mitigation controls against respective causes and consequences demonstrates that the risks are well understood and are being controlled.

Furthermore, a probability model is implemented to characterise risk assessment based on site-specific risks following an approach used in Bourne, 2011. This approach depends on expert judgment to assess the relative risks and quantitative methods based on historical data about the previous performance of comparable systems.

The relationship among threats, safeguards, and consequences is considered as a probability network, where each threat initiates at a given rate, each safeguard fails at a given rate, and each consequence has a given significance weighting. Using this information, Probability Theory can be applied to determine the probability of a significant consequence occurring despite the safeguards in place.

Application

An MMV plan was developed for a CCS project that required transporting CO2 from an onshore treatment facility to a depleted nearshore reservoir, where it would be sequestered over 15 years. The field is a faulted anticline structure deposited mainly of coastal plain sediments, compartmentalised by north-south normal faults. The intermediate and deeper interval of the field comprise the primary injection intervals.

Extensive subsurface characterisation studies were performed to understand the petrophysics and physical properties of the reservoir prior to depletion, revealing that the caprock was made up of thick shale sequences and indicating that the deeper reservoirs consisted of sandstones interlayered with clays. Meanwhile, reservoir simulation and geomechanical modelling allowed

identification of CO2 storage injection targets, and subsurface geochemical studies enabled prediction of potential interactions between CO2 and mineralogy.

Storage potential was estimated using mass balance and production history for the depleted gas candidate zones. A fault reactivation analysis performed via geomechanical modelling determined that the potential for fault slip through the planned CO2 injection phase was negligible. Based on the latest reservoir dynamic simulation results, the injection strategy assumes with reservoir pressures restored to 95% initial virgin conditions, with sufficient capacity to support the project requirement.

Site assessment identified ideal injection intervals, but a complete MMV plan must also consider potential threats that could cause a loss of conformance, including situations in which:

• The original models are inaccurate due to unexpected geological heterogeneities; incorrect representation of the physical, chemical, or geomechanical processes governing fluid transport, or mechanical rock properties; or insufficient analysis of uncertainties within the models.

• The monitoring strategy is unsuitable due to an unrecognised bias in data acquisition, processing, or interpretation.

Project risk assessment was conducted after site selection, site characterisation, and delineation of the AoR to identify site-specific conformance and containment risks, encompassing well integrity, fluid reactions, injectivity, subsurface characterisation, plume migration, caprock integrity, fracture and fault integrity, and reservoir subsidence.

Safeguards and barriers for mitigating the identified risks were specified during this process. These include geologic safeguards such as specific caprock seals, fault seals, geochemistry, mineralogy, and potential fluid and mineralogical reactions. Each planned injection level has a caprock seal sequence consisting

of an efficient primary geological seal supplemented by a cumulative stack of overlying low net to gross strata. The pressure competence of each composite reservoir seal system has been demonstrated via its ability to withhold production induced differential pressures at reservoir depth providing a high confidence top seal system at each injection interval.

Engineered barriers (aka active safeguards) include installing plugs resistant to CO2 in wells that will be plugged and abandoned, using chrome tubing and chrome casing over the injection intervals to reduce the effects of corrosion, and using CO2-resistant cement along the injection interval to prevent fluid migrating upward along the annulus. Mechanical pressure testing will ensure well integrity, and logs over the well length will ensure cement bond integrity. The cased and cemented segments will be inspected as well.

The monitoring segment of the MMV plan provides for routine sampling of CO2 streams as they are delivered and injected to determine quantities, composition, and characteristics, ensuring compliance with regulations and protocols.

The active safeguards — the site-specific monitoring technologies selected for the project — were screened systematically to determine their complementary and overlapping capabilities, sensitivity, resolution, reliability, and cost.

Table 1 summarises the potential technical capabilities in terms of information gained, application, frequency of deployment (years), coverage, and platform power consumption.

Once the key technologies were selected, the next step was to identify monitoring network performance targets and establish KPIs for performance evaluation. Although there is no expectation that the site would experience loss of containment, the plan requires control response options and corrective measures to be identified for losses within and above the injection zone.

Figure 2 Risk Qualitative Analysis Bowtie Diagram.

Geochemical

Seismic Monitoring

Downhole

Seismic

Seabed Monitoring

Side

Fluid

Detect leakage of CO2

Detect emission of CO2

Impact assessment of CO2

Protect against inaccurate claims

Detect leakage of CO2

Detect emission of CO2

Impact assessment of CO2

Protect against inaccurate claims

Table 1 Summary of the potential technical capabilities of each identified monitoring technology.

A baseline monitoring plan, comprising multiple, independent monitoring systems, was developed to assure the integrity of the storage complex, wells, and geological features. The plan was constructed for normal operations, with built-in redundancy systems that mitigate the consequences if the baseline system unexpectedly underperforms. Operating procedures also were developed for responding to monitoring alarms.

The long-term security of CO2 storage is verified by showing that pressure and CO2 accumulation inside the storage site are consistent with model-based forecasts within the range of uncertainty. If necessary, models will be calibrated and updated, and injection and monitoring will be adapted to optimise storage performance.

Changes within the hydrosphere, biosphere, and atmosphere will be measured to demonstrate the security of CO2 storage by verifying geological containment, well integrity, and the absence of any environmental effects outside the storage complex. This monitoring of changes is sufficient to provide early warning signs of unexpected loss of containment and trigger additional effective control measures necessary to prevent or remediate significant environmental impacts. The effectiveness of this approach is reflected in a review of underground gas storage site failures worldwide which demonstrates the historical rate of major leakage is 10-6 (King and King, 2013; Freifeld et al., 2016; Jones, et. al, 2023).

QRA analysis demonstrates the incremental risk reduction of each passive safeguard and of each active safeguard. This analysis using a systematic evidence-based risk-assessment process, reliant on collective expert judgement, a lower risk threshold on the order of 10-6 is recommended as the tolerable risk threshold (Figure 3).

This model provides a basis for assigning threat initiation rates to the wells that comprise the storage site. Initiation rates for other threats were estimated by selecting a rate factor to

represent the expected rate relative to legacy wells. These other threats were judged equally unlikely, as the appraisal data provided no direct evidence for the existence of any threats within the storage site. It should be noted that assigning weights to individual consequences simply recognizes the fact that the potential impact of each identified consequence is not equal.

The final element of the MMV plan addresses post-injection site care and site closure and describes the activities that will be performed to meet operator and regulatory requirements. This includes tracking the position of the CO2 plume and the pressure front for a minimum of 10 years following cessation of injection (or a length of time equivalent to the injection period), provided there are no significant issues that arise from injection operations. The site closure application begins once it has been proven that there is no potential endangerment to the geosphere.

After site closure approval, the operator is responsible for plugging all monitoring wells, restoring the site to its original condition, and submitting a site closure report and associated documentation per recommendations contained in BS ISO 27914:2017.

Conclusion

Carbon capture can achieve 14% of the global greenhouse gas emissions reductions needed by 2050 (Center for Climate and Energy Solutions, 2023), equivalent to about 1.2 Gt per year (IEA, 2023). However, as of January 2024, there are about 40 commercial CCS projects globally (Statista, 2024) capturing about 40 Mt per year. Expanding the number of CCS projects is essential to reducing the amount of CO2 released into the atmosphere, and thorough MMV planning is fundamental to achieving that goal.

A comprehensive, risk-based MMV plan demonstrates containment objectives have been achieved, supports strate-

Figure 3 Reduction in risk computed for increasing number of passive and active safeguards. Each line represents one realisation of the anticipated failure rate for each safeguard selected at random from the recognised range of potential failure rates for each safeguard.

gic planning and field development, and enables informed decision making. In short, it changes the operating paradigm, establishing a blueprint for future operations and expediting the global execution of safe and reliable CCS projects.

References

ANSI-NACE MR0175/ISO 15156 standards, General principles for selection of cracking-resistant materials.

Bourne, S. [2011]. Measurement, Monitoring and Verification Plan, 07-0AA-5726-002, Shell Canada Energy, Chevron Canada Limited. and Marathon Oil Canada Corporation, for the Quest Project.

British Standards Institution Carbon Dioxide Capture [2017]. Transportation and Geological Storage — Geological storage Section 6 Risk management (BS ISO 27914).

California Air Resources Board [2018]. Carbon Capture and Sequestration Protocol under the Low Carbon Fuel Standard (CA LCFS).

Center for Climate and Energy Solutions

https://www.c2es.org/content/ carbon-capture/.

Daniels, S., Hardiman, L., Hartgill, D., Hunn, V., Jones, R. andRobertson, N. [2023]. Deep Geological Storage of CO2 on the UK Continental Shelf: Containment Certainty, Supplementary Note A: Breakdown of combined well and geological storage risks for typical storage sites, OGL.

Dean, M. and Tucker, O. [2017].A risk-based framework for Measurement, Monitoring and Verification (MMV) of the Goldeneye storage complex for the Peterhead CCS project, UK. International Journal of Greenhouse Gas Control, 61, 1-15.

International Energy Agency Carbon Capture, Utilization, and Storage [2023]. Tracking https://www.iea.org/energy-system/carbon-capture-utilisation-and-storage.

Statista [2024]. https://www.statista.com/topics/4101/carbon-capture-and-storage/#topicOverview (number of commercial CCS projects in the world, January)

Underground Natural Gas Storage Integrity and Safe Operations [2016]. compiled by The American Petroleum Institute, The American Gas Association The Interstate Natural Gas Association of America, July.

U.S. EPA [2023]. Geologic Sequestration of Carbon Dioxide Underground Injection Control (UIC) Program 40 CFR 146

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