First Break June 2025 - Navigating Change: Geosciences Shaping a Sustainable Transition

Navigating Change: Geosciences Shaping a Sustainable Transition

EAGE

TECHNICAL

FIRST BREAK ® An EAGE Publication

CHAIR EDITORIAL BOARD

Clément Kostov (cvkostov@icloud.com)

EDITOR

Damian Arnold (arnolddamian@googlemail.com)

MEMBERS, EDITORIAL BOARD

• Lodve Berre, Norwegian University of Science and Technology (lodve.berre@ntnu.no)

Philippe Caprioli, SLB (caprioli0@slb.com) Satinder Chopra, SamiGeo (satinder.chopra@samigeo.com)

• Anthony Day, NORSAR (anthony.day@norsar.no)

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

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

• Stephen Hallinan, Viridien (Stephen.Hallinan@viridiengroup.com)

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

Fabio Marco Miotti, Baker Hughes (fabiomarco.miotti@bakerhughes.com)

Susanne Rentsch-Smith, Shearwater (srentsch@shearwatergeo.com)

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

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

EAGE EDITOR EMERITUS

Andrew McBarnet (andrew@andrewmcbarnet.com)

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Hang Pham (publications@eage.org)

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

A breakthrough in the imaging of a CO2 plume — using OBN data to the full

25 Detection of CO2 distribution by seismic pulse width analysis using mollifier functions F. P. L. Strijbos

35 Geostatistical AVA seismic inversion for reservoir characterisation of the Pozo D-129 Formation: A case study in San Jorge Basin, Argentina Cecilia Zarpellón, Angie Padrón, Manuel Arijón, Antonio Ornés and Paola Fonseca

Special Topic: Navigating Change: Geosciences Shaping a Sustainable Transition

47 Adapted from the hydrocarbon mindset: Global screening and prospectivity mapping for critical metals with reference to copper and nickel Paul Helps, Graeme Nicoll and Joseph Jennings

57 Mainstream, modular, multi-dimensional: A global agenda for geothermal in 2025 Marit Brommer

61 Revolutionising geothermal heat extraction from abandoned mines for a sustainable energy future

Julien Mouli-Castillo and Jeroen van Hunen

67 Revealing the salt tectonic puzzle: Mesozoic base of the Norwegian North Sea Alena Finogenova, Vita Kalashnikova, Barbara Eva Klein, Marcin Kaluza, Tatiana Nekrasova, Rune Øverås, Vlad Sopivnik, Elena Akhiyarova, Anna Ivanova, Eli Karine Finstad and Natalia Kukina

75 Multicycle injection and withdrawal in sedimentary basins, a multi-disciplinary analysis of pore-scale fluid flow for hydrogen storage

Johnson, J.R, Kiss, D, Shukla, M, van Noort, R, Nooraiepour, M. and Yarushina, V

83 A breakthrough in the imaging of a CO2 plume — using OBN data to the full Vetle Vinje, Ricardo Martinez and Phil Ringrose

89 Geosciences and the Energy Transition: Dispelling the myth, building solutions

Elodie Morgan and Camille Cosson

95 Geothermal is becoming key in the renewable energy transition

Kim Gunn Maver and Thomas Møgelberg

102 Calendar

cover: The city of Toulouse (La Ville Rose) will host the EAGE Annual Conference and Exhibition this month.

European Association of Geoscientists & Engineers Board 2024-2025

Near Surface Geoscience Circle

Andreas Aspmo Pfaffhuber Chair

Florina Tuluca Vice-Chair

Esther Bloem Immediate Past Chair

Micki Allen Liaison EEGS

Deyan Draganov Technical Programme Representative

Eduardo Rodrigues Liaison First Break

Vladimir Ignatev Liaison CIS / North America

Ruth Chigbo Liaison Young Professionals community

Gaud Pouliquen Liaison Industry and Critical Minerals community

Mark Vardy Editor-in-Chief Near Surface Geophysics

Martin Brook Liaison Asia Pacific

Madeline Lee Liaison Women in Geoscience and Engineering community

Oil & Gas Geoscience Circle

Yohaney Gomez Galarza Chair

Johannes Wendebourg Vice-Chair

Lucy Slater Immediate Past Chair

Wiebke Athmer Member

Alireza Malehmir Editor-in-Chief Geophysical Prospecting

Adeline Parent Member

Jonathan Redfern Editor-in-Chief Petroleum Geoscience

Xavier Troussaut EAGE Observer at SPE-OGRC

Robert Tugume Member

Timothy Tylor-Jones Committee Member

Anke Wendt Member

Martin Widmaier Technical Programme Officer

Sustainable Energy Circle

Carla Martín-Clavé Chair

Giovanni Sosio Vice-Chair

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Sanjeev Rajput Vice-President

Laura Valentina Socco President

Martin Widmaier Technical Programme Officer

Andreas Aspmo Pfaffhuber Chair Near Surface Geoscience Circle

Maren Kleemeyer Education Officer

Yohaney Gomez Galarza Chair Oil & Gas Geoscience Circle

Carla Martín-Clavé Chair Sustainable Energy Circle

Diego Rovetta Membership and Cooperation Officer

Peter Rowbotham Publications Officer

Christian Henke Secretary-Treasurer

Our diverse community is driver of change

Valentina Socco, EAGE president, reflects on her year in office.

It has been a great honour to serve EAGE as president during the past year. The vitality of our Association is impressive and witnessing it is a privilege. In a time of great changes, it is not straightforward to adapt and respond to the different challenges that environment, innovation and geopolitics pose for us, but EAGE is not only resilient, it acts as driver of change.

The transformation started two years ago with the introduction of Circles replacing Divisions. The establishment of the new Sustainable Energy Circle continues and supports an extremely active community of members. Its tremendous innovative potential is being expressed through an increasing number of technical communities.

Our Technical Communities tackle strategic topics related to energy transition, sustainable exploitation of natural resources, energy security and related technological developments, including artificial intelligence (AI).

This transformation has also proven highly effective in attracting and engaging new stakeholders in our areas of interest. The 2024 edition of GET, our flagship event targeting global energy transiton, was a remarkable success, seeing attendance increase sixfold compared to 2023, alongside a significant rise in participation from industry and institutions. The numbers for the 2025 edition suggest a further growth to come. It is noteworthy that this event is bringing together researchers, professionals, and companies who never participated in an EAGE event before, confirming that our transformation process expands our horizons, increases our impact, and creates new opportunities for our members.

As part of this evolution, the Near Surface Geoscience Circle will be transformed into the new Environment, Minerals, and Infrastructure Circle (EMI). This new name reflects the expanding scope of the Circle and its mission to serve as a platform for knowledge exchange and innovation in key areas for a growing global population. This includes building sustainable

infrastructures that respect environment and cultural heritage and are resilient to climate forcings; improving land management to mitigate the impact of natural hazards and increase our capability to adapt to climate change; creating a safe environment by controlling and reducing water and soil pollution; providing effective methods for characterisation, monitoring and manage-

ment of water resources; and responding to the growing demand for mineral resources which are strategic for energy transition and technological development. Multi-disciplinary expertise in geoscience and engineering will be increasingly essential to ensuring the sustainability and safety of our development, and the new name aims to communicate these priorities more clearly and connect us with the relevant industries and professionals.

Building the Associated

Borehole seismic courses for everyone

Digital event scores a hit in Edinburgh

EAGE president Valentina Socco at GET 2024.

Among the challenges we face, recent geopolitical developments are promoting cultural models that question science-based decision-making, elevate personal opinions over scientific evidence, casting doubt on the climate and environmental crises, and pushing diversity and inclusion off political agendas. Globally, the scientific research ecosystem is suffering from public disinvestment and political interference.

In this context, EAGE stands as a safe space where academia and industry collaborate, share knowledge, and generate mutual opportunities. However, to be a true driver of change, we must look beyond our comfort zone and engage in the global conversation about the role of geoscience and engineering in society. The recent creation of a new Special Interest Community for Geoscience Communication and Public Engagement is a step in this direction, aiming to enhance public understanding of Earth systems and the role geoscientists and engineers play in the energy transition and other crucial areas.

EAGE remains deeply committed to promoting diversity and inclusion. This is reflected in the wide range of topics addressed by our Technical Communities, the many initiatives led by our local and student chapters, and the efforts of our Women in Geoscience and Engineering and Young Professionals Special Interest Communities. We are also proud to introduce the Rosemary Hutton Award for Best Paper in Geoenergy, which celebrates excellence in sustainable energy and honours an outstanding woman scientist.

EAGE also champions continuous technological development. During the last year, tremendous work has been done to implement AI applications into the digital services offered to our members. New AI applications will be available for supporting delegates at the Annual Conference and for offering new opportunities in navigating EarthDoc.

Our member community is our greatest strength and most valuable asset. Its unwavering support, active participation, energy, and generosity of members in sharing their time and expertise with the Association are key to our continued success, growth, and evolution. On behalf of the Board and the entire Association, I extend my heartfelt thanks and appreciation to each of them.

A warm thanks also goes to our Board of Directors and to our staff at Head Office and in the regions who share our passion and dedication in making EAGE a successful organisation where innovation and creativity are always supported by professionalism.

During this year I have had the privilege and the pleasure to work with a very active and competent Board, whose members I really thank for their availability and commitment.

For the 2025 Annual Conference, we have chosen the theme Navigating Change: Geosciences Shaping a Sustainable Transition. With this we mean to highlight the great potential of our community to propel the change that humanity needs to progress safely and sustainably. I look forward to meeting you in person in Toulouse.

Meet the Chapter champions 2025

At the end of 2024 we launched a special challenge for our Local and Student Chapters worldwide: a competition designed to celebrate and reward their exceptional efforts in recruiting new EAGE members. They definitely rose to the challenge.

Chapters play a vital role in connecting with local professionals, strengthening our global network, and expanding EAGE’s reach. The EAGE Champions initiative was not only a way to recognise their dedication but also an opportunity to win funding for future local activities.

After months of enthusiasm and community-building, we are thrilled to announce the winners:

• Local Chapter London, UK

• Student Chapter University of Lagos, Nigeria

• Student Chapter Ahmadu Bello University, Nigeria

• Student Chapter Kurukshetra University, India

London Chapter reacted to the win: ‘We are immensely grateful to everyone who endorsed us in the challenge. We know

that the competition was high. This year we are specifically focusing on supporting students in the London area. We are planning an initiative where students will be able to present their work to the wider EAGE London community, in line with the topics of our monthly Evening Lectures.’

Members of the Student Chapters at the University of Lagos said: ‘This achievement means a lot to our community. We plan to use the prize money to strengthen our educational workshops, which play a vital role in enhancing our members’ practical experience. This year, we aim to deepen our engagement with local geoscience companies and invest in new learning resources to better support our members’ development.’

Kurukshetra Student Chapter said: ‘This year, we have planned several initi-

atives, including conducting groundwater awareness campaigns in Kurukshetra University to address the local water crisis and empowering underprivileged girls through earth science education to inspire future geoscientists. We will organise field surveys to provide practical exposure to geophysics and implement school outreach programs to promote the relevance of geophysics in society. Our focus will be on hosting workshops, seminars, and field visits to enhance public understanding, as well as developing engaging initiatives such as exhibitions, community activities, and social media campaigns tailored to diverse audiences.’

A huge thank you to all participating Chapters for their hard work and commitment. We look forward to seeing the amazing projects that will emerge from this well-earned recognition.

LEAP WHOLE WORKFLOWS IN A SINGLE BOUND

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No more jumping through hoops — DUG Elastic MP-FWI Imaging gives you everything you need with one powerful leap.

Congratulations to the winners of EAGE’s 2025 Awards

As an association committed to promoting innovation and excellence for inclusive and sustainable development, EAGE proudly acknowledges the hard work of its members in advancing the field and fostering collaboration across disciplines. Here are this year’s winners that were nominated by colleagues like you.

Desiderius Erasmus Award

For lifetime contributions in the field of resource exploration and development.

Carlos Torres-Verdín

For his contributions to the community, particularly in the fields of formation evaluation and rock physics.

Honorary Membership Award

For highly significant and distinguished contributions to the geoscience community at large or to the Association in particular.

Luigi Zanzi

For his contributions to applied geophysics, particularly in the field of civil engineering.

Conrad Schlumberger Award

For outstanding contributions to the scientific and technical advancement of the geosciences, particularly geophysics.

Tijmen Jan Moser

For his contributions to advancing our understanding in fields of seismic imaging, inversion, and subsurface exploration, and his years serving Geophysical Prospecting

Alfred Wegener Award

For outstanding contribution to the scientific and technical advancement of EAGE’s disciplines, particularly petroleum geoscience and engineering.

Hugh Daigle

For his contributions to both petroleum engineering and new energy-related topics which benefit from his profound understanding of formation evaluation and pore space.

Arie van Weelden Award

For Young Professionals who have made highly significant contributions to one or more of the disciplines in our Association.

Chao Song

For his outstanding work on seismic modelling, inversion, and the integration of deep learning techniques in geophysics.

Myrto Papadopoulou

For her outstanding work on seismic reflection imaging and surface wave analysis toward minerals and geothermal energy exploration, CO2 storage, and geotechnical characterisation.

Nigel Anstey Award

For the Best Paper published in First Break in 2024.

Isabel Espin and co-authors

For their paper ‘Angle-Restricted FWI for Shallow Reservoir Characterisation’.

Ludger Mintrop Award

For the Best Paper published in Near Surface Geophysics in 2024.

Huamei Zhu and co-authors

For their paper ‘A framework for GPRbased water leakage detection by integrating hydromechanical modelling into electromagnetic modelling’.

Norman Falcon Award

For the Best Paper published in Petroleum Geoscience in 2024.

Nigel H. Platt and co-authors

For their paper ‘Footwall uplift and erosion during Jurassic rifting: Scott and Telford fields, Outer Moray Firth, UK Central North Sea’.

Robert Mitchum Award

For the Best Paper published in Basin Research in 2024.

Amando P. E. Lasabuda and co-authors

For their paper ‘Unravelling controls on multi-source-to-sink systems: A stratigraphic forward model of the early–middle Cenozoic of the SW Barents Sea’.

Loránd Eötvös Award

For the Best Paper published in Geophysical Prospecting in 2024

Stephen Secker and co-authors

For their paper ‘Marine vibrator source motion correction for strictly monotonic sweeps’.

Rosemary Hutton Award

For the Best Paper published in Geoenergy in 2024.

Catherine M. Gibson-Poole and co-authors

For their paper ‘Site characterisation of the Endurance CO2 store, Southern North Sea, UK’.

Guido Bonarelli Award

For the Best Oral Presentation at the EAGE Annual 2024.

R. Bachrach and co-authors

For their paper ‘Scholte-Wave Interferometry Using Passive Surface Distributed Acoustic Sensing (S-DAS) with Application for CCS Monitoring’.

EAGE extends its Associated Societies network

EAGE signed three new Associated Society agreements and renewed one in the first half of this year.

One of these new partners is AGAP Qualité (France). By leveraging its expertise on hydrogeology, geotechnics, passive seismic methods, and geophysical technologies for the benefit of the environment, we aim to contribute to the advancement of subsurface geophysics worldwide.

We also joined forces with the Geochemical Society of Japan (GSJ, Japan), a professional association committed to the promotion of geochemistry through technical events and an international peer-reviewed journal since 1953.

Prof Dr Yoshio Takahashi, GSJ president, says that the collaboration will greatly benefit their members by providing them access to ‘short courses and seminars to learn about various fields related to geochemistry in person and online. These platforms are very attractive for our members, especially for young scientists, to learn new things and be involved in international research communities’.

The third agreement was signed in South America with the Colegio de Geólogos de Chile (CGC – Chilean Geologists Board). Created in 1972, the CGC gathers, represents and supports the professional development of Chilean geologists. Thanks to its technical expertise and knowledge of the local/ regional geology, CGC has been invited to support the First

EAGE Conference on the Future of Mineral Exploration, coming on 14-16 October 2025 in Santiago, Chile.

Concluding an active semester, we also renewed our cooperation agreement with AVENIA (France). Even though our partnership began in 2019, we updated its terms to strengthen synergies between our major events; collaborate on European R&D geoscience projects and initiatives; and encourage dialogue between scientific, industrial and societal actors.

We look forward to cooperating with our 98 Associated Societies worldwide to continue making a positive impact on the broader geoscience and engineering community.

Viking battle of wits tests geoscience knowledge in Oslo

It was a lively evening in March when the Oslo Local Chapter hosted a geoscience quiz at the University of Oslo’s Department of Geosciences. The event turned out to be quite the brain-teaser, with questions ranging from the simple to complex on the topics like: paleontology, oil and gas, geophysics and seismic interpretation, planetology, geology of

Norway, paleomagnetism, sedimentology, petrography and mineralogy.

The quiz itself ran smoothly, but it was not just about the score - right answers lit up the big screen and sometimes sparked discussions among contenders and organisers alike.

Geoscience enthusiasts displayed deep knowledge across the board with

the top players getting the right answers to about two-thirds of the questions. It was Ofelia Soledad Silio, from the Research Group for Basin Studies (UiO), who took home the top prize, the huge book Geology of Norway. Post-quiz, the atmosphere buzzed with an informal vibe as attendees unwound with refreshments. Apart from networking, a spontaneous discussion between the board members of the Oslo Students chapter and the Local chapter was sparked about future projects. Overall, the quiz night was a testament to the community’s passion for geoscience and to the fun that can come from combining learning with a touch of competition. Here’s to more such evenings of knowledge and camaraderie.

Collaborating with its associated societies, EAGE aims to further promote knowledge exchange and dissemination.

Beneath the Norwegian landscape lies a hidden world of geoscecrets.

Welcome from GET executive chair

The EAGE Global Energy Transition Conference & Exhibition (GET 2025), in Rotterdam from 27-31 October, will again feature four dedicated technical conferences, all under the theme ‘Powering the Transition: Innovation, Integration & Involvement’. Here Maurice Hanegraaf, market director, TNO GDN, and chair, GET 2025 executive committee, invites us to join forces, innovate, and shape the energy systems of tomorrow.

As chair of this year’s conference, I am proud to bring together experts and pioneers from across disciplines to address the pressing questions of our energy transition.

The conference isn’t just about dialogue, it’s about direction. How do we balance immediate energy needs with long-term climate commitments? How do we scale up geothermal, carbon capture and storage, and energy storage – and harness the full potential of wind power through smarter integration? Our path forward is not defined by technology alone: it also requires the right policies, financial frameworks, and, above all, societal engagement and public trust to truly succeed. Together, we will explore not only what’s possible, but what’s essential for a just, secure and sustainable energy future.

I invite you to connect, collaborate, and be inspired because real progress happens when knowledge meets action. Let’s harness our insights, challenge our assumptions, and shape an energy system for generations to come. I’m honoured to take this journey with you.

Contribute to the Technical Programme and join key stakeholders in shaping the energy transition. Submit your abstract by 15 June 2025. Early bird registration is open until 1 September 2025. Learn more at eageget.org.

Carbon Capture and Storage Conference Geothermal Energy Conference

and Energy Storage Conference Offshore Wind Energy Conference

Nigeria has a new Student Chapter

EAGE’s latest Student Chapter in Nigeria has been launched at Ladoke Akintola University of Technology (LAUTECH). This is what the students have to say.

Our Chapter provides an opportunity for LAUTECH students to engage with a global network of geoscientists, fostering academic and professional growth in geophysics and related fields. We are motivated by a collective desire to advance geoscience knowledge, develop practical skills, and contribute to solving real-world problems through innovative geophysical applications.

We focus on environmental geophysics and digital geoscience applications, as these areas align with global trends and the need for sustainable solutions. We plan to

explore near-surface geophysical techniques for groundwater exploration, contamination studies, and geohazard assessments. We are also keen on integrating geophysics with artificial intelligence, remote sensing, and GIS for better data processing and interpretation.

We are looking forward to participating in EAGE student e-summits, online events and competitions. Additionally, we plan to organise fieldwork, hackathons, and collaborative projects with other student chapters and institutions.

We believe our new Chapter is not just a student organisation but a movement towards innovation, skill development and global networking in geoscience. We are excited about the journey ahead and the opportunities for growth.

Hydrogen

STUDENT CHAPTER

Members of the LAUTECH Student Chapter.

Maurice Hanegraaf.

Advancing borehole seismic for the energy transition

Sébastien Soulas, a leading expert in borehole geophysics, is bringing two new courses to the EAGE Education Catalogue in 2025. He will teach Borehole seismic monitoring for sustainable energy solutions at GET 2025 and VSP technology – From check shot to advanced DAS at the Eight EAGE Borehole Geophysics Workshop (29 September – 1 October, Al Khobar, Saudi Arabia). In this interview, he discusses the value of borehole seismic for the energy transition and the future of distributed sensing.

How do you see borehole seismic methods contributing to the success of geothermal and CCS projects today?

Vertical seismic profiling (VSP) combined with surface seismic can provide a valuable real-time geophysical monitoring technology for reservoir characterisation and management. It can also provide the geologic framework for locating and interpreting events detected by microseismic monitoring. Advancement in downhole sensing technology for active and passive seismic monitoring using a combination of C point and 1-C distributed sensors is becoming an important part of the CCS MMV strategy for full wave recording as well as data integration for geothermal reservoir characterisation. However, it’s important to characterise, technically

evaluate and quantify limitations and merits of each borehole seismic sensing technology and, from an instrumentation standpoint, see how these technologies can be combined and integrated with surface seismic or standalone in a cost-effective way for high resolution imaging, 4D monitoring and microseismic cap rock integrity monitoring.

How do your courses help reposition VSP as a valuable tool for sustainable energy development?

Most of the borehole seismic solutions for both integrated reservoir characterisation and active/passive seismic monitoring are valid and directly transferable beyond oil and gas applications. However, there are key constraining factors associated with monitoring conditions for CCUS where dedicated monitoring wells are not always feasible due to costs and harsh/hot environment for geothermal monitoring. Advanced geophysical exploration and development methods for geothermal fields are like oil and gas technology. This encompasses, for example, derisking the sub-horizontal drilling of geothermal doublets where multi-component VSP can add value including improved reservoir studies even in highly congested suburban areas. Dedicated, fit-for-purpose, cost-effective and, combined with distributed acoustic sensing system, VSP can be very pertinent using decades of in-depth legacy knowledge built from the oil and gas industry.

Who do you think will benefit most from joining your courses?

I do believe that a holistic approach to understand the value and limitations of

borehole seismic data and its complex integration with surface seismic for new energies geophysical monitoring and reservoir characterisation is paramount in the context of the rapid evolution of downhole sensing technology towards data analytics to improve decision-making. Increased needs in permanent monitoring and reducing subsurface model uncertainties via surface seismic calibration with more and more complex signal processing toolbox like FWI and ML is making the process very complex in extracting real business value.

Multi-levels fully passive 3-C fibre optical system being deployed in a borehole.

Experienced and young professionals from geologists, geophysicists, geoscientists and reservoir engineers could benefit in joining the course as it would provide a practical overview of conventional borehole geophysics and highlight its evolution towards using and combining with DAS.

Young professionals at the wellhead at the Avalon HDR geothermal site deploying 3-C VSP tool for training.

Workshops and short course await you at NSG 2025

The EAGE Near Surface Geoscience Conference and Exhibition is renowned for bringing cutting-edge and cross-disciplinary technologies to the forefront of geoscience discussions, and this year’s edition is no exception with some first class short courses and workshops.

Among the highlights of the event is the short course on Satellite InSAR Data:

Monitoring from Space presented by Dr Alessandro Ferretti (TRE ALTAMIRA). This one-day programme resonates powerfully with the parallel meeting on Geohazards Assessment and Risk Mitigation, as well as with the multi-disciplinary nature of the conference, bridging the gap between advanced satellite technologies and applied geoscience applications.

Satellite radar data, particularly from synthetic aperture radar (SAR) sensors, have revolutionised surface deformation monitoring. Capable of measuring sub-centimetre ground displacements over vast areas and long timeframes, InSAR (Interferometric Synthetic Aperture Radar) is a game-changer for geohazards assessment, reservoir management, and environmental monitoring. These tools are no longer confined to specialised remote sensing teams, they are becoming indispensable across disciplines from optimising design and construction operations to identifying at-risk locations and providing early warning for mining assets.

Ferretti’s course is designed with accessibility in mind, offering a clear, practical introduction to how InSAR works and its profound potential for real-

world applications. In fact, InSAR is one of the most multi-disciplinary technologies, with application examples ranging from a reservoir in the Middle East, a volcano in Sicily, and coastal subsidence in the Netherlands. Attendees will benefit from case studies and experience sharing from diverse applications.

The NSG 2025 experience is further enhanced with three fantastic workshops. The first titled Geophysical exploration to volcanological areas: Imaging challenges and public and operational constraints by Pier Paolo Bruno (Università degli Studi di Napoli Federico II) and Paola Ragazzo (Eni) will focus on the latest methodologies for geophysical inversion in volcanological areas, emphasising both active source and ambient noise (passive) seismic data. Additionally, it will explore joint inversion approaches that integrate seismic, gravity, electromagnetic, and other geophysical datasets to enhance understanding of volcanic systems.

The second workshop on Geophysical applications to archaeology: Innovation in acquisition and data modelling by Federico Cella (Università di Camerino), Chiara Colombero (Politecnico di Torino) and Maurizio Milano (Università degli Studi di Napoli Federico II) aims

EAGE Education Calendar

to bring together the international geophysical research community to explore the latest technical and methodological advancements in data analysis, processing and interpretation. Topics will include archaeogeophysical remote sensing, signal enhancement, 3D imaging, joint investigations, and inter-disciplinary synergies between geophysics, petrochemistry and soil science. By refining these approaches, the workshop seeks to highlight their added value in the rediscovery and preservation of cultural heritage.

Lastly, the workshop on Airborne geophysics: Advances and perspectives from different platforms’ by Massimo Chiappini (Istituto Nazionale di Geofisica e Vulcanologia), Gianluca Fiandaca (University of Milano “La Statale”) and Andrea Viezzoli (Emergo), will explore all main geophysical techniques. Looking into advances in data acquisition, integration, processing and modelling. A part of the workshop will be highly interactive, with a live demo on AEM data processing and modelling using open source software. The field of applications includes geologic mapping, environmental geophysics, hydrogeophysics, mining and resource exploration, health and safety, and international security.

1 JUN COMPRESSIVE SENSING, EXPLAINED AND CHALLENGED, BY JAN DE BRUIN TOULOUSE, FRANCE PART OF EAGE ANNUAL 2025 RESERVOIR ENGINEERING FOR HYDROGEN STORAGE IN SUBSURFACE POROUS MEDIA, BY GANG WANG

2 JUN SEISMIC PROCESSING OF MULTIPLES: CONCEPTS, APPLICATIONS, TRENDS, BY CLÉMENT KOSTOV GEOSCIENCE COMMUNICATION AND PUBLIC ENGAGEMENT (EET), BY IAIN STEWART

6 JUN STATE OF THE ART IN FULL WAVEFORM INVERSION (FWI), BY IAN JONES

* EXTENSIVE SELF PACED MATERIALS AND INTERACTIVE SESSIONS WITH THE INSTRUCTORS: CHECK SCHEDULE OF EACH COURSE FOR DATES AND TIMES OF LIVE SESSIONS FOR THE FULL CALENDAR, MORE INFORMATION AND REGISTRATION

Every month we highlight some of the key upcoming conferences, workshops, etc. in the EAGE’s calendar of events. We cover separately our four flagship events – the EAGE Annual, Digitalization, Near Surface Geoscience (NSG), and Global Energy Transition (GET).

Second EAGE Conference & Exhibition on Guyana-Suriname Basin 9-11 September 2025 – Georgetown, Guyana

The Guyana-Suriname Basin has become one of the world’s most exciting offshore exploration frontiers, with over 18 billion barrels of oil equivalent discovered to date. The conference will gather geoscientists, engineers, industry leaders, and regulators to explore the latest developments in exploration, reservoir imaging, drilling technologies, sustainable practices across the basin, and discuss the region’s ongoing transformation into a major global energy hub. We welcome contributions that highlight innovative research, new exploration concepts, case studies and lessons learnt from operations in this dynamic basin.

Registration early fee deadline: 15 June 2025

Third EAGE Workshop on Geothermal Energy in Latin America

12-14 November 2025 – Guancaste, Costa Rica

The workshop will once again serve as a key platform for technical exchange on the development of geothermal energy, a constantly renewable, high-capacity (>80%) resource with low environmental impact with significant potential in Latin America for power generation and direct uses. Geothermal’s geological complexity demands a better understanding of the subsurface geothermal system to mitigate exploration and development risks. Targeting stakeholders across the entire geothermal value chain, the workshop is to focus on new exploration techniques, reservoir characterisation, emerging technologies, regulatory frameworks, environmental and social impact assessment.

Call for Abstracts deadline: 1 August 2025

First EAGE Workshop on Energy Transition in Latin America’s Southern Cone 17-18 September 2025 – Buenos Aires, Argentina

The workshop will provide insights into how the Southern Cone region (including Argentina, Uruguay, Paraguay, Chile and southern Brazil) can develop its renewable resources and restructure its energy infrastructure to transition from traditional high-carbon fuels to low-/zero-carbon and sustainable energy sources. Topics will include: cross-border collaboration, the need for smart grid expansion, investment in storage technologies, innovation and digitalisation, social equity, policy development, workforce transformation, and inclusive planning procedures to support a fair and equitable transition.

Abstract submission deadline: 20 June 2025

EAGE/FESM Conference on ‘Petrophysics meets geoscience: unlocking reservoir potential in a dynamic energy landscape’ 18-20 November 2025 – Kuala Lumpur, Malaysia

The energy landscape is evolving rapidly, demanding innovative approaches to reservoir characterisation. With a focus on practical applications, the event will showcase how these integrated approaches can optimise reservoir management, enhanced hydrocarbon recovery, and support the development of geothermal and carbon storage projects.

In an era defined by the energy transition, this conference is a must-attend for professionals seeking to stay at the forefront of reservoir characterisation and maximise subsurface potential. Kuala Lumpur, a vibrant hub in the heart of Southeast Asia, provides the perfect backdrop for this exchange of knowledge and innovation.

Our flagship digital event in Edinburgh was a huge hit

Glyn Edwards, global subsurface data and AI unit leader at bp and conference chair, and Krystel St Clair, seismic interpretation transformation lead at bp and member of the technical committee, report on the fifth edition of EAGE Digital, held on 24-26 March 2025 in Edinburgh under the theme ‘Enhancing Predictions and Investments with Digital Technologies’. The event marked our largest gathering yet, welcoming over 500 participants and highlighting the increasing momentum around artificial intelligence and the growing impact of next-generation technologies in the industry.

Several key themes emerged during the conference:

Data management & OSDU

The importance of organising and standardising data effectively was a major focus. When leveraging AI, with vast amounts of data in various formats and locations, efficient management is crucial to avoid the ‘garbage in, garbage out’ scenario. AI was highlighted as a tool to clean, organise, and standardise data first which will then make further utilisation of AI more streamlined.

Open Surface Data Universe (OSDU), a platform aimed at standardising data formats and minimising interoperability issues between tools, was highlighted as something the energy industry wants and is committed to. There is no option B, and we all need to actively participate and progress with intention and pace.

Why does this matter? Data is at the foundation of what we do in geoscience, and it is important for us to leverage our vast resources effectively, leading to

better decision-making and operational efficiency.

Generative AI (GenAI)

GenAI, which can create original content from user prompts (like chatbots such as Copilot and ChatGPT) was another significant topic. Discussions centred on balancing the use of large language models (LLMs) and agents with the specific needs of geoscience, which often involves unique terminology not found in natural language. More graphical models such as GraphRAG or geoscience specific models like GeoBERT were discussed to help bridge the gap and help make sense of geoscience data.

It was generally agreed that GenAI is still maturing and is currently too inaccurate to fully understand geoscience and engineering without significant supervision and expert training from SMEs.

Why does this matter? GenAI offers a new way to approach our interpreta-

What participants had to say

‘EAGE Digital is an excellent conference; small enough to allow efficient networking, yet big enough that many of the key decision-makers in digital in our industry are in the same place. High quality keynotes and insightful panels, addressing the big topics with insight and honesty.’

Trygve Randen, SVP digital products & solutions, SLB

‘The key takeaway for me - I think it has to be generative AI. At times, it’s a controversial topic, but we’ve worked

really hard this week to look at it from the positive side: how we can use AI to our advantage? Generative AI allows us all to access and leverage key technologies much more quickly and much more smartly.’

Michael Wynne, vice president, upstream solutions, S&P Global Commodity Insights

‘The presentations highlighted that the current digital transformation is above all a ‘digital integration’: geoscientists now

tion and integration workflows, reducing the time spent searching for data and clicking endless buttons. It can help geos get up to speed in new areas more easily, allowing us to focus on analysing data.

Value tracking

Tracking the value of digital products, which can often have subtle and non-obvious cost savings, was another key theme. While some specific examples were provided by TotalEnergies, bp and Akerbp in one of the dedicated technical sessions, it was clear that this is an area still under development with more work required to support successful deployment of digital products in the industry.

Why does this matter? Accurately tracking the value of digital products helps justify investments and demonstrates their impact on cost savings and efficiency.

leverage AI and digital technologies in every step of the subsurface workflows, from seismic interpretation to reservoir simulation. The energy resources sector has always been very technology-friendly, but what really changes is the pace of innovation. With AI and data science making tremendous progress every year, events such as EAGE Digital are essential to keep track of recent advances and learn from each other’s experience and practices.’

Antoine Bouziat, IFPEN

Industry collaboration

The need for industry collaboration and partnerships was emphasised in order to keep up with rapid AI and technological changes, which are now occurring on a 2–5 year cycle rather than the 10-15 years it would previously take.

Why does this matter? As an industry, we should collaborate in the good times and the bad to stay at the forefront of technological advancements as our challenges are common and we can be known less for being a ‘dinosaur’ industry.

Digital boom

There is a massive increase in digital products and ideas, both externally and internally at bp. We often see assets creating bespoke solutions to problems in tandem with other areas of the business so effective

communication is key to managing these new technologies and ideas efficiently. Why does this matter? Embracing the digital boom allows us to innovate and develop bespoke solutions that can drive business growth and efficiency.

Takeaways

The 5th EAGE Digitalization Conference and Exhibition may well prove to be an inflection point in OSDU adoption. We were surprised by the level of support for OSDU and the strong agreement that it isn’t progressing fast enough. It was one of the most debated topics, with many defending it against doubts about its success. GenAI sessions were consistently well attended, and the David Rowan keynote sparked lively discussion – though there was caution around how applicable other industries’

Signs of revival fuel interest in Libya’s oil and gas sector

After years of uncertainty and underinvestment, Libya’s oil and gas sector is showing clear signs of revitalisation. A series of recent events point to growing momentum and renewed international attention to the country’s vast hydrocarbon potential.

One such signal came from EAGE, which dedicated a second and specialised technical meeting to Libya’s carbonate reservoirs. Held last February, the virtual event – Libyan Carbonates: Carbonate Geology and Its Role in Libya’s Exploration Success – brought together geoscientists and engineers to discuss the complexities of carbonate formations which hold significant promise for future exploration and development. The high attendance of 140 people underscored the industry’s scientific and operational interest in the region.

On the commercial and strategic front, the Libyan National Oil Corporation (NOC) made headlines with the launch of its first

work is to our safety-critical environment. A key takeaway was the significant opportunity for collaboration across many areas, and a growing recognition that we don’t need to compete everywhere – reflected in the TotalEnergies and SLB joint keynote, the open OSDU discussions, and the shared GenAI use cases. The next edition can hopefully build on this by focusing more on how vendor tools are becoming increasingly OSDU-enabled.

We are already excited for the 6th EAGE Digitalization Conference and Exhibition, taking place from 16-19 March 2026 in Stavanger, Norway. Learn more

Mediterranean zones. The shift to a new production sharing agreement (PSA) model is designed to create more attractive terms for investors with the ultimate goal of boosting production capacity from the current 1.4 million barrels per day to 2 million.

These developments, while distinct in nature, both point to a broader trend: a renewed effort to reposition Libya as a viable and attractive player in the global energy landscape. Whether through technical collaboration or strategic investment, the international community is watching and increasingly re-engaging with Libya’s promising oil and gas sector.

Building on this increased activity in Libya and the successes of its earlier events, EAGE is already preparing a third meeting, planned as a face-to-face event, to further strengthen collaboration and networking within the technical and commercial communities.

If you are interested in joining the Technical Committee or helping in different ways to shape the content and direction of this upcoming event on Libya, please reach out to EAGE’s Middle East office via middle_east@eage.org.

How geochemistry contributes to the energy transition

The EAGE-EAG Technical Community on Geochemistry has embarked on a journey to show how the discipline plays a significant role in the energy transition era.

The quest started in September 2024 at the webinar Targeting and predicting key resources of the energy transition, where guest speakers Olivier Sissmann and Adriana Traby (IFPEN) shared their latest research on geochemistry for hydrogen, helium and lithium exploration with over 60 attendees.

One of the takeaways referred to H2 source rocks exploration. Leveraging chemical, e.g., Eh (FO2) data when available from old fluid data in drilling databases, satellite, geophysical (magnetic and gravimetric anomalies), and petrology data, as well as targeting iron mines and related

iron-rich lithologies, seem to be efficient proxies to discover new H2 sources.

In April 2025, the community set its focus on the need for evaluating the potential for geochemical reactions caused by CO2 injection at storage sites — partly to address regulatory demands but also to identify risks related to predicting injectivity impacts. Dr Linda Stalker (CSIRO), together with over 30 participants, explored how to tackle these challenges at the webinar Geochemistry impacts in high quartz systems for injectivity risk management and the art of the negative result

Dr Stalker explained: ‘You can start with simple tools for lower risk sites those with high quartz content in particular. Batch reaction models can be used to determine whether there is a risk of precipitation in res-

ervoir/storage intervals versus dissolution in topseal (shale, mudstone) intervals. Constrained by data, you can develop a series of sensitivity cases and stretch cases to test potential impacts to report to regulators.’

If you missed these discussions, go to the EAGE Youtube Channel to check out the recordings.

Toulouse Annual was due to be their next stop with a workshop on Geochemistry’s role on advancing climate change and energy transition research and a Dedicated Session on Reactive flow and transport in porous media

Connect with the EAGE-EAG Technical Community on Geochemistry to find out what’s next.

Become a reviewer for Petroleum Geoscience and Geoenergy

Are you passionate about advancing geoscience research and want to have a direct impact on the future of your field? Do you want to collaborate with leading experts and contribute to high-quality, peer-reviewed publications? If so, we invite you to become a reviewer for Petroleum Geo-

science and Geoenergy, co-owned journals of the Geological Society and EAGE.

As a peer reviewer, you’ll play a vital role in the rigorous process that ensures the highest-quality research is published. Your expertise will directly impact the accuracy and credibility of studies on key topics such as reservoir modelling, renewables, carbon capture, and energy storage.

Becoming a reviewer offers a unique opportunity to engage with the latest research, sharpen your analytical skills and refine your expertise, while also helping others to improve and refine their work.

Reviewers are acknowledged for their valuable contributions. The Geological

Society publishes a reviewer thank you list each year, providing you with recognition and visibility within the scientific community. In addition, reviews can be effortlessly tracked in your Web of Science profile, showcasing your review work and expertise without compromising anonymity.

Whether you’re an experienced or early career academic, researcher, or industry professional, your insights will be invaluable to the success of both journals. Sign up to become a reviewer and make a lasting impact on your field.

Send your expression of interest to email: lucy.bell@geolsoc.org.uk. 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!

Personal Record Interview

Life shaped by energy, family and purpose

Eugene Okpere is executive vice president exploration, strategy and portfolio, integrated gas and upstream at Shell based in London. He says his international career journey encompassing posts in many countries including Brunei, Nigeria, South Africa, and notably Trinidad & Tobago, has been inspired by his parents, family and faith.

Born into the business

I was born in Birmingham, UK, while my dad was finishing his PhD in mechanical engineering. However, I have no Brummie accent – our family moved back to Nigeria when I was young. As the eldest child in a big family, discipline and my Christian faith were pretty much non-negotiable. My dad, Dr Kisito Okpere, joined Shell in 1972 and went on to lead Shell Nigeria Exploration and Production Company (SNEPCo), so it is safe to say, Shell is in my blood.

Eureka moment

Growing up, I saw how energy could both catalyse progress and present significant challenges. This sparked my decision to pursue geology at the University of Benin, Nigeria. But the real ‘eureka’ moment came during a two-week seismic processing internship, where I watched experts interpret subsurface data. I was hooked.

First experiences

I started my career at Mobil Producing Unlimited in 1991 in Nigeria, gaining hands-on experience with drilling and operations as a well site geologist. I then moved to Shell in Nigeria, marking the beginning of an exciting journey spanning seismic interpretation, exploration and development, new business development, strategy and business planning across several countries including Brunei, Nigeria, UK and the Netherlands.

South Africa move

One defining moment of my career came in 2009 when I joined Sasol in South

Africa to lead its global exploration business. This included the somewhat humorous experience of being mistaken for Denzel Washington during a business trip to Uzbekistan. While I can assure you Denzel’s job is safe, the work was serious – growing exploration across conventional and unconventional assets globally. I returned to Shell, taking on leadership roles across Africa and South America, culminating in senior vice president and country chair in Trinidad and Tobago.

Trinidad and Tobago highlight

Leading Shell in Trinidad and Tobago was one of the most fulfilling chapters of my career. I oversaw upstream gas production and our majority share in Atlantic LNG, a cornerstone of Trinidad’s economy and the company’s LNG portfolio. This role allowed me to combine technical leadership with stakeholder engagement and geopolitical navigation. By working closely with government, community, and international partners, we helped strengthen the company’s position as a key contributor to the Caribbean country’s energy future.

Role in Shell

Currently, based in London, I lead Shell’s global exploration, strategy & portfolio organisation, an integral part of Shell’s strategy to deliver more value with fewer emissions. It’s about discovering and developing assets that can compete for capital against lower-carbon opportunities while providing secure, reliable energy the world still needs.

Meaning of diversity

Real diversity goes beyond ticking boxes. Diverse backgrounds challenge thinking, strengthen teams, and lead to better decisions. I’ve seen first-hand how leadership is enhanced when it reflects the world we live in.

Faith and family

My Christian faith is my anchor. If I were stranded on an island and could bring only one thing, it would be my Bible – without hesitation. Family is just as central to who I am. My wife, Violet, a civil engineer, is a powerhouse in her own right, currently Shell’s vice president for contracting and procurement, projects and technology. With Shell’s support for dual careers, we’ve had the opportunity to raise our two children across several continents, embracing every chapter of life together.

Legacy in motion

Energy isn’t just my career; it is woven into my family’s history. My dad helped shape Nigeria’s oil and gas sector, and over the years, several relatives – including my own daughter – have forged their own paths in an industry that powers economies and shapes lives worldwide. I believe deeply in mentorship, in the power of legacy, and in leadership rooted in values, integrity, and purpose. These principles have guided my journey.

As a child, I dreamed of becoming an astronaut. While I may not have made it to space (yet!), spending my life exploring the mysteries beneath our feet has been just as thrilling.

CROSSTALK

BY ANDREW

M c BARNET

Coming to terms with chaos

Even as we focus on our Annual meeting in Toulouse this month, it will be hard to steer clear from discussing the extraordinary impact on the political and economic world order ignited by the craziness of President Trump’s first 100 days of his second administration which he celebrated last month with a now, all too familiar, MAGA rally.

There is a clear and present threat to our geoscience and engineering community that near-term assumptions about investment in the energy sector will be disrupted, and not in a good way. The longer term is not so concerning as the fundamentals of global energy supply and demand into the foreseeable future and the inescapable need to address climate change issues remain a constant.

Not many things in this life are certain. For Benjamin Franklin (1706-1790), American founding father, diplomat and a true polymath with literary and scientific interests, it was famously death and taxes. To which these days we could add climate change. Its potential impact looms over everything we do as individuals, communities and countries. We may already be behind the clock in meeting the 2050 Net Zero targets, not even close in some people’s view, and we may also be witnessing a hopefully temporary loss of momentum due to tariff war confusion and a hangover of post Covid weariness.

acceptance speech, he stated quite unequivocally, if regretfully, that the old economic order that has basically served the world since the end of the Second World War is broken. This was a judgment that went beyond resentment at Trump’s baffling musings over Canada becoming America’s 51st state. In other words, the US under Trump is a loose cannon and no longer to be regarded as a reliable ally, trading partner, or reassuring anchor when times are tough.

‘The longer term is not so concerning’

There are some easy conclusions to draw from this drama. First and foremost is the creation of uncertainty in the workings of the world economy. Whether this plunges us into recession as a result is a moot point at this juncture. Among other things, tariffs portend higher consumer prices, supply chain disruption, reduced international commerce and slower economic activity especially for countries dependent on exports, just how seriously remains to be seen. For what it’s worth at the time of writing, the US economy had its worst quarter in three years, with GDP shrinking at the equivalent of an annual rate of 0.3%. Consumer confidence around the globe is ebbing.

Right now the analysts are having a field day elaborating endless scenarios guessing where Trump’s chaotic policy-making may lead. What is irrefutable is that governments worldwide are beyond writing off as an ‘art of the deal’ negotiating tactic the president’s unexpected, apparently limitless power to employ Executive Orders to unilaterally impose or lift tariffs on just about every country on the planet except Russia.

For example, Mark Carney, newly elected prime minister of Canada, is probably one of the sanest voices in the international financial world with experience as former governor of both the Bank of Canada and the Bank of England. In his election

If economic disarray takes hold, everyone will inevitably look to the price of oil for guidance. In advancing his ‘America First’ agenda, Trump has consistently argued for lowering the cost of oil. This makes total sense for the US as the world’s largest producer: cheaper gas prices at the pumps and lower costs for oil-dependent industries such as transport, manufacturing and agriculture should be beneficial to company profits and goods and services for consumers.

Logically, lower oil prices should provide a boost to the world economy, but historically this has not proven the case. The reasons are not that complicated. As we have seen in various crises over time, recession is likely to occur when supply outstrips demand. An oil glut is very much on the cards if tariffs do suppress demand for oil as seems likely. For example, it will not require much to burst the dam holding back oil supply. OPEC+ has been struggling to maintain discipline

in constraining production precisely because over-supply hurts those member countries which depend heavily on crude export for revenue. Any sign of recession that brings prices down is out of OPEC+ control, but it creates a situation that invites a free for all with producing countries trying to make up their revenues by increasing their volume of sales.

President Trump is already aiding and abetting a possible price collapse by pushing his ‘drill baby drill’ mantra. This may prove mission impossible, and is undeniably wrong-headed. Under his predecessor President Biden, the US reached record oil production so there may not be much room for expansion, especially, if as many speculate, the years of the shale boom may be coming to an end. It is said that making production more efficient has been the key to profitability in recent years for shale operators. The US Energy Information Administration (EIA) recently estimated that shale oil production will peak at 10 million bpd in 2027, up from about 9.69 million bpd this year, declining thereafter to about 9.33 million bpd by 2050.

Which brings us to global oil and gas investment and the price at which this is viable. According to Statista, on 28 April 2025, the Brent crude oil price stood at $64.73 per barrel, compared to $62.05 for WTI oil and $68.16 for the OPEC basket. Crude oil prices were the lowest they had been in four years following introduction or threat of widespread trade tariffs. Rystad Energy, reporting before the Trump administration took office, found that onshore Middle East was the cheapest source of new production, with an average breakeven price of just $27 per barrel. The segment also boasted one of the most significant resource potentials. Offshore shelf was the next cheapest ($37 per barrel), followed by offshore deepwater ($43) and North American shale ($45). Conversely, oil sands production break-evens averaged $57 per barrel, but could go as high as $75.

which has meddling form in the energy business, has built a 5% plus stake in bp in a campaign to have the company do more in the way of a pivoting from renewables on the basis that the Net Zero agenda imposed ‘massive costs’ and was a ‘drag on growth’.

These developments in themselves may not be too much of a setback because the energy transition does not and cannot depend on oil/energy company funding and decarbonisation initiatives. But they may reflect an escalating vocal feeling, most conspicously expressed by right of centre parties in many countries, that the proposed or actual level of public spending on tackling climate change cannot be justified.

It is an easy target for government critics because unlike long-term spending, say on a multi-year low cost housing programme, there is unlikely to be a tangible result, e.g., we will need scientists to confirm that decarbonisation is actually happening. The obvious exceptions are wind power and solar energy which are as much as about reducing electricity cost as saving the planet and do not address many of the carbon emission reduction issues or the requirement for consistent provision of power.

‘It is an easy target for government critics’

We are in a place where such hostile sentiments will likely propagate if we cannot come up with convincing counter arguments that persuade the sceptics, encourage the many who instinctively recognise the need for action if not the form it should take, and at least appease the more vehement Net Zero activists.

The problem all too familiar to the EAGE community is that there is no single solution. For instance, the article in this issue of First Break by Elodie Morgan and Camille Cosson and in the previous month by Mike Lakin and the special energy briefing for the Annual provided by S&P Global Commodity Insights, indicate that we are all working with the same data in trying to resolve the energy trilemma.

Those numbers will surely have changed simply as a result of probably quite significant increases in the cost of materials and services as a result of the inflationary pressure of tariffs. But of course industry investment sentiment also has to be taken into account. A few months ago the big oil companies were expected to maintain or marginally increase their expenditure on new production following the familiar rubric of exploiting existing or near-field reserves and engaging in areas promising predictable major hydrocarbon riches, e.g., offshore Brazil, Gulf of America, the Caribbean, offshore Namibia, etc.

The strategy may still remain in place even as oil industry profitability comes under pressure amplified by the need to meet stakeholder expectations. Crucially the strain is taking its toll on investment in the energy transition. Shell, TotalEnergies and Equinor have all pared back their commitments to focus on their main business, but without seriously abandoning the cause. As reported in the Financial Times, hedgefund Elliott Management,

If we are honest it is a tough sell. Pointing this out in the public domain has got former British Prime Minister Tony Blair into hot water in some quarters for seemingly going soft on Net Zero in support of corporate interests. The admirably comprehensive The climate paradox: Why we need to reset action on climate change published by the Tony Blair Institute for Global Change, faultlessly all the issues from technical solutions to climate justice. In his forward, Blair states the incontrovertible truth about energy transition that ‘there is no proper process in place that allows the detailed and complex policy work to be done, mandated by the few nations that can make a real difference to climate change … A new cooperative approach to technological solutions could be a galvanising next chapter – focusing political and real capital on alternative fuels and carbon-capture technology, including financing, deployment and R&D.’

EAGE members will surely say amen to that.

Views expressed in Crosstalk are solely those of the author, who can be contacted at andrew@andrewmcbarnet.com.

BGP Borehole Geophysics

Pioneering advanced borehole technology solutions

Core business areas

As a leader in borehole technologies innovation, we specialize incutting-edge borehole technologies using fiber-optical sensing techniques, delivering real-time, high-resolution insightsinto reservoir dynamics, geomechanical behavior, and fluid movement. Our solutions empower the E&P industrywith advanced monitoring and data-driven decision-making, optimizing exploration, production, and long-term reservoir monitoring—while ensuringenvironmental safety and sustainability.

VSP surveys – 3C downhole geophone array VSP and DAS-VSP surveys for high-resolution structural imaging around wellbores and formation fluid boundary mapping and tracing around wellbore.

Joint borehole-surface seismic data acquisition – Integrating surface and downhole seismic data for enhanced subsurface imaging.

Long-term reservoir dynamic monitoring – Tracking fluid changes and movements, pressure, and production effects over time.

Micro-seismic monitoring – Real-time fracture mapping and induced seismicity detection for hydraulic fracturing, oil/gas storage field and CCS/CCUS monitoring.

Downhole fiber-optical sensing deployment – Enabling highresolution downhole DAS (distributed acoustic sensing), DTS (distributed temperature sensing), and DSS (distributed strain sensing) monitoring.

Key technologies

Vertical seismic profiling (VSP):

Zero Offset VSP

Offset VSP

Walkaway / Walkaround / Walkabove VSP

3D-VSP & Time-Lapse (4D) VSP

Fracturing & geomechanical monitoring:

Micro-seismic monitoring for hydraulic fracturing

Integrated oil/gas storage &CCS/CCUS site integrity monitoring

Fiber-Optical pressure sensor interrogator: DAS & DTS Interrogator Development & Manufacturing– High-performance, ruggedized systems for downhole and surface applications.

Downhole Fiber-Optical Pressure Sensor

Joint high density and 3-D DAS-VSP data acquisition

3-components micro-seismic monitoring

Downhole deployment optical fiber

INDUSTRY NEWS

Global renewables capacity rises by record 15%

Global renewable energy capacity has increased by 585 GW in the past year, according to the International Renewable Energy Agency (IRENA)’s Renewable Capacity Statistics 2025.

A record rate of 15.1% annual growth surpasses a growth rate of 14.3% in 2023. As the cost of electricity produced from most forms of renewable power continues to fall, renewables are becoming an increasingly cost-effective power source, said IRENA.

‘2024 marks yet another benchmark in renewable energy capacity and growth. The historic expansion is strong evidence of both the economic competitiveness and the scalability of renewables, prompting a clean energy revolution that can help the world to achieve its target to triple renewable power capacity by 2030 – if challenges are addressed.’

Overall, renewables accounted for 92.5% of total power capacity expansion in 2024, up from 85.8% in 2023. Their share in the world’s total installed power capacity rose from 43% to 46.4% during the same period. Solar and wind remained key to this momentum, jointly accounting for 96.6% of net renewable expansion.

Solar energy remained the driving force behind this expansion, responsible for 42% of the total global renewable power capacity mix. The solar sector alone grew by 32.2%, adding almost 452 GW to reach a total capacity of 1865 GW worldwide. Solar photovoltaic (PV) tech-

nology accounted for virtually all solar capacity growth, demonstrating its continued cost-effectiveness and scalability, said IRENA. In 2023 the global weighted average cost of electricity from new solar PV projects dropped by 12%, the steepest decline among major renewable sources.

Regional disparities in renewable energy capacity deployment intensified

tions decline from 1.1 GW in 2023 to just 0.7 GW in 2024. Africa’s capacity grew by only 4.2 GW and the Middle East by 3.3 GW.

Despite a record growth rate, progress still falls short of the 11.2 terawatts needed to align with the global goal to triple installed renewable energy capacity by 2030, said IRENA. If the current

from 2023 to 2024, with Asia strengthening its dominance from 69.3% to 72% of global additions at 421.5 GW. China alone accounted for more than 88% of Asia’s increase. By contrast, Central America and the Caribbean contributed the least with only a 3.2% share of the global addition, while the Small Island Developing States saw their contribu-

growth rate persists, the world will be approximately short 0.8 TW by 2030. Achieving the target now requires an annual growth rate of 16.6% until 2030, it added.

IRENA called for more ambitious renewable energy targets in the next round of the Nationally Determined Contributions (NDCs).

TGS expands Mauritania

Indonesia awards oil and gas contracts

OWIC plans to regulate underwater noise

Wind, along with solar, accounted for 96.6% of net renewable expansion.

TGS expands offshore Mauritania 3D data

TGS has significantly expanded its multi-client data library offshore Mauritania, with the addition of more than 101,500 km2 of 3D seismic data.

The expansion adds to the existing library of more than 19,000 km2 of reprocessed PSDM 3D seismic data and multiple regional 2D seismic surveys. Together, these integrated datasets provide a more comprehensive and nuanced view of the subsurface, helping to refine known plays while revealing new exploration opportunities, said TGS.

‘Early insights are emerging through the combination of regional geological knowledge and detailed mapping of trap trends, spanning from shelf-edge wells to deeper outboard fairways,’ the company added. ‘Notably, evidence of Late Cretaceous channel-fan systems within the basin domain is providing a fresh perspective into the region’s hydrocarbon potential.’

Mohamed Ould Khaled, the Mauritanian Minister of Energy and Petroleum, said: ‘With the extension of our offshore data library with new 3D seismic data, Mauritania is opening the door to a new era of

energy exploration. Our rich, underexplored basins and stable investment climate make Mauritania one of the most exciting frontiers for oil and gas. We are ready to work hand in hand with international partners to unlock this immense potential and deliver long-term, mutually beneficial growth.’

David Hajovsky, executive vice-president of multi-client, TGS, said: ‘Aside

from greatly expanding the quantity of high-quality multi-client subsurface data in West Africa, the true value of this extensive regional study lies in its ability to contextualise borehole data across the area. By re-evaluating historical exploration results exploration teams are better equipped to derisk future ventures and make informed investment decisions.’

Indonesia awards five oil and gas contracts

Indonesia has announced the winners of the Direct Bidding Auction for Phase II of Oil and Gas Working Areas (WK) in 2024, consisting of WK Kojo, WK Binaiya, WK Serpang, WK Gaea and WK Gaea II.

Etan Fleet Ltd has won the Kojo area and will do a G&G study and acquire and process 500 km2 of 2D seismic data.

A consortium of PT, Pertamina Hulu Energi, PC North Madura II, and SK

Earthon Co have won the Binaiya area and will carry out a G&G study along with acquiring and processing 400 km2 of seismic data.

A consortium of PC North Madura II, Inpex, and SK Earthon has won the Serpang area and will carry out a G&G study along with acquiring and processing 400 km2 of seismic data.

A consortium of Enquest, PT Agra Energi, bp, MI Berau, CNOOC, ENEOS Xplora, Indonesia Natural Gas Resources Muturi, and KG Wiriagar has won the Gaia area and will carry out a G&G study along with acquiring and processing 150 km2 of seismic data.

A consortium of Enquest, PT, Agra Energi, bp, MI Berau, CNOOC, ENEOS Xplora, Indonesia Natural Gas Resources Muturi Inc and KG Wiriagar has won the Gaea II area and will carry out G&G studies along with acquiring and processing 100 km2 of seismic data.

The five winners winning consortiums have pledged to invest a total of $21.7 million for the first three years of the exploration period.

‘In the last 4 years, since the oil and gas working area tender with more attractive terms and conditions, 24 new Cooperation Contracts have been signed,’ said Tri Winarno, Indonesia’s acting director general of Oil and Gas.

The country’s Ministry of Energy and Mineral Resources has pledged to support increased oil and gas production by optimising technology, including horizontal multi-stage fracturing and the implementation of enhanced oil recovery (EOR).

The second strategy is reactivation of idle wells and fields and thirdly the government will conduct massive exploration. In the next two to three years, around 60 oil and gas work areas will be prepared.

TGS multi-client library offers a comprehensive view of the subsurface offshore Mauritania.

US develops new oil and gas programme

The US Bureau of Ocean Energy Management is developing a new schedule for offshore oil and gas lease sales on the US Outer Continental Shelf.

BOEM will soon publish in the Federal Register a Request for Information and Comments on the preparation of the 11 th National OCS Oil and Gas Leasing Program. This publication will initiate a 45-day public comment period and serve as the initial step in the multi-year planning process.

A new planning area offshore Alaska – the High Arctic – is being established as the 27th OCS planning area. Additionally, boundaries of other existing planning areas are being updated to align with BOEM’s revised jurisdiction.

Once finalised, the 11 th National OCS Program will replace the current 10th Program (2024-2029), which includes just three lease sales over five years – all located in the Gulf of America.

As of 1 April 2025, BOEM manages 2227 active oil and gas leases covering approximately 12.1 million acres in OCS regions. Of these, 469 leases are currently producing oil and gas.

In fiscal year 2024 alone, production from OCS leases accounted for approximately 14% of domestic oil production and 2% of domestic natural gas production, yielding $7 billion in federal revenues.

BOEM’s most recent assessment estimates a mean of 68.79 billion barrels of undiscovered oil and 229.03 trillion cubic feet of natural gas.

Earlier this year, the Trump administration reaffirmed its commitment to offshore energy development with Executive Order 14154, ‘Unleashing American Energy,’ to ‘encourage energy exploration on federal lands and waters including the Outer Continental Shelf’.

PXGEO appoints Chuck Davidson as executive chairman

PXGEO has appointed Chuck Davison, Jr as executive chairman and chief executive officer.

Davison Jr brings more than 30 years’ experience in growing and modernising international energy businesses and particular expertise in subsea technologies, services and products. His previous roles include chief operating officer at Oceaneering International and chairman of Magseis Fairfield.

He also held the position of chairman and CEO at Fairfield Geotechnologies, leading a major turnaround and transformation of the company.

In parallel to his new role at PXGEO, Davison Jr will continue to lead EnerMech, a technical solutions company for the energy industry, which shares the same shareholder as PXGEO.

As part of the transition, founder Peter Zickerman will continue as PXGEO

vice-chairman and chief development officer, and will continue to serve on the board.

Meanwhile, PXGEO has expanded its subsea offering with the acquisition of Modus Subsea Services, a provider of offshore life-of-field support services specialising in autonomous subsea operations using Underwater Intervention Drones (UID) based on the Saab Sabertooth platform. The company has also developed and commercialised the industry’s first-ever UID subsea residency solution.

‘PXGEO and Modus Subsea Services will leverage their respective technological expertise and enhance their subsea autonomous offerings to provide their customers with a range of benefits, including increased efficiency, reduced exposure, and a lower environmental footprint,’ said PXGEO in a statement.

The UK North Sea oil and gas joint venture between Shell and Equinor will be headquartered in the Silver Fin building in Aberdeen city centre. With Shell and Equinor each holding a 50% stake, the joint venture will take over stakes of Equinor’s Mariner, Rosebank and Buzzard fields and Shell’s Shearwater, Penguins, Gannet, Nelson, Pierce, Jackdaw, Victory, Clair and Schiehallion fields.. It will be the UK’s largest independent producer.

US natural gas production remained relatively flat in 2024, growing by less than 0.4 billion cubic feet per day (Bcf/d) compared with 2023 to average 113 Bcf/d, according to the US Energy Information Administration. Production growth in the Permian was offset by declining production in the Haynesville and relatively flat production in Appalachia.

Eni has reported first quarter operating profit of $4.2 billion, net profit of $1.6 billion, and adjusted cash flow of $3.9 billion. Gross capex was $2.2 billion.

Exxon Mobil has agreed with Calpine Corporation to transport and permanently store up to 2 million metric tons per annum (MTA) of CO2 from Calpine’s Baytown Energy Center near Houston. This is part of Calpine’s Baytown Carbon Capture and Storage (CCS) Project that is designed to capture the facility’s CO2 emissions, enabling the 24/7 supply of low-carbon electricity to Texas customers as well as steam to nearby industrial facilities.

In response to President Donald J. Trump’s declaration of a ‘National Energy Emergency’, the US Department of the Interior is implementing emergency permitting procedures to accelerate the development of domestic energy resources and critical minerals. These measures are designed to ‘expedite the review and approval of projects related to the identification, leasing, siting, production, transportation, refining, or generation of energy within the United State’s. The new permitting procedures are designed to take a ‘multi-year process’ down to 28 days.  BRIEFS

UK’s First CO2 injection test takes place at the Poseidon project in the North Sea

Perenco, Carbon Catalyst and Harbour Energy have conducted the UK’s first offshore CO2 injection test at the Poseidon project in the North Sea. The project involved injecting liquid CO2 into a heavily depleted North Sea gas field, achieving injection rates above 1 million tonnes per annum (Mtpa).

‘This technical feat wasn’t just an operational success — it was a critical derisking milestone for both the Poseidon project and the broader CCS industry, providing concrete evidence that repurposing the UK’s mature offshore infrastructure for CO2 storage is not only possible, but commercially viable,’ said the project partners.

The Leman gas field, the UK’s largest legacy gas field, located at the southern edge of the Southern North Sea (SNS), has produced over 14 trillion cubic feet (Tcf) of gas. Leman now has an estimated storage capacity of 1 billion tonnes of CO2.

‘Sitting within reach of some of the UK’s major emission hubs — including London and the South East — Poseidon is also ideally positioned to receive CO2 from Europe’s industrial corridors, such as the German Rhine Valley, the Netherlands, Belgium and Northern France,’ said the partners.

Over a three-month trial, the team executed a rigorous CO2 injection programme into the Leman H fault panel, utilising the Leman Hotel unmanned wellhead platform and a previously suspended gas well.

The goals of the injection test were to generate hard data on the viability of storing CO2 in offshore depleted gas reservoirs at commercial rates of injection; confirm the potential for repurposing existing infrastructure, from topsides to well completions, for cost-effective CCS deployment; introduce advanced Measurement, Monitoring, and Verification (MMV) technologies capable of tracking CO2 flow, pressure changes and well integrity; demonstrate stable CO2 injection at scale across gas, super-critical and liquid phases; test the boundaries around the CO2 fluid properties and behaviour as it flows from well head to bottom hole and then into the geological store; and assess the operability of the system and its capacity to maintain liquid-phase injection at Mtpa levels.

A total of 4000 tonnes of food-grade CO2 was sourced from Air Liquide’s Netherlands facility. From there, it was shipped across the North Sea via the Atlantic Carrier supply vessel to Petrodec’s ERDA jack-up rig, which had been outfitted with a CO2 injection package including 24 cryogenic ISO tanks. These 20-ft tanks enabled the controlled injection of 400-ton liquid CO2 batches into the reservoir via the adjacent wellhead.

‘This complex setup not only enabled continuous, high-rate injections but also tested the practicality of offshore liquid-phase transport and storage — key learnings for future commercial deployment,’ said the partners.

The partners secured the first CO2 well test consent from the North Sea Transition Authority (NSTA) and Offshore Petroleum Regulator for Environment and Decommissioning (OPRED).

Poseidon’s MMV programme included Vertical Seismic Profiling (VSP) using Distributed Acoustic Sensing (DAS), passive seismic monitoring, and seabed DAS via telecom cables already laid on the seabed. ‘These techniques aimed to understand the capabilities of geophysics to track the pressure front as it moved through the reservoir, providing real-time insights into CO2 migration and model conformance — crucial for long-term storage safety and regulatory compliance,’ said the partners.

More than 15 full injection cycles were executed with stable injection achieved across all CO2 phases — gaseous, super-critical, and liquid. Commercial-scale injection rates of 1 Mtpa were achieved, limited only by topside facility constraints.

‘The results point to a viable commercial case for repurposing depleted reservoirs,’ said the partners.

Test data will be integrated into the front-end engineering design (FEED) for a commercial-scale development. Meanwhile, discussions continue with the UK Government on an appropriate business model. A CCS storage permit application is expected in 2026, with a Final Investment Decision (FID) targeted for 2027. First injection is slated for 2029.

US increases estimate of oil and gas reserves in the Gulf of America

The US Department of the Interior has significantly increased its estimated oil and gas reserves in the Gulf of America Outer Continental Shelf.

The Bureau of Ocean Energy Management’s analysis reveals an additional 1.30 billion barrels of oil equivalent since

2021, bringing the total reserve estimate to 7.04 billion barrels of oil equivalent. This includes 5.77 billion barrels of oil and 7.15 trillion cubic feet of natural gas – a 22.6% increase in remaining recoverable reserves.

BOEM’s updated assessment evaluated over 140 oil and gas fields, identi-

fying 18 new discoveries and analysing more than 37,000 reservoirs across 1336 fields in the Gulf. The review added 4.39 billion barrels of oil equivalent in original reserves, up from the previous estimate of 3.09 billion barrels of oil equivalent.

OWIC launches measures to regulate underwater noise in the North Sea

The Offshore Wind Industry Council (OWIC) has set out measures to ensure that the management of underwater noise is co-ordinated more effectively among key industries operating in the North Sea.

The Underwater Noise Conflict Resolution Framework Report highlights the evolving variety of seabed users working under different regulatory regimes to deliver offshore wind, oil and gas and carbon capture and storage projects. Activities include conducting underwater surveys, installing foundations for wind turbines and dealing with unexploded bombs on the seabed.

Measures to conserve marine wildlife are in place in some areas; for example, the southern part of the North Sea is a Marine Protected Area to safeguard harbour porpoises which are sensitive to sound, said OWIC. ‘Government regulators, nature conservation bodies and marine industries already work together to manage any noise impacts and to ensure that noise is kept within agreed limits –but there is a need to plan ways forward should government thresholds lead to some projects not being able to carry out activities at the same time,’ OWIC.

The report puts forward proposals for a co-ordinated framework to support closer co-operation and forward planning of different activities to avoid noise limits being exceeded, as well as a new decision-making process through which

scheduling conflicts can be resolved quickly. ‘The fact that a transparent arbitration process is currently lacking is a key concern for offshore industries as this risks delays to crucial offshore projects,’ said OWIC.

Environment and consents manager Juliet Shrimpton, said: ‘Marine industries work hard to ensure that rigorous underwater noise limits are adhered to, but we need to improve the way that different industries work together, supported by regulators and nature conservation bodies, so that activities can be co-ordinated more effectively. Critically, we need to ensure that if conflicts arise, these can be resolved through a transparent, fair and timely process.’

OWIC’s environment and consents workstream sponsor Benj Sykes, Ørsted UK country manager, said: ‘Initiatives like this are important to ensure that we continue to roll out new projects sustainably, and avoid delays so that we can generate economic growth by accelerating the deployment of vital new clean energy infrastructure whilst ensuring we take proper care of the marine environment. This will also help to enable us to stay on track to meet the government’s target of clean power by 2030.’

The Underwater Noise Conflict Resolution Framework Report was produced by Xodus Group, commissioned by the Offshore Wind Industry Council.

Equinor has halted offshore construction in the outer continental shelf for the Empire Wind project. On 16 April, the US Bureau of Ocean Energy Management (BOEM) ordered Empire to halt all activities until it has completed its review. Empire is considering appealing the order. The federal lease was signed in 2017. Empire Wind 1 has secured all necessary federal and state permits and has a gross book value of around $2.5 billion.

KBR is partnering with Neptune Energy to produce battery-grade lithium carbonate (Li2CO3) from gas field brine at the Altmark site in Germany, utilising KBR’s proprietary PureLi refining and conversion technology.

Energiequelle has received planning consent for its Oulu Green Hydrogen Park project in Finland. The first phase includes construction of a hydrogen production plant with a maximum capacity of five MW and a hydrogen refuelling station for buses and heavy commercial vehicles.

Öresundskraft Kraft & Värme AB and INEOS have signed an agreement to store up to 210,000 tonnes of CO2 annually from Sweden in Denmark. The captured carbon dioxide is planned for permanent storage in Greensand facility in the Danish part of the North Sea, with the first volumes to be stored from 2028.

Denmark has awarded Norne Thorning Storage an exploration licence for the Thorning structure as a site for carbon capture and storage. Norne will gather the necessary information about the structure to evaluate and confirm its suitability for safe and permanent CO2 storage.

Block Energy has announced Phase 2 of its CCS project in Georgia including pilot injection of CO2 into the Patardzueli Middle Eocene reservoir, to prove mineralisation and permanent storage of CO2. Analysis of Middle Eocene reservoir rock samples suggest the reservoir is suitable for CO2 mineralisation at depths shallower than forecast.

Two porpoises close to Tobermory Bay offshore Scotland.

Global rig utilisation falls to lowest level since 2021

Utilisation in the offshore rig market has hit the lowest levels recorded since 2021, according to research by Westwood Insight. Factors include Saudi Aramco’s suspension of more than 30 jackup contracts by up to one year, the entry of new-build rigs into the market without work to go to, and the deferment of several long-term deepwater drilling and plug and abandonment projects.

The combination of a dip in firm demand (currently 18% lower than March 2024) and an increase in supply (7% higher than March 2021), has led to a fall in marketed utilisation to 88% – representing a 6% drop in less than two years.

With Westwood predicting utilisation of the combined jackup, semisub and drillship segments to fall further this year to

Oil

and gas round-up

Reconnaissance Energy Africa (ReconAfrica) has agreed a joint exploration project in Angola with the National Oil, Gas and Biofuels Agency (ANPG). The partners will jointly explore a project in the Etosha-Okavango basin, located onshore in southeastern Angola.

Eni and YPF have signed a Memorandum of Understanding (MoU) to evaluate Eni’s participation in the Argentina LNG project, promoted by YPF and designed to develop the resources of the ‘Vaca Muerta’ onshore gas field.

bp and Chevron have made an oil discovery at the Far South prospect in the deepwater US Gulf of America. It drilled the exploration well in Green Canyon Block 584, located in western

around 85% – it seems likely that more rigs could permanently be removed from the active drilling fleet as the year progresses, said Westwood.

Year to date, nine rigs have been confirmed for removal from the active fleet. These consist of four jackups – owned by Shelf Drilling, White Fleet Drilling and Well Services Petroleum – and three 8500-series semisubs owned by Valaris, all of which were under 15 years old. Additionally, Noble confirmed the disposal of two modern S12000-design, ultra-deepwater drillships that it inherited during its acquisition of Pacific Drilling – one of which never drilled a single well and was just 10 years old.

For jackups, 39 of these units are cold stacked and 19 are warm stacked (seven of these for over a year). Eight of these warm assets do not have a valid SPS in place and three more will expire this year or next if not renewed. Most of the units included in Westwood’s analysis are located in the Middle East, India or US waters, with Shelf Drilling and Enterprise Offshore owning most of these rigs.

‘To sum up, due to the reduction in jackup, drillship and semisub demand and utilisation this year, more assets will be moved to cold stack due to not having follow-on commitments in place,’ said Westwood. ‘These factors we believe will spur further older, idle and surplus assets to be removed from the fleet, which in the long run may help to set the stage for a stronger recovery in utilisation from the second half of 2026 onwards, when Westwood expects to see a rebound in demand.’

Green Canyon approximately 120 miles off the coast of Louisiana in 4092 feet of water. The well was drilled to a total depth of 23,830 feet. The Far South co-owners are bp (operator, 57.5%) and Chevron (42.5%). Both the initial well and a subsequent sidetrack encountered oil in high-quality Miocene reservoirs. Preliminary data supports a potentially commercial volume of hydrocarbons.

Pantheon Resources has announced strong flow rates from a well testing programme at the Kodiak and Ahpun oil fields on Alaska’s North Slope. The Megrez-1 well was fracture stimulated in the Topset 1 reservoir interval over some 290 ft from 7165 ft to 7453 ft MD. Preliminary analysis indicates that although the reservoir is

oil bearing, it appears to be in a transition zone with limited to no mobile oil and gas. Technical data gathered increases confidence in the productivity and hydrocarbon potential of the intervals higher in the wellbore and indicates mobile oil will be found in the shallower stratigraphic sequences.

Petronas and Beicip Franlab Asia have embarked on an Integrated Basin Study to explore untapped resources in the Malay Basin, located off the coast of Peninsular Malaysia. The study is deploying advanced 4D modelling and machine learning technologies to analyse the subsurface architecture at both basin and reservoir scales. It also focuses on predicting hydrocarbon migration and entrapment by harnessing big data from the Malay Basin.

Offshore Rig Attrition by Type & Annual Marketed Utilisation (2013-2025YTD).

Source Westwood RigLogix.

Detection of CO2 distribution by seismic pulse width analysis using mollifier functions

F. P. L. Strijbos1*

Introduction

Abstract

The relative contribution of buoyancy to dissipative forces that characterise CO2 flow can significantly impact the capacity of a geological storage site. For example, a smaller contribution of the buoyancy forces due to limited density variation with depth will cause the plume to spread out more laterally.

With CO2 being injected in supercritical thermodynamic conditions, close to the critical point, thermodynamic models support that its diffusion within the formation will create a plume with acoustical properties that vary gradually. Such impedance profiles (not limited to linear ramps) generate so-called transitional reflection responses. We describe a method to detect and analyse such transitional reflections based on the analysis of reflection pulse width performed using basis functions called mollifiers.

This method performs well on a synthetic dataset. When we apply this technique on the Sleipner data it detects anomalies at locations where previous publications have observed or inferred CO2 chimneys. This study introduces a novel approach to identifying transitional reflection responses in CO2 storage sites, demonstrating its effectiveness in detecting anomalies that were previously observed or inferred, thus providing a new tool for monitoring and assessing geological storage sites.

The monitoring objectives for the storage of carbon aim to identify the subsurface distribution of the CO2 plume (International Organization for Standardization, 2017). The way injected CO2 distributes itself after injection has a significant effect on this storage capacity. For example, if buoyancy dominates due to large density variations, CO2 will migrate upwards in a narrow cone and a smaller volume will contain residually trapped CO2

(Ringrose et al., 2017). If due to heat loss the supercritical fluid becomes more viscous, CO2 spreads out before getting trapped and residual CO2 remains in a larger volume.

Equation of state plots of CO2 show that density and velocity change very rapidly near the critical point (van der Meer, et al 2009). We can use this sensitivity of density and velocity to temperature and saturation to monitor the movement of CO2 provided these changes can be resolved within the available

1 TASK G&EO

* Corresponding author, E-mail: floris.strijbos@gmail.com DOI: 10.3997/1365-2397.fb2025040

Figure 1 Density r, viscosity m and p-wave velocity Vp distribution for several thermodynamic models using the equation-of-state published by Span and Wagner (1996). The density change over viscosity ratio determines with some proportionality constant C the dynamic behaviour of the CO2 plume.

seismic bandwidth. Fawad and Mondol (2022) model the impact of CO2 fluid properties on acoustic impedance and Vp/Vs ratio which can be used for seismic monitoring. Figure 1 shows the behaviour of density and velocity as a function of depth for several thermodynamic models. The constant gradient model assumes that injection doesn’t affect the formation temperature. The local dissipation model has temperatures dropping slowly away from the injection point. The isothermal model is an extreme model where temperature remains high throughout the CO2 plume. The hydrostatic model ignores any effect of the changing CO2 density r within the plume. These curves have been calculated using the Span and Wagner (1996) equation of state for CO2. The ratio of CO2 density r over viscosity m shown in the last track characterises the CO2 flow (De Paoli et al., 2022). We expect the heat transport of injected CO2, or the movement of CO2 leaving a wake of residually trapped CO2, to yield gradual changes in acoustic properties. The dynamic behaviour thus can be observed if we can accurately determine the plume shape and the impedance variations within the plume itself. Impedance may, however, vary too slowly to detect using conventional interpretation techniques. Our novel method treats gradual impedance changes as a transitional reflection response, such that slow variations can be detected better.

Wolf (1937) derived an analytical solution for the normal incidence reflection response of a linear velocity transition zone, a so-called ‘Wolf Ramp’.

O‘Doherty and Anstey (1971) show that reflection by a layered sequence with a ‘transitional’ impedance variation, i.e., strictly increasing or decreasing, is frequency dependent. Liner and Bodmann (2010) use this frequency dependence to detect transitional impedance variations with spectral decomposition. Their method assumes that impedance varies linearly within the transition zone (Wolf ramp) and relies on detecting corresponding interference patterns that are difficult to detect due to the reduced temporal resolution of the spectral decomposition method. An improved temporal resolution could be achieved using wavelet-based decomposition, preferably using a basis that is well suited to seismic data and this task.

In this paper, we present an alternative method based on a decomposition of the seismic data using functions known as mollifiers. The parameter that scales these functions can be derived from the reflection pulse width. We will further detect transitional

responses (not limited to linear ramp profiles) using this method and will test this technique on a finite difference synthetic data set. Then, we apply this technique on the seismic data recorded in 2010 over the Sleipner injection site to analyse possible CO2 distribution.

In this paper we restrict ourselves to normal-incidence modelling and apply this to the interpretation of Sleipner near-stack data.

The

normal incidence response of a transition zone

Liner and Bodmann (2010) and Kwietniak et al. (2021) have used the Wolf Ramp analytical solution to interpret transition zones associated with lithological changes. For this they use spectral decomposition techniques. These lithological changes or impedance changes due to CO2 injection may, however, not result in a purely linear trend as a function of depth or time. Amundsen and Ursin (2023) provide an analytical solution to a gradient interface described by a smoothed Heaviside function which results in a frequency response that is quite different from the Wolf ramp response. We will see that the exact functional shape of a transition has indeed a large impact on its frequency response.

In order to understand both the impact of discretisation interval and slope we compare the analytical expression for the Wolf ramp to sigmoid-shaped profiles calculated with the recursive Green’s function technique. The mollifier functions that we will introduce in the next section to represent reflections from a transitional zone integrate to a sigmoidal function. The parameterisation of an impedance ramp and the parameterisation representing its reflection are thus related. In Figure 2 we show the results for a range of discretisation intervals and different slopes. Each sigmoid is parametrised with a scale factor a which determines the slope and the discretisation interval ∆z. The Wolf ramp and the sigmoid transition calculated with a 5-metre discretisation step show a polarity flip which is not present for the other curves. Similar behaviour has been modelled and experimentally verified in a classic paper by Schoenberger and Levin (1974). More recently Amundsen and Ursin (2023) provide an analytical solution that confirms the loss of high frequencies. We explain this loss of high frequencies as follows: with an increasing number of layers and decreasing slope, the reflection coefficients drop. Furthermore, a smooth transitional shape causes the (larger)

Figure 2 The reflection response for several velocity models (left). The corresponding amplitude- and phase response (right). Parameter ‘a’ is a scale factor that determines the steepness of a sigmoid model. ∆z is the layer thickness and ∆t is the delay applied to the phase.

Figure 3 Two mollifier functions with scaling parameters 0.1 (blue) and 0.03 (red). The difference between these mollifiers (black curve) form a bandpass filter.

number of multiples to spread out in time. This timing variation acts as a high-cut filter.

The sigmoid with a 0.01 metre step and a factor equal to 100 shows in Figure 2 a flat spectrum and a constant 180 degrees phase response related to the polarity of the impedance contrast. The remaining functions all show an amplitude decay that is nearly linear on a logarithmic scale. The linear trends related to the time arrival time differences have been removed to facilitate comparison of the phase spectra. There is a small non-linear component as the ramp is defined in depth and its time domain equivalent therefore is skewed somewhat. The strong amplitude decay corresponds in the time domain to a broadening of the seismic reflection. This broadening provides a means to detect a transition response for example due to formation density and velocity changes upon injection of CO2 from variation in its pulse width.

Pulse width analysis

In this section we will describe how we can use pulse width to approximate reflections by a family of functions called ‘mollifier functions’. Mollifiers are smooth functions that can approximate non-smooth functions to an arbitrary smoothness or scale via convolution. Such a non-smooth function could be a ramp or its derivative convolved with a short wavelet. We replace the typical convolutional model for seismic data as a series of reflections or spikes convolved with a wavelet, by a convolutional model consisting of a series of spikes convolved with the difference of two mollifiers. These two mollifiers are a scaled and dilated version of each other. This convolutional

model has the advantage that each function separately provides a representation of the earth reflectivity at a different scale (e.g., see Strijbos, 2024).

The mollifiers are parameterised by a scale parameter that relates to its pulse width. We define the pulse width as the time between the extrema of the wavelet derivative. We find that in the presence of noise a more stable pulse width is estimated from the extrema of a 90° rotated trace.

Each mollifier corresponds to a high-cut filter and the difference of two mollifier represents a band-pass filter. A simple illustration of such an approximation is shown in Figure 3. The blue curve corresponds to a coarse scale representation of the seismic data. The red curve is associated with the fine detail. The difference of the two curves creates a wavelet with an approximately 7-35 Hz bandwidth (black curve).

A decomposition of the data into the two mollifiers allows us to identify changes to the bandwidth of the data as a pulse width change. We start from the functional form for a mollifier:

(1)

where τ denotes the scale parameter. It is a requirement for a mollifier function that as this scaling factor goes to zero, the function approximates a delta function.

At each spike location t0 we establish the spike amplitude R(t = t0). Figure 4 illustrates the pulse width analysis. A 7-35 Hz bandpass filter (blue curve) represents the reflection to be approximated. The pulse width DT is measured between the extrema of the 90° rotated data (red curve). From DT we can calculate the scale parameter τ0. For this we use the roots of the 2nd derivative of the equation describing the Gaussian Mollifier,

to derive the relationship between the scale parameter and pulse width:

τ1 is assumed to be a fixed parameter determined by the lower frequency limit of the data. That this is justified for a transitional response can we see from the low frequency behaviour shown in Figure 2.

Scale parameter τ relates to the high-cut frequency of the mollifier function: (4)

Equations (3) and (4) are used to determine the scale factors from the pulse width and the low-cut frequency of the data. A mollified version of R(t) at a larger (i.e., ‘coarser’) scale τ1 can be created by convolution of the reflection series with the corresponding mollifier function: (5)

Figure 4 A 7-35 Hz Butterworth filter (blue). The pulse width is picked as the peakto-trough time difference on the 90 rotated Butterworth (red). Equations (3) and (4) are used to determine the scale factors from the pulse width and the low-cut frequency of the data. The difference between the corresponding 0.033 mollifier and a fixed 0.065 mollifier (black) approximates the Butterworth filter.

The denominator ensures that the difference of the two mollified traces preserves the amplitude of the input trace. The black curve shows the resulting approximated data.

A decomposition of the data using mollifiers and pulse width analysis can be done in three ways. First, we can use the pulse width analysis to estimate the fine scale mollifier at each spike location and create a separate trace with a coarse scale mollifier at each spike location honouring the amplitude relationship expressed in Equation (5). Alternatively, we can create a coarse scale volume by convolving the fine scale mollifier volume with the coarse scale mollifier. Or, if we have a good signal-to-noise ratio we can subtract the fine scale mollifier from the input data. An overview of the various steps is given in Figure 5.

We demonstrate the first decomposition method using a simple finite difference synthetic. The first track in Figure 6 shows two sigmoidal velocity depth profiles stretched to time. We create from these models finite difference synthetics using two mollifiers: a Gaussian mollifier with a fine scale (0.0025) and one with a coarse scale (0.02). Track 2 shows the difference of these two models which results in a bandlimited wavelet. The corresponding synthetic data in tracks 3 and 4 show an incident wave followed by a reflection from the velocity ramp. Compared to the first arriving incident wave the reflection from the ramp has lost high frequencies. The smoother reflection for profile (B) results in more high-frequency loss.

Note that the traces in tracks 3 and 4 are multiplied by their corresponding scale parameter to see the relative error between reference and inverted traces. We invert the traces in the 2nd track using steps described in Figure 5.

The coarse scale shows a difference for the less steep velocity profile only. For equation (5) to be valid the reflection response should be white, but as we have seen in Figure 2 this is not the

Figure 5 Flowchart detailing spectral shaping, pulse width analysis and mollifier decomposition steps. The letters between brackets correspond to the Figure 9 subfigures.

Figure 6 Finite difference modelling showing velocity models for two ramps labelled (A) and (B). These ramps are sigmoidal in depth but become asymmetric as a function of time (left). The receiver is placed between the source and the ramp. Track 2 shows the models created by combining the individual synthetics shown in tracks 3 and 4. These combined models are inputted to the inversion. The incident wave arrives first at about 0.7 seconds. The ramp reflection arrives at about 1.7 seconds. For both models the forward model and inverted data for a 0.0025 and 0.02 Gaussian mollifier are shown in tracks 3 and 4.

case for a transitional response and as a consequence the amplitude of the coarse scale mollifier is over-predicted. We will utilise this overprediction to identify transitional reflections.

In the next section we will apply these methods to the 2010 Sleipner near-stack seismic data.

Sleipner 2010 data pulse width analysis

At the Sleipner site CO2 is injected at near critical conditions into sandstones of the shallow Utsira formation. The thermodynamic modelling discussed in the introduction shows that under these conditions a transitional impedance change may develop. The monitoring of the actual seismic response has been done at a two-to-three-year interval since injection started in 1996. 4D seismic data have been released for the timelapse vintages up to 2010. This data release has resulted in an extensive range of publications that discuss the interpretation of the developing Sleipner CO2 plume. In this paper we focus on the 2010 monitor dataset, where we expect the plume to be well developed and to have a strong velocity sag visible. We will not use any 4D difference data: without an accurate correction for the sag interpretation of 4D difference (time) data is particularly difficult in the lower-level part of the plume.

Several authors have observed vertically aligning discontinuities in reflection strength (e.g. Arts et al., 2004; Williams and

Chadwick 2021; Furre et al. 2019, 2024). These discontinuities are assumed to be ‘CO2 chimneys’ where a whole reservoir column is filled with a high CO2 concentration. Figure 7 shows the relative impedance seismic data of a weighted stack of the 2010 near- and mid-stack offsets. The chimneys were not visible on the full- and far stacks. Along this inline Williams and Chadwick (2021) identified three ‘putative chimneys’. The locations of these chimneys are indicated by the black arrows. ‘Chimney 1’ shows a narrow, transparent and near-vertical anomaly confined to a couple of traces in any direction we look. Indeed, some reservoir models made for CO2 injection (e.g., Wen and Benson, 2019) show the highest saturation in a near-vertical zone above an injection point combined with a wider cone with lower saturations expanding out horizontally. ‘Chimney 2’ is directly overlain by a shallow amplitude anomaly which even creates a small velocity sag of its own. ‘Chimney 3’ doesn’t show up on this display.

Furre et al. (2019) interpret several other chimney locations based on the location of the earliest appearance of 4D anomalies. They denote these as ‘invisible feeder chimneys’.

A full waveform inversion scheme based on a cost function calculated from time shifts between recorded- and synthetic data is used by Martinez et al. (2024) to build a detailed image. Their result highlights a ‘source feeder’ and several additional chimneys.

In this paper we apply the method described in the previous section in several steps:

• The average autocorrelation function of the data showed some residual multiple energy which could be effectively suppressed by subtracting a scaled and shifted version of the input data.

• We use the wireline logs of well 15/9-13 to create a normal incidence synthetic. As the sonic and density logs for this well are of poor quality, we replace the density log by a pseudo-log using the empirical relationship between porosity, velocity and shale content derived by Han et al. (2012).

• The amplitude spectrum of the data is then shaped to be consistent with the global reflectivity observed in the well logs (‘spectral blueing’).

Figure 8 A comparison between the 15/9-13 relative impedance synthetic and the 2010 inverted near stack data. The synthetic is created using a 90 rotated 3-70 Hz Butterworth filter.

Figure 7 The relative impedance of a weighted stack of the 2010 near- and midstack data. Along this line Williams and Chadwick (2021) identified three ‘putative chimneys’. The black arrows indicate the interpreted chimney locations.

• We invert the 2010 near stack data using the sparse spike inversion scheme described in the previous section.

Figure 8 shows a comparison between the synthetic trace and the inverted seismic data represented by the difference of the two mollifiers. The match is good across the Utsira section and this validates the inversion. Very little contrast is visible in the lower Utsira section, suggesting a more homogeneous formation. Traditionally the Sleipner Utsira reflectors are numbered 1 to 7 based on spikes observed in the gamma ray log. In Figure 8 we can see that these spikes are very thin and below seismic resolution. The loops that can be observed in the synthetic correspond to wider zones of increased gamma ray values. We label these high impedance loops ‘5B’, ‘7B’, ‘8B’ as they don’t exactly coincide with the gamma ray spikes. Based on the observed response in Figure 8 we can divide the Utsira plume into two zones: An upper zone where the presence of potential seals or net-to-gross variations can create a cyclic reflection response. The lower zone

Figure 9 A comparison of the two lower octaves (a) with the two highest octaves (b) along the trajectory of well 15/9-A16. An overlay of pulse width (c) over a backdrop of the full bandwidth impedance also shown in (d) The inversion mollified in 3D using a 5-point Gaussian and a 0.144 ms Gaussian function corresponding to an equivalent frequency of about 7 Hz (e). This Gaussian is calculated from the observed spike amplitude and its pulse width. The full bandwidth result filtered back to approximately the same bandwidth (f).

is more homogeneous and slower changes of acoustic properties have the potential to create a transition reflection response. The loop below level 5B is much broader than the overlying levels and this may indicate a transitional reflection. Alternatively, there might be some attenuation related to transmission through the upper layers as this loop broadens directly below the overlying anomalies. Without a more detailed analysis it is hard to be conclusive about the contribution of transitional reflection versus cyclic transmission losses.

In Figure 9a and Figure 9b we compare two lower octaves with the two highest octaves along the trajectory of well 15/9A16. The injection zone is indicated by the small green bar. The highest frequency band is equivalent to 1/48 of the scale associated with the lowest frequency band. We can see that below 950 ms, approximately at the top of the loop we identify as 5B, coherent low-frequency energy dominates, whereas above this level higher frequencies dominate. Taking into account the time sag related to the low velocities in the plume, we note that the low

Figure 10 Two traverses and a time slice at 1008 ms through a 3D cube with the 0.144 ms Gaussian (left), the full bandwidth result (middle) and a time slice at 928 ms showing the trajectory of the traverses (white) and the 15/9-13 well trajectory (yellow). The green bar indicates the (projected) injection zone.

frequencies are strongest at and above the injection zone, whereas also immediately to the right (East) of the injection zone less low frequency energy is present. This low frequency reflectivity is consistent with the presence of a transitional reflection at this scale. The alternative model, high-frequency loss upon transmission through the overlying layers, would not create a section with stronger low frequencies than the overlying formations.

Figure 9c shows an overlay of reflection pulse width (colour) over a backdrop of the full bandwidth impedance shown also in Figure 9d. An anomalously large pulse width is observed at the top of loop 5B offset to the left with respect to the injection zone.

In Figure 9e the lowest frequency band is shown. This band has a low signal-to-noise, but by combining the mollifier with a 5-point Gaussian filter essentially a 3D mollification can be done. Figure 9e shows this 3D result using a 0.144 ms scale, corresponding to an equivalent frequency of about 7 Hz. The amplitude at each spike location is scaled using equation (5). For comparison we show in Figure 9f the trace-by-trace mollification created by filtering the full bandwidth inversion back to approximately the same bandwidth. This results in a 1D filter that also includes the Gaussian residual of the sparse spike inversion.

In Figure 10 we compare the 3D result with the full bandwidth along two trajectories. The white arrows indicate the location of chimneys 1 and 2. The anomaly below reflector ‘5’

lies above the injection zone, but is slightly offset w.r.t. chimney 1. Chimney 2 dissects the anomaly bounded by reflectors 5 and 8. The time slices through the anomalies show that these form sheet-like features. It is possible that these are the thin and bright filaments corresponding to warm fluid ‘protoplumes’ that are described by De Paoli et al. (2022) in the context of the initial stages of convection.

Discussion

In this paper we used a decomposition of the data into two mollifiers to analyse the pulse width. Although a similar analysis can be done on data with a regular wavelet, the (integrated) mollifier shape follows a sigmoid shape that can be expected for the gradual response associated with transport phenomena. Furre et al. (2024) note that the deeper anomalies within the Sleipner CCS site are hard to interpret ‘…where the reflectivity pattern is complex and affected by time-shifts’. Nevertheless, the authors have interpreted seismic anomalies in terms of flow, but not in terms of gradual changes of fluid properties. We detected in the Sleipner seismic data frequency dependent reflections and distinct pulse width anomalies. Figure 11 displays these anomalies with the ‘putative chimneys’ from previous publications. We cannot be sure about the exact nature of these anomalies, but they are located where CO2 flow transport and/or change in fluid properties are

possible. A drop in bandwidth in itself is not enough to exclude a cyclic reflection response. In fact, the shallow gas anomalies visible in this figure show anomalies that may be indicative of a transmission-related frequency loss (e.g., see discussion in De Bruin et al., 2022). We note, however, that such transmission losses require a high reflection response more typical of shallow gas. The interpretation of the anomalies as ‘protoplumes’ may be open to challenge in a setting where many physical phenomena could occur, but at least these anomalies are observations to test various fluid mechanical models against. A key step in the method is to analyse reflection events as transients rather than a reflection series with stationary or slowly evolutionary spectra. The use of an assumed fixed coarse scale value in the decomposition may not be an accurate assumption, but at the same time we can consider it as the scale against which any bandwidth changes are compared.

Conclusion

CO2 injected close to its critical point has the potential to create a frequency dependent (transitional) reflection response. We illustrate that the shape of the transition zone matters, with a sigmoid-shaped transition having a stronger attenuation than a linear transition over similar depth range. The mollifier-based decomposition of the Sleipner 2010 near stack data showed a response consistent with a transitional reflection in the lower part of the CO2 plume. We described a novel technique to detect bandwidth loss through its impact on the pulse width. This method performs well on a synthetic dataset. When we applied this technique on the Sleipner data we detected anomalies at locations where previous publications have observed or inferred CO2 chimneys.

Acknowledgements

The author gratefully acknowledges Equinor and the partners of Licence PL046 for making the 4D seismic data from the Sleipner CCS site available under the Sleipner CO2 Reference Dataset Licence (Equinor ASA, 2020). I thank the First Break editors and reviewers for the excellent feedback that has led to a significantly improved paper.

Conflict of interest

The author has no conflict of interest to declare.

Data availability

The seismic data is available from the CO2 DataShare site (https://doi.org/10.11582/2020.00005)

Figure 11 The pulse width anomalies overlain on the inverted seismic along inline 1838 (left) and crossline 1124 (right). The locations of chimneys identified by Williams and Chadwick (2021) are indicated by the white arrows.

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BY 21 JULY

14-18 SEP. 2025

Geostatistical AVA seismic inversion for reservoir characterisation of the Pozo D-129 Formation:

A case study in San Jorge Basin, Argentina

Cecilia Zarpellón1*, Angie Padrón1, Manuel Arijón1, Antonio Ornés2 and Paola Fonseca2

Abstract

A comprehensive seismic reservoir characterisation study was conducted in a gas field in Argentina, utilising geostatistical AVA seismic inversion to generate input for reliable static and dynamic model simulation. The study encompassed a range of disciplines, including petrophysics, rock physics modelling and geostatistical AVA seismic inversion, followed by effective porosity co-simulation.

The key advantage of the geostatistical inversion method lies in its ability to integrate all available data, i.e. wells, seismic, and geological knowledge, resulting in outcomes that honour all input and produce reliable results.

A notable aspect of this study was the use of 3D prior probabilities models for geostatistical inversion which proved to be crucial for better characterisation of litho-facies across the area, outperforming the 1D approach.

The results of the geostatistical inversion, combined with the conceptual depositional model and previous seismic attributes study, showed significant consistency, increasing confidence in the outcomes of the geostatistical inversion.

The results of this study will be used to build static models of the field, enabling estimation of the in-place gas volume and its associated uncertainty. These models will also serve as input for dynamic simulations for the future development of this field.

Introduction

A comprehensive seismic reservoir characterisation study was conducted in a gas field in Argentina, utilising geostatistical AVA seismic inversion to generate input for reliable static and dynamic model simulation. The study encompassed a range of disciplines, including petrophysics, rock physics modelling and geostatistical AVA seismic inversion, followed by effective porosity co-simula-

tion. The outcome of this effort was a set of 20 equally probable realisations, generated within a 300 ms vertical time window, covering an area of approximately 180 km².

This study focused on the productive reservoirs in the upper interval of the Pozo D-129 Formation in the Chulengo field which was discovered in 2020 through the drilling of an exploratory well with an initial production of 275,000 m³/day of gas. To date,

1 Pan American Energy | 2 Viridien

* Corresponding author, E-mail: czarpellon@pan-energy.com DOI: 10.3997/1365-2397.fb2025041

1 Location map showing the area of

Figure

study: Chulengo field, Cerro Dragón area, Golfo San Jorge Basin, Argentina.

a total of five wells have been drilled, with a cumulative gas production of 415,174,000 m³ from 945,000,000 m³ of original gas in place (OGIP) (Canocini et al. 2023). This concession, operated by Pan American Energy (PAE) with a 100 % interest, is located in the Cerro Dragón area of the Golfo San Jorge Basin in the Chubut province of Argentina (Figure 1).

The Golfo San Jorge Basin is an intracratonic basin whose main axis has a predominantly west-east direction. It is limited to the north by the North Patagonian Massif, to the south by the Deseado Massif, to the west by the Andes Mountain range and to the east along the continental margin of the Atlantic Ocean (Figure 1) (Cohen et al., 2022).

A simplified stratigraphic column of the study area is shown in Figure 2. The Pozo D-129 Formation serves as both the primary source rock in this sedimentary basin and the reservoir rock of this study. Specifically, the target reservoirs are situated within the upper section of the Pozo D-129 Formation, as highlighted in Figure 2. These reservoirs consist of tuffaceous sandstones deposited by the vertical aggradation of gravitational processes that transported sediments from the lake platform to the foot of the slope thus forming lake fans during the Early Cretaceous period (López Angriman et al. 2014). The conceptual depositional model of the upper section of the Pozo D-129 Formation is depicted in Figure 3, where the Koro area is associated with the

Figure 2 Stratigraphic column of the Cerro Dragón area. The target reservoirs are located within the upper section of the Pozo D-129 Formation (red rectangle).

Figure 3 Conceptual depositional model of the upper section of the Pozo D-129 Formation, (modified after Brown and Fisher, 1977).

lake platform, the Chulengo area with lake fans and the slope representing the limit between the two areas.

The slope line, schematically represented in the conceptual depositional model (Figure 3), can reliably be interpreted using seismic attributes such as the instantaneous phase (Figure 4). In Figure 4, the white polygon shows the study area, and the black line depicts the interpreted slope line that clearly delimits zones with contrasting phases: the Koro area to the north-west of the slope line and the Chulengo area to the south-east of the line (Zarpellón, 2010).

The instantaneous phase map shown in Figure 4 suggests that this attribute is capable of differentiating depositional environments in the Pozo D-129 formation, showing instantaneous phase of around +/-180 degrees for platform deposits (Koro area) and around zero degrees for fan deposits (Chulengo area).

Methods

The scope of work included petrophysics, rock physics modelling and generation of litho-facies probability and elastic property volumes through geostatistical AVA seismic inversion. This was followed by computation of effective porosity volumes through co-simulation. The general workflow is summarised in Figure 5.

As the first stage of this study, petrophysics and rock physics modelling was conducted with ten wells. Five of these wells were in the Chulengo area, two in the Koro area and the other three wells were near the study area. First, a comprehensive log revision was performed which included editing and conditioning where required. Rock-physics modelled well logs were used later for deterministic and geostatistical inversions.

Integrated multi-disciplinary teams from Pan American Energy (PAE) and Viridien worked interactively to produce a petro-

Figure 4 Instantaneous phase attribute map for the upper section of the Pozo D-129 Formation. The white polygon shows the study area, and the black line depicts the interpreted slope line.

Figure 5 General workflow for the present study.

physical and rock physics model that characterises the rock in terms of reservoir properties and elastic response simultaneously.

The petrophysical interpretation included clay, quartz and tuff volumes, effective and total porosity as well as water saturation. These results were calibrated using additional information, such as rotary side-wall core, magnetic resonance, tested intervals, and total gas curves. The rotary side-wall core data came from a well in the Chulengo area. The magnetic resonance interpretation was available in six wells in total, three of which were in the Chulengo area, two in the Koro area and one well near the study area. Furthermore, the water saturation curve was calibrated with tested intervals and a curve of total gas provided for all wells.

The complex mineral composition was generated from the response of several logs considering a multi-mineral approach which applies inverse statistical methods to a matrix containing curve responses and uncertainty values for formation constituents.

Porosities were calculated from the density log and weighted matrix density. Water saturation was estimated using Archie’s model with the estimated effective porosity, a brine salinity of 9862 ppm of NaCl @ 91°C, a cementation exponent (m) of 2, a saturation exponent (n) of 2.1 and a tortuosity factor (a) of 1. Effective porosity was calculated by using the total porosity and shale volume, as PHIE = PHIT *(1-VSH).

Building on the results of the petrophysical evaluation, three lithofacies were determined based on effective porosity (PHIE) and water saturation (SW) cut-off, as shown in Table 1.

The results of petrophysical analysis in the upper interval of the Pozo D-129 Formation in one well of the Chulengo area are shown in Figure 6.

The overall good agreement observed between the pay litho-facies, tested intervals and total gas curves (Figure 6) suggested that the petrophysical interpretation was robust for the Pozo D-129 Formation.

A rock physics model provides the link between a rock’s petrophysical and elastic properties. A grain-supported rock physics model for consolidated sand was used to model elastic logs. The main inputs for the model are fluid and mineral properties, petrophysical properties, such as porosity and water saturation, and the theoretical values for shear modulus, compressional

Figure 6 Petrophysical interpretation in one well of the Chulengo area.

Lithofacies Cut-offs

Pay

PHIE >8% and SW <65%

Reservoir

PHIE >8% Non Reservoir PHIE <8%

Table 1 Definition of lithofacies based on their cut-offs.

modulus, and density for each mineral. Measured elastic logs (density, P-sonic and S-sonic) of good quality were used as a reference to calibrate the model.

Modelled P-impedance and Vp/Vs logs coloured by lithofacies (left) and effective porosity (right) are shown in Figure 7, where all ten wells were considered within the Pozo D-129 Formation. The pay lithofacies response corresponds to the lowest P-impedance and Vp/Vs (left) which is also associated with the highest effective porosity (right).

The petrophysical and rock physics model, which characterises the rock in terms of reservoir properties and elastic response, was consistent and played an essential role in the integration of geostatistical inversion and co-simulation.

In parallel, seismic conditioning was performed to increase the signal-to-noise ratio of the seismic data. This conditioning was first applied in the pre-stack domain and then in the poststack domain. The post-stack conditioning is explained later in this article.

The processing steps applied to pre-stack CDP gathers were: Trim statics, radon de-multiple and COV de-noise. One gather example before and after conditioning is shown in Figure 8.

Pre-stack seismic conditioning produced high-quality data that was used as input for both deterministic and geostatistical inversions.

Deterministic AVA inversion, followed by probabilistic lithofacies classification, was also performed as part of the study but they are outside the scope of this article. The main benefit of deterministic inversion for the geostatistical inversion was its ability to quantify the signal-to-noise ratio for each seismic angle stack and across the study area.

Geostatistical inversion was the core component to achieve the goal of this study. This is a probabilistic method that integrates well logs, seismic and other geologic inputs to generate outcomes

that honour all input data. Geostatistical inversion simultaneously generates several highly detailed equi-probable solutions (realisations) of elastic properties and lithofacies probabilities. These realisations exceed seismic vertical resolution. Additionally, by having several realisations it is possible to understand the range of uncertainty and associated geological risk. Several examples regarding the geostatistical inversion technique have been published in the literature which illustrate its benefits over deterministic methods, emphasising the importance of facies in the process and showing its successful application on synthetic and real data (Sams et al., 2011; Sams and Saussus, 2012; and Filippova et al., 2011).

Figure 9 illustrates the main differences between the results of the deterministic and geostatistical inversions. First, the deterministic inversion provides a prediction at seismic resolution, whereas the geostatistical inversion yields a much higher vertical resolution extracted from well data through a geostatistical model. Another difference is that the deterministic inversion generates a single ‘optimum’ solution while the geostatistical inversion produces several equi-probable solutions (20 realisations in this study). The number of realisations was chosen to obtain sensible statistics while balancing computing resources available and running times. This means that an uncertainty analysis can be performed based on the geostatistical inversion results but not on the deterministic inversion solution. A single realisation from the geostatistical inversion is shown in Figure 9. The third main difference comes from the match between the inversion result and measured well logs. The geostatistical inversion is constrained by the well data, which means that all realisations perfectly match the well logs. This is not the case for the deterministic inversion where variations from measured logs can be observed at the various well locations.

As shown in Figure 9, geostatistical inversion exceeds vertical seismic resolution which yields to successful characterisation of the thin reservoirs of Pozo D-129 Formation.

The final stage of the study was co-simulation of effective porosity. Co-simulation is a stochastic approach that generates several realisations of rock properties (effective porosity in this case) from geostatistical inversion. The co-simulation performed in this study used the relationship between P-impedance, Vp/ Vs, density, and effective porosity from well logs to create Probability Density Functions (PDFs), as shown in Figure 10. The pay lithofacies is characterised by lower P-impedance, lower Vp/Vs, lower density, and higher effective porosity than the other two lithofacies (reservoir and non-reservoir). The pay lithofacies can be differentiated from the other two (reservoir and

Figure 7 Modelled elastic cross plots with all ten wells in the Pozo D-129 Formation, colour-coded based on litho-facies (left) and effective porosity (right).

Figure 8 Pre-stack CDP gather before (a) and after (b) conditioning in the time window of interest.

non-reservoir) even though some overlap between them is still present. In particular the Vp/Vs property seems to be the most effective discriminator.

Challenges

Several challenges had to be overcome during the course of this study. The first was the structurally complex fault systems which represented a real challenge for seismic imaging, seismic velocity and AVA compliance (the first two were not part of this case study). The most significant faults (15 in total) were incorporated into a stratigraphic/structural model used to support both the deterministic and geostatistical inversion (Figure 11).

The second challenge lay in the fact that seismic amplitudes were strongly unbalanced laterally and were not fully consistent

Figure 9 Comparison of a NW-SE profile extracted from the P-impedance, Vp/Vs, and lithofacies determined from (left) deterministic, and (right) geostatistical inversion. A single realisation out of the 20 computed for geostatistical inversion is shown.

Figure 10 Crossplots between elastic properties and effective porosity exhibiting relationships, with the cluster points colour-coded with lithofacies. The PDFs are also included at the top of each column. The well log data plotted are from the petrophysics and rock physics model.

across angles. To address this, amplitude normalisation was applied to the seismic angle stacks. This was achieved through computation of 3D scale factors for each angle stack independently. Figure 12 shows a section with the AVO gradient attribute computed from seismic angle stacks before and after post-stack conditioning. Before conditioning, a significant lateral variation in the energy of some reflectors can be observed. For instance, within the target interval highlighted by a red ellipse, the energy level appears dimmed compared to the areas on both sides. After conditioning, the AVO gradient energy is more balanced across the section. All in all, post-stack seismic conditioning improved the quality of the data used as input to the deterministic and geostatistical inversions.

The last challenge was the low seismic signal-to-noise ratio for some intervals as evidenced by a poor match in some well-to-

seismic ties. Figure 13 shows the well-to-seismic tie displaying the AVO traces for one well in the Chulengo area. Correlation is variable both vertically and across angles (laterally). In this display two different intervals are highlighted. The blue rectangle highlights a relatively thick vertical window with very low seismic-synthetics cross-correlation (blue area). This window coincides with the Mina del Carmen Formation which was outside the scope of the geostatistical inversion even though it lies immediately above the target reservoirs of the Pozo D-129 Formation. The low cross-correlation in the Mina del Carmen Formation may be partly attributed to small impedance contrasts, resulting from the widespread presence of tuff throughout the interval. In contrast, the red rectangle shows an area where seismic-synthetics cross-correlation is high (yellow/orange colours) at this well location. The target reservoirs are located within this interval.

Also, some of the challenges faced during this study were related to seismic limitations. These limitations were attributed to several factors, including sparse acquisition survey geometries, aliased noise affecting near offset/angles, limited far offset/angles and significant topographic and weathering layer variability.

Finally, with the continuous advancement of seismic processing technologies, the current seismic dataset could benefit from the application of more advanced algorithms to further improve the seismic (and velocity field) quality and, as a result, the quality of the inversion products.

Results

Pay probability (posterior probability) is computed following Bayesian inference which is part of the geostatistical inversion method. Here, two approaches of ‘prior’ probability were compared: 1D versus 3D (Figure 14). In both cases, 140 vertical micro-layers were defined with an average thickness of 0.5 ms. As defined during the petrophysics analysis, three lithofacies were used: pay, reservoir and non-reservoir. The sum of each lithofacies probability equals 100%. As it can be observed in Figure 14, overall probabilities for non-reservoir lithofacies were by far higher than the other two, for both 1D and 3D approaches. Notably, the overall probabilities in the 1D approach were higher for pay than for the reservoir lithofacies, while in the 3D approach, the general probabilities were the lowest for pay lithofacies. This observation suggested that the general posterior pay probability might be lower with the 3D approach compared with the 1D approach.

To create the 3D prior probability models, we followed a three-step process. Firstly, we clustered available wells into three distinct areas: Chulengo (five wells), Koro (two wells), and a southwestern region outside the study area (two wells). Next, we computed 1D prior probabilities for each area and micro-layer using the available stratigraphic grid and litho-facies definitions at wells. We then defined three pseudo-wells, assigning each the corresponding 1D profiles, and located them at the midpoint of the wells in each area. Finally, we used the stratigraphic grid to interpolate the 1D prior probabilities of the pseudo wells for

Figure 11 3D view illustrating the complex fault system within the study area: 15 faults are displayed along with the horizon for top of the Pozo-D129 Formation.

Figure 12 AVO gradient before (a) and after (b) poststack conditioning. The red ellipse highlights an area where reflectors were enhanced after conditioning.

each litho-facies and micro-layer. Global kriging was employed as the interpolation method, with a variogram range of 50 km. Additionally, it is worth noting that the slope line interpreted from the separate attributes study was omitted in the construction of this model.

Pay probability maps following these two approaches are shown in Figure 15. By using the 1D approach, pay

probability was overestimated according to fluid production data from a blind well located in the NW (Koro) area. On the other hand, the 3D approach produced a more realistic estimation of pay probability in general. This comparison also suggested that the 1D approach was simplistic to properly account for the lateral geological variations present in the study area.

Figure 13 Well-to-seismic tie in AVO mode display in the Chulengo area.

Figure 14 Prior probabilities: 1D (left) and 3D (right)

3D prior proportions for geostatistical inversion proved to be crucial for better characterisation of lithofacies between the Chulengo area (south-east) and the Koro area (north-west) compared with the 1D approach.

Final geostatistical inversion was generated by following the approach with 3D prior probabilities. One realisation is shown in Figure 16 along with the slope line interpreted from the separate seismic attributes study of the area. The slope line delimits the Koro area (NW) and the Chulengo area (SE). All maps show a level of consistency, in particular pay probability and pay thickness, showing similar lateral trends. Also, in Figure 16, it was observed that in general pay thickness and pay probability were consistently higher where P-impedance and Vp/Vs were lower.

When comparing the geostatistical inversion maps shown in Figure 16 with the conceptual depositional model (Figure 3) and the previous seismic attribute study (Figure 4) significant

consistency was observed. This provided added confidence in the outcomes from the geostatistical inversion.

An arbitrary section through five producing wells (Chulengo area) showing part of the geostatistical inversion results and co-simulated effective porosity is shown in Figure 17. A single realisation is shown on the left-hand side and the most probable or average properties based on all 20 realisations are displayed on the right-hand side. As expected, the pay lithofacies correlates well with the highest effective porosity values. Additionally, the single realisation shows more details than the mean/most probable properties.

Figure 18 shows several average pay probability maps within the reservoir window around the location of five producing wells in the Chulengo area. The high probability zone delineates well this producing field. Also, lateral variations can be observed between the three random realisations. Statistical analysis of these differ-

Figure 15 Pay probability maps from 1D (left) and 3D (right) prior probabilities.

Figure 16 Maps within the reservoir window for realisation 20 and the slope line interpreted from seismic attributes as shown in Figure 4.

ences made it possible to quantify the level of uncertainty (standard deviation, not shown in this article) associated with the pay probability.

Similarly, Figure 19 shows several average effective porosity maps covering the same area. The high effective

porosity zone also delineates well this producing field. Again, lateral variations can be observed between the three random realisations, which were used to quantify the level of uncertainty (standard deviation, not shown in this article). Notably, it was also observed that the five wells of the Chu-

Figure 17 Arbitrary section through five producing wells in the Chulengo area showing part of the geostatistical inversion results and co-simulated effective porosity. A single realisation (left) and mean/ most probable out of 20 realisations (right).

18 Average pay probability maps in the

area within the reservoir window (black dots correspond to five producing wells).

Figure 19 Average effective porosity maps in the

area within the reservoir window (white dots correspond to five producing wells).

Figure

Chulengo

Chulengo

lengo area were not located in zones with the highest effective porosity.

The lithofacies probability and effective porosity volumes will be used to build static models of the field that will allow estimation of the in-place gas volume along with its associated uncertainty. This data will be used to dynamically simulate the future development of this field.

Finally, regular interaction between the multi-disciplinary teams of Pan American Energy and Viridien was instrumental in ensuring the high quality of this integrated seismic reservoir characterisation study.

Conclusions

First, the primary objective of generating reliable input for building static models to conduct dynamic simulations of the Chulengo field has been successfully achieved through geostatistical inversion.

Second, the use of 3D prior probabilities for geostatistical inversion has proven crucial for better characterisation of litho-facies between the Chulengo area (south-east) and the Koro area (north-west), outperforming the 1D approach.

Third, the results of the geostatistical inversion, conceptual depositional model, and previous seismic attribute study, have shown significant consistency, increasing confidence in the outcomes of the geostatistical inversion.

Finally, the results of this study will be used to build static models of the field, enabling estimation of the in-place gas volume and its associated uncertainty. These models will also serve as input for dynamic simulations for the future development of this field.

Acknowledgements

We thank Juan Moirano and Lorena Caviglia from Pan American Energy and Andy Holman, Diego Lopez, Robert Porjesz and Fabien Allo from Viridien for insightful discussions and suggestions.

We thank Pan American Energy and Viridien for giving permission to publish this paper.

References

Brown, L.F., Jr. and Fisher, W.L. [1977]. Seismic-Stratigraphic Interpretation of Depositional Systems: Examples from Brazilian Rift and Pull-Apart Basins. In: Payton, C.E. (Ed.) Seismic Stratigraphy – Applications to Hydrocarbon Exploration, 26, 213248.

Canocini, A., Andersen, D. and Muniategui, M. [2023]. Metodología para caracterizar y desarrollar un yacimiento de gas exploratorio utilizando un modelo integrado de producción. Fm. D-129 en el Yacimiento Chulengo. Cerro Dragón. Cuenca del Golfo San Jorge. 8° Congreso de Producción y Desarrollo de Reservas, Buenos Aires.

Cohen, M., Castillo, V., Fernandez, S., Galarza, B., García Torrejón, L., Millo, L., Plazibat, S., Poveda, L., Scasso, J. and Vernengo, L.F. [2022]. Exploración y Desarrollo de Hidrocarburos en Cerro Dragón, Cuenca del Golfo San Jorge, Argentina. Relatorio XXI, Congreso Geológico Argentino, Geología y Recurso Naturales de la Provincia de Chubut, 1463-1494, Puerto Madryn.

Filippova, K., Kozhenkov, A. and Alabushin, A. [2011]. Seismic inversion techniques: choice and benefits. First Break, 29(5), 103–114. https:// doi.org/10.3997/1365-2397.29.5.49948.

López Angriman, A., Zarpellón, C., Mussel, F. and Cohen, M. [2014]. Modelo Paleogeográfico de la sección Superior de la Formación Pozo D-129. Su aplicación al desarrollo de reservas en la cuenca del Golfo San Jorge, Argentina. 9° Congreso de Exploración y Desarrollo de Hidrocarburos, Actas 1: 489-510, Mendoza.

Sams, M.S., Millar, I., Satriawan, W., Saussus, D. and Bhattacharyya, S. [2011]. Integration of geology and geophysics through geostatistical inversion: a case study. First Break, 29(8), 47-56. https://doi. org/10.3997/1365-2397.2011023.

Sams, M.S. and Saussus, D. [2012]. Facies as the key to using seismic inversion for modelling reservoir properties. First Break, 30(7), 45-52. https://doi.org/10.3997/1365-2397.2012009.

Zarpellón, C. [2010]. Modelo paleogeográfico de la sección superior de la Formación Pozo D-129: determinación del quiebre del talud mediante la utilización de atributos sísmicos. Reporte interno Pan American Energy. Unpublished report.

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NAVIGATING CHANGE: GEOSCIENCES SHAPING A SUSTAINABLE TRANSITION

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The theme of this year’s EAGE Annual Conference and Exhibition in Toulouse is ‘Navigating Change: Geosciences Navigating a Sustainable Transition’. This month, geoscientists are demonstrating in different ways how their expertise is making a vital contribution to the energy transition. Geothermal, carbon and hydrogen storage are among the topics covered.

Paul Helps et al demonstrate mineral system approaches to globally screen for prospective areas for both sedimentary-hosted copper and magmatic nickel systems.

Marit Brommer gives an overview of the burgeoning global geothermal energy scene.

Julien Mouli-Castillo et al demonstrate why mine water geothermal heat (MWGH) extraction offers significant potential for decarbonising heat supply in regions with former coalmining operations.

Alena Finogenova et al highlight the key findings that have emerged from their work on the Elephant project for the past two years, working towards the public release of a detailed, freely accessible Mesozoic Base of the Norwegian North Sea.

Johnson, J.R et al show that injection rate is critical to multicycle hydrogen storage in porous media utilising analogue and numerical models.

Vetle Vinje et al demonstrate a long-offset, wide-azimuth four-component OBN survey, in combination with Full-Waveform Inversion, that produces 3D images with unprecedented detail and a geobody of the Sleipner CO2 plume that can be used for quantitative analysis.

Elodie Morgan et al on the impact of geosciences on energy transition and the role of geoscientists ten years after the Paris agreement.

Kim Gunn Maver explains why many different applications of geothermal energy will develop rapidly in the coming years.

First Break Special Topics are covered by a mix of original articles dealing with case studies and the latest technology. Contributions to a Special Topic in First Break can be sent directly to the editorial office (firstbreak@eage.org). Submissions will be considered for publication by the editor.

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Special Topic overview

January Land Seismic

February Digitalization / Machine Learning

March Reservoir Monitoring

April Underground Storage and Passive Seismic

May Global Exploration

June Navigating Change: Geosciences Shaping a Sustainable Transition

July Reservoir Engineering & Geoscience

August Near Surface Geo & Mining

September Modelling / Interpretation

October Energy Transition

November Marine Acquisition

December Data Management and Processing

More Special Topics may be added during the course of the year.

Adapted from the hydrocarbon mindset: Global screening and prospectivity mapping for critical metals with reference to copper and nickel

Paul Helps1*, Graeme Nicoll1 and Joseph Jennings1 demonstrate mineral system approaches to globally screen for prospective areas for both sedimentary-hosted copper and magmatic nickel systems.

Technology transfer for the energy transition

Over the past few years, we have been applying our experience in developing and employing hydrocarbon exploration workflows to aid subsurface mineral exploration, allowing for predictions to be made into the unknown – both deeper into the subsurface and in locations away from data control. These predictions are based upon robust geological frameworks built on diverse datasets, regional knowledge, and data-driven models. For example, Wrobel-Daveau and Nicoll (2022) proposed a new approach, using our in-house plate tectonic model and a combination of large datasets, to globally identify volcanic arcs and their durations throughout the Phanerozoic, as a potential predictive method for the discovery of possible porphyry copper occurrence locations. In this article, we discuss how we have used this holistic mindset and similar mineral system approaches to globally screen for prospective areas for both sedimentary-hosted copper and magmatic nickel systems.

Copper and nickel are two of the commodities considered foundational to the Energy Transition, the drive to help mitigate climate change through a progressive global switch to lower carbon energy sources. Along with the likes of lithium, cobalt and rare earth elements, these ‘critical minerals’ will be needed in ever greater abundance to support electrification and infrastructure upgrades, as well as provide the raw components for electric vehicles, renewable energy generation, and battery storage

(Figure 1). For example, electric vehicles use more than twice as much copper (~60 kg) as petroleum-powered cars and the average home now contains more than 180 kg of copper (Mills, 2023).

Copper

Importance of copper in the Energy Transition

Copper is a soft, ductile metal with very high thermal and electrical conductivity. It is the cornerstone for many electricity-related and renewable energy technologies (Figure 1). For example, just the clean-energy technology share of the total demand for copper is forecast to rise significantly to >40% (IEA, 2021). Mills (2023) reported that the annual demand for copper is set to increase to 36.6 million tons by 2031, and up to 50 million tons by 2035, compared to roughly 25 million tons in 2023. However, future copper supply forecasts are currently around 30.1 million tons, leaving a gap of 6.5 million tons by the start of the next decade (Mills, 2023).

This supply gap, coupled with the prolonged timeline for predictions to discovery, and eventually to production, necessitates a shift in the mindset and tools that are used in the conceptualisation and exploration of copper, as well as all the other critical metals.

Where is copper found? Two contrasting deposit types

The two main deposit types from which copper is produced are igneous-hosted porphyry deposits and sediment-hosted copper

1 Halliburton

* Corresponding author, E-mail: Paul.Helps@halliburton.com

DOI: 10.3997/1365-2397.fb2025042

Figure 1 The amounts of copper and other elements used in transportation and clean energy technologies. The rapid and progressive use of such technologies will drive a significant demand for these commodities.

Source: The Role of Critical Minerals in Clean Energy Transitions, IEA 2021.

2 Map showing the modelled distribution of Phanerozoic volcanic arcs and their cumulative durations made using the plate tectonic model from the Neftex solution, (Wrobel-Daveau and Nicoll, 2022). This map can be used as a proxy for porphyry and hydrothermal activity within subduction zone volcanic arc mineral systems, at depth or away from regional data control. Shown in black are the USGS global porphyry copper permissive tracts, showing where surface geology indicates the presence of mineral system components (Dicken et al., 2016).

deposits. These are the focus of this section. Additional potentially large sources of copper include volcanic hosted massive sulphide (VMS) and iron oxide copper Gold (IOCG) deposits, while there are also numerous other deposit types where copper can be a minor component. Porphyry and sediment-hosted deposits contain the majority of the world’s currently identified copper resources (Hammarstrom et al., 2019), with porphyry deposits (74%, 1315 Mt, millions of metric tons) being more abundant than the sediment-hosted deposit types (10%, 176 Mt). However, despite the larger size of typical porphyry deposits, sedimentary-hosted deposits typically are of a significantly higher grade, 0.5–5% compared to close up in porphyries (Hammarstrom et al., 2019). Higher grade deposits have the added advantage of potential lower production costs, emissions and waste products (IEA, 2021), all of which are central to an efficient energy transition.

Porphyry copper deposits

Porphyry copper deposits consist of copper ore minerals, typically chalcopyrite (CuFeS2) or bornite (Cu5FeS4), that form in veins and disseminations precipitated from high-temperature fluids associated with cooling magmas (Hammarstrom et al., 2019). Porphyry deposits mainly form in continental or island magmatic arc settings (Figure 2), and most of the known deposits are of Mesozoic or Cenozoic age, although Paleozoic deposits are also preserved in parts of Europe, Asia, Australia, and the Americas. A few Precambrian deposits (>541 Ma) are also known from Namibia, China, Western Australia, Finland, Sweden, Canada and Brazil (Hammarstrom et al., 2019). In general, these deposits all form in the upper crust at depths less than 5 km below the surface. Older deposits deposits, therefore, are more likely to be eroded away than younger deposits. Other commodities often associated with porphyry deposits include molybdenum, gold, and silver.

With the grades of ore from existing and long-running mines falling, as well as fewer new deposits being discovered (also typically of lower grade), copper porphyry exploration focus has started to shift to deposits at greater depths (e.g. Zhong et al., 2018; Jelenković et al., 2016). To meet demand, this trend of progressively deeper exploration will need to continue (Ghorbani et al., 2023; Schodde, 2014). While higher exploration costs are likely to be partially offset by more valuable, previously unexploited deposits, finding the deposits in the first place is a significant challenge, because deep subsurface exploration techniques and mindsets, commonplace in hydrocarbon exploration, are only starting to take hold within the mineral exploration industry. Wrobel-Daveau and Nicoll (2022) proposed a methodology to help begin to explore for porphyry deposits in such a way (Figure 2). We continue to build upon this initial approach and incorporate hydrocarbon industry datasets into a mineral systems-based workflow to globally screen for sedimentary-hosted copper prospectivity.

Sedimentary-hosted copper deposits

Sedimentary-hosted copper deposits form by movement of oxidised, metal-bearing fluids across a reduction front, which results in the precipitation of copper-rich sulphides (e.g. Hitzman et al., 2010; Hitzman et al., 2005; Cox et al., 2007; Cailteux et al., 2005; Brown, 2005). The production of these types of fluids has likely been common since the formation of the first red beds in the Paleoproterozoic. However, supergiant deposits (>24 million Mt), those of most interest to mineral explorers, are currently recognised in only three basins: 1) the Paleoproterozoic Kodaro-Udokan basin of Siberia; 2) the Neoproterozoic Katangan basin of south-central Africa; and 3) the Permian Zechstein basin of northern Europe (Hitzman et al., 2010; Hitzman et al., 2005).

Figure

A current lack of data on the Paleoproterozoic Udokan deposits means geological context is uncertain. However, both the Neoproterozoic and the Permian were times of supercontinent breakup, associated with the formation of failed rifts that subsequently became intracratonic basins. Such basins are ideal settings for the deposition of various strata that make up the critical components of sedimentary-hosted copper mineral systems (Hitzman et al., 2005; Hitzman et al., 2010). These basins are also well suited to applying exploration tools and techniques from the hydrocarbon industry.

Geological models

The formation of sedimentary-hosted copper deposits are complex, with some aspects still unknown or at least uncertain. The sedimentary-hosted copper prospectivity/screening workflow we have developed with our mining clients was initially based on the work of Hitzman et al. (2010), who focused on Neoproterozoic and Permian deposits, the latter in the German and Polish Kupferscheifer districts of the Zechstein basin (Zientek et al., 2015). It is summarised below, Figure 3 and in Table 1.

1. Global tectonic framework that favours the formation of failed rifts that subsequently develop into intracratonic basins, but not passive margins where asymmetric structures can lead to metal-rich fluid escape.

2. Within these basins, basal, oxidised syn-rift red beds, with subsidiary bimodal volcanic rocks, are considered as the primary copper sources.

3. Marine sandstones, siltstones, and shales (locally may be organic-rich) transgressively overlie the red bed sequences. These siliciclastic sequences grade upward into marine carbonates, which contain thick evaporite sequences that are the source of saline brines.

4. Heat from burial and/or igneous activity initiates convection in residual or evaporite-derived brines, which circulate downwards and leach metals from the stratigraphically lower red-bed sediments and volcanic units.

5. Continued convection causes the oxidised and metal-rich brines to circulate upward to the top of the red-bed sequence, where they encounter organic-rich sediments, which provide the necessary chemical reductants to precipitate copper sulphides.

6. Fluids may also utilise intra-basinal fault systems to escape to higher levels. Sulphides can be precipitated when these fluids encounter significant zones of in-situ or mobile reductants, such as hydrocarbons.

7. Evaporite beds also provide an effective top seal to this hydrologic system.

8. Basin edges provide lateral containment, preventing the escape of metalliferous fluids from the basin.

Sedimentary-hosted copper mineral system framework

To use this geological model in the development of a global screening tool/workflow, a holistic mineral system approach was utilised (e.g. Dulfur et al., 2016; McCuaig et al., 2010). This methodology links the conceptual geological mineral system with data or proxies that are available to support exploration. To achieve this, we identified processes or components from the geological model that are critical to the development of the mineral system (‘Mineral System Fundamentals’).

Using terminology after Dulfur et al. (2016), we have linked these fundamentals to ‘Theoretical Criteria’, which are geological parameters that we have identified to inform on the existence of each of the critical components. Data that can be used, either directly or as a proxy, to spatio-temporally map the presence of each of the ‘Theoretical Criteria’ can then be accessed and incorporated as ‘Mappable Criteria’. This then becomes the framework for subsequent geoprocessing and prospectivity map creation (Figure 4).

Although forming in a very different way to petroleum, the sedimentary copper system has similar fundamentals. We are still thinking about familiar concepts such as source, host rocks (or reservoirs) and seals – it’s just that they are reordered in terms of the geological parameters representing them.

Organic-rich rocks are no longer the source; they provide a chemical seal. Continental clastics and volcanics are now the source of the commodity. Evaporites can still provide a seal but are also important sources of the necessary brines/working fluid from which the copper sulphides are transported and ultimately precipitated.

From a screening workflow point of view, we have in-house data and products that help us to understand and predict the presence of these components. We just need to reorder and change some of our thinking about how we use them. While ini-

Figure 3 Sedimentary copper mineral system showing the main Theoretical Criteria, conceptualised into Mappable Criteria, described in Table 1, and then used in the geoprocessing workflow (modified after Hitzman et al., 2010).

tially developed to aid hydrocarbon exploration workflows, our in-house datasets and products represent more than 24 years’ effort to characterise the geology of the subsurface (Simmons, 2021). We firmly believe that these diverse and rich datasets are equally valuable in being used in the exploration for mineral deposits, geothermal or screening favourable sites for carbon storage (Wrobel-Daveau et al., 2023; Smith et al., 2023; Helps & Nicoll, 2022; Helps et al., 2024).

Sedimentary-hosted copper mineral prospectivity

To generate prospectivity maps, we have taken various in-house point, line and polygon datasets, which can be used to assess

Mineral System

Crustal Pathways

Copper/Metal Sources

Tectonic boundaries acting as conduits for metal-rich fluids

Basin Margins used to identify areas where basin-bounding faults may occur that act as conduits for metal-rich fluids

Faults acting as conduits for metal-rich fluids

Oxidised red bed sequences within epicontinental settings

Bimodal volcanic rocks as a secondary copper source

Brine Source

Host Rocks

Copper/ Metal Traps

Tectonic Setting

the presence of the mappable criteria within the sedimentary-hosted copper mineral system framework (Table 1). For example, our gross depositional environment (GDE) maps provide key inputs to our screening workflow, helping to produce input polygons for the presence of age-relevant metal and fluid sources, organic-rich reductants, and evaporite brine sources and seals. Tectonic understanding and insight into fluid pathways is provided by geodynamic units (GDU) and basin margins, faults and tectonic domain polygons, all sourced from our plate tectonic model. Examples of point data include our geochronology and whole-rock geochemistry datasets, which are used to identify additional igneous copper

Geodynamic Unit (GDU) boundaries represent deep-seated structures acting as conduits for metal-rich fluids

Basin margins

Geodynamic Units (Plate Model)

Basins and Geological Province Boundaries

Age-relevant faults Faults (Tectonic Elements)

Continental sediment lithologies on gross depositional environment (GDE) maps

Volcanic lithologies on GDE maps

Volcanic igneous rocks as a potential secondary copper source Mafic volcanic lithologies

Plutonic igneous rocks as a potential secondary copper source Mafic plutonic lithologies

Brines, which, through convection, move downwards and leach copper from the oxidised red bed/volcanic units

Siliciclastics units in which Cu/ metal deposits are typically hosted in Sed-Cu systems

Organic-rich sediments provide the necessary reductants to precipitate copper sulphides from circulating metal-rich brines

Rift settings are favourable for the development of epicontinental basins within which continental, volcanic, evaporite and organicrich successions may be present. They also provide lateral containment that prevents fluid escape from the basin

Passive margins highlight where rift basins have evolved (through spreading) into asymmetric structures that are prone to lateral fluid escape and, thus a risk to the mineral system

Evaporite successions on GDE maps

Siliciclastic sediment lithologies on GDE maps

Organic-rich sediments on GDE maps

Continental sediments as a proxy for the deposition of oxidised red bed sequences

Rift setting attributed tectonic domains and point data

Passive margin setting attributed tectonic domains and point data

1 Mineral systems framework for the sedimentary-hosted copper system used during this work.

Evaporites deposition as a proxy for a source of brine

Sequenced GDE Maps

Sequenced GDE Maps

Geochronology, Wholerock Geochemistry, Mineral Deposits

Geochronology, Wholerock Geochemistry, Mineral Deposits

Sequenced GDE Maps

Sequenced GDE Maps

Sequenced GDE Maps

Tectonic Domain

Polygons (Plate Model) & Geochronology

Tectonic Domain

Polygons (Plate Model) & Geochronology

Table

sources, and provide supplementary tectonic setting information (Table 1).

Buffers are applied to each of the input datasets, to account for geological or data uncertainty. Each of the geological parameters also receives a weighting, with those viewed as most critical, such as a primary metal or brine source, having a higher weighting to characterise their importance to the overall mineral system. Parameters perceived as representing increased risk, such as passive-margin development, can receive a negative weighting. The final prospectivity maps are styled utilising the weighting value of all relevant parameters to that point in space and time, depicted by cool to warmer colours (less to more prospective areas).

The temporal order of each geological parameter is also very important and is a key step in the geoprocessing workflow. The age filters applied to the various screening components can be viewed as dynamic and not just specific to a single time surface or age range of interest.

Figure 4 shows the final screening map we have generated for an area of interest (AOI) in Europe, for a lower Permian interval mineral system, such as that associated with the Kupferscheifer district deposits. This map includes a preservation risk layer, highlighting areas of potential erosion and non-preservation as grey polygons. Known Permo-Triassic sedimentary-hosted copper deposits and occurrences from our mineral deposits database are also displayed. These are not used in the geoprocessing but are invaluable for validating the inputs as well as the final screening maps. The geological model is heavily influenced by the Kupferscheifer district model, but the data and trends suggest that there is also validity to applying components of this model globally for efficient first pass assessments. The workflow can then be quickly refined to give insights into any sedimentary basin of interest, once the local basin scale temporal and spatial specifics are identified and calibrated.

Nickel

Importance of nickel in the Energy Transition

Nickel is a metal that is known for its strength, toughness and resistance to corrosion and oxidation. It is a key component of notable alloys, such as stainless steel and is utilised by industries such as aerospace, chemicals, marine and offshore engineering. However, there has been a significant increase in demand in the past decade, as it is also a key component in modern electronics and batteries, essential components in the drive towards electrification of transportation (IEA, 2021). In recent times, nickel supply has generally matched that of demand. Although recent and significant contributions to the market from Indonesia may have depressed the market, forecasts suggest supply outstripping demand in the coming decades (e.g. Fraser, 2021), due to the increased demand for nickel from the electric vehicle (EV) and the battery market (Figure 1). As such, the extension of our work into nickel is also in line with our recent thinking around the theme of metals being critical for the Energy Transition, as well as associated infrastructure upgrades that are needed across the globe.

There are several types of nickel deposits known and exploited around the world. These include:

Magmatic nickel sulphide deposits – These form from the crystallisation of nickel-rich magma from the Earth’s mantle. As the magma cools, nickel sulphide minerals, including pentlandite and pyrrhotite separate out forming ore bodies. These types of deposits are often associated with ultramafic or mafic rocks and are known for their high-grade.

Lateritic nickel deposits – These form when ultramafic rocks are deeply weathered in tropical or subtropical regions. Over time, prolonged weathering can cause nickel to leach into the soil and accumulate within a lateritic soil profile. These deposits tend to be geologically recent, but account for a large proportion of current market supply. They are commonly found in tropical countries, such as Indonesia and New Caledonia.

Figure 4 Screening map output generated for an AOI in Europe for a lower Permian sedimentary-hosted copper system. Permissive tracts – areas of favourable geology for sedimentary-hosted copper deposits (purple-lined areas) from the USGS, Zientek et al. (2015), are also included for further validation.

Nickel-cobalt-copper sulphide deposits – These are typically associated with mafic and ultramafic intrusive rocks and contain nickel along with cobalt and copper in the form of sulphide minerals. These can occur either as disseminated sulphides within a host rock, or as discrete ore bodies, and are often found alongside other minerals such as platinum group elements.

Nickel-cobalt laterite deposits – These are a type of lateritic nickel deposit that are also enriched in cobalt, due to the presence of cobalt-rich minerals such as limonite, erythrite, and asbolite. Cobalt shares some similarities in use cases with nickel, also forming a key component in EV batteries.

Nickeliferous sedimentary deposits – These form from the accumulation and diagenesis of nickel-rich sediments in marine or lacustrine environments. They can either form as disseminated sulphides within sedimentary rocks or as concentrated nickel-rich layers. These are typically lower in grade than magmatic nickel sulphide deposits but can still be economically viable in some cases.

Metamorphic Nickel deposits – These deposits form through metamorphic processes leading to the formation of nickel-bearing minerals. They can occur in a variety of geological settings, including regional metamorphism and contact metamorphism.

Due to a relatively high-grade and greater geographical spread of deposits, in this article we will focus on our work with magmatic nickel sulphide deposits.

Magmatic nickel sulphide system

Magmatic nickel sulphide deposits form through a series of geological processes involving the interaction of nickel-rich magma with sulphur-rich rocks. The process begins with the partial melting of the Earth’s mantle, which produces mafic or ultramafic magma rich in metals including nickel. Within the mantle, most nickel is hosted or associated with minerals that have a high melting temperature, such as olivine. As such, this process requires abnormally high temperatures and explains why ultramafic rocks that are formed at these temperatures, such as pyroxenites, dunites, gabbos as well as komatiites and picrites, have a much higher amount of nickel than mafic rocks that have formed in other lower temperature settings. Tholeiitic basalts have been proposed as parental magmas to some deposits, such as Voisey’s Bay. Whilst they are not high temperature, they are high volume, which may explain why large amounts of magmatic nickel sulphide are associated with large igneous provinces (Barnes and Lightfoot, 2005). Major weaknesses at the margins of cratons may facilitate the transfer of melt

from the mantle to the crust. Any location where large amounts of magma are produced beneath thinner lithosphere, such as near to the margin of cratonic roots, produces favourable settings for these types of deposits (Figure 5).

Once in the crust, the process of sulphur saturation can occur. This is driven by the interaction of magma with sulphur-rich rocks or sediments within the crust. Once the solubility limit of sulphur within the silicate-rich magma is attained through pressure and temperature conditions, sulphide droplets form. These are denser than the surrounding melt and so tend to settle at the base of the magma chamber. Here they interact with the surrounding magma, and become enriched in metals such as nickel, copper and platinum group elements. Over time these droplets can accumulate to form significant sulphide deposits.

The fundamental processes of generation of these deposits are similar, regardless of whether they are tholeiitic intrusion-related, picrite-related or komatiite-related. Differences occur when and where the parental magmas attain sulphur saturation in varying geological settings via differing mechanisms (Figure 5).

Magmatic nickel mineral system framework

To use the above geological model in the development of a global screening tool/workflow, a holistic mineral system approach was again utilised (e.g. McCuaig et al., 2010; Dulfer et al., 2016). This concept was taken by Dulfer et al. (2016) and applied to the magmatic nickel sulphide mineral system, with a view of studying intrusion-hosted nickel potential in Australia. With the purpose of identifying previously unrecognised nickel deposits and new regions for exploration, a mineral systems-based knowledge-driven modelling approach was considered the most appropriate method. Accordingly, as we are looking to leverage our in-house portfolio to undertake the same process on a global scale, we have, adapted and expanded upon the Dulfer et al. (2016) study to map to datasets we have available to support exploration and global-scale thinking (Table 2).

Magmatic nickel mineral prospectivity

To generate prospectivity maps, we have taken various point, line and polygon datasets, which can be used to assess the presence of the mappable criteria within the magmatic nickel sulphide system framework. Manipulations and buffers are applied to each of the input datasets, to account for geological or data uncertainty (Table 2).

Figure 5 Schematic model of Ni-Cu-PGE sulphide oreforming systems a) in the Proterozoic to recent and b) in the Archean (modified from Dulfer et al., 2016).

Figure 6 shows the final screening map we have generated for Australia, to validate against the output from Dulfer et al.

Mineral System

Presence of ultramafic magmatism

Presence of ultramafic bodies in the subsurface

Metal Source

Magmatic Processes (Sulphide formation)

Magmatic Processes (Country Rock Assimilation)

Country Rock

Crustal Pathways

Nickel enrichment in magmatic system

Potential metal sources indicated by high chalcophile element abundance (Ni, PGE, Cu)

Sulphur saturation in magmatic system as a proxy for the potential to form immiscible sulphide liquids into which Ni-Cu-PGE elements concentrate

Elevated S/Se ratios (above mantle average) can indicate contamination of mantlederived rocks by S-rich country rocks

Sulphur-rich country rocks as a source of sulphur, a critical component of immiscible sulphide liquid formation

Structures of various scales that permit metaliferous fluid and magma migration

(2016). Known nickel deposits and occurrences from our mineral deposits database are also displayed. These are not used in the

Ultramafic lithologies

Subsurface ultramafic rocks

Nickel abundance

Cu abundance

PGE (specifically Pt and Pd) abundance

Sulphur abundance

S/Se ratios

Gravity anomalies as a proxy for the presence of ultramafic rocks in the subsurface

Magnetic anomalies as a proxy for the presence of ultramafic rocks in the subsurface

Chalcophile (Cu) abundance as a proxy for a nickel-rich magma source

Chalcophile (PGE elements Pt and Pd) abundance as a proxy for a nickel-rich magma source

Immiscible sulphide liquids

Whole-rock Geochemistry, Geochronology, Surface Geology, GLiM

Global Gravity (Bouguer Anomaly)

Global Magnetic (Magnetic Intensity)

Whole-rock Geochemistry

Whole-rock Geochemistry

Whole-rock Geochemistry

Whole-rock Geochemistry

A proxy for sulphur abundance and the possibility of immiscible sulphide liquid formation Whole-rock Geochemistry

Sulphur abundance Sulphur abundance

Geodynamic unit boundaries

Basin and province boundaries

Whole-rock Geochemistry

Geodynamic Units (Plate Model)

Basin and Geological Province Boundaries Faults Faults (Tectonic Elements)

Table 2 Geological components broken into Mineral System Fundamentals, Theoretical Criteria and Mappable Criteria, for the magmatic nickel system. This workflow breakdown helps us to understand the mineral system as well as conceptualise how to turn academic concepts into actionable industry outcomes.

Figure 6 Mineral Prospectivity map for magmatic nickel in Australia, based upon Neftex datasets –the aim was to rapidly replicate the work of Dulfer et al. (2016), gain confidence in the workflow and to expand it towards a global overview. Main nickelbearing deposits are shown (purple) with major reference deposits (green – as used in the Dulfer study) relative to the predicted mineral belts.

geoprocessing work but are invaluable for validating the inputs as well as the final screening maps. The output map, associated data and trends suggest that there is also validity to applying components of this model globally as demonstrated in Figure 7.

Conclusions and next steps

The filters, buffers and parameter weighting used in the geoprocessing of the key geological components within these mineral system examples have been refined through discussions with our mining clients. Some of these values are relatively well understood, others are still uncertain or debated. Due to this, we have mapped all geological and age filters, buffer sizes and weightings to parameters, which can be edited prior to processing. This mineral screening engine prototype can, for example, generate a Europe-sized screening map rapidly in ~5 minutes. What could have taken months to produce can now be executed in minutes.

These first pass screening results allow for an efficient starting point for mineral prospectivity mapping in any global location to identify where the geological conditions were favourable, including subsurface and frontier regions. This allows mineral explorers to quickly build up a portfolio of options and then focus attention on more detailed investigations and potential discoveries at the local level. More fundamental questions can then be asked and multiple geological scenarios tested in short succession, allowing the potential for a stochastic ensemble of model ranges to be considered.

This framework approach has already been highly-refined for sedimentary-hosted copper deposits, and we have now released additional global screening maps for other important time intervals during the late Neoproterozoic and Phanerozoic. Additionally, we have taken this framework approach and started applying it to other important mineral systems, such as rare earth elements, sedimentary-hosted lead and zinc as well as lithium in formation waters. There are many similarities, as well as significant differences, between the individual mineral systems and screening workflows, and we are working towards a modular multi-mineral screening system.

At Halliburton Landmark, we have been applying our experience in developing and employing hydrocarbon exploration workflows to mineral exploration, allowing for predictions to be made into the unknown – both deeper into the subsurface and in locations away from data control. These predictions are based on robust geological frameworks built on diverse datasets, regional knowledge, and data-driven models. We are actively working with our clients in the mining space to refine and enhance these screening methodologies and improve the mineral screening engine workflows.

References

Barnes, S. and Lightfoot, P.C. [2005]. Formation of Magmatic Nickel Sulfide Deposits and Processes Affecting Their Copper and Platinum Group Element Contents. Economic Geology – One Hundredth Anniversary Volume

Brown, A.C. [2005]. Refinements for Footwall Red-bed Diagenesis in the Sediment-hosted Stratiform Copper Deposits Model. Economic Geology, 100(4), 765-771.

Cailteux, J.L.H., Kampunzu, A.B., Lerouge, C., Kaputo, A.K. and Milesi, J.P. [2005]. Genesis of sediment-hosted stratiform copper-cobalt deposits, central African Copperbelt. Journal of African Earth Sciences, 42, 134-158.

Cox, D.P., Lindsey, D.A., Singer, D.A., Moring, B.C. and Diggles, M.F. [2007]. Sediment-Hosted Copper Deposits of the World: Deposit Models and Database. Open File Report no. 03-107, Digital Dataset.

Dicken, C.L., Dunlap, P., Parks, H.L, Hammarstrom, J.M. and Zientek, M.L. [2016]. Spatial database for a global assessment of undiscovered copper resources. U.S. Geological Survey (USGS), Scientific Investigations Report 2010-5090-Z, 29 p.

Dulfer, H., Skirrow, R.G., Champion, D.C., Highet, L.M., Czarnota, K., Coghlan, R. and Milligan, P.R. [2016]. Potential for intrusion-hosted Ni-Cu-PGE sulfide deposits in Australia: A continental-scale analysis of mineral system prospectivity. Commonwealth of Australia – Geoscience Australia, p. 1-129.

Fraser, J., Anderson, J., Lazuen, J., Lu, Y., Heathman, O., Brewster, N., Bedder, J. and Masson, O. [2021]. Study on future demand and

Figure 7 First pass global magmatic nickel prospectivity map, based on bounding conditions initially tested for Australia with Neftex datasets (see Figure 6) and then expanded upon to make initial global predictions.

supply security of nickel for electric vehicle batteries. Publications Office of the European Union, Luxembourg, ISBN 978-92-7629139-8, doi:10.2760/212807, JRC123439.

Ghorbani, Y., Nwaila, G.T., Zhang, S.E., Bourdeau, J.E., Cánovas, M., Arzua, J. and Nikadat, N. [2023]. Moving towards deep underground mineral resources: Drivers, challenges and potential solutions. Resources Policy, 80, 103222.

Hammarstrom, J.M., Zientek, M.L., Parks, and Dicken, C.L. [2019]. Assessment of undiscovered copper resources of the world, 2015. Scientific Investigations Report, 2018-5160, 644 p.

Helps, P.A. and Nicoll, G.R. [2022]. Lithium: A Source to Sink Story. Subsurface Insights, June, p. 1-10.

Helps, P.A., Lang, C. and Dadwal, E. [2024]. Mapping the Potential for Carbon Storage in Mafic and Ultramafic Rocks. Subsurface Insights, September, p. 1-17.

Hitzman, M., Kirkham, R., Broughton, D., Thorson, J. and Selley, D. [2005]. The Sediment-Hosted Stratiform Copper Ore System. SEG One Hundredth Anniversary Volume.Hitzman, M.W., Selley, D. and Bull, S. [2010]. Formation of sedimentary rock-hosted stratiform copper deposits through Earth history. Economic Geology, 105(3), 627-639.

IEA. [2021]. The Role of Critical Minerals in Clean Energy Transitions. Jelenković, R., Milovanović, D., Koželj, D. and Banješević, M. [2016]. The Mineral Resources of the Bor Metallogenic Zone: A Review Geologia Croatica. Hrvatski Geoloski Institut (Croatian Geological Survey), p. 143-155.

Lang, C. and Nicoll, G.R. [2022]. Geothermal Energy: Geological Play Elements for Screening Workflows. Subsurface Insights, August, p. 1-11.

McCuaig, T.C., Beresford, S. and Hronsky, J. [2010]. Translating the mineral systems approach into an effective exploration targeting system. Ore Geology Reviews, 38(3), 128-138.

Mills, R. [2023]. The global copper market is entering an age of extremely large deficits. Mining.Com

Schodde, R. [2014]. The Global Shift to Undercover Exploration – How Fast? How Effective? The Society of Economic Geologists 2014 Conference, Keynote paper

Simmons, M.D. [2021]. Arabian Plate sequence stratigraphy at 20: History and legacy. Subsurface Insights, July, p. 4-13.

Smith, J., Jennings, J. and Butt, T. [2023]. Identify CO2 Storage Potential with On-Demand Screening. Subsurface Insights, April, p. 1-9.

Smith, J.W., Holwell, D.A., McDonald, I. and Boyce, A.J. [2016]. The application of S isotopes and S/Se ratios in determining ore-forming processes of magmatic Ni–Cu–PGE sulfide deposits: A cautionary case study from the northern Bushveld Complex. Ore Geology Reviews, 73(1), 148-174.

Treloar, M. [2019]. A Global Approach to Screening Exploration Potential. Exploration Insights, November, p. 22-28.

Wrobel-Daveau, J. and Nicoll, G.R. [2022]. Plate tectonics as a tool for global screening of magmatic arcs and predictions for related porphyry deposits. Economic Geology, 117, 1429-1443.

Wrobel-Daveau, J., Nicoll, G.R. and Eglington, B. [2023]. From Playbased Exploration to Mineral System Workflows: The Holistic Exploration Mindset. Subsurface Insights, March, p. 4–14.

Wyborn, L.A.I., Heinrich, C.A. and Jaques, A.L. [1994]. Australian Proterozoic Mineral Systems: Essential Ingredients and Mappable Criteria. Geoscience Australia, 7 p.

Zhong, J., Chen, Y., Chen, J., Qi, J. and Dai, M. [2018]. Geology and fluid inclusion geochemistry of the Zijinshan high-sulfidation epithermal Cu-Au deposit, Fujian Province, SE China: Implication for deep exploration targeting. Journal of Geochemical Exploration, 184, 49-65.

Zientek, M.L., Oszczepalski, S., Parks, H.L., Bliss, J.D., Borg, G., Vox, S.E., Denning, P.D., Hayes, T.S., Spieth, V. and Taylor, C.D. [2015]. Assessment of undiscovered copper resources associated with the Permian Kupferschiefer, Southern Permian Basin, Europe: Chapter on Global mineral resource assessment.

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Mainstream, modular, multi-dimensional: A global agenda for geothermal in 2025

Marit Brommer1* gives an overview of the burgeoning global geothermal energy scene.

Introduction: From margins to momentum

Geothermal is having a moment. Long viewed as a niche resource tucked away in volcanic zones or pilot projects, it now stands at the threshold of global relevance. From lithium-rich brines and superhot rock (such as the Krafla Magma Testbed in Iceland, Figure 1) to closed-loop systems and urban heat networks, the sector is demonstrating it can do far more than just power a lightbulb — it can transform whole economies, decarbonise industries, and build resilient infrastructure. (Figure 2).

This isn’t just technical evolution; it’s strategic repositioning. Geothermal is no longer a fringe solution. It is an infrastructure backbone, a climate enabler, and an equity multiplier.

And yet, geothermal remains massively underutilised. Today, it provides less than 1% of the world’s energy — despite being renewable, baseload, and available nearly everywhere beneath our feet. In a decade where urgency defines every energy decision, this underrepresentation is no longer acceptable.

If we are to meet global climate goals, build energy systems that are both clean and reliable, and deliver tangible benefits to communities across continents, geothermal must become mainstream, multiplied, and multi-dimensional.

To realise its full potential, we must reposition geothermal not as an alternative, but as a core component of our energy,

industrial, and social transformation. That means building a global agenda around three guiding principles:

• Mainstream: Integrated into national policies, investment frameworks, and infrastructure planning — not as a special case, but as standard infrastructure.

• Modular: Scalable, adaptable, and deployable across diverse geographies, resource types, and use cases — from urban hubs to remote villages.

• Multi-dimensional: Capable of delivering electricity, heat, minerals, cooling, food, water security, and wellness — often simultaneously.

This is a strategic imperative — one that will determine whether geothermal remains a missed opportunity or becomes a pillar of 21st-century systems thinking (Figure 2).

Mainstream: Aligning perception, policy, and capital

To become mainstream, geothermal must move from the margins of policymaking and finance into the heart of national energy strategies. This begins with visibility, but it depends on valuation.

One of geothermal’s most persistent barriers is the resource-reserve gap. While geothermal is often quoted as having vast global potential — hundreds of gigawatts of technical potential — only a small fraction is classified as viable reserves. This lack of

1 International Geothermal Association

* Corresponding author, E-mail: marit@lovegeothermal.org

DOI: 10.3997/1365-2397.fb2025043

Figure 1 Drilling for super hot (magma) in Iceland at the Krafla Magma Testbed will push the drilling boundary and is seen as geothermal’s next frontier (www.kmt.is).

Figure 2 Switching on one lightbulb in 1914. Well testing Larderello in Tuscany, now Italy’s largest geothermal field supplying more than 860 Mwe. Source: Enel Green Power Archive.

standardised classification and valuation leaves the sector difficult to assess, compare, or price — particularly in early-stage investment.

To address this, the International Geothermal Association (IGA), in partnership with global institutions and leading organisations, is calling for an International Commission for Geothermal Standards (ICGS). The ICGS is in the scoping stage and aims to deliver a harmonised framework for:

• Resource and reserve classification, across both electricity and heat

• Standardised infrastructure and equipment protocols (especially for heating and cooling)

• Transparent reporting protocols for geothermal projects such as the well-classification scheme presented by the International Association for Drilling Contractors (IADC)

• Valuation methodologies for thermal energy, mineral co-products (like lithium), and direct-use applications

These frameworks build on trusted standards like UNFC and SPE-PRMS, aiming to create a globally accepted ‘language of geothermal’.

By making the subsurface visible and its resources valued, geothermal becomes not just technically viable — but financially legible. It becomes investable. Data makes geothermal real. Standards make it bankable.

Modular: Scaling up by scaling out

Unlike many energy technologies that rely on centralised, onesize-fits-all infrastructure, geothermal is inherently modular. It can scale up to heat entire cities — or down to serve a single clinic. It can provide power to an industrial park or hot water to a rural village. It adapts to the landscape, not the other way around.

This modularity is one of geothermal’s greatest strategic strengths. It allows the technology to thrive across resource types, climates, political systems, and infrastructure readiness levels. In Germany and the Netherlands, modular deep geothermal systems are at the heart of a heating revolution. In East Africa, containerised solutions and small-scale direct-use projects are displacing diesel and expanding rural access. In Asia-Pacific island states and Caribbean nations, modular systems paired with closed-loop technology are reshaping energy security with minimal environmental footprint.

Geothermal’s modularity also extends to ownership and innovation. It enables indigenous-owned projects in Canada, campus-scale geoexchange systems in the US, and public–private heat networks in urban China. Its modular nature makes it well-suited to diverse finance models — from local cooperatives to sovereign infrastructure funds.

The future of energy isn’t about one big solution — it’s about thousands of adaptable ones.

Multi-dimensional: Beyond the megawatt

What sets geothermal apart from most other renewables is its incredible versatility. It is not just a source of electricity — it is a multi-functional, cross-sectoral enabler of whole systems. It is base-load energy and base-layer infrastructure.

Unlike wind or solar, which primarily feed the grid, geothermal spans sectors and value chains:

• It heats hospitals, powers factories, and grows food in Icelandic and Dutch greenhouses.

• It enables lithium extraction from geothermal brines — a critical input for electric vehicles and energy storage.

• It drives wellness and cultural economies, from historic spa cities in Europe to hot spring resorts across Asia and Latin America.

It also supports agricultural processing, industrial steam, desalination, and even thermal comfort in schools and public housing — making it indispensable to integrated planning for climate-resilient cities.

This multi-dimensionality allows geothermal to be embedded in a broader range of policy goals: climate adaptation, health, energy sovereignty, food security, and regional development.

Embracing this integrated role unlocks new business models, multi-benefit financing, and inter-ministerial collaboration. Geothermal’s impact is no longer just technical — it is profoundly transformational.

From potential to presence: A global heat map

Geothermal is not developing evenly around the world — but that’s exactly its strength. Its growth is shaped by context, culture, climate, and capacity. Understanding these regional differences helps us to chart a truly global, and locally grounded, geothermal agenda.

Asia-Pacific: Scaling with diversity

The Asia-Pacific region is a mosaic of geothermal potential and approaches. Indonesia is leading the way with more than 3 GW in its development pipeline, supported by robust public-private partnerships and ambitious national targets. China dominates global geothermal direct-use, rolling out district heating systems in dozens of northern cities and embedding geothermal into clean winter heating strategies. Meanwhile, Japan, despite high resource potential, prioritises low-impact geothermal that respects its volcanic and cultural heritage — deploying modular and closed-loop systems near protected zones.

Africa: From pioneers to new frontiers

In Kenya geothermal is no longer emerging — it’s embedded. The Olkaria field supplies more than 40% of the country’s electricity, making Kenya a global leader in geothermal integration. Ethiopia and Djibouti are tapping into the East African Rift with support from multi-lateral partners. Uganda is developing early-stage projects as part of broader energy access and grid diversification efforts. Across the continent, geothermal is increasingly seen as a pillar for energy security and regional industrialisation — but it requires stronger investment ecosystems to scale.

Europe:

Heating up, not powering up

In Europe, the geothermal story is mostly thermal. Countries like the Netherlands, Hungary, and Germany are scaling direct-use applications — especially for urban district heating. Here, dense infrastructure, decarbonisation mandates, and cold climates create ideal conditions. While power generation remains limited due

to geological constraints and seismic concerns, policy reform is opening new doors. The EU is investing in transparent permitting, public data, and innovation hubs to mainstream geothermal into its climate-neutral cities agenda.

Latin America: Depth and dormancy

Latin America has a deep geothermal legacy — but momentum varies. El Salvador and Costa Rica have long relied on geothermal for base-load power and grid stability. Chile and Colombia are in active exploration phases, eyeing their Andean potential. However, progress across the region remains sporadic, often hindered by financing gaps, permitting complexity, and institutional inertia. Unlocking geothermal here requires stronger multi-lateral collaboration, regional risk-sharing tools, and clearer pricing structures.

Middle East: From megawatts to multi-purpose

The Middle East is a relative newcomer to geothermal — but interest is growing fast. Turkey now hosts more than 1.7 GW of installed capacity and is pioneering geothermal for cooling and agricultural use, especially in greenhouses. Saudi Arabia is exploring geothermal for desalination, district cooling, and inte-

Figure 3 The Three Ms framework for geothermal system innovation and deployment: Mainstream refers to the integration of geothermal technologies into national energy strategies and grid planning; Modular emphasises scalable, replicable system architectures enabling rapid deployment and hybridisation; Multidimensional captures the cross-sectoral applications of geothermal energy across electricity generation, direct heat use, district cooling, and resource cascades (e.g., agriculture, desalination)

grated city-scale systems — notably in high-profile projects like NEOM. With high subsurface temperatures and existing oil and gas expertise, the region could become a geothermal leader — if policy frameworks and commercial models evolve accordingly.

North America: Innovation as infrastructure

In the United States geothermal is undergoing a renaissance — not just in megawatts, but in method. Companies like Fervo, Eavor, and GreenFire are pioneering superhot rock, closed-loop, and advanced geothermal systems (AGS), backed by federal support and venture capital. Simultaneously, efforts to repurpose oil and gas fields are accelerating, offering a just transition for fossil-based regions. In Canada, indigenous leadership is reshaping geothermal development — merging energy sovereignty, economic development, and environmental stewardship into a powerful new model.

From wells to systems: Scaling the backbone of resilience

Unlocking capital: Despite geothermal’s growing momentum, the scale of deployment remains a stark mismatch with its potential. On average the geothermal sector drills around 400 swells annually. Globally, we count just over 6300 productive geothermal wells today (Figure 3):

• 3600 wells for electricity generation, spread across 30 countries

• 2768 wells for heating and cooling, active in 88 countries

This reflects progress — but also how far we still need to go. To support climate-aligned energy systems, we must ramp up to 20,000 geothermal wells annually by 2050. That’s not incremental change — it’s a step change of two orders of magnitude.

Achieving this requires more than drilling rigs. It calls for systems-level thinking: combining standards, capital, policy, and people. Geothermal isn’t just about producing energy — it’s about building infrastructure that lasts, adapts, and delivers across sectors.

From risk to resilience

The single biggest barrier to geothermal scale-up is not geology — it’s capital misalignment. Too few investors understand the value of geothermal’s long-term returns, especially when early-stage risk is high and resource classification is inconsistent.

But this is changing.

Innovative financial tools are unlocking new pathways:

• Risk mitigation facilities like GRMF (East Africa) and GDF (Latin America) are derisking early drilling and leveraging 5–10x in private capital.

• Outcome-based financing, such as feed-in tariffs activated upon production success, are aligning risk and reward in places such as Kenya and Indonesia.

• Green bonds, concessional loans, and blended finance structures are reframing geothermal as infrastructure, not experimentation.

Globally, multilateral banks and climate finance institutions are beginning to recognise geothermal’s potential as a resilience asset. But scaling will require governments to create investment-grade environments through:

Figure 4 A) Eighty eight countries use geothermal directly for heating, cooling, balneology and agricultural purposes with a total of 2678 productive wells.B) 30 countries have geothermal installed for electricity, predominantly the ring of fire, hot spot Iceland and East African rift countries through 3600 wells. The geothermal sector drills on average 400 wells annually. Source: International Geothermal Association, 2025.

• Transparent permitting

• Standardised valuations

• Inter-ministerial co-ordination

• Integration into national energy and climate plans

Capital doesn’t flow to potential — it flows to prepared systems

The

road

to 2040: Five shifts that matter

The path from 400 wells to 20,000 wells per year isn’t linear — it’s transformative. Here are five interconnected shifts that must define the geothermal agenda over the next 15 years:

1. Scale subsurface confidence

Invest in geological data, digital twins, and AI-powered exploration to reduce dry risk and accelerate permitting. Public data portals can dramatically cut costs and boost investor trust.

2. Mainstream the thermal market

Geothermal for heating and cooling must be embedded into city planning, building codes, and industrial decarbonisation strategies. From district networks in Europe to campus systems in Asia, this is geothermal’s biggest growth frontier.

3. Finance is what matters

Transition from project-by-project grants to scalable finance structures: national geothermal funds, regional insurance

pools, and sovereign guarantees. Let geothermal compete as infrastructure.

4. Build the workforce of the future

Cross-skill professionals from oil and gas, develop regional geothermal training hubs, and equip new graduates with policy, ESG, and systems thinking skills. People drill wells — not plans.

5. Think integration, not isolation

Geothermal is not a standalone sector. It touches food, water, health, housing, and industry. Success will be measured not just in megawatts — but in how geothermal powers resilient, low-carbon, multidimensional economies.

Conclusion: This is the decade to deliver

The heat beneath our feet is not waiting. Geothermal has proven its versatility, its reliability, and its relevance. What it needs now is scale, strategy, and shared vision.

With global standards taking shape, capital mechanisms gaining traction, and new technologies unlocking fresh terrain, geothermal stands ready to move from potential to presence — and from presence to pillar.

This is the decade where geothermal moves from being the underdog of clean energy to the backbone of climate resilience.

Let’s drill the future — together.

Revolutionising geothermal heat extraction from abandoned mines for a sustainable energy future

Julien Mouli-Castillo1* and Jeroen van Hunen2 demonstrate how to explore for mine water geothermal heat, which offers significant potential for decarbonising heat supply in regions with former coalmining operations.

Introduction

Mine water geothermal heat (MWGH) extraction offers significant potential for decarbonising heat supply in regions with former coalmining operations, providing a compelling opportunity to address the urgent need for sustainable heating solutions. As countries like the UK transition towards a net-zero carbon economy, exploiting some of the 23,000 extensive flooded mine networks becomes increasingly attractive due to their widespread availability and proximity to urban centres (Gluyas et al., 2020). These mines represent a substantial and untapped renewable heat source capable of supporting local energy needs, reducing reliance on imported fossil fuels, and contributing significantly to emissions reduction targets. However, realising the full potential of MWGH is challenged by the complex nature of mine systems, their variable and uncertain conditions, and the inherent difficulty in assessing their current state accurately. Comprehensive evaluations are complicated by incomplete, outdated, or inaccurately documented mine records. This poses significant risks and uncertainties in the early stages of project development, potentially impacting the economic viability of the project.

To overcome these challenges, the GEMSToolbox – a sophisticated yet computationally efficient modelling tool – has been developed specifically to facilitate rapid screening and feasibility assessment of geothermal heat extraction from mine

water. This tool represents a significant advancement in mine water geothermal modelling by effectively bridging the gap between overly simplified analytical approaches, which often neglect important site-specific details, and fully-coupled 3D numerical models that, although accurate, are computationally expensive and require a lot of detailed data often unavailable at the feasibility stage. Loredo et al. (2016) offers an overview of these different methodologies. The GEMSToolbox integrates rigorously tested computational methodologies that simplify the representation of complex mine geometries and physical processes while maximising the use of available data. By enabling detailed yet rapid analyses, stakeholders can confidently perform extensive, site-specific feasibility studies early in the project lifecycle when available data are limited, thus gaining a much better understanding of how uncertainties impact the project’s key metrics. This enhances the likelihood of a successful project implementation (Figure 1).

The tool stems from the coordinated research effort: Geothermal Energy from Mines and Solar-Geothermal (GEMS). This Engineering and Physical Science Research Council project that completed in February 2025 contained three research work packages. The first, led by Professor Jeroen van Hunen, developed numerical modelling of mine water flow and heat exchange to assess the long-term sustainability of heat extraction, ensuring model reliability through careful calibration and

1 University of Glasgow | 2 Durham University

* Corresponding author, E-mail: Julien.Mouli-Castillo@glasgow.ac.uk

DOI: 10.3997/1365-2397.fb2025044

Figure 1 Diagram illustrating how the GEMSToolbox combines speed from (semi-) analytical models and complexity from fully coupled 3D models to provide a suitable software tool for initial studies to determine the feasibility of particular mine systems for MWGH extraction purposes.

application to prospective production sites. The second, under the leadership of Dr Zhiwei Ma, explored innovative solar-geothermal dual storage systems that integrate MWGH with a sorption heat pump cycle, harnessing 15-20°C mine water to deliver consumer-ready hot water while meeting dynamic heating demands. The third work package, led by Professor Simone Abram, delved into the political economy and community policy dimensions of MWGH, examining governance, investment frameworks, and public narratives with a focus on NE England through detailed regional and local case studies.

Novelty and key features

Existing MWGH assessment methods are often characterised by significant limitations. On one end of the spectrum, analytical solutions are frequently overly simplistic, typically relying on idealised geometries that seldom reflect the intricate nature of actual mine workings. Such simplifications, e.g., using a single-gallery isolated mine workings design, can lead to substantial inaccuracies when evaluating the feasibility and long-term sustainability of geothermal projects. On the other hand, time dependent 3D numerical simulations, though accurate, demand significant computational resources, requiring extensive expertise and data from expensive acquisition campaigns. These constraints render them less suitable for rapid initial feasibility analyses, especially when a wide range of scenarios need to be assessed.

In this context, the GEMSToolbox presents an innovative advancement by seamlessly combining computational efficiency with realistic and detailed mine-specific geometries. It achieves this by putting mine water geothermal use at the centre of its philosophy. Where many, more detailed and comprehensive software packages support the modelling of a whole host of technologies at the expense of complexity and time, GEMSToolbox is only applicable to mine water geothermal and hence can be redesigned from the bottom up by carefully selecting assumptions, physical processes and purposefully crafting their mathematical and numerical implementation, i.e., through the representation of mine galleries as interconnected pipe networks, employing a hydraulic modelling technique. This method allows rapid and stable calculation of water flow distributions throughout even highly complex mine networks. It effectively captures variations in flow dynamics, accounting for different flow regimes that may exist due to variations in mine geometry, hydraulic connectivity,

and operational conditions, thus significantly enhancing analytical confidence.

Beyond hydraulic modelling, GEMSToolbox introduces advanced analytical heat transfer calculations designed to characterise heat exchange dynamics between flowing mine water and the surrounding geological formations. This approach integrates two complementary analytical models: a radial heat transfer model optimised for isolated galleries and a planar model tailored specifically to address the heat interactions occurring in densely excavated mine areas. By employing these two distinct approaches, GEMSToolbox ensures accurate modelling of the heat diffusion process through the rockmass and advection through the water, capturing essential thermal dynamics that affect geothermal resource sustainability over time.

Crucially, the tool incorporates a novel geometric weighting technique that dynamically blends the radial and planar models according to the specific spatial relationships within mine networks. This method effectively addresses thermal interference effects between adjacent galleries, which conventional analytical approaches frequently overlook. As thermal interference significantly impacts the potential heat recovery from densely packed mine workings, this weighting technique enhances the reliability of predictions. It serves to minimise the risks related to overestimating the geothermal resource, ensuring more precise and dependable assessments that support strategic decision-making in the early stages of MWGH project development.

Benefits for prospective users

For stakeholders evaluating MWGH potential — ranging from government agencies, energy developers, to regional planners — GEMSToolbox provides essential benefits. Its rapid screening capabilities enable users to quickly evaluate multiple operational scenarios, significantly reducing preliminary analysis time and enabling more robust decision-making processes. Stakeholders benefit from enhanced accuracy, as detailed mine geometry and thermal interference factors are explicitly considered, thus reducing the risks associated with oversimplified resource evaluations.

The computational efficiency offers substantial cost savings compared to traditional 3D coupled models. Its ability to run effectively on standard computing platforms ensures that comprehensive assessments are accessible to a broader

Figure 2 Illustration of the applied mine plan ditigisation. The left panel shows an approximately 500-by-500 m part of an original mine plan from the UK’s Mining Remediation Authority. The right panel shows the result of the digitisation of the mine plan using GIS. Reproduced from Mouli-Castillo et al. (2024), with the permission of © The Mining Remediation Authority.

range of stakeholders, significantly lowering barriers to entry. Furthermore, GEMSToolbox employs an intuitive comma-separated values (CSV) input file structure compatible with common software such as Excel, greatly enhancing accessibility and ease of operation. This approachable interface simplifies the analysis workflow, making detailed mine assessments accessible even for teams without extensive technical expertise.

Inside the toolbox

GEMSToolbox operates through a carefully structured process that sequentially combines hydraulic modelling with heat exchange analysis, ensuring a comprehensive evaluation of mine water geothermal systems for long term system sustainability. The hydraulic component of the tool models the mine galleries as a network of interconnected pipe segments with nodes representing key junctions such as gallery intersections or borehole locations (Figure 2).

This network-based approach simplifies the complex geometries of actual mine workings, while retaining the essential details necessary for accurate flow simulations. The modelling is founded on fundamental conservation principles: the conservation of energy is applied along each pipe segment through Bernoulli’s principle, and the conservation of mass is maintained at every node. Detailed formulations are used to compute friction-induced head losses based on the Darcy-Weisbach equation, with the model dynamically adjusting for flow regimes — whether laminar or turbulent — using appropriate empirical correlations. This method is implemented via an incidence matrix that defines the connectivity between pipes and nodes, and it employs a Newton-Raphson iterative scheme to solve the resulting system of equations efficiently (Todini and Pilati, 1988; Rossman et al. 2008), ensuring that the hydraulic head distributions and flow rates accurately reflect the

Figure 3 3D representation of the mine workings at depth. The visual representation is of the mine galleries only, not the surrounding rock. After the discretised mine plans (Figure 2) are read into the GEMSToolbox, flow is then efficiently calculated as a pipe network of connected galleries. The figure illustrates the resulting flow field due to injection and abstraction of X litres/sec for a hypothetical scenario of a MWGH extraction system from the mine workings involving two different worked coal seams below the Durham University (UK) campus. Figure produced using the Paraview software package. (Demonstrative case study: Durham University).

Figure 4 Using the previously calculated water flow through the mine network (Figure 3), heat exchange between the flowing water and the surrounding rock mass is calculated using a methodology modified from Rodríguez and Díaz (2009). The top panel shows the resulting temperature distribution resulting from a 30-year heat extraction period at 6.5 l/s. The bottom panels illustrate how initial heat extraction follows a radial pattern of heat diffusion towards the mine galleries from the surrounding rock mass (left), while, at a later stage when heat is extracted from further away, heat extraction follows a more planar pattern, in which heat is primarily extracted from above and below the worked coal seam. (Demonstrative case study: Durham University).

steady-state operating conditions of an open loop system (Figure 3).

Following the hydraulic analysis, GEMSToolbox transitions into a heat exchange modelling phase that captures the thermal interactions between the flowing water and the surrounding rock mass. As water traverses the gallery network, its temperature at each node is computed as a flow-weighted average of inputs from adjacent galleries (Figure 4). The thermal modelling is grounded in Fourier’s law, and it utilises well-established correlations to determine the heat transfer coefficient via the Nusselt number, thereby capturing the heat flux between the rock and the water. For galleries that are relatively isolated, a radial heat transfer model is applied to capture cylindrical diffusion dynamics and heat exchange processes. In contrast, in densely excavated areas where galleries are closely spaced, a planar heat transfer model is used to account for significant thermal interference as the thermal ‘halos’ of adjacent galleries overlap (Figure 4: details provided in Mouli-Castillo et al., 2024). GEMSToolbox combines these models using a weighting factor derived from the spatial configuration of the galleries and the simulation time, ensuring that each segment is assigned an accurate representation of its heat transfer dynamics.

Furthermore, the tool facilitates comprehensive analysis and stakeholder communication by exporting simulation results in versatile 3D VTK formats, which can be visualised using the ParaView open-source software. A CSV output of the production wells flow temperatures is also provided for convenient analysis in any spreadsheet editor. This seamless integration of detailed hydraulic and thermal modelling not only enhances the accuracy of feasibility assessments but also supports robust decision-making by providing clear insights into the geothermal potential and sustainability of mine water systems.

Demonstrative case study

The GEMSToolbox was demonstrated through a hypothetical MWGH scheme beneath Van Mildert College at Durham University in the United Kingdom. Legacy mine plans were meticulously digitised into detailed geometric models capturing two coal seams interconnected by historical shafts. Two scenarios were examined: one in which annual heat demand was distributed evenly throughout the year, and another operating constantly at peak demand rates to assess maximum impact.

The model clearly illustrated how sustained geothermal extraction affects mine water temperatures over extended periods, highlighting critical insights into thermal interactions between mine galleries and variations in rock thermal properties. The rapid simulation performance – under one minute per scenario on standard laptops – illustrates the practicality and effectiveness in comprehensive feasibility assessments, providing essential insights for future planning and operational management of MWGH projects.

Future plans and development

Future developments promise to enhance the feasibility capacity and sustainability assessment features of the tool. Currently in development is the incorporation of porous media flow, which will enable the modelling of the complexities of disused mine workings by modelling both 2D purposefully collapsed zones (Figure 5: Wang et al., in preparation) and backfilled/ or collapsed room and pillar systems (Figure 6). The former are often associated with longwall mining which is characteristic of many 20th-century and contemporary mines. The latter is combined to complete the enhancement with random porosity and permeability profiles, designed to mimic the unpredictable nature of mine collapses post-closure and will be seamlessly integrated with groundwater flow through the mine (Figure 7). Such a feature not only deepens the realism

of simulations but also opens up exciting possibilities for understanding and optimising resource recovery in challenging environments.

Looking ahead, a suite of planned innovations is set to further improve both capabilities and user-friendliness of GEMSToolbox. In the upcoming year we are looking to develop capability to handle time-dependent flow rates and injection temperatures to enable the dynamic modelling of heat storage mine water systems, making it possible to simulate seasonal variations and operational fluctuations. Longer term, the integration of geochemical interactions between mine water and surrounding rock formations will enhance environmental compliance and ensure the long-term viability of geothermal projects. Another long-term aim, is an artificial intelligence (AI) module to automate the digitisation of legacy mine plans, transforming painstaking manual efforts into a streamlined, rapid process.

Conclusion

The introduction of GEMSToolbox represents a significant advancement in assessing the feasibility of mine water geother-

6 Back-filling of mine galleries was common practice when mine systems were operational, but this is often not illustrated on mine plans. In addition, since closure of a mine system, partial collapse of the galleries is likely to have occured. To incorporate these effects in the model, future models will be able to model some galleries as porous zones (rather than open galleries), as illustrated here with the green areas of the mine workings.

Figure 5 Illustration of a model setup that combines mine galleries (light-blue lines) and porous zones resulting from longwall mining (dark-blue meshed area). This approach is applied in a new version of GEMSToolbox.

Figure

mal heat extraction projects. By effectively bridging the gap between overly simplistic analytical approaches and complex numerical simulations, it empowers stakeholders to rapidly and reliably evaluate MWGH potential. This practical, accurate, and computationally efficient tool thus supports the wider adoption of mine water heating, contributing significantly towards achieving low-carbon heating solutions and broader decarbonisation objectives.

Acknowledgements

We thank our collaborators on the GEMS project for their insights and discussions around mine water heating. We thank the Durham Energy Institute for offering a platform to discuss our research. This research was funded by the EPSRC grant number EP/V042564/1 Geothermal Energy from Mines and Solar-Geothermal heat (GEMS). During the preparation of this work the author(s) used ChatGPT o3-mini to improve the readability of the text. All outputs were edited by the authors. This article was written with the support of EPSRC grant number EP/ X028402/1 for JMC.

References

Gluyas J.G., Adams C.A. and Wilson I.A. [2020]. The theoretical potential for large-scale underground thermal energy storage (UTES) within the UK. Energy Rep, 6(4), 229–237.

Loredo C., Roqueñí N. and Ordóñez A. [2016]. Modelling flow and heat transfer in flooded mines for geothermal energy use: A review. Int J Coal Geol, 164, 115-122.

Mouli-Castillo, J., van Hunen, J., MacKenzie, M., Sear, T. and Adams, C. [2024]. GEMSToolbox: A novel modelling tool for rapid screening of mines for geothermal heat extraction. Applied Energy, 360, 122786.

Rodríguez, R., Díaz, M.B. [2009]. Analysis of the utilization of mine galleries as geothermal heat exchangers by means a semi-empirical prediction method. Renew Energy, 34, 1716–1725.

Rossman, L. [2008]. Epanet 2 users manual, p. 104.

Todini, E. and Pilati, S. [1988]. A gradient method for the analysis of pipe networks. Computer applications in water supply, 1, 1–20.

Wang, Y., Mouli-Castillo, J., Mayhew, S., Tu, J., Liang, H. and van Hunen, J. [n.d.]. A numerical approach to combined open gallery and porous flow in flooded mine workings, manuscript in preparation. Manuscript in preparation

Figure 7 Illustration of the potential effect of groundwater flow on the temperature distribution in the mine workings. Plots from left to right show an increasing groundwater flow rate, in which groundwater flows in the negative x-direction. This feature will be embedded in a future version.

Revealing the salt tectonic puzzle: Mesozoic base of the Norwegian North Sea

Alena Finogenova1*, Vita Kalashnikova1, Barbara Eva Klein1, Marcin Kaluza1, Tatiana Nekrasova1, Rune Øverås1, Vlad Sopivnik 2, Elena Akhiyarova1, Anna Ivanova1, Eli Karine Finstad2 and Natalia Kukina1 have been dedicated to the Elephant project for nearly two years, working towards the public release of a detailed, freely accessible Mesozoic Base of the Norwegian North Sea. In this article, the authors highlight the key findings that have emerged from their work.

Abstract

This article expands on the EAGE extended abstract ‘Structural Styles and Lithology Changes at the Mesozoic Base from UltraLarge 3D Seismic’, to be presented at the 86th EAGE Annual Conference in Toulouse. The project’s interpretation and the structural grid for the Norwegian Continental Shelf are publicly available, a shared resource for researchers, students, and energy companies.

The study covers the details of a seismic interpretation of the Mesozoic base — a major unconformity mapped at the top of the Permian Zechstein Supergroup and the acoustic basement, where Zechstein onlaps the older strata. This surface underlies key Triassic, Jurassic, and Cretaceous hydrocarbon units, important for subsurface mapping, exploration, and petroleum systems modelling. Using a reprocessed, ultralarge broadband 3D seismic dataset (78,450 km²) across the North (NNS), Central (CNS), and South (SNS) zones of the Norwegian North Sea and 817 wells, the study integrates recent advances in salt tectonics and the Zechstein lithology research (Figure 1). Previous findings are integrated into a

consistent interpretation of structural styles and lithological variation. Understanding Mesozoic base morphology and Zechstein compositional trends has significant implications for identifying prospective plays and reservoirs, including the Zechstein salt bed potential for underground storage suitability.

Introduction

The North Sea geological evolution understanding is a long-standing priority. A critical structural marker is the Mesozoic base — top of the Permian Zechstein Supergroup (ZSG), or crystalline basement where ZSG onlaps. This surface underlies prolific Triassic, Jurassic, and Cretaceous hydrocarbon-bearing sequences, vital for reservoir prediction, trap delineation, and tectonic reconstruction.

The North Sea tectonics and stratigraphy are well-documented (e.g., Evans et al., 2003). Many studies address ZSG structural styles. Karlo et al. (2014, 2015), among others, have provided detailed analyses of the Triassic-age salt tectonics in the CNS and the SNS, focusing on the interplay between salt

1 Pre Stack Solutions-GEO AS (PSS-GEO) | 2 Lime Petroleum AS * Corresponding author, E-mail: alena@pss-geo.com DOI: 10.3997/1365-2397.fb2025045

Figure 1 Overview of the study area illustrating the integration of data used for a harmonised interpretation of structural styles, lithological variations, and salt tectonics across the Norwegian North Sea.

welds, structural highs, and sediment infill patterns. Deposition of ZSG took place in the Northern Permian Basin (Ziegler, 1989), resulting in over a kilometre of halite accumulation in the basin centre (Smith et al., 1998), while carbonate banks and sulphates developed along its margins, particularly in the Utsira High area (Clark et al., 1998). From the Late Permian to Early Triassic, the North Permian Basin was affected by north-south rifting, followed by a second rifting phase during the Middle to Late Jurassic, which led to the development of the Viking Graben as a dominant, north-westerly trending structure (Fazlikhani et al., 2017). Extension continued into the Early Cretaceous, with localised evidence of structural inversion. A more extensive phase of inversion occurred during the Late Cretaceous period, particularly across the southern Central Graben.

The timing of salt tectonics is summarised by Stewart (2007) and further explored by Joffe et al. (2022). While salt movement began shortly after deposition in the Permian, major mobilisation is associated with Early Triassic rifting. The development of Triassic mini-basins, characterised by significant thickness variation, contributed to salt deformation through differential loading. During the Jurassic rifting phase, salt thickness influenced the propagation of basement-involved faults; basement-linked faults are observed only in areas where salt thickness was less than the fault throw (Stewart, 2007).

Lithology variations of ZSG have been well documented (Joffe et al., 2022; Jackson et al., 2013; Jackson et al., 2018).

The ZSG is primarily composed of halite, anhydrite, and carbonate rocks, with minor claystone, sandstone, and potassium salts (Jackson et al., 2018). More recently, Marín et al. (2023) investigated compositional variability within the Zechstein and its implications for underground salt cavern storage — an application gaining traction in the energy transition context, including hydrogen and CO2 storage.

While these studies form a valuable regional understanding of the salt structure, mechanical behaviour, and stratigraphy, some were limited by datasets or data quality, hindering regional correlation.

This study follows the main conclusions drawn by the cited researchers for different locations across the North Sea and implements those conclusions in a consistent manner during the structural interpretation of the available ultra-large 3D merge.

Methods and dataset

The regional Mesozoic base interpretation was conducted across 78,450 km² and based on a newly merged, broadband reprocessed 3D seismic dataset (the Merge cube). This dataset combines denoised, deghosted, true-amplitude data with high 25 × 25 m bin resolution, providing exceptional clarity over the NNS, CNS, and SNS. The interpretation was calibrated to a quality selected 817 key wells (of 1620), including 139 penetrating the Permian or basement and 85 recent NPD releases (2024). Seven regional horizons were interpreted using auto-tracking and manual picking, improving continuity in complex structures (Figure 2), enabling high-resolution 50 × 50 m structural grids capturing Mesozoic base morphology (Figure 3). In the NNS, Viking Graben horizon interpretation was difficult due to burial depth. However, it was successfully traced along basin flanks with reliable reflectors.

Key observations and tectonic styles

Horda Platform and East Shetland Basement

In the NNS, pre-Triassic rocks are generally interpreted as crystalline basement in most areas where the base Mesozoic surface is traceable on seismic data. The carbonate- and evaporite-rich Zechstein Group, which underlies the Triassic in the CNS and SNS (Lervik, 2006), is largely absent on the Horda Platform and in the East Shetland Basin.

Focusing on the East Shetland Basin, the Zechstein Group is locally present in the Magnus Basin and partially within the basin itself, as confirmed by well 6201/11-3R. The structural grid reveals a complex geometry of inverted fault blocks with steeply dipping Permian and Triassic strata. On the Horda Platform, well 32/4-1 T2 is believed to penetrate Devonian strata, although this has not been confirmed by dating methods (Würtzen et al., 2021).

Møre Basin margin

The 3D seismic merge provides a detailed image of the Slørebotn Sub-basin and the western margin of the Gossa High (Figure 4). The Gossa High is a basement core structure, interpreted as a continental margin core complex exhumed by the continuous displacement from both the Slørebotn and the Møre basins. It experienced multiple phases of exposure and erosion, including

Figure 2 An example of careful interpretation work. The approximate location of section A–A’ is shown in Figure 1.

during the Triassic, pre-Bathonian, and Oxfordian-Volgian. In the late Jurassic, sediments derived from the Gossa High infilled local grabens while the crests of rotated fault blocks were eroded. The high is likely to have acted as a sediment source for adjacent depocentres. Evidence of basement erosion is visible on the structural grid as elongated features with fluvial geometries (Figure 4, Fragment 1). The rounded form of grabens along the Gossa High’s flanks may reflect the erosion of steep slopes on rotated fault blocks and infill by locally sourced sediments.

Måloy Slope

The Måløy Slope has acted as a zone of bypass, erosion, and deposition between the Norwegian mainland and the offshore

northern North Sea depocentres since the Permian. On its eastern flank, rift-related half-graben mini-basins are infilled with alluvial Jurassic and, in places, Triassic strata. There is a southward increase in Permian-Triassic thickness toward the Horda Platform. The structural grid shows clear evidence of deep basement deformation and fault block erosion during the Jurassic, including features indicative of fluvial processes (see northern corner, Figure 4, Fragment 2).

Unlike the NNS, the CNS shows greater variation due to halokinetic deformation and basement-linked tectonics. Salt-rich areas have fewer faults, while carbonate- and clastic-dominated regions, such as the Heimdal Terrace and Utsira and Sele Highs in Quadrants 24 and 25, display distinct rift-related faulting (Figures 5–8).

Utsira High and Heimdal Terrace

The Base Mesozoic structural grid, blended with Variance, details an NE-trending normal fault system formed in response to the Middle Jurassic-Early Cretaceous rifting. N-NW-associated faults are present within major rift fault ramps (Figure 5). North of the Utsira High, minor faults shift to EW. An additional faults system strikes in an EW direction like the direction of mentioned faults on the edge of the Utsira high (see faults near wells 25/8-3, 25/8-4) and possible direction of the Hardangefjord Shear Zone. Triassic/Statfjord thickness map (Figure 5b) shows the Utsira Shear Zone’s impact on the Permian-Triassic patch half-graben morphology, with increased thickness along the eastern dipping side, where the Smith Bank appears as an addition to Mid-Jurassic strata. It was noticed that the EW trend fault zone (red-dashed line, Figure 5b) divides the Utsira Shear Zone into Southern and Northern segments with possible lateral shift along the fault. The patch grabens have similar geometry on the opposite sides of the EW fault zone. This observation was not mentioned in previous studies and may be interpreted in different ways and require further analysis.

Figure 3 Time map of the Mesozoic base showing the locations of zoom-in fragments (1-8) presented in Figures 4-9.

Figure 4 Time map of the Mesozoic Base blended with the Variance attribute for the Møre Basin margin (Fragment 1) and the Måløy Slope (Fragment 2).

Sleipner terrace, Sleipner Basin

On the Sleipner Terrace, the fault pattern differs from the Utsira High due to the influence of a ductile component – Zechstein evaporites. K.E. Kane et al. (2010) identified a fault-parallel monocline (an extensional forced fold from the Sleipner Fault Zone) and three fault-perpendicular, salt-cored anticlines that compartmentalise the Sleipner Basin into four sub-basins, associates with displacement gradients along the Sleipner Fault Zone.

The structural grid (Figure 6) confirms and refines these conclusions. The main Sleipner Fault Zone (SFZ) trends NW-SE, with fault blocks on the Sleipner Terrace separated by NE-SW faults. However, the fault strike becomes less consistent north and west in the Sleipner Basin. Instead, the morphology of structures changes to more rounded shapes of folds typical for salt displacement and salt mobilisation structures. Between wells 15/6-4 and 15/6-7, a small diapir exists in a salt-bounded mini-basin, the northernmost standalone diapir on the grid. Further north, near well 16/4-3, rounded features clearly indicate salt displacement.

Stord Basin

Due to sparse data, the Triassic and Paleozoic strata on the northern slope of the Patch Bank Ridge, which dips towards the Stord Basin, are not well studied. The ridge is a prominent basement structure (Bauck et al., 2024). NS-oriented normal fault ramps are likely infilled with Permian/Triassic sediments, although their age remains unconfirmed by well data. The structural grid (Figure 7) shows evidence of fault-block erosion, with numerous northeast-oriented incisions exhibiting clear fluvial morphology. Reservoir prediction work suggests that these incisions are filled

Figure 5 Fragment 3. Illustration of Base Mesozoic morphology and fault pattern in the Utsira High and Heimdal Terrace area: a) Time map for Base Mesozoic blended with Variance attribute; b) Time thickness map for the Triassic/Statfjord interval blended with Variance, illustrating the geometry of the Utsira Shear Zone and an east-oriented shear zone (red-dashed line), with pointed thickness increases similarly in rift-related graben mini-basins on opposite sides of the E–W-oriented fault.

Figure 6 Time map blended with the Variance attribute for Fragment 4 (southwestern slope of the Utsira High). The figure illustrates morphological changes within the Sleipner Terrace, where basement-linked normal faults are observed, transitioning toward the Sleipner Basin, where halokinetic deformation leads to the formation of rounded mini-basins.

with sand-rich sediments and that sand quality improves with distance from the axis (Figure 7b).

Ling depression and Sele High

Halokinetic deformation dominates the Ling Depression, forming salt walls over 1.5 km thick and standalone diapirs (Figure 8). The large salt structures have been formed in several stages and mobilised in stages influenced by rifting-related extensional faulting. North of the Ling Depression, thinning halite layers show links between Basement and Permian faults.

Salt collapse structures, widely observed in the Ling Depression and further south, formed during the Jurassic to Cretaceous due to differential erosion and salt dissolution. This deformation displaced Jurassic, Triassic, and sometimes Cretaceous slide blocks, creating collapse grabens above diapirs.

The SNS features the thickest Zechstein Formation in the Norwegian North Sea, characterised by large salt walls, stocks, pod-interpod structures, mini-basins, and thin-skinned deformation, with frequent small diapirs and collapsed salt features (see Marín et al., 2023; Jackson et al., 2019).

Debate exists on whether ZSG thickness variation aligns with pre-Permian topography/major faults or is post-depositional, driven by Triassic differential loading (Karlo et al., 2014; Marín et al., 2023; Jackson et al., 2019). A detailed grid (Figure 9a) shows increased salt structure thickness southward correlating with the Triassic thickness. It is easy to outline the Triassic depocentre.

Towards the basin depocentre, the geometry of merged salt walls/stocks сhanges from linear (elongated N-E salt walls, consistent mini-basins) to irregular (smaller, round salt-bounded mini-basins). The gravity gliding possibly influenced linear salt structures on the northern Triassic basin slope, reducing as the slope dip decreased. Eastwards towards the Egersund Basin, salt wall geometry is more fault-linked, with primarily fault-bounded mini-basins.

The Variance along the Base Mesozoic, blended with Time maps of the Cromer Knoll Top or Base Cretaceous Unconformity (Figures 9b, 9c), refines the tectonic framework. Grabens above salt collapse structures correspond to elevated Variance (black areas) and align with synclinal geometries on the Cromer Knoll Top time map – this outlines both small salt collapse structures and large grabens.

Zechstein formation composition variations

The faults observed along the Base Mesozoic surface may indicate a changing lithology to carbonate or clastic and/or salt thinning within ZSG. Notable examples include faults within the Sleipner Terrace, the faults to the east of the salt-bounded mini-basins in the Ling Depression (Figures 6, Figure 8), and small faults in the Central Viking Graben (Figure 9c). This observation highlights the role of halite in isolating underlying formations from post-salt tectonic deformations and can serve as an indicator for regional mapping of ZSG composition or areas where ZSG is absent. Comparing amplitude attributes with Marín et al.’s (2023) lithology data reveals salt diapirs without anhydrite caps are often bright negative reflectors, while high-density anhydrite shows positive polarity (Figure 10).

Carbonate-rich Zechstein around the Utsira and Sele Highs shows strong positive amplitudes. Where Triassic/Jurassic sediments are absent above the Basement Highs, the low

Figure 8 Observed morphological variation caused by salt deformation in the Ling Depression and the Sele High (Fragment 6).

Figure 7 Fragment 5. Structural style near the Base Mesozoic within the southern edge of the Stord Basin: a) Time map blended with variance attribute, b) Examples of seismic sections and the Bast Quality Attribute along erosional features.

Figure 9 Structural styles and salt collapse structures: illustration for the South sector of the North Sea: a) Time thickness map of the Triassic sequence with indicated depocenter and salt structures bounding Triassic mini-basins (Fragment 7), b and c) Time of Cromer Knoll Top blended with variance extracted along the Base Mesozoic Surface demonstrates different sized salt collapse structures for Fragment 8 and 7.

Figure 10 Amplitude variations along the Mesozoic base and its comparison with well observations provided in the study by Marín et al. (2023).

contrast between Basement and Cretaceous rocks hinders distinct reflections — a key to paleo-topography interpretation.

Conclusion

By synergistically analysing an exceptionally large 3D seismic merge alongside extensive well data, this study has integrated regional findings into a unified structural framework for key stratigraphic markers. The detailed structural grid, combined with seismic attributes such as Variance and Amplitudes, enhances the visualisation of morphological features across the entire study area (78,450 km²). While initial observations are presented here, further in-depth analysis is needed to fully interpret these features and draw conclusions on the Norwegian sector’s structural architecture and lithological variations.

Making the resulting interpretative products and structural grids publicly available is a significant contribution to collaborative geoscience in the region. This open-access approach fosters shared knowledge of the Norwegian Continental Shelf, unlocking substantial potential for future investigations. This research supports identifying promising exploration targets and potential reservoir pinch-outs and provides a critical scientific foundation for evaluating Zechstein salt formations for future subsurface storage initiatives, contributing to broader energy transition strategies. The underlying data is available upon request through PSS-GEO. Researchers and industry professionals can contact the corresponding author for access and further information.

Acknowledgement

The authors thank Lime Petroleum and Pre Stack Solutions-GEO for granting permission to publish this material and providing public access to the Zechstein Surface dataset.

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Multicycle injection and withdrawal in sedimentary basins, a multi-disciplinary analysis of pore-scale fluid flow for hydrogen storage

Johnson, J.R1*, Kiss, D1, Shukla, M2, van Noort, R1, Nooraiepour, M2, and Yarushina, V1, show that injection rate is critical to multicycle hydrogen storage in porous media utilising analogue and numerical models.

Abstract

Hydrogen (H2) is viewed worldwide as one of the key pathways to reducing GHG emissions, especially in hard to abate sectors. However, the beneficial implementation of hydrogen as a fuel for transport, and in industries such as steel production requires a constant, reliable supply of hydrogen independent of the availability of energy. Therefore, hydrogen storage will be needed on a range of time scales, and over a range of volumes. Geological storage in porous reservoirs offer the largest storage ‘containers’, with volumes large enough to cover even seasonal cycles. However, this also means that H2 storage will be cyclic, and this cyclical nature in combination with the variable timeframes of that storage introduce complexity into the system at multiple scales. Effective and efficient operation of H2 storage sites thus requires understanding of how both injection rate itself, and how cyclical injection/ withdrawal cycles will impact fluid (e.g., H2-formation water, H2-buffer gas) interactions in the reservoir. To further develop this understanding, we utilise analogue and numerical modelling in addition to petrographical analysis to identify potential areas of further research within this underexplored topic.

Introduction

The production and storage of hydrogen (H2) for future use, from energy that would not be used otherwise, is an efficient approach to maximising usage and preventing energy loss (EU Commission, 2022; DOE, 2025; IEA, 2025). Both Europe and North America have begun to map out what the major components and hubs of a hydrogen economy could be (e.g., EU Commission H2 Action Plan, 2022; NREL, 2025). Potential use cases for surplus energy stored as H2 have been identified including optimisation of power grid networks (Kovac et al., 2021; Sikiru et al., 2024), as a replacement fuel or reactant for high PT industry applications (e.g., steel, concrete) (Tang et al., 2020; Cavaliere et al., 2023; Williams et al., 2024), for transport (e.g., long-distance road, shipping), and in some cases as an optimised ‘local’ power grid separate or hybridised with the main (Hajiaghasi et al., 2019; Ceylan and Devrim, 2023). There are a host of potential solutions for the storage of H2 including

1 Institute for Energy Technology | 2 University of Oslo

* Corresponding author, E-mail: James.Johnson@ife.no

DOI: 10.3997/1365-2397.fb2025046

physics-based (e.g., compressed gas, cold storage, liquid) and material-based methods (e.g., adsorbent, liquid organic, hydrides, chemical) (DOE, 2025). In a hydrogen economy it is possible that all of these will find a niche.

One of the key storage options is geological storage (e.g., depleted hydrocarbon reservoirs, saline aquifers, salt caverns, lined and unlined rock caverns) (Johnson et al., 2024a). Geological storage is advantageous when considering four clear factors, (1) storage capacity, (2) safety, (3) security, and (4) cost advantage. However, there are also potential drawbacks to geological storage of H2 which are dependent on the type of host rock (e.g., salt caverns, porous media, mined and unlined rock caverns). Here we look at the potential of and analyse some of the unknowns of H2 storage in comparatively non-reactive porous media (i.e., sandstone). Storage potential for H2 within sandstone reservoirs is dependent on the total connected pore space (Φ-K) of a given reservoir less the required space of fluids already present (e.g., brine, hydrocarbons) and the buffer gas (e.g., H2, N2, CH4, CO2) necessary to keep reservoir pressures within the required operational window. Total space available can be modified by removing fluids. However, this will have an economic impact (Zolfaghari et al., 2022). The range of potential storage size for hydrogen-utilising sandstone reservoirs has been estimated from 105 to 108 m3 (Emmel et al., 2023; Johnson et al., 2024a; IEA, 2025). Due to the depth and comparative isolation of sandstone reservoirs from population centres it has been suggested that they would both be safer and more secure than non-geological storage options (Muhammed et al., 2022; Johnson et al., 2024a). Utilising previously existing infrastructure may have economic benefits (Emmel et al., 2023), although the economic advantage of such utility may be somewhat limited by hydrogen-specific considerations (e.g., hydrogen embrittlement) (Dwivedi and Vishwakarma, 2018).

As a hydrogen storage will typically go through periodic injection-withdrawal cycles, with cycles on daily to seasonal timescales, the efficiency of a hydrogen storage facility is highly dependent on the movements of hydrogen and other fluids in the reservoir relative to one another. To optimise injection,

hydrogen needs to displace other fluids (e.g., brine, cushion gas) to a sufficiently high degree, while during withdrawal these fluids need to displace all hydrogen, minimising trapping in the pore network. These interactions may be dependent on the properties of the rock (e.g., mineral composition, Φ-K), the fluids (e.g., composition, viscosity, surface energy considerations), and the flow rates (i.e., injection and withdrawal rates). With the particular aim of better understanding the impact of flow rate and cyclicity of injection, we have used a combination of analogue and numerical modelling to investigate the interaction between injected gas and fluid already present in the pore space. Initial studies have focused on N2 as the stored gas. The reason for this focus is two-fold, (1) N2 is one of the primary candidates for a buffer gas due to a combination of it being relatively inert (Mohamed and Paleologos, 2018), being abundantly available, and already frequently being found in subsurface reservoirs (Mysen, 2019), and (2) the physical properties of N2 are reasonably similar to those of H2, meaning it could also represent a potential candidate for a safe laboratory analogue to H2 Utilising endmember studies such as this allows us to explore what the impact of injection rate is on the geometries and connected bodies they take on in the pore space. Understanding this can have a large impact on understanding the economics of hydrogen storage in porous media, the potential degrees of freedom that may exist when injecting and withdrawing hydrogen, and finally it can highlight where greater understanding would be required.

Methodology and background theory

Here, we are utilising a microfluidic cell in order to understand broadly (1) the relationship between gas injection and the fluid within the previously occupied pore space, (2) what the distribution of fluids are after withdrawal, and (3) finally how these relationships alter as a result of multicycle injection. While most experiments reported here were carried out using N2, we also performed experiments using different gases

(e.g., N2, He, CO2, H2). In this paper we explore the results from the injection of N2, which is helpful to understand both (1) specifically the behaviour of a potential buffer gas and (2) more broadly the expected behaviour trends of gas injected into porous media.

Laboratory setup and image analysis

The laboratory setup utilises a Darwin Microfluidics 11 Elite pump to inject the gas into a microfluidic cell whose pore space is fully saturated. For this study we performed single cycle at a variety of injection rates between 0.02 mL/min (i.e., 0.04 mm/s) and 1.00 mL/min (2.10 mm/s). The lower injection rates (0.02 mL/min, 0.05 mL/min, 0.10 mL/min) were chosen as they are representative of the typical range of basinal hydrological subsurface flow rates present in a number of siliciclastic systems worldwide (Garven, 1985; Rivera and Calderhead, 2022; He et al., 2024). One of the higher injection rates (i.e., 0.50 mL/min) was chosen as it is representative of the typical near wellbore flow rates resulting from injection (Miri et al., 2015). We also performed multicycle injection at a rate of 0.50 mL/min.

The pore structure within the cell itself was created by laser-etching out glass around ‘grains’ that have a diameter of 1mm and have an orientation of 45o to the inlet. This results in pore spaces that have a diameter of 0.5 mm, and channels between them that are 0.5mm long and 0.25mm wide. The total dimensions of the cell are 10cm x 5cm. The cell, which is composed of borosilicate glass and can be considered representative of a clean sandstone reservoir with high quartz content and high permeability. is representative of a non-reactive reservoir matrix. While such a reservoir does not exist it is worth considering that (1) there are several near pure quartz arenites that could be utilised (Figure 1) for slow-cycle (e.g., weekly, monthly, yearly) H2 storage and (2) in the case of multicycle injection over a prolonged period of time it is possible that reactions could occur only upon the initial injection (Kim et al., 2025). Note, Figure 1 (Ternary diagram estimates compiled from: Al-Harbi and Khan, 2008; Dutton, 2009; Heath et al.,

Figure 1 (a) ternary diagram reviewing average mineralogical compositions for sandstones, with (b) an example of how complex sandstones can be (Tilje Formation, Norway) under microscope at 800um scale, and (c) a shot of the microfluidic cell representing the pore space (dark) between ‘grains’ (light).

2013; NPD, 2025; Pells, 2004; Shing, 1992; Walz et al., 2005; Weibel et al., 2010; Xie et al., 2024) clearly shows that even fairly clean sandstones are exceedingly complex in grain and pore space geometry. The range is influenced by several factors including but not limited to deposition and diagenesis. The model presented here provides end-member analysis of pore space to better understand the first principles.

The microfluidic cell sits on top of an opaque sheet of plexiglass that diffuses light from an LED source. An Olympus E-5 was utilised to capture raw images at an interval of three seconds. The raw images were corrected for background effects (e.g., surface reflectivity), and then a non-local means filter was applied to ensure clear boundaries between fluids within the cell. Thresholding based on the gaussian distributions of grayscale spectra, allows for separation of different components (e.g., gas, fluid, microfluidic cell ‘grains’). These images can then be segmented to provide an understanding of internal connectivity between the fluids (e.g., gas pockets) within the cell. Finally, geometry analysis is carried out in order to quantitively understand and characterise the behaviour as the fluids interact. Here we have utilised area, centre of mass, orientation, symmetry, and elongation, as described in Johnson et al., (2022a) and (2024b).

Numerical modelling

The numerical models are based on immiscible porous flow using a continuum approach (e.g. Buckley & Leverett, 1942). This approach treats porosity and intrinsic and relative permeabilities as an effective property of a representative elementary volume, which is much larger than an individual pore. The equations describing the flow are derived based on the conservation of mass and momentum in the individual phases. We consider two incompressible phases with negligible capillary action.

Results

Figure 2 (a) initial injection results for a range of rates showing the injected gas in blue and the space occupied by fluid or the artificial grain patterns in black, and (b) the same for the withdrawal cycle associated with those injection rates. (c) The relationship between space occupied and the injection rates for injection (squares) and withdrawal (circles). (d) The relationship between ‘connectivity’ of the gas bubbles and the distribution of those bubbles along the x-axis (i.e. penetration depth).

Single injection, different rates

Injection rates have an impact on capillary forces, as identified by Johnson et al., 2024a, such that there is a greater initial distribution of gas at higher injection rates than lower (Figure 2). It was found that the relationship between injection rate (Ir) and the total space (Φt) occupied after injection is: (1)

This equation has an R2 value of 72%. However, the relationship between injection rates and emplacement after withdrawal is more complex (Figure 2). The soft relationship between injection rate and emplacement after withdrawal is best characterised by first looking at the relationship between the normalised connectivity of the gas bubbles (Sb) and the average depth of penetration (Ip) for said bubbles after withdrawal:

(2)

The equation has an R2 value of 80%. Equation 2 shows that, on average, lower initial injection rates correlate to larger gas bubbles. However, by characterising the groups broadly into categories that are more typical of groundwater flow rates (i.e., shaded) and those more typical of injection (i.e., unshaded). Then it can be seen that there is a soft relationship between injection rate and total emplacement, represented here by normalised connectivity.

Multiple injections, single rate

In the multicycle tests carried out at 0,50 mL/min, N2 is injected and withdrawn a total of three times (Figure 3). While the first injection and withdrawal shows similar qualitative results to

what was seen in the single cycle tests, subsequent cycles vary highlighting the impact of cyclicity (Figure 3). Specifically, the continuous pathway that forms between entry and exit is no longer controlled by boundary conditions. Furthermore, previously existing bubble groups exist in the surrounding matrix which appear to show a higher pore space occupancy (Figure 3).

The tests performed at 0.50 mL/min for the injection rate show very consistent results. The relationship between total space (Φ) occupied and the number of injection cycles (In) is described by: (3)

The equation has an R2 value of 98%. After three cycles a natural logarithmic relationship can be seen suggesting that it is approaching total possible penetration. On the other hand, after three withdrawals, the relationship between the total occupied pore space (Φ) and the number of withdrawal cycles (Wn) is linear, suggesting further cycles would be required to achieve a steady state occupation of the total space penetration:

(4)

When investigating normalised distribution of the gas bubbles in the x-axis of the microfluidic cell (i.e., parallel to flow) and along the y-axis (i.e. perpendicular to flow) it is possible to extract further interaction trends (Figure 4). Injection pathways start as boundary controlled (Figures 3 and 4) in the first cycle. Upon the initial withdrawal and second injection the pathway overcorrects towards the opposite boundary (Figure 4), although it no longer appears to be boundary controlled (Figure 3). Finally, in subsequent injection and withdrawal cycles it moderates towards centre between the injection and withdrawal points. Along the x-axis, a dampening signal appears to take place wherein the normalised distribution moves towards centre during each withdrawal cycle, and then backs away in diminishing amounts during the injection cycles (Figure 4).

Figure 3 a segmented image of multicycle injection of N2 into a microfluidics cell, showing the internal connectivity of gas and the displacement of the fluid within the engineered pore space.

Symmetry, elongation, and orientation were also investigated for all connected bubbles. While the distributions varied somewhat from experiment to experiment, average values per experiment for each of these parameters were nearly identical. Symmetry was consistently 0.75 +/- 0.01, where 1.0 would be perfectly symmetrical and anything below 0.5 would indicate a shape where the centre is located outside of the shape itself. For elongation the average was 0.45 +/- 0.01 where 1.0 would indicate axes of equal length. Therefore, on average, connected bubble groups are twice as long as they are wide. Finally, the orientation of connected bubble groups relative to the injection flow direction was, on average, -2.7o, indicating that injection orientation impacts flow direction.

Numerical modelling

While the microfluidics cell experiments are useful to understand fluid displacement on the pore scale, numerical models can provide a tool to upscale the pore scale results to the reservoir scale. Furthermore, numerical models can provide information on the ways macro-scale permeability heterogeneities influence macro-scale fluid displacement. We carried out simulations using a high-resolution grid (3071x383 grid points), with randomly generated elliptic flow barriers, resembling pore networks in a granular matrix. The results concurrently show a strong flow localisation on permeable fluid pathways and the development of fluid fingers along these pathways. The example we provide in Figure 5 assumes a relatively fast injection case with negligible capillary effects. However, injection and production rates often have an inverse relationship with sweep efficiency in heterogenous reservoirs (e.g. Buckley & Leverett, 1942). When multiple injection-withdrawal cycles are considered, it can be critical to maintain a relatively stable gas plume to ensure a reasonably efficient recovery, thus requiring to keep injection and production rates below certain limit values. Our results demonstrate that multiphase fluid flow simulations based on continuum methods can create fluid displacement patterns similar to those observed in microfluidics experiments. This suggests that joint interpretation of the experimental and numerical results provides a promising

avenue to upscaling from experimental scale to reservoir scale, which is necessary to ensure efficient gas recovery from porous storage formations.

Discussion

Boundary conditions

Systems of various sizes and within various environments have indicated that injection will often be boundary controlled at least initially. Boon and Hajibeygi, (2022) shows that when H2 is pushed through a core in a flow-through apparatus that H2 accumulates at the surface of the core. Similarly, numerous reservoir simulations for both H2 (e.g., Shi and Gates, 2024) and other gases (e.g., CO2) (e.g., Schipanov et al., 2019) indicate that fluid flow is boundary controlled. However, it has also been observed in both simulations (e.g., Kulkarni and Rao, 2005) and field observations (e.g., Sohrabi et al., 2004) that during multicycle injection, for example when using certain IOR/EOR techniques such as WAG, the controls around fluid flow become increasingly complex due to pore space interactions. While the numerical modelling shown here appears less influenced by boundary conditions (Figure 5) than seen in the experiments, some impact is still visible.

Injection rates

Equation 1 highlights that the efficiency of injectivity is maintained across a broad range of rates, at least in terms of total penetration (Figure 2). Indeed, even at 0,05 mL/min (i.e., 0,105 mm/s) the injection is still 75% as efficient as the upper limit of typical injection rates (1.00 mL/min) where rates are limited to prevent geomechanical alteration of the formation. This provides a significant amount of flexibility in terms of engineering design, especially when considering longer storage cycles (e.g., monthly, seasonal). Unfortunately, this also indicates that in reservoirs with

average-to-high groundwater flow rates (<0,105 mm/s), such flow will likely interact and impact plume shape. This interaction between the hydrological current will have an impact on potential recovery rates. This emphasises the need to either (1) look for basins with particularly low hydrological gradients (e.g., WCSB) or (2) implement an enhanced buffer gas that will maintain continuity despite chemical reactivity and typical hydrological gradients (He et al., 2024).

Post-withdrawal penetration depth

Total penetration depth, after withdrawal, from the point of injection appears to be primarily driven by injection rate (Figure 2). This supposition is well supported within the literature (Wang et al., 2016; Boon and Hajibeygi, 2022). However, a secondary influence was identified during the single injection rate, multicycle experiments that show a cyclical pattern around the mean penetration depth controlled by injection rate. The cyclical pattern appears to be dampening with each subsequent injection cycle (Figure 4). This secondary influence is not commonly identified or discussed within the literature to the best of our knowledge, and therefore warrants further research.

It is also worth noting that the pore space was approaching a plateau in gas occupation after the third injection cycle (Equation 3), but still appeared to need a couple more cycles of withdrawal to reach a similar post-withdrawal plateau (Equation 4). The literature has not to the best of our knowledge explored this disparity and what the result would be at the reservoir level.

Connectivity and pore space penetration

Similar to the analogue models, there is a clear relationship between the porosity-permeability parameters, and the pathways available to the injected fluid. Both the analogue and numerical

Figure 4 Changes in centre of mass is shown for the y-axis (top) and x-axis (bottom) as injection and withdrawal occurs over three cycles for experiments #033-036.

models show successful and failed arms that reach from one end of the cell to the other.

Unsurprisingly, a greater number of injection cycles results in greater utility of the available pore space (Figure 3). This has also been observed through a number of other methods (Lyssy et al., 2023). However, this can be countered over time due to an impact on the pore shape itself (Zhu et al., 2022). While slower injection rates may result in shallower penetration during the withdrawal phase, they also result in bubbles that are typically more interconnected between the pore space (Figure 2).

Rosikhin et al., (2022) highlights that a large accumulation of gas within the subsurface will be more resistant to movement. Furthermore, it has been shown that larger accumulations of gas will assist in the pace and penetration of all injectivity cycles subsequent to the first (Figure 3). However, further research is required to understand the degree of impact that this has.

Bubble shape and orientation

In addition to connectivity and size of the bubbles, the orientation and shape of the bubbles can impart a secondary impact on fluid flow. The consistency of the bubble shape, reflected by an elongation number of 0,45 +/- 0,01, (i.e., bubbles that are on average twice as long as they are wide) may be influenced by the ‘container’ shape. Note, that the cell dimensions are 10cm x 5cm with a similar orientation. While it is possible this is an artifact of the experimental approach, it is also possible that ‘container’ shape will influence fluid accumulation shape as noted on the larger scale within the literature (Liu et al., 2021). Similarly, the relatively high degree of symmetry for the bubbles is at least partially influenced by the symmetry of the pore space pattern. While this is a reasonable baseline assumption for sandstones that are quartz-rich the assumption increasingly breaks down as the composition of the sandstone becomes less homogenous in nature (Figure 1). Furthermore, depositional setting will impact how well-rounded the grains within the matrix are (Hiatt and Kyser, 2000; Johnson et al., 2022a) introducing the importance of understanding original sedimentological settings.

Figure 5 A representative example of the numerical flow simulations, showing a) the initial permeability field, b) the saturation of the displacing fluid and c) the flux density of the displacing fluid. The displacing fluid is injected over the entire left boundary with a constant flux, while the pressure is kept constant on the right boundary. There is no flux normal to the top and bottom boundaries. All values are dimensionless.

While the initial injection is influenced by boundary conditions (Figure 2) locally the multicycle injection experiments indicate that injection direction will determine orientation. This is well supported by other first principle analogue models (e.g., Li et al., 2020; Johnson et al., 2022b). For high injectivity rates (i.e., fracking), it has been shown that geological stress orientations, both historical and present, can impact fluid orientation (Johnson et al., 2022b). However, interactions within the reservoir are less well understood within the realm of diffusion with a multitude of potential factors that could influence orientation.

Conclusions and future work

Perhaps, most importantly, this work highlights that understanding flow at the pore scale can indicate what other scales (e.g., basinal) are critical to understand. We found that while there should be an incredible dynamic range possible for injection rates for H2 storage, especially for long term (e.g., monthly, seasonal), it was also made clear that hydrological systems are likely to have a significant impact that is not currently well understood. The literature suggests that greater injection rates should result in greater penetration depths. This premise is challenged somewhat, especially after withdrawal by this study, as it has been by others in the literature. Regardless, it has been shown that a lower injection rate would likely result in more cohesive gas bodies with greater size and interconnectivity. Such interplay has been shown to be helpful in preventing gas loss in the subsurface. Furthermore, there is an interesting relationship between the boundary conditions present and the behaviour of the gas. This is present both in initial injection cycles, but may also be reflected in bubble shape and orientation. Fully understanding the impact of injection rate on all of these geometrical parameters will have a direct impact on the cost, functionality, and suitability of any H2 storage system utilising porous media.

Acknowledgements

We would like to thank Forskningsrådet for grant # 333118 (HYDROGENi) for their support.

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A breakthrough in the imaging of a CO2 plume — using OBN data to the full

Vetle Vinje1*, Ricardo Martinez1 and Phil Ringrose2 demonstrate how a long-offset, wideazimuth four-component OBN survey, in combination with Full-Waveform Inversion, can be used to produce detailed 3D images and a geobody of the Sleipner CO2 plume that can be used for quantitative analysis.

Introduction

Sleipnir is the eight-legged mythological horse of the Norse chief god Odin. Sleipnir could outrun any creature even across the sky and the sea. Sleipner is also an oil and gas field development project which includes the world-famous carbon capture and storage site in the North Sea located about 250 km west of Stavanger and the topic of this paper. Sleipner, one of the largest and longest-running carbon storage sites worldwide, has been very valuable as a ‘test lab’ for several monitoring technologies and CO2 flow simulation methods from the initial CO2 injection in 1996 until the present day. Excess CO2 from the Sleipner Vest gas field is constantly scrubbed from the natural gas production using the Amine MEA solvent capture process and injected into the shallow Utsira sandstone aquifer formation through a deviated well from the Sleipner A platform, delivering the CO2 in supercritical phase into the Utsira formation at a depth of around 1000 m. Almost 20 million tonnes have been injected during the last 29 years.

Geology and previous seismic surveys

The Utsira aquifer formation, hereafter termed the storage unit, is well suited for carbon storage due to its thick sandstone unit

with high porosity (27-40%) and excellent permeability (several Darcy). The storage unit (800-1000m deep) is capped by a 50-100m-thick impermeable mudstone preventing further upward migration of the CO2. There are also several mudstone layers above this level, further adding to the long-term safety of the storage complex. The storage unit itself, although predominantly sandstone, contains several thin mudstone streaks usually less than a metre thick (Furre et al., 2024). This inhomogeneity within the storage formation acts to improve storage effectiveness and is the main reason for the complex flow pattern of the injected CO2 manifested as a total of nine identified layers of CO2 within the storage unit (Eiken et al. 2011, Furre et al., 2024, Martinez et al., 2024).

An extensive series of 4D seismic monitor surveys has been acquired over the Sleipner storage unit. Following the baseline survey prior to injection in 1994, ten monitor surveys (in 1999, 2001, 2002, 2004, 2006, 2008, 2010, 2013, 2016 and 2020) have been acquired by towed streamers with similar survey geometries (Furre, et al. 2024), all, except the 2004 survey, in a north-south direction. In addition, ultra-short streamer data (David et al, 2024a, Dehghan-Niri et al., 2024) and sparse node acquisition (David et al, 2024b) have been successfully tested

1 Viridien | 2 NTNU

* Corresponding author, E-mail: vetle.vinje@viridiengroup.com DOI: 10.3997/1365-2397.fb2025047

Figure 1 The nine layers of the plume imaged by the 2010 vintage streamer seismic. FWI velocity (a), corresponding FWI image (b) and legacy reflection-based PSTM (c) stretched to depth using the FWI model. The maximum frequency is 42 Hz. Notice the poor imaging of the deepest layers of the plume in the Legacy PSTM image.

as low-cost monitoring tools over Sleipner. As shown in many studies (e.g. Furre et al., 2024 and Martinez et al., 2025a), the injected CO2 is easy to spot on both 3D and 4D seismic images. During the 29 years of injection, the brine in the porous sandstone has been partly displaced by CO2 in a supercritical phase – a fluid with gas-like viscosity and a liquid-like density. It is compressible like a gas but has a density closer to that of water which leads to a significant reduction in seismic P-wave velocity, to even lower values than the velocity of seismic sound in water. The presence of CO2 therefore leads to a significant reduction in acoustic impedance which is why the CO2 is so clearly visible in seismic images.

The low seismic velocity in the CO2 plume is illustrated in Figure 1 a). This is from a Full-Waveform Inversion (FWI) (Martinez et al., 2025a), showing the plume in dark colours with seismic velocities down to 1480 m/s and lower. The FWI is based on the 2010 vintage streamer data with dual-source shooting in flip-flop mode into ten streamers, each 6 km long. In 2010, the total cumulative CO2 injection was 12.1 Mt (Norwegian Offshore Directorate, 2024), which means that the plume was less developed than it is today. Figure 1b shows the FWI image computed as a derivative using the relation of Zhang et al. (2020), which is comparable with Figure 1c showing the legacy Pre-Stack Time Migration (PSTM) image (shown in Furre and Eiken, 2014). Here, the PSTM image was stretched to depth using the FWI velocity and filtered down to the FWI frequencies. The red circle marks the CO2 injection point with the source feeder (SF) serving as the initial upward migration route for the CO2.

The nine layers of the plume, that were already developed and identified in 2010, are numbered from the deepest layer 1 to the uppermost layer 9 trapped against the top seal of the storage unit.

In FWI, the entire wavefield is used, including the multiples and the long-offset data traces. This improves the imaging of the deepest parts of the plume, compared to the legacy PSTM image in Figure 1c. In this image neither the source feeder (SF) nor the deepest layers 1 to 3 are clearly visible. In addition, the ‘shielding effect’ of the high reflectivity of the upper parts of the plume body obscures the imaging of the base of the storage unit (BU) and the deep regional reflector (RR) on the PSTM, while the complete

Figure 2 Regional-scale OBN data acquired over the Sleipner field (a); the node and source footprint (b); and the OBN survey geometry with triple-source shooting over the ocean bottom nodes (c). The outline of the CO2 plume is shown in red in (b).

Figure 3 a) hydrophone receiver gather and b) vertical particle velocity (Vz) receiver gather.

inversion technique in FWI improves the imaging of these deeper units as well.

2023 Ocean Bottom Node survey

These insights convinced us that FWI is the preferred imaging technique for the Sleipner plume. FWI has been demonstrated earlier over Sleipner on streamer data (Mispel et al., 2019, Martinez et al., 2024, Martinez et al., 2025b) and on sparse nodes (David et al., 2024b). However, there is a need for improved data with better azimuth and offset coverage. All the 4D data acquired over Sleipner for the last 30 years has been done using narrow-azimuth towed streamers providing limited offset range and only measuring the acoustic P-waves detected by the streamers in the water.

In 2023, a golden opportunity presented itself to test FWI over the Sleipner carbon storage site using high-quality Ocean Bottom Node (OBN) data. During that summer, Viridien (then CGG) and TGS acquired a full-scale modern OBN survey over the entire Sleipner area, as shown in Figure 2. The grey polygon in Figure 2b shows the 1200 km2 50 x 300 m four-component node layout area. The black polygon is the 25 x 50 m source carpet shot by a triple-source vessel. Figure 3 shows an example of a node gather from this survey with the hydrophone (a) and vertical particle velocity (b).

A state-of-the-art (acoustic) FWI algorithm (Zhang et al., 2018) was applied to invert for the P-wave velocity using the subset of sources and receivers within the blue and purple polygons in Figure 2 (b). This gives a full-azimuth data set with long offsets of up to 8 km. Horizontal and vertical cross-sections of the P-velocity volume from this FWI is shown in Figure 4. Following

the approach described in Martinez et al. (2024), the initial velocity model was a smoothed regional model available in the area. The anisotropic delta and epsilon parameters were estimated from empirical relations using well-logging velocities and gamma-ray logs as shown in Martinez et al. (2024). The inversion honoured a two-layer Q model, with Q = 60000 in the water column, and Q = 180 in the sediments, which agrees with the regional Q model of Carter et al. (2020) for the Norwegian North Sea.

The inversion used the entire wavefield, including primary reflections, ghosts, multiples and transmissions. Moreover, the 4C recordings enabled the use of both the hydrophone (P) and the vertical particle velocity (Vz) data in the inversion. The inversion was run iteratively up to a maximum frequency of 70 Hz. Progressing the inversion beyond this frequency led to minimal improvement in the inversion.

Geobody extraction and volume estimation

The result of the FWI OBN analysis, shown in Figure 4, confirms that we can observe the same nine layers of the plume as in the 2010 vintage streamer seismic (Figure 1). However, since 2010 an additional 7 Mt of CO2 has been injected, bringing the total injected mass from 1996 to 2023 up to 19.1 Mt (Norwegian Offshore Directorate, 2024). Consequently, we observe an increase in the lateral extension of the layers of the plume, especially the upper ones. The maximum frequency of the seismic data in the plume zone (up to 70 Hz in this case) limits the resolution so that the FWI velocities will only show a low-pass version of the true velocity of the CO2 layers. This is illustrated in the synthetic traces in Figure 5 where five low-velocity (1480 m/s) anomalies of decreasing thicknesses are embedded

Figure 4 Velocity cube from FWI using the 2023 OBN data showing imaging of the multi-layer CO2 plume, and shallower natural gas pockets and channels.

in a 2045 m/s background. The 1480 m/s velocity represents CO2-saturated sandstone in the storage unit while the 2045 m/s velocity is an estimate of the surrounding brine-filled sandstone. The true full-band velocity profiles are converted to the twoway traveltime domain where they are lowpass-filtered with a 70 Hz cutoff filter before being converted back to the depth domain. In Figure 5, the black curves represent the velocities in the true blocky layers, while the red curves are proxies for their lowpass-filtered versions, as present in the FWI.

Estimates of the CO2 layer boundaries and the thicknesses of the layers are found by choosing the mean velocity value between 1480 and 2045 m/s, i.e. 1762.5 m/s. This value is indicated by the yellow circles on the red curves in Figure 5. We observe that for the 20 m and 10 m layers the thickness is correctly estimated. As the true layer thickness decreases towards 5 m we enter the tuning zone. For 5 m the layer thickness is overestimated. When the CO2 layer gets even thinner, it eventually escapes detection, as for the 2 m layer. The minimum detection limit in this case is 3.5 m. We might hope that the lack of detection of the thin sub-3.5 m layers is compensated by the overestimation of the slightly thicker layers, but it is obvious that the band-limited nature of the seismic data also limits the accuracy in any thickness and volume estimations. Furthermore,

the assumption of a constant velocity of 1480 m/s in the plume volume is a gross simplification. The real seismic velocity in the CO2-saturated aquifer depends on many factors, including the pressure and temperature that varies throughout the plume (Nazarian and Furre, 2022). This illustrates the complexity and potential error bars in volume estimations of CO2.

To extract a geobody from the complex plume, the 70 Hz FWI velocity in Figure 4 is first upsampled from 3.125 x 3.125 x 2 m to 1.5625 x 1.5625 x 1 m followed by a triangulation of the iso-velocity (Viso = 1762.5 m/s) surface. This geobody is seen towards the north-west in Figure 6 and reveals many details of the CO2 distribution, both as layers and feeders. The path of the deviated well from Sleipner Vest and the injection point are also displayed. The CO2 plume is elongated along the north/south with a length of about 5 km, while the width in an east-west direction is around 1 km. There is a distance of about 250 m from the base of the geobody to the uppermost layer 9 which is trapped towards the upper seal at a depth of around 800 m beneath the sea surface. The source feeder at the base of the plume (SF, Martinez et al., 2025b) is massive while the vertical migration routes between the upper layers are more subtle. These vertical pathways are difficult to detect on conventional reflection seismic images, whereas, by using the

5 Five vertical profiles of low-velocity (1480 m/s) CO2 layers with different thickness. The black curve shows the true layer, while the red curve is the low pass-filtered version of the layer using 70 Hz as the absolute cutoff. The velocity value 1762.5 m/s indicated by the yellow circles, is used to estimate the true CO2 boundary.

Figure 6 CO2 plume geobody with the CO2 injection well and injection point, the source feeder and the nine identified layers. The vertical is scaled up with a factor of five in the plotting.

Figure

complete wavefield in the FWI, we can map them much more clearly.

It is also possible to extract the volume of the geobody in Figure 6. We estimated the volume to be 144.8 million m3 which is 0.1448 cubic km. This would fill a lake of 1000 x 1000 m to a depth of 144.8 m. Or it could fill about 58,000 Olympic swimming pools.

Volumetric measurements like these are valuable for estimations of the mass of CO2 in the Sleipner plume when it is used in combination with estimates of porosity, irreducible brine saturation and the in-situ density of CO2 (a subject of continuing research). They are also valuable for storage assurance, by helping to confirm that the CO2 remains within the storage complex, and for understanding flow mechanisms. These insights have important implications for future storage projects where storage capacities have to be estimated, and pore-space utilisation needs to be optimised.

Conclusions

We have demonstrated that a 2023 long-offset, wide-azimuth four-component OBN survey in combination with the latest version of Full-Waveform Inversion can be used to produce detailed 3D images and a geobody of the Sleipner CO2 plume that can be used for quantitative analysis. We furthermore demonstrate that we can estimate the volume of the CO2 plume quite accurately which gives a good basis for estimation of the mass of CO2 present in the plume (as a mobile dense phase). Mass quantification and phase determination using this geobody is the subject of ongoing research.

Acknowledgements

This article summarises and builds on research conducted by Ricardo Martinez as part of his PhD thesis at NTNU (to be submitted in Q2 2025), supported by the co-authors, Vetle Vinje and Phil Ringrose. The work was partially funded by the Norwegian Research Council (NRC) via the Centre for Geophysical Forecasting (CGF) (grant no. 309960).

We thank Viridien and TGS for access to the 2023 OBN data and for permission to show the results. We furthermore thank Equinor Energy AS and the Sleipner license partners, LOTOS Exploration and Production Norge AS, Vår Energi ASA and KUFPEC Norway AS for use of the Sleipner 2010 survey data and other datasets made available via the CO2 Storage Data Consortium (CO2datashare.org).

We finally thank Joachim Mispel, Andrew Ratcliffe, Peng Zhao, Haishan Zheng, Hao Jiang, Harrison Moore, Steve Hollingworth and Viridien’s Sleipner imaging team for their valuable contributions to this study.

References

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Geosciences and the Energy Transition:

Dispelling

the myth, building solutions

Elodie Morgan1* and Camille Cosson1 reflect on the impact of geosciences on energy transition and the role of geoscientists ten years after the Paris agreement.

Introduction

Thursday night, Paris, 7 pm

A glass of Chardonnay on the terrace, soaking in the late sun after a long day at work. Some friends arrive, bringing along other friends. The afterwork begins, and the conversation flows. We meet new people, share drinks and fromages, and enjoy a pleasant moment. French art de vivre! And then, without fail, somebody asks, with curious, eager eyes: ‘And you, what do you do for a living?’ Many jobs are hard to explain; ours is a case in point. How do you say it?

‘I’m a geophysicist?’ How many times have you seen that bemused, puzzled look: ‘Wait, what did you say you were?’ Yes… you know what I mean. And you can replace ‘geophysicist’ with just about any other geoscience-related job. Most people have no clue what we do in our day-to-day job. Or worse: sometimes, they assume they do ‘Oh… so you work in oil, right?’ And just like that, the mood shifts. You hear the disapproving tone, and without a single follow-up question, you know what is coming next: a conversation you did not ask for, part prosecution, part incomprehension.

This typical moment sums up something many geoscientists have encountered. Time and again the situation above summarises what we have felt more than once. Our jobs are not just hardly visible and understandable, they are controversial. It is easy to feel misunderstood, even marginalised, when even small talk turns into awkward debate.

Geoscientists have a pivotal role to play in the energy transition – but if geosciences are so often misperceived in everyday life, how can we possibly lead the change the world so urgently needs? How can we reduce the misconceptions surrounding our occupation? In the midst of semi-accusations and misconstrued assumptions, what should we truly be held accountable for? And should society trust us to help solve the defining challenge of our time?

In this article, we chose to explore this often-controversial topic through a few key reflections.

Firstly: where do we stand, 28 years after the Kyoto Protocol, 19 years after An Inconvenient Truth (Al Gore), and ten years after the Paris Agreement at COP21? Have we made progress or are we falling short of expectations?

Secondly: what is the true extent of our expertise, and how far does it align with today’s pressing challenges?

Thirdly: let us be clear, geoscientists will not single-handedly make this transition happen. To address the energy transition takes

1 SpotLight Earth

* Corresponding author, E-mail: Elodie@spotlight-earth.com DOI: 10.3997/1365-2397.fb2025048

a village: governments, industries, and institutions must commit to common targets and create meaningful incentives. This includes setting an actual price for emissions. Only then can we trigger the scale of action needed to address hard-to-abate CO2 emissions.

This brings us to another hot topic: Carbon capture and storage (CCS). Will it save us, or is it just an excuse to keep emitting, business as usual? Can it be a sustainable solution, or should it remain a transitional one?

And finally: what about us, our industry, our colleagues, our next steps? Are we ready for the challenge ahead?

In this article, we shall dive into the world of geosciences, from our legacy to today’s challenges, navigating through the waves of misinformation, half-truths, and genuine insights. And in this ocean of news, one question remains:

As a geoscientist, what do you want to contribute?

Where do we stand now, 28 years after the Kyoto Protocol and 10 years after Paris Agreements at COP 21?

It is getting hot in here: 2024 is the warmest year on record since the pre-industrial era. And the targets aren’t cooling It down Despite the climate agreements signed throughout the last decades and in spite of the policies implemented in numerous states around the planet, the monitored evolution of the global mean temperature is rather ruthless (Figure 1). From a steady increase in the 1980s to the 2010s, it is now dramatically spiking. This is ground for a

Figure 1 Yearly surface temperature from 1880–2024 compared to the 20th century average (1901-2000). Blue bars indicate cooler than average years; red bars show warmer than, average years. (NOAA, 2022).

harrowing prediction, with the worst to be expected in the coming years: there is now ample scientific consensus on the impact of anthropic activities on climate change. Such as: extreme weather, for instance with an increased frequency of droughts and inundations, a sharp decrease in crop yields, loss of biodiversity with the Holocene Extinction, increase in ocean acidification, drastic melt of the ice cap, increased sea levels… This raises a troubling question: where have we failed in turning policies into actual impact?

Over the past 20 years, CO2 emissions — one of the main greenhouse gases — have started to flatten globally. In fact, they have been steadily decreasing in the European Union, the United States, and Japan over the last decade (Figure 2).

However, these historically high emitters are no longer the main drivers of rising global emissions. Today, most of the growth comes from developing countries, where fast-paced industrialisation and rising energy demand reflect the pursuit of the standard of living long enjoyed by western nations. This shift is not about blame — it is about acknowledging the complexity of a global system, where economic development is still deeply tied to carbon-intensive pathways. Moreover, CO2 emissions per capita in these regions are increasingly influenced by strong demographic growth (Figure 3). As populations grow and urbanise, so does the demand for energy, transportation, housing, and food — intensifying emissions, even when per-person energy use remains relatively modest compared to developed nations.

The clock is ticking: Can clean energy save us from overshooting the 1.5°C threshold?

According to IEA, replacing fuel consumption with the implementation of clean energy has allowed us to avoid the equivalent of 6% of the total global fossil fuel in 2024 being released into the atmosphere (Figure 4). However, this progress was not enough to stop the rise of global CO2 emissions, which has increased by 1.3 Gt since 2019. As years pass, the likelihood of meeting the challenge of limiting the temperature rise to 1.5°C steadily decreases, going from reachable to unattainable. Yet, achieving net zero is crucial, if only to mitigate the impact on future generations.

Bolder actions and strategies are required to further develop renewable power generation and electrification, while intensifying the efforts to decrease GHG emissions stemming from the consumption of fossil fuel. According to IEA’s net zero pathway, the key mitigating measure to reach net zero emissions by 2050 include: energy from wind and solar photovoltaics, electrification, energy efficiency measures, shifting to bioenergy and hydrogen and… carbon capture utilisation and storage (CCUS). How fast we can shorten the timing for adopting new consumption behaviours, transforming energy supply chains and industrial processes, is largely uncertain.

When we talk about solar panels, wind farms, electric vehicles, or even CCS, one thing becomes clear: geoscientists can be involved in every single step. Our skills are woven into every

4 Change in CO2 emissions from fuel combustion and avoided emissions from deployment of selected clean technologies, 2019-2024 (IEA, 2025).

Figure 2 CO2 total emissions per capita by region, 2000-2023 (IEA, 2024).

Figure 3 CO2 total emissions by region, 2000-2023. (IEA, 2024).

Figure

stage of the energy transition — from sourcing critical minerals to managing the subsurface, assessing risks, and ensuring long-term sustainability.

Want a green future? Call a geoscientist

Geosciences have historically played a crucial role in resource extraction and utilisation, which has played a significant role in the development of the current climate crisis (Gardiner et al., 2023). However, geosciences are equally essential to energy transition, moving towards renewable energy and decarbonisation, which fundamentally depends on natural subsurface resources (Figure 5).

1. Raw material supply. Achieving energy independence, reducing reliance on fossil fuels, and diversifying the energy mix necessitate the large-scale adoption of renewable technologies that are heavily reliant on the supply of raw materials:

• Lithium, cobalt, and nickel are essential for battery production

• Gallium is utilised in solar panels.

• Raw boron is employed in wind technologies. Geoscientists’ expertise, knowledge, and technological capabilities are crucial for estimating reserves, planning, and optimising the responsible and sustainable sourcing of these materials, thereby ensuring the viability of energy projects.

2. Low carbon geoenergy. Diversifying the energy mix involves introducing low-carbon energy sources. The geothermal industry harnesses the Earth’s heat to produce heating and electricity. Nuclear reactions, derived from uranium and plutonium, produce fission energy used for electricity generation. However, radioactive waste management and decommissioning remains a challenge.

3. Energy storage. Ensuring a stable energy supply given the hard to predict availability of renewable energy sources, due to seasonal and geographic constraints, requires various storage options to provide a buffer against fluctuations.

4. Waste management. CCUS or CCS isessential to achieving net zero emissions objectives. The hard to abate CO2 emissions captured from carbon-intensive industries are permanently sequestered within geological formations, typically in porous reservoir rocks, saline aquifers or depleted reservoirs, and less frequently in magmatic rocks.

Geosciences are an essential tool for the energy transition; geoscientists have a thorough understanding of the natural processes central to climate change, such as the CO2 cycle and greenhouse effects. They understand the challenges in finding the primary resources that will fuel energy transition and are thus instrumental in developing technologies and solutions to unlock sustainable and responsible transition.

Transition to green: It takes a village

Finding a suitable path to meet the set targets is another challenge altogether. As a first step, it is crucial to properly circumscribe the problem before identifying any potential solutions. Grasping the complexities of the energy transition requires a comprehensive view, allowing for the identification of key pain

points, interconnections, and dependencies. Geosciences and energy are not just fields of study; they are at the very centre of global issues, driving political, economic, and environmental decisions. Many of us are drawn to this field precisely because of its complexity and the profound geopolitical impact it carries. It is only when we understand the broader picture that the problem can be addressed by decomposing it into smaller, more manageable issues that can be tackled by different stakeholders.

But understanding alone is not enough. The transition will not happen in a vacuum; it needs unfold in a world where business is still largely driven by profit. While the urgency of climate change demands immediate action, the reality is that industrial decarbonisation is often shaped by economic incentives, not just environmental ideals. Shifting from a profit-only model to one that also prioritises sustainability is a major challenge. To make it happen, businesses need strong regulatory frameworks, aligned policies, and sometimes real pressure to innovate, adapt, and remain competitive in a changing world. Understanding how these constraints can also prove to be market opportunities is also paramount to the success of what is at hand.

No green light without policy power

Policy-makers play a crucial role in driving the energy transition, setting the course and pace, and creating the right legal framework to support industrial shift at an accelerated rate. In Europe, the Green Deal aims at making Europe the first climate-neutral world region by 2050. It includes a wide range of policies and measures to reduce greenhouse gas emissions and promote renewable energy. Two of the latest examples at the time of writing this paper are: EU proposals for a cross-border energy infrastructure project, worth up to €600 million, and the £22 billion plan to support CCS. Several other initiatives aimed at improving the energy mix, capturing and storing CO2 met with interest and success in the year, supporting the development of net zero industrial hubs.

One result of these policies is the number of ‘clean-energy’ start-ups created in the world. Favourable environment and policies lead to the creation of new firms, bringing disruptive technologies to the market and driving energy transition (Figure 6).

Figure 5 The use of the subsurface for technologies associated with the energy transition (Gardiner et al., 2023).

Need more time to reach net-zero? CCS is here. Greenwashing or game-changer?

As the world races to meet climate targets, CCS has emerged as a key technology, drawing geoscientists from the oil and gas sector due to the possible knowledge transfer and similarities with exploration and production. While CCS offers a real-world solution to sequester CO2 in depleted oil and gas reservoirs or saline aquifers, its role in the energy transition is sometimes the topic of heated debate. Some view it as a temporary fix, buying time to decarbonise harder-to-abate industries, while others question if it is just another form of greenwashing.

While CCS can help to mitigate emissions in the short term, it should not be viewed as the end-all solution, enabling us to continue emitting at current rates. Its role is not to compensate ongoing high emissions; rather, it is to serve as a necessary gap-management process, while we transition to renewable energy sources. CCS is best seen as part of the immediate toolkit for decarbonising sectors that cannot quickly switch to cleaner alternatives, such as cement, steel, and heavy industry.

This tactical, short-term decarbonisation solution, helping to eliminate unavoidable emissions while industries transition, is on its way to becoming the full-scale solution needed. Since 2005,

Figure 6 Clean energy start-ups created since 2000 in the world (IEA Database). Clean energy means start-ups working towards sustainable development, such as pollution control, waste management and green consumer goods, but also topics related to energy sectors such as renewables, green buildings or electric vehicles.

the number of CCS projects has surged, with 782 new projects announced between 2015 and 2024 (IEA 2024). However, the challenge remains: is it enough to bridge the gap, or is it merely a crutch to delay deeper systemic changes?

Also, CCUS has met with setbacks such as political resistance, protests, and economic hurdles. This can be understood: after all, its roots lie in enhanced oil recovery (EOR), an approach developed during the 1970s oil crises to extract more oil from existing fields. Furthermore, the background or current involvement of several CCS operators in the oil and gas industry has fuelled perceptions that these projects may simply justify continued extractive practices.

For all its history in the fossil fuel industry, the potential of CCS for global warming is clear. The foundational technology is proven, with contributions making full-chain CCS feasible. This potential is currently underused, as the industry lags far behind its 2030 target of capturing 1 Gt of CO2 annually, with only 0.045 Gt captured and 0.001 Gt removed from the atmosphere in 2022 (Figure 7). According to the IEA’s Net Zero Roadmap, the current project pipeline could capture around 0.4 Gt of CO2 and store 0.42 Gt annually by 2030 — a mere 40% of the 2030 goal for CCUS (International Energy Agency,

Figure 7 Carbon Capture, Utilisation and Storage (CCUS) projected capture capacity to reach net zero emission 2030 target versus announced and operational capture capacity (IEA, 2024).

2024). These delays can be attributed to factors such as long permitting processes, high operating costs, and limited social acceptability.

CCS is highly sensitive to market volatility and political instability. While some in the oil and gas sector may question its economic viability, we must shift our perspective. To accelerate CCS, strong policies and improved market conditions are crucial. This includes supporting CCS hubs, creating better market incentives, and expanding projects in emerging markets. CCS must be recognised as a critical industry for managing CO2 emissions; we must shift from extraction to waste management – just as vital for society as recycling has proven to be.

For geoscientists transitioning from oil and gas to CCS, the shift is significant. While technical skills may overlap, the key difference lies in project development and management: in traditional exploration and production, the goal is to seek positive surprises in subsurface exploration. With CCS, the focus is on preventing surprises over long periods. With this perspective, it is essential to repurpose existing knowledge and technologies to make CO2 storage successful.

The next chapter for geoscientists: from powering progress to shaping a sustainable legacy

Tracing the history of energy sources, from biomass to coal, oil, gas and now renewables, tells a story we know well: energy systems evolve (Figure 8). So do we. Geoscientists have been at the core of every major energy shift, and the transition ahead will be no different. Resistance to change is nothing new, it is part of human nature and the history of our profession. But change always comes, and this time, it is being driven by an undeniable reality: the planet is warming up.

For over a century, geoscientists have fuelled economic growth, industrialisation, and global prosperity through the extraction of subsurface resources. Our expertise shaped the modern world. But today, we find ourselves at a turning point. The knowledge and skills that once enabled the oil and gas boom now place us at the heart of the energy transition. Geoscientists bring a unique perspective, a deep understanding of the Earth, its processes and of the status of its resources. We grasp the intricacies of the carbon cycle, the availability of critical minerals for electrification, and the geological complexities of CO2 storage. This awareness makes us not only relevant, but essential,

to navigating today’s most pressing environmental and energy challenges.

Yet the context and the expectations have profoundly shifted. The energy transition is not just a technical transformation; it is a cultural and ethical shift as well. As geoscientists, we are being called to rethink our relationship with the subsurface: to act not just as explorers, but as stewards. Whether it is finding and securing safe CO2 storage, harnessing geothermal energy, responsibly producing critical minerals, or extracting oil and gas more efficiently and cleanly as part of a transitional energy mix, geoscientists are essential to this next chapter.

The old recipes no longer apply in a world shaped by emergency and uncertainty. But therein lies our opportunity: the energy transition is a fertile ground for innovation. It invites geoscientists to push boundaries, to bring decades of scientific knowledge into new domains, and to create breakthrough solutions. For this to happen, leadership must empower the next generation — by nurturing talent, supporting research, and fostering inter-disciplinary collaboration.

Meeting the scale of this challenge requires overcoming silos, across technical domains and even beyond, across segments: geology, engineering, economics, law, sociology. Only by connecting the dots can we develop solutions that are as comprehensive and adaptive as the transition demands.

Sustainability concerns everyone. It will not happen without collaboration. It will not happen without collective support. Geoscientists can contribute to promoting sustainability by disseminating knowledge (Ringrose, Amundsen and Landrø, 2024), not only through science and innovation but also through outreach. By informing policymakers and the public about the reality of resource scarcity, the importance of recycling, the complexity of the energy mix, and the true urgency of climate change, we can build broader awareness and momentum for action.

The transition is underway. The question is no longer if it will happen, but how — and with whom?

So the question is not whether the future needs geoscientists, it does. The real question is: what kind of geoscientist will you choose to be?

Will we stay steeped in the models of yesterday, or will we embrace the complexity of tomorrow’s challenges – environmental, social, technical, and ethical?

Figure 8 Energy transition through 200 years based on historical primary energy consumption projections from Vaclav Smil and current data from bp’s Statistical Review of World Energy (Rahman et al., 2023).

Now is the time to bring not only our skills but also our ecological consciousness, our adaptability, and our collective intelligence to the forefront. We are no longer just finding resources. We are shaping the legacy we leave behind.

Conclusion

Geoscientists stand at a critical juncture of energy and sustainability. The energy transition is not merely a technical challenge but a profound cultural and ethical shift. With their unique expertise and perspective, geoscientists are well-equipped to help navigate this transformation. Make no mistake: climate change is here, and it will continue to escalate unless addressed. Moving forward requires overcoming silo mentality and fostering true interdisciplinary collaboration. Our role as geoscientists does not stop at science, it extends to outreach, education, informing both policymakers and the public.

Because here is the truth: in a world flooded with fake news, misunderstandings, and oversimplified narratives, the voice of science, and especially of geosciences, is more essential than ever. From awkward afterwork conversations to major political decisions, the way people perceive our field shapes its future.

The energy transition is no longer a question of if, but who will lead it. We believe geoscientists must rise to the occasion. Not just as experts, but as communicators, collaborators, and changemakers.

The time to act, and to speak up, is now.

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Geothermal is becoming key in the renewable energy transition

Kim Gunn Maver1* and Thomas Møgelberg1 explain why many different applications of geothermal energy will develop rapidly in the coming years.

Introduction

The world is facing a significant challenge decarbonising the heat supply which is dominated by non-renewable energy sources. Meanwhile, geothermal energy stands as a potential source of renewable energy that can address most heating needs (Figure 1).

The interest in geothermal energy is rapidly increasing, and its usage is predicted to significantly grow in the coming years for district heating but also for district cooling, industrial usage, and electricity generation as part of a green transition and reduction in CO2 emissions (EGEC, 2024).

The European Parliament’s plenary vote on January 18, 2024, led by Professor Krasnodębski, MEP of the European Conservatives and Reformist Group, has re-enforced the support for a European geothermal energy strategy. The resolution clearly outlined the benefits of geothermal energy solutions, stating:

‘[…] geothermal energy offers long-term benefits that can outweigh the high upfront costs associated with its development, such as it being a sustainable source of energy with a low environmental impact, stable and predictable energy costs, low operating costs, long lifespan and reliability that creates business and employment opportunities in local communities, and helps to reduce dependence on imported fuels.’

The resolution concludes by outlining ‘The potential of geothermal energy to make a substantial contribution to attaining key strategic objectives within the EU, including reaching climate targets by decarbonising different industrial sectors,

bolstering the EU’s open strategic autonomy by strengthening energy security needs, eliminating fossil-fuel dependencies on unreliable third countries, such as Russia, increasing the competitiveness of European industries and empowering consumers thanks to an affordable and reliable supply of heat and electricity.’

Recently there has also been confirmation that Dan Jørgensen, Commissioner for Energy and Housing from the European Commission, will publish the Geothermal Action Plan in Q1 2026 as he acknowledges that (EGEC, 2025a):

‘.... geothermal energy has an important role to play in the decarbonisation of the EU’s energy system’.

and

‘The potential of geothermal energy has been so far hindered by challenges related inter alia to planning, permitting, skills, financing and availability of data’.

For district heating, geothermal energy has direct application. Right now, many countries experience political momentum to both expand the district heating network and to decarbonide it (Figure 2).

This increasing interest in geothermal energy is natural; geothermal ticks all the boxes of the energy challenges (Figure 3), and the investment in geothermal energy is set to grow significantly (Figure 4). This results in growth expectations that match the capacity additions experienced in wind and solar over the past decades (Figure 5).

The interest and development in geothermal are expected to be persistent. Observing the following very general geothermal

1 Green Therma

* Corresponding author, E-mail: kgm@greentherma.com

DOI: 10.3997/1365-2397.fb2025049

Figure 1 Highlighted areas indicating the potential for geothermal energy within global energy use, sources of heat, and heating use (IRENA, IEA, and REN21, 2020).

energy fun facts, the geothermal business case is obvious (Figure 6).

Harvesting geothermal energy

This increased focus on geothermal energy is supported by the continuous technology development for extracting heat, especially for new closed-loop solutions that represent the next generation of geothermal energy solutions known as Advanced Geothermal Systems (AGS), (Figure 7).

Hydrothermal solution

Historically, the use of geothermal energy started with conventional doublet hydrothermal well solutions that use one well to produce formation water and another well to inject cooled formation water at a distance, typically at a vertical depth of 1-3 km. The solution is dependent on a geothermal reservoir’s thickness and parameters such as porosity, permeability, and geochemistry to ensure hydrologic connectivity between the two wells to maintain heated formation water production.

These geological reservoir requirements limit the application of the solution. Generally, sustaining the delivery of heated fluids above 70-100 °C is not possible due to compacting sediments reducing or removing the hydrologic connectivity with depth.

Enhanced Geothermal Systems

Enhanced Geothermal Systems (EGS) are used when there is a requirement to enhance permeability and porosity in a conventional hydrothermal system by fracturing the rock and creating an artificial reservoir through hydraulic, chemical, and thermal stimulation. However, fracturing the rock to enhance injectivity and formation connectivity carries the risks of compromising groundwater aquifers, damaging the geological formation, and inducing seismicity with the potential consequence of damaging surface infrastructure and buildings.

EGS is thus not always working. Due to its risks, it is not always acceptable to use which limits its usage.

Figure 2 Several European nations see political momentum building to significantly expand and decarbonise district heating networks.

Figure 3 Energy challenges solved by geothermal energy.

Advanced Geothermal Systems

Closed-loop solutions represent the next generation of geothermal energy solutions (AGS), introducing energy extraction from a closed-loop system through conductive heat transfer as opposed to convective heat transfer in hydrothermal solutions and EGS. It constitutes an innovative approach to geothermal energy extraction that functions without the need for particular geological properties and requirements, providing flexibility when choosing project sites and aiming to overcome the challenges and risks related to conventional doublet hydrothermal solutions and EGS. This enables the application of AGS virtually anywhere and limits development risks related to resource availability (IEA, 2024). It can also be used for heat storage.

Several new innovative closed loop geothermal well solutions and designs are currently in development (Think GeoEnergy, 2024). The solutions can be divided into two main categories: a single well using a coaxial pipe-in-pipe solution with a possible slanted/horizontal section and two or more mono-pipe wells connected at deep intersection points.

Figure 8A and B presents the single well solution, where a fluid circulates through the subsurface in a co-axial pipe. Here, cold water is circulated down through the outer closed casing and returned as heated water inside the inner tubing.

A key issue in the co-axial solution is that the heat loss of the returning fluid will be high if not properly thermally insulated. To accommodate this issue, effective solutions have been proposed (Maver et al., 2023). To improve the harvesting of heat, some solutions develop networks of proprietary thermally conductive material around the wellbore, which is anticipated to allow wellbores to absorb more heat compared to standard geothermal wells (Jacobs, 2024). The addition of a long horizontal/ slanted section to the well will also significantly improve the heat harvesting area (Figure 8B), (Maver et al., 2023). Hereby, the limitation of thermal conduction compared to convection is overcome.

Figure 8C and D illustrates mono-pipe closed-loop solutions. These solutions require two or more wells to be connected in the subsurface to circulate the fluid. The parallel boreholes with several km long horizontal sections might be achieved with multilateral drilling. These sections are connected to two deep vertical boreholes, forming a circuit (Figure 8C), (Longfield et al., 2022). An alternative way to realise the solution is with deviated well pairs (Figure 8D). Here, legs are deployed from a service well and thereby connect to the injection and production wells to create closed heat harvesting loops (Vouillamoz, 2023).

Figure 6 Geothermal energy potential footprint and abundance (IEA, 2024; Adapted from Lovering et al., 2022 and National Renewable Energy Laboratory; Beard and Jones, 2023).

Figure 5 Estimated geothermal capacity installation versus historic wind and solar capacity installation (IEA, 2024; IRENA, 2024).

Figure 4 Global investment in next-generation geothermal energy (IEA, 2024).

The closed-loop solutions have a number of operational benefits that make them commercially attractive including the ability to reach a depth where it is possible to find a high temperature for direct usage without the need of heat pumps on the surface (Table 1).

Key parameters for closed-loop solutions

Three main parameters

Previously, closed-loop solutions were described as having application potential virtually anywhere and resource availability is practically no risk. However, three key parameters impacting the commercial viability of the solutions need to

be considered: 1) The geothermal temperature gradient and thereby the depth at which a certain temperature is reached, 2) the thermal conductivity of the geological formation controlling the heat flow to the well, and 3) the rock type which impacts the drilling and completion performance and thus determines the number of days it takes to drill and complete a well.

Geothermal temperature gradient

The geothermal temperature gradient varies with geographical location, is much lower onshore than offshore, and shows significant variations depending on the geological setting. The temperature from the continental crust has a median gradient of 34 degrees °C/km (HeatFlow, 2025). The Rhine Graben in Germany and France, e.g., has an above average temperature gradient of 50-58 °C/km (Dezayes et al., 2008), whereas Fennoscandian Shield has a temperature gradient below average of 8-15 °C/km (Kallio, 2019).

In most geological settings, the geothermal temperature gradient is known and can be planned for in advance. To accommodate a low gradient, the well has to be drilled deeper.

Thermal conductivity

Thermal conductivity of the rock correlates with the produced amount of thermal energy. Thermal conductivity varies with the composition of the rock and is controlled primarily by the relative effectiveness of heat transport through grain-to-grain paths of the rock. The presence of pores in the rock will therefore limit the heat transport. A rock type’s range of thermal conductivities depend on the grain size, grain composition, material between the grains, pore fluid composition, pore size and porosity (Robertson, 1988).

The thermal conductivity of rocks can be deduced from existing wells with e.g. core samples and cuttings analysed in a laboratory with lithological descriptions and geophysical well

Figure 8 Different closed-loop geothermal well configurations.

Figure 7 Geothermal technology solutions for harvesting the earth’s heat.

logs. Summarised observed thermal conductivity and mechanical properties from 70 best published papers demonstrate coal having the lowest thermal conductivity of 0.2 W/(mK) and sandstone having the highest thermal conductivity of 7.1 W/(mK) (Lee et al., 2015). Rocks usually falls within the range of 0.4–7.0 W/(mk) (Cermak and Rybak, 1982).

A rock can have a large variation in thermal conductivity, complicating the optimal positioning of the geothermal well even in cases of nearby analogue wells. However, the well needs to be situated at an optimal stratigraphic level to achieve a thermal conductivity that can ensure an adequate energy output over time. One solution, though expensive, is to drill a pilot hole and use a needle probe method to gather information for the development of a thermal conductivity model of the well and upon that decide on the well’s final completion.

Mapping thermal conductivity

Ideally, mapping the thermal conductivity should be part of the initial well plan.

ENERGY ACCESS

Laboratory tests have shown a correlation between thermal conductivity and compressional wave velocity (Pimienta et al., 2014). There are examples of how this correlation has been used to predict thermal conductivity from seismic interval velocities, including a simple linear relationship between thermal conductivity and seismic interval velocity for clastic sedimentary rocks (Duffaut et al., 2018). However, this application will be dependent on the quality of the seismic data, including frequency content, to gain thermal conductivity data at a usable level.

Further research into mapping thermal conductivity of the subsurface from seismic data would offer substantial benefits for the commercial implementation of closed-loop solutions.

Drilling rate

The commercial use of geothermal energy is very dependent on drilling costs, which are related to the depth, well type, geological setting, and completion requirements. The rate of penetration (ROP) when drilling is important because it — together with

Very limited energy usage The main electricity requirement is a circulation pump.

Constant energy source It is an uninterrupted and constant energy source available

ENVIRONMENTAL IMPACT

Virtually eliminating the need for transport

No rare minerals and metals requirement

Minor surface footprint

Limited CO2 emissions (and high energy efficiency)

With limited geological requirements, the geothermal well solution can theoretically be located anywhere close to the end user, eliminating the need to use energy for distribution.

Standard pipes and equipment are used for a geothermal well completion and does not require any rare earth minerals and metals.

For direct usage of the heated water, the surface installation is limited in size.

The main power component needed to produce the heated water is a circulation pump.

Limited water usage Limited working fluid usage; it is a closed-loop system with no circulation in geological formations.

PROJECT COST

Durability As closed-loop solutions do not circulate fluids within the reservoir section, issues known from doublet hydrothermal solutions can be mitigated. This includes the system lifetime, where systems in most cases can be designed to last for more than 50 years (Vouillamoz, 2023; Maver et al, 2024).

Predictable and low operational cost

Efficient and safe execution

No failed wells

SUBSURFACE IMPACT

Following the installation of the geothermal well completion (which requires no downhole equipment for operation), limited maintenance of downhole pipes and surface installations is required, minimising the maintenance cost and resulting in a low operational cost.

The utilisation of original oil and gas industry technology, know-how, and vast experience including recent US onshore unconventional drilling cases ensures an efficient and safe well execution.

With no requirement of an active hydrothermal aquifer with specific flow characteristics, the well will always produce heat. There is the potential for uncertainty relating to temperature and MWth output.

No fracturing of the subsurface As it is a completely closed loop solution, and no enhancement of the subsurface is done, there is no need for fracturing the subsurface to create hydrologic connectivity.

No micro-seismicity induced Without the requirement of stimulating a hydrothermal reservoir, no seismicity is induced.

No ground water pollution Without fracturing, there is also no risk of interfering with and polluting groundwater reservoirs.

Table 1 Benefits of a closed-loop solution.

the mobilisation and demobilisation of the rig — significantly impacts the number of days before which a well is completed and thereby the overall well cost.

ROP is dependent on drill bit type and condition, formation properties, drilling mud properties, weight on bit, rotary speed, and hole cleaning efficiency. The ROP exhibits a large variation with examples as low as 2 m/hour in granite and as high as 75 m/hour in salt.

Due to this range in ROP, the commerciality of geothermal projects is dependent on the exact rock type targeted. Any ROP-related improvements, irrespective of rock type, will have a significant impact on the use of geothermal energy.

Oil and gas industry

Drilling technologies are usually developed in the oil and gas industry and then transferred and adapted for the benefit of the geothermal industry (Cultrera, 2016).

Improving drilling operations shows significant promise. The onshore unconventional shale gas industry in USA has proven that ingenuity can successfully transform an industry both technically and economically through best practices and improved well designs.

Since 2010, designs have demonstrated that it is possible to drive a major production increase in oil and gas (EIA, 2016). By planning campaigns of hundreds or even thousands of wells at a time with a high degree of repeatability, the operators adopted the factory production mentality to field development, impacting both efficiency and cost significantly.

The oil and gas industry could be instrumental in encouraging future geothermal developments; up to 80% of the investment required in a geothermal project involves capacity and skills that are common in the oil and gas industry. With the engagement from policymakers and from the oil and gas industry, it is estimated that costs for next-generation geothermal wells could decrease by up to 80% by 2035 (IEA, 2024).

By placing greater emphasis on and expanding a dedicated and specialised geothermal well industry, adopting a manufac-

turing mentality during drilling, and developing larger projects to capitalise on a localised learning curve, it is expected that drilling and completion costs will be reduced significantly in the future.

For geothermal wells, it has been reported that in a high-temperature, deep granite well, an average ROP of approx. 20 m/hour was achieved by using polycrystalline diamond compact (PDC) drill bits. The drilling performance fits an expected learning rate of 35% for drilling time improvement, indicating significant advances in performance and cost in the future (Fervo, 2024). This learning curve phenomenon has also previously been observed for larger European geothermal projects (Latimer & Meier, 2017).

The geothermal future

The use of geothermal energy will increase, and even so more with closed-loop solutions, put us in control of our heating and energy security, giving businesses, towns, governments, and communities access to the abundant, untapped green energy beneath our feet.

With a continuous push to better understand the subsurface, develop drilling capabilities, have a relevant rig fleet available, use geoscience capabilities and oilfield service capabilities, the use of geothermal energy has just started and is set to show significant growth.

Focus has been on district heating, but geothermal energy has diverse application potential, including application for direct industrial usage, electricity generation, heat storage, and district cooling (Figure 9).

Many recent publications about geothermal revolve around the direct use of geothermal energy in industrial applications. Examples include heating greenhouses in Austria using a well depth of 3.5 km delivering 125°C water on the surface as well as heating Janssen Pharmaceutical Campus using 85°C water from a well depth of 2.4 km (EGEC, 2025b).

Even for the most mature applications of geothermal energy, the decarbonisation potential of district heating is

Figure 9 The heating and cooling energy need worldwide.

largely untapped (IEA 2022). Using closed-loop solutions with near-global applications, it would be possible to significantly impact the decarbonisation of district heating, district cooling, industrial heating requirements, and electricity production. This would aid the move towards ‘zero’ CO2 emissions by providing a nearly unlimited source of heat directly from the earth’s interior — a source that is both reliable and cost effective.

Acknowledgements

Thank you to Louise Broen Larsen for reviewing the manuscript.

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CALENDAR OF EVENTS

7-11 Sep 32 nd International Meeting on Organic Geochemistry (IMOG) www.imogconference.org

9-11 Sep Second EAGE Conference and Exhibition on Guyana-Suriname Basin www.eage.org

14-18 Sep Seventh International Conference on Fault and Top Seals www.eage.org

15-17 Sep Fifth EAGE Workshop on Assessment of Landslide Hazards and Impact on Communities www.eage.org

15-18 Sep AOW Energy 2025 www.aowenergy.com

16-18 Sep The Middle East Oil, Gas and Geosciences Show (MEOS GEO) www.meos-geo.com

17-18 Sep First EAGE Workshop on Energy Transition in Latin America’s Southern Cone www.eage.org

22-24 Sep Sixth EAGE Borehole Geology Workshop www.eage.org

29 Sep1 Oct Second AAPG/ EAGE Mediterranean and North African Conference (MEDiNA) medinace.aapg.org

29 Sep1 Oct Eighth EAGE Borehole Geophysics Workshop www.eage.org

6-8 Oct Second EAGE Data Processing Workshop www.eage.org

6-8 Oct Empowering the Energy Shift - The Role of HPC in Sustainable Innovation: Ninth EAGE High Performance Computing Workshop www.eage.org

6-9 Oct GEOTERRACE-2025: International Conference of Young Professionals www.eage.org

14-16 Oct First EAGE Conference on the Future of Mineral Exploration: Challenges and Opportunities www.eage.org

15-16 Oct 3 rd EAGE/SUT Workshop on Integrated Site Characterization for Offshore Renewable Energy Melbourne Australia

CALENDAR OF EVENTS

18-20

13-14

2-4

8-11