First Break May 2025 - Global Exploration

VO L U M E 4 3 I I S S U E 5 I M AY 2 0 2 5

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Global Exploration EAGE NEWS Welcome to Toulouse CROSSTALK A voyage around TotalEnergies TECHNICAL ARTICLE Characterisation of compacted sandstones

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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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Intra-Draupne sandstone. Is it present in the Marulk Basin, just north of the Statfjord field?

Editorial Contents 3

EAGE News

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Personal Record Interview — Mahad Nadeem Janjua

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Crosstalk

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Industry News

Technical Article

PUBLICATIONS MANAGER Hang Pham (publications@eage.org) MEDIA PRODUCTION Saskia Nota (firstbreakproduction@eage.org) Ivana Geurts (firstbreakproduction@eage.org) ADVERTISING INQUIRIES corporaterelations@eage.org EAGE EUROPE OFFICE Kosterijland 48 3981 AJ Bunnik The Netherlands • +31 88 995 5055 • eage@eage.org • www.eage.org EAGE MIDDLE EAST OFFICE EAGE Middle East FZ-LLC Dubai Knowledge Village PO Box 501711 Dubai, United Arab Emirates • +971 4 369 3897 • middle_east@eage.org • www.eage.org EAGE ASIA PACIFIC OFFICE EAGE Asia Pacific Sdn. Bhd. UOA Centre Office Suite 19-15-3A No. 19, Jalan Pinang 50450 Kuala Lumpur Malaysia • +60 3 272 201 40 • asiapacific@eage.org • www.eage.org EAGE LATIN AMERICA OFFICE EAGE Americas SAS Av Cra 19 #114-65 - Office 205 Bogotá, Colombia • +57 310 8610709 • americas@eage.org • www.eage.org EAGE MEMBERS’ CHANGE OF ADDRESS Update via your MyEAGE account, or contact the EAGE Membership Dept at membership@eage.org

27 Reservoir characterisation of compacted sandstones in the Osmancık Formation, Thrace Basin, Türkiye Taner Arpacı, İsmail Ömer Yılmaz, Serhat Akın and Emin U. Ulugergerli

Special Topic: Global Exploration 37

Egypt’s West Mediterranean Sea – a global exploration hotspot Mark Hamilton

43 Oil and gas exploration hotspots in Asia Pacific: Data-driven opportunities in Malaysia, Indonesia, and India Tad Choi, Nicolas Hand, Subodh Notiyal, Verity Agar and Duncan Woolmer 49

Global exploration – what role do hotspots play?

Bob Fryklund, Bill Mynatt and Clare Barkere

51 Intra-Draupne sandstone. Is it present in the Marulk Basin, just north of the Statfjord field?

Carl Fredrik Gyllenhammar 57

Ultra-deepwater: The lowest risk exploration Neil Hodgson, Karyna Rodriguez and Lauren Found

61 The Pelotas Basin: A rising global exploration hotspot Sindre Bull-Jansen, Javier Martin, Christian Strand, Karen Purcell and Mustafa Al-Waily 67 Supporting global exploration trends with geoscience insight Erling Frantzen, Anna Lougon and Joe Zhou 75 What does the energy mix look like in a truly achievable transition and where will the secure energy needed come from to power the world?

Mike Lakin 86

Calendar

FIRST BREAK ON THE WEB www.firstbreak.org ISSN 0263-5046 (print) / ISSN 1365-2397 (online)

cover: Remotely operated vehicle searches for oil and gas resources in a deep sea environment. This month First Break showcases global hot spots.

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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 Laura Valentina Socco President

Christian Henke Secretary-Treasurer

Sanjeev Rajput Vice-President

Diego Rovetta Membership and Cooperation Officer

Peter Rowbotham Publications Officer

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

SUBSCRIPTIONS First Break is published monthly. It is free to EAGE members. The membership fee of EAGE is € 85.00 a year including First Break, EarthDoc (EAGE’s geoscience database), Learning Geoscience (EAGE’s Education website) and online access to a scientific journal.

Maren Kleemeyer Education Officer

Martin Widmaier Technical Programme Officer

Andreas Aspmo Pfaffhuber Chair Near Surface Geoscience Circle

Companies can subscribe to First Break via an institutional subscription.

Every subscription includes a monthly hard copy and online access to the full First Break archive for the requested number of online users.

Orders for current subscriptions and back issues should be sent to First Break B.V., Journal Subscriptions, Kosterijland 48, 3981 AJ Bunnik, The Netherlands. Tel: +31 (0)88 9955055, E-mail: subscriptions@eage.org, www.firstbreak.org.

First Break is published by First Break B.V., The Netherlands. However, responsibility for the opinions given and the statements made rests with the authors.

COPYRIGHT & PHOTOCOPYING © 2025 EAGE All rights reserved. First Break or any part thereof may not be reproduced, stored in a retrieval system, or transcribed in any form or by any means, electronically or mechanically, including photocopying and recording, ­without the prior written permission of the publisher.

Yohaney Gomez Galarza Chair Oil & Gas Geoscience Circle

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PAPER The publisher’s policy is to use acid-free permanent paper (TCF), to the draft standard ISO/DIS/9706, made from sustainable ­forests using chlorine-free pulp (Nordic-Swan standard).

Carla Martín-Clavé Chair Sustainable Energy Circle

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HIGHLIGHTS

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Great Technical Programme planned for Toulouse

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Naples perfect setting for NSG 2025

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Chairs talk up GET

Digital future for First Break Announcement from CEO Marcel van Loon

I would like to take this opportunity to share with members that we are planning big changes for First Break in 2026 details of which we should be in a position to announce at the Annual in June.

The Board have accepted that, like many similar publications, sustaining a monthly printed version of the journal is no longer economically viable in terms of print, international distribution costs and advertising revenue trends. Digital publishing options have therefore been considered.

We believe that we have come up with a very dynamic solution that honours members’ expectations of First Break in terms

of providing first class technical content, industry news and analysis, and comprehensive coverage of our Association’s services, events, etc. At the same time the new format will provide additional opportunities for companies and organisations looking for exposure to our community through advertising, partnerships, sponsorships, etc.,

thereby meeting our revenue objectives.

Furthermore, less printing, packaging and mailing of First Break aligns with our mission to reduce the carbon footprint of the Association’s activities.

We are proposing that beginning in 2026 there will be printed editions of First Break every quarter. This will be supported by an entirely reimagined online platform designed to provide a continuous reference point for members covering every aspect of our community in a variety of digital formats, the contents of which are under discussion but podcasts, videos, live coverage, etc. will certainly be in the mix linked where appropriate to the printed First Break and potentially EarthDoc. Once we have established the basic model, we will be inviting you, our members, to participate in a survey to establish what kind of content you would like to see in the new set up.

I hope members will join me in being excited at this initiative which can greatly improve our communications as the role of geoscience and engineering adapts to the energy transition.

Online only issues in 2025 In anticipation of the upcoming changes, please be aware that this year there will only be nine printed issues of First Break. In the months of July, August, and December, the journal will only be available online, still published in the current format at the beginning of the month.

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EAGE NEWS

Time to vote in annual elections The annual Ballot to select the Board members is up and running, and we want you to be a part of it.

The Board plays a crucial role in shaping the direction of our Association and developing policies that serve your interests.

Your participation in the ballot is important as it is when you have a say in how our Association operates on your behalf.

Check your inbox for a personalised invitation with instructions on how to vote.

Here are this year’s candidates.

Mike Branston – Vice President Dr Mike Branston is a highly accomplished geophysicist with 27 years of global experience. He holds a BSc in Geophysics with Geology from Liverpool University and a PhD in Geophysics from Keele University, specialising in 4D microgravity and micro seismicity. In 2006, he was awarded chartered geologist status by the Geological Society of London.

In Dr Branston’s professional journey he has taken on pivotal roles in various countries, including Norway, Malaysia, the UK, and Qatar. Currently, he serves as the new energy domain lead at SLB Exploration Data, based in Kuala Lumpur, Malaysia. His role involves advising and supporting geophysical activities related to the new energy sector on a global scale.

Throughout his career, Dr Branston has been dedicated to designing technical solutions for subsurface imaging and monitoring challenges. He has published extensively and has been actively involved in several geophysical societies, primarily the EAGE. He has chaired and co-chaired numerous technical committees, including EAGE GET and PETEX conferences, and he has been a technical reviewer and session chair for EAGE and SEG annual conferences. Additionally, he has taught courses on advanced marine acquisition techniques for EAGE and SLB’s NExT. Dr Branston is also a co-inventor of five patent applications related to carbon storage monitoring and has received funding for geophysical monitoring projects.

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Timothy Tylor-Jones – Vice-Chair Oil and Gas Geoscience Circle Timothy Tylor-Jones is a senior geoscientist with over 21 years of experience. Currently a senior geophysicist and team lead at bp, he focuses on low-carbon gas projects for the energy transition. He actively involves in mentoring and building internal capability at bp.

Tylor-Jones is a chartered geologist and chartership assessor with the Geological Society and a certified petroleum geologist with AAPG. He is co-author of A Practical Guide to Seismic Reservoir Characterisation (Springer, 2023) and a regular EAGE contributor.

Tylor-Jones says: ‘I believe this Circle plays a vital role in advancing our profession, supporting technical excellence, fostering collaboration, and ensuring geoscientists are actively contributing to the energy transition.

I joined the Circle in October 2024 and, while early in my tenure, I’ve been a longtime supporter of EAGE and its mission to promote innovation, knowledge exchange, and professional fellowship. These values strongly reflect my own. I see the vice chair role as a chance to support the chair, help build momentum across our initiatives, and bring visibility to the great work being done by our members.’

Benjamin Bellwald – Vice-Chair Sustainable Energy Circle Benjamin Bellwald is a senior geoscientist with 13 years of experience in managing complex projects related to low-emission challenges, marine geohazards, geotechnical analysis for seabed infrastructure, seabed and subsurface characterisation, seabed engineering, and technology development.

Skillset includes excellent leadership, complex data interpretation and integration, data acquisition, inter-disciplinary result dissemination and high-impact publication.

Bellwald holds a bachelor degree in climate and water and a master degree 2025

in geology and geochemistry from ETH Zurich, and a PhD in marine geology and geophysics from University of Bergen.

Bellwald says: ‘I am currently co-chairing the EAGE Wind Energy Technical Community, and have previously been a committee member of the EAGE Special Interest Community on Decarbonization and Energy Transition. I am excited to contribute to and present myself in the role of vice-chair, Sustainable Energy Circle.’

Eric Verschuur – Publications Officer Eric Verschuur received his MSc in applied physics in 1986 and his PhD with honors in 1991, both from TU Delft. He is currently an associate professor in the Department of Geoscience at TU Delft.

Since 2016, he is the program director of the Delphi research consortium. His research focuses on geophysical exploration and monitoring for the energy transition and subsurface applications.

In 1997, he received the J. Clarence Karcher Award from SEG, and in 2006, he was honoured with the SEG’s Virgil Kauffman Gold Medal. He served as an associate editor for Geophysics from 2003 to 2013 and is currently on the editorial boards of the Journal of Seismic Exploration and the Journal of Geophysics and Engineering.

Since 2006, he has been a member of the EAGE Research Committee (chair 2013-2016). He was selected as the lecturer for the inaugural EAGE Education Tour in 2006, delivering a course on multiple removal, which he has since presented more than 50 times around the world.

Verschuur says: ‘As publications officer, I have the opportunity to contribute to this vital aspect of the EAGE organisation. My goal is to maintain the high standards of our scientific publications while ensuring that our First Break remains a vital pillar of delivering insightful and impactful articles to our community. Additionally, I will strive to achieve a balanced approach between physical and electronic publications to best serve our members.’

THE CHOICE IS CLEAR DUG MP-FWI Imaging

Conventional Kirchhoff migration workflow

Depth slice 50 m TVDSS

DUG MP-FWI IMAGING FOR NEAR-SURFACE RESOLUTION DUG MP-FWI Imaging uses the entire wavefield, including all free-surface multiples. Multiples, normally considered as problematic noise (especially in a shallow-water setting), illuminate the subsurface in complementary ways to primary reflections. The result is that the subsurface is sampled far more completely, and with a wider range of angles.

More signal. Higher resolution. Superior imaging. How illuminating!

info@dug.com | dug.com/fwi

2 km

This legacy dataset (late 1990s) was not acquired with shallow high-resolution in mind. It’s a conventional towed-streamer acquisition in a shallow-water environment.

EAGE NEWS

Get ready for the 86th EAGE Annual in Toulouse On 2–5 June 2025, we’ll welcome geoscientists and engineers from around the world to the MEETT Toulouse Centre for a week of innovation, learning, and connection under the theme Navigating Change: Geosciences Shaping a Sustainable Transition. Here’s a checklist of what you can expect.

Opening Session EAGE Annual 2025 opens with a high-level session featuring leading voices in energy, tackling key industry topics and celebrating excellence in geoscience and engineering through prestigious awards.

and Energy Transition, offering fresh perspectives on the shift to smarter operations and a sustainable energy future.

Technical Programme The heart of EAGE Annual 2025 lies in its rich and diverse Technical Programme, shaped by leading experts and built on high-calibre submissions from around the world (see interview on page 7 with Martin Widmaier, our Technical Programme Officer).

Workshops, Field Trips, Short Courses and Hackathon Before and after the main event, dive deeper with hands-on Workshops, Field Trips, Short Courses, and the popular Hackathon, running Sunday, Monday, and Friday. Whether you’re expanding your expertise or exploring new ground, these sessions offer a chance to learn from industry leaders, connect with peers, and put your skills into action.

Exhibition Discover what’s next in geoscience at the EAGE Exhibition, where over 200 exhibitors, ranging from industry leaders to innovative start-ups, will be showcasing cutting-edge tools, technologies, and research. Be sure to check out the theatre talks focused on Digital Transformation

Community and Student Activities EAGE Annual is a great moment for our community and students to come together, share ideas, and get inspired. Drop by the Community Hub for meetups, discussions, and activities designed to support learning and career growth.

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Social Programme Networking is one of the highlights everyone looks forward to. Whether it’s the Icebreaker Reception, the lively Conference Evening at Victor Hugo Market, or relaxed catch-ups over drinks and lunch, there are plenty of chances to connect.

Registered guests (your partner and family members) can join in too, with access to all the main events and a special tour of Toulouse.

Register now Visit eageannual.org for full details and to register. You can sign up for the full week, per day, or choose Conference or Exhibition only. To make the most of your time, consider the All Access package – it includes workshops, field trips, short courses, the hackathon, plus the Conference, Exhibition, Icebreaker Reception, and Conference Evening. Register before 15 May 2025 to take advantage of discounted fees!

EAGE NEWS

Aiming for unrivalled technical quality at the Annual in Toulouse

Technical Programme Officer Martin Widmaier (vice president, geophysical support, TGS), explains why the Technical Programme at the Annual in Toulouse will be special.

Tell us about this year’s theme.

Our chosen theme – Navigating Change: Geosciences shaping a sustainable transition – is very well reflected in the Technical Programme. We continue to facilitate knowledge transfer and technology development related to hydrocarbon exploration and production, i.e., energy security, while increasingly promoting the role and responsibility of the geoscientific and engineering communities with respect to renewable energies and a sustainable future.

What would you pick as the highlights this year?

Three highly relevant and popular themes stand out in this year’s Technical Programme: full waveform inversion (FWI), carbon capture and storage (CCS), machine learning (ML) and artificial intelligence (AI). FWI technology is making a huge impact on improved velocity building and subsurface imaging in geologically complex areas. The FWI-related sessions will cover recent advances in technology and the latest case studies from many basins. The sessions with a CCS theme will cover the full range from screening and site characterisation to site operations and monitoring. The high number of paper submissions related to ML and AI demonstrate that our industry is fully committed to the digitalisation path. The ML and AI sessions focus

on the separate disciplines to which the technology can be applied.

How does this year’s programme compare with recent Annuals?

The EAGE Annual Conference in Oslo last year in particular was a great event with a balanced programme covering many disciplines. The preparations for Toulouse will follow this successful recipe with only minor adjustments. However, I would highlight two notable changes.

First, TotalEnergies as host sponsor has made a significant contribution to this year’s event. The company was responsible for forming the Local Advisory Committee (LAC) with partner sponsors and invited industry representatives. The LAC worked on strategic programme aspects, discipline expansion, and added regional content facilitated by the French geoscientific communities.

Secondly, EAGE and SEG will emphasise the collaboration between the associations. EAGE has incorporated the four best papers from IMAGE 2024 into the schedule, and SEG/AAPG will follow with a ‘Best of EAGE 2025’ session at the IMAGE 2025 conference later this year.

How far does the programme accommodate EAGE’s three Circle member structure?

The technical programme clearly reflects the evolving focus and interests of EAGE’s three Circles, as it should! The Circle chairs – Yohaney Gómez Galarza (Oil and Gas), Andreas Pfaffhuber (Near Surface), and Carla Martín-Clavé (Sustainable Energy) – are members of EAGE’s Technical Programme Committee (TPC). As defined in EAGE’s by-laws, the three Chairs, together with me, ensure that we represent and support a wide range of disciplines. The Technical Programme also shows the positive impact of EAGE’s Technical Communities. Their members have been very active FIRST

Martin Widmaier.

in proposing and planning workshops and dedicated sessions.

Are there new topics or trends being introduced this year?

Sustainable energy and energy transition-related topics continue to be the most prominent trends and growth areas. I have already mentioned the CCS sessions as one of the Programme’s highlights.

Additionally, geothermal exploration and geothermal technologies will be a ‘hot’ topic. Last but not least, hydrogen as well as critical minerals, will be addressed during the conference. For example, we will have a dedicated session about exploration and production of unconventional lithium.

How does the Programme relate to our professional community?

Along with the Exhibition, pre- and post-convention workshops and the strategic agenda, the Programme should be very compelling for everyone - from senior management representatives to subject matter experts and our young professionals. It offers both learning and networking opportunities, and there is a lot of innovation and technical progress ongoing that is waiting to be shared amongst our professionals.

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EAGE NEWS

Are you up for this year’s Annual AI-focused Hackathon?

‘EAGE-Agents’ sounds like something from a Bond movie. In fact, it is the Hackathon being planned by our Technical Community on Artificial Intelligence on 1-2 June in Toulouse ahead of the Annual.

The mission, should you choose to accept it, will be designing, testing, and implementing agentic AI applications capable of autonomously processing real-world seismic data.

Not sure if this challenge is for you?

Giuseppe Amendola and Matthieu Guillouet, winners of the Hackathon ‘Coding to Net-Zero: AI for energy-efficient future’ last year in Oslo, recall their experience.

What motivated you to join the EAGE Annual Hackathon?

We were driven by the chance to collaborate with professionals from diverse backgrounds, tackle real-world challenges in geoscience and engineering, and develop innovative solutions using data science

and machine learning. The hackathon provided a dynamic setting to experiment with new ideas, learn from peers, and push the boundaries of problem-solving in our field.

What did you develop?

We came up with a generative AI solution for geoscience data called GeoEmbed.

This is an AI agent designed to create robust and efficient embeddings for geoscience applications. By analysing patterns in seismic images, well logs, attribute maps, and text descriptions using advanced AI models like vision transformers, it enables various applications.

For example, it can identify features in seismic data, such as gas chimneys or DHIs (Direct Hydrocarbon Indicators), using text or images as input.

How was the experience for you?

Throughout the hackathon, we learnt from highly skilled professionals who introduced us to cutting-edge AI challenges and solutions. Our project allowed us to explore new technologies, such as fine-tuning large GenAI models, giving us hands-on experience with the latest

Presenting Hackathon results in Oslo.

Matthieu Guillouet (left) and Giuseppe Amendola (right), winners of the Hackathon in Oslo.

advancements. Not only did this broaden our technical expertise but also deepened our understanding of the ongoing AI revolution and its impact on geoscience and engineering.

What about this year?

The EAGE Annual Hackathon 2025 offers a unique chance to explore how AI can transform seismic data processing.

Whether you’re an experienced coder or new to AI, the event presents tailored challenges that foster creative thinking and practical implementation.

To accept the Hackathon challenge, sign up at eageannual.org.

EAGE Education Calendar 1 JUN

COMPRESSIVE SENSING, EXPLAINED AND CHALLENGED, BY JAN DE BRUIN RESERVOIR ENGINEERING FOR HYDROGEN STORAGE IN SUBSURFACE POROUS MEDIA, BY GANG WANG

2 JUN

TOULOUSE, FRANCE

PART OF EAGE ANNUAL 2025

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 PLEASE VISIT WWW.EAGE.ORG AND WWW.LEARNINGGEOSCIENCE.ORG.

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EAGE NEWS

Fresh look at compressive sensing in seismic acquisition

ModelVision

Jan de Bruin (JdB VitalSeis) discusses his new short course being presented at the Annual meeting on Sunday 1 June.

Tell us about the ‘fresh look’!

The course does not shy away from highlighting problems with compressive sensing (CS) in seismic acquisition.

Almost everything, at least everything I have been able to find in the literature about CS, is in the range from mildly positive to extremely positive, such as ‘a revolution in signal processing’ or ‘a new paradigm’.

I can give an independent analysis because I have no vested interest in companies either using CS or not using it. The course intends to explain, not to ‘sell’ a technology.

How does the course balance math and common language?

One expert in CS admits he can’t explain it but ‘there’s a ton of math behind it’.

This course explaions it but saves people the rather significant amount of time needed to go through the math that’s behind it by using common language and logical arguments. This is why the course can fit into one day. At the end of the math, there are conclusions many of which are true, and there are lemmas that are actually proven, but not all of them apply to seismic acquisition, and not even all of them apply to the other areas where CS claims success, for example, megapixel camera pictures and MRI. The course is probably the only place right now where people can find out about the shortcomings.

How has your experience shaped your perspective on the practical application of CS in geophysics?

It is more my background in physics that counts here, and an understanding of how best to measure things (such as the wavefield). CS is mainly relevant in seismic acquisition. Processing has the task to deal with data that has been acquired using CS, which I and some others claim is not fundamentally different from interpolation, but is called ‘reconstruction’.

Interpreters should, if CS has worked as promised, not notice any difference other than a significant reduction in cost.

Magnetic & Gravity Interpretation System Simulate your target before you fly SRTM + satellite + flight plan

Your target model and DEM

What kind of debates do you hope participants will bring to the table, and how do you see these shaping the learning experience?

Which debates could unfold depends largely on the audience. There may be people who have used CS, who can share their experience; people who are considering using CS and have questions about it; people who are excited about CS after reading about it; as well as people who are sceptical about CS. There will likely be plenty of scope for discussion, but presenting the course material will take priority (and take at least some 80% of the time).

TMI simulation

Tensor simulation (Bzz)

Course details at eageannual.org.

Mark AGMM in your agenda Mark your calendar for the Annual General Meeting for Members (AGMM) in Toulouse taking place on Wednesday 4 June 2025 from 13:30 to 14:30. This is your opportunity to meet the EAGE Board, learn about the activities of the past year and contribute to shaping the future of EAGE. We encourage members to attend and share their thoughts, ideas and feedback. Visit eage.org/about eage/ agmm for more details. We look forward to seeing you there!

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Tensor Research support@tensor-research.com.au www.tensor-research.com.au

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EAGE NEWS

Why Naples makes perfect venue for 2025 Near Surface meeting

Naples (Napoli), the host city for this year’s NSG, is a true geoscience treasure. Its unique geological landscape and historical challenges provide fascinating real-world examples for each of the conference’s main tracks. Here’s a guide. is bradyseism, a cyclical ground uplift and subsidence, particularly evident in the town of Pozzuoli (just 15 km from the city centre of Naples). This phenomenon has gained deeper scientific attention in recent times, particularly as a new phase of unrest has emerged since 2011, after 26 years of subsidence, making Pozzuoli a global case study for monitoring and understanding natural hazards.

Looking down on Mount Vesuvius.

Environmental and engineering geophysics The 31st Meeting on Environmental and Engineering Geophysics offers a broad forum to explore the full spectrum of near-surface applications: an opportunity to connect your work with that of the multidisciplinary EAGE near-surface community. With topics spanning from geothermal energy to archaeological investigations, the programme resonates strongly with the Naples region, where a dynamic geological setting and rich cultural heritage provide an inspiring backdrop for discussion.

Geohazards assessment and risk mitigation This is a topic which immediately brings to mind Mount Vesuvius near Naples. Volcanic activity and tectonic processes can have complex interactions. One of these

UXO and object detection This topic resonates with many projects around Naples, such as a recent call for the removal of unexploded ordnance at the San Giovanni di Dio e Ruggi d’Aragona new hospital development. Operations like this highlight the need for precise detection technologies to ensure public safety and smooth progress, particularly in project areas with historical contamination risks.

Mineral exploration and mining Naples’ rich volcanic history is exemplified by historical deposits of pumice and pozzolana. These materials, prized since Roman times for their lightweight properties and use in high-quality concrete, played a crucial role in ancient construction, including iconic structures like the Pantheon and aqueducts. The pozzolana, a natural pozzolanic material,

was particularly valued for its ability to strengthen cement through its reaction with lime. These deposits remain significant not only for their historical use but also for their continued application in sustainable building practices today.

Infrastructure planning, monitoring and BIM Here we have a critical issue for Naples’ complex ground composition and historic urban layout. The excavation works for Naples Metro Line 1, for instance, unearthed a number of archaeological finds spanning various historical periods, in addition to confronting challenges related to layers of volcanic ash, pumice, and soft soils. These discoveries were made possible through meticulous geophysical surveys that identified buried structures, enabling engineers to adapt construction plans accordingly. This not only prevented potential structural issues related to unstable ground but also safeguarded Naples’ rich archaeological heritage, integrating it into the modern urban face of the city.

Join us in Naples this September to dive into five dynamic conferences, all in one vibrant location.

Visit eagensg.org for more details.

EAGE Student Calendar 18 MAY

MINUS CO2 CHALLENGE 2025: APPLICATION DEADLINE

ONLINE

21 MAY

EAGE STUDENT WEBINAR ON GROUND PENETRATING RADAR (GPR) IN APPLIED GEOPHYSICS: PRINCIPLES, APPLICATIONS AND NEW TRENDS, BY HESHAM EL-KALIOUBY

ONLINE

1 JUN

LAURIE DAKE CHALLENGE 2025: FINAL ROUND

TOULOUSE, FRANCE

2 JUN

LAURIE DAKE CHALLENGE 2025: WINNER ANNOUNCEMENT (DURING THE ANNUAL OPENING CEREMONY)

TOULOUSE, FRANCE

2-5 JUN

86TH EAGE ANNUAL CONFERENCE & EXHIBITION (STUDENT ACTIVITIES) (REGISTRATION OPENS)

TOULOUSE, FRANCE

FOR MORE INFORMATION AND REGISTRATION PLEASE CHECK THE STUDENT SECTION AT WWW.EAGE.ORG.

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EAGE NEWS

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).

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

EAGE/AAPG Workshop on Tectonostratigraphy of the Arabian Plate 2-5 November 2025 – Riyadh, Saudi Arabia

The global energy transition is evolving rapidly, and the Southern Cone of Latin America has immense potential to drive innovation and sustainable solutions. This first workshop will bring together industry experts, researchers and policy makers to discuss the latest developments in geological hydrogen, offshore wind, geothermal, CCUS and other key issues shaping the future of energy. We invite professionals from academia and industry to present technical papers and share their views on innovative research, emerging technologies and success stories from the region and beyond.

The workshop offers an in-depth exploration of the tectonostratigraphic framework of the Arabian Plate, focusing on the tectonic forces that have shaped the region’s lithostratigraphy and its geological history. Participants will gain a comprehensive understanding of structural geology, sequence stratigraphy, and techniques for interpreting geological maps and cross-sections. Through a mix of lectures, hands-on activities, and field-trip exercises, attendees will acquire skills to analyse and identify key structural features of the Arabian Plate.

A highlight of the workshop will be the two-day field trip to Riyadh, visiting the East Janadriyah and Umm-Shual anticlines.

Abstract submission deadline: 20 June 2025.

Abstract submission deadline: 5 May 2025.

3rd EAGE/SUT Workshop on Integrated Site Characterisation for Offshore Renewable Energy 15-16 October 2025 – Melbourne, Australia

First EAGE Workshop on Surface Logging 12-14 November 2025 – Paris, France

The EAGE and the Society for Underwater Technology (SUT) are collaborating on this workshop initiative to enhance the integration of geoscience and engineering disciplines in delivering robust site characterisation for offshore renewable energy projects. The need for multi-disciplinary collaboration has never been greater. The workshop will explore regional geo-engineering challenges, regulatory considerations, and investment landscapes, offering key takeaways for developers, contractors, consultants, and academics. Key topics include regulatory considerations, project challenges, lessons learned, technology updates, and case studies on integrated site characterisation.

Surface logging plays a pivotal role in modern well construction, providing real-time data that enhances operational safety, efficiency, and decision-making. As digitalisation and cross-disciplinary collaboration advance, surface logging is gaining increasing attention.

This workshop will explore surface logging technologies and their applications, improving subsurface understanding, optimising well operations, and reducing operational risks. It will cover how surface logging integrates geological, petrophysical, and drilling data to improve well placement, reservoir evaluation, and hazard detection.

Additionally, the workshop will highlight its growing relevance in energy transition, with applications in unconventional resources, geothermal wells, and emerging gas exploration.

Abstract submission deadline: 20 June 2025.

Abstract submission deadline: 15 June 2025.

For the latest updates and information, visit eage.org/events FIRST

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EAGE NEWS

How GET 2025 conference chairs view programme mix The four key technologies – Carbon Capture & Storage (CCS), Geothermal, Hydrogen & Energy Storage, and Offshore Wind – are deeply interconnected and together form the backbone of a low-carbon energy future. That’s why the EAGE Global Energy Transition Conference & Exhibition (GET) on 27–31 October 2025 continues to enable cross-conference sessions, creating more opportunities for attendees to explore how these technologies work together. Feedback from our 2024 event strongly suggested that participants valued being able to engage with all four key areas under one roof. Ahead of the conference, we spoke with various conference advisers to hear their insights on integration, innovation, and what’s in store for attendees. Here are some edited comments.

Carbon Capture & Storage Conference

Geothermal Energy Conference

What are the most pressing challenges in scaling up CCS technologies and how can we address them?

CCS is an important component in addressing climate change.

However, obstacles remain, one example is public perception, which often does not fully acknowledge the necessity of CCS. This can be addressed via transparent communication and explanation of the technology.

Nicole Grobys, DGMK One of the obvious challenges that need to be addressed is the investment model. There is a need to promote and implement CCS solutions with a holistic vision, meaning that CCS should be integrated within complete energy processes, rather than a standalone solution.

Pierre Le Guern, Eliis The most pressing challenges in scaling up CCS technologies include high costs, limited infrastructure, and concerns about storage safety and public acceptance. Addressing these requires implementing incentivising investment through government policies and fostering public-private partnerships.

Sonia Isabella López Kovács, Repsol The unique phase behaviour of CO2 means that changes to the overall system - such as emitters/sources coming on or offline, well workovers, or other events - could have impacts to the long-term reliability of the infrastructure and operations.

Understanding potential transients, along with temperature and pressure variations, is crucial to mitigate risks and prevent disruptions.

Jeremy J. Walter, CMG The most pressing challenges in scaling up CCS technologies are the finicalities of governments not understanding the need for urgent change and companies not being bold enough to put a percentage of their gross income into developing the technologies further.

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Ghazal Izadi COO, XGS Energy, co-chair Geothermal Energy Conference Synergies between the Geothermal Energy and the other conferences?

Geothermal energy has strong synergies with other renewable sectors. For example, hydrogen production can leverage geothermal heat for more efficient electrolysis, reducing reliance on fossil fuelbased processes. Additionally, geothermal resources can provide baseload power to complement offshore wind and energy storage, helping to stabilize the grid when intermittent renewables fluctuate.

How is geothermal energy contributing to global sustainability goals?

Geothermal plays a crucial role in decarbonising electricity and heating, offering baseload power that is reliable and continuous.

With advancements in next gen technologies, geothermal can scale globally, even in regions without conventional hydrothermal resources.

How are technological innovations integrating across sectors?

Advanced drilling technologies from oil and gas are making geothermal more viable. Additionally, integrating AI-driven reservoir modelling and super-hot rock research could significantly improve heat extraction and efficiency. Grid-scale energy storage solutions, like lithium or thermal batteries, can also enhance the effectiveness of geothermal as a flexible power source.

What developments do you anticipate at this year’s conference?

The geothermal sector is seeing breakthroughs in closed-loop systems, superhot rock drilling, and hybrid geothermal-hydrogen projects. I expect key announcements on new pilot projects, industry partnerships, and financing mechanisms that could accelerate deployment. The next few years is all about massive scaling.

EAGE NEWS

Hydrogen & Energy Storage Conference

Offshore Wind Energy Conference

Daniel Palmowski Director of business development, Terranta, co-chair Hydrogen & Energy Storage Conference

Sanket Bhattacharya Seismic business development manager, Fugro. co-chair Offshore Wind Energy Conference

Synergies or integration between the Hydrogen and the conferences?

Synergies between the Offshore Wind Conference and the other conferences?

The energy transition is essentially moving towards a multi-source supply chain. This means that the supply chain will be very versatile, and storage of (renewable) energy will have to adapt to the variability of supply and demand. To make this work, integration of generation, conversion, storage and consumers will be essential. I do not see the need for synergies, but rather the need for integration.

I see a great importance in synergies, particularly between OWF and CCUS. Some key points are: 1) Reduced carbon footprint Offshore wind farms can provide the necessary power for CCUS operations, including the energy-intensive process of capturing and injecting CO2. 2) Offshore space optimisation: By co-locating wind farms and CCUS facilities, the use of shared-offshore space will offer more optimized ways of offshore operations. The Southern and central North Sea represent such a potential example of shared-offshore space. 3) Shared infrastructure - Offshore wind farms and CCUS facilities can share infrastructure such as platforms, subsea cables, and maintenance vessels reducing the overall cost and logistical complexity of both operations. 4) Regulations & Permitting - Joint projects can streamline regulatory and permitting processes, as both wind farms and CCUS facilities often require similar environmental assessments and approvals.

How do hydrogen and storage contribute to global sustainability goals?

Energy storage is key to supporting a continuous supply.

Unlike fossil fuel storage, we are reversing the problem: during surplus periods, we convert excess energy (electricity, heat) into hydrogen, which might not be immediately needed. Heat storage is a very important form of energy storage as there is no conversion needed. If there is a market for hydrogen, green hydrogen storage will be necessary. Efficient storage is essential for managing excess energy. The main role of energy storage in the transition is as an enabler: without it, forms of energy like heat, electricity, and hydrogen will not succeed to play a role in the energy transition. Additionally, energy storage reduces the need for extra generative capacity.

Impact of this year’s coming discussions?

I think we need to convince investors, public and private, that there is not much to worry about and to not waste time. I feel we are at a point already where we are discussing problems that might be irrelevant in the future, because we lack the real-world problems that really matter.

How is OWF contributing to global sustainability goals?

One of the biggest drivers of the energy transition is offshore wind.

Since originating in Denmark in the early 1990s, offshore wind has established a strong presence in Europe with almost half of the world’s 75 GW installed capacity. And the offshore wind sector has global ambitions to reach over 260 GW of capacity by 2030.

Throughout the European Union, renewables represent the largest share of domestic energy production, with 43% in 2023 compared to 6% for gas, 3% for oil and 19% for solid fuels. This milestone in Europe’s transition to clean energy aligns with meeting many of the world’s climate change targets. So, offshore wind energy is not only pivotal but is actually one of the key critical pillars of this energy transition.

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.

Visit our conference pages to find out more: Carbon Capture and Storage Conference

Geothermal Energy Conference

Hydrogen and Energy Storage Conference

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EAGE NEWS

EAGE joins discussion on future agenda of European geological survey organisations

EuroGeoSurvey meeting.

EAGE officials recently attended the launch event in Brussels of the Strategic Research and Innovation Agenda (SRIA) of EuroGeoSurveys, the not-for-profit

association which represents 37 European Geological Survey organisations.

CEO Marcel van Loon, with EU Public Affairs colleagues Ilaria Viezzoli and Danny Landegge, took part in the panel discussions on the future of Europe’s geological resources.

EuroGeoSurveys’ SRIA is a forwardthinking initiative designed to promote the sustainable use and management of Europe’s subsurface resources. With a strong focus on geoscientific data, it aims to support the energy transition, enhance European competitiveness, and tackle global challenges such as energy security, climate change, and resource sustainability. A key element of the project is the development of a comprehensive 3D Atlas of Europe’s subsurface, a tool that will provide

invaluable data for companies working on subsurface projects across the continent.

For EAGE, this initiative is more than just about accessing data—it aligns with the organisation’s broader commitment to European affairs and strategic collaboration with EU goals. By actively participating in such events, EAGE strengthens its role in shaping the future of geoscience in Europe, fostering connectivity among all stakeholders.

During the event, our team had the opportunity to connect with many like-minded professionals who share our vision. We look forward to continuing these discussions and welcoming them to future EAGE events. More information about SRIA can be found on the EuroGeoSurveys website.

EAGE to cooperate with AGAP Qualité EAGE has signed a cooperation agreement with the French association AGAP Qualité.

Created in 1992, one of the missions of AGAP Qualité is to develop methodological guides and quality standards to supervise geophysical studies, guaranteeing reliable and reproducible results for all professionals. Michel Hayet, president of the organisation, says, ‘One of our first initiatives was to publish a Code of Good Practice’.

AGAP Qualité facilitates the exchange of experiences among its corporate, institutional, and individual members by organising symposia, conferences, and thematic working groups. Topics covered include geophysics applied to infrastructure, new subsurface imaging methods, and advances in geophysical technologies for the benefit of the environment.

Hayet explains: ‘In synergy with EAGE, AGAP wishes to position applied geophysics at the forefront of future challenges, by ensuring constant updating of professional standards and integrating new technologies to meet sustainability and performance requirements.’

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Collaborating with AGAP Qualité, EAGE aims to promote the advancement of subsurface geophysics worldwide. Photo from AGAP Scientific Days 2024.

We look forward to collaborating with AGAP Qualité in the promotion and advancement of subsurface geophysics worldwide and are honoured to count on 2025

its participation at the 86th EAGE Annual in Toulouse. So don’t miss the chance to visit its representatives at our Associated Societies area in the Exhibition.

EAGE NEWS

Geoenergy invites deep dive into energy transition

Ambient Noise Monitoring for Nodal Surveys

Geoenergy journal is inviting submissions for a forthcoming thematic collection entitled ‘Energy targets at modern and ancient divergent settings: origins, controls, opportunities and implications’ with a deadline of 31 May.

Texture of a serpentinite-mined mountain.

We are seeking contributions that address the generation of geological targets in divergent tectonic settings that are of importance to the energy transition. These can involve formational processes and controls (e.g. serpentinization, magma-

tism), current applications, and/or challenges. Key targets of interest include geothermal resources, metal resources, hydrogen resources, formations that can accommodate CO2 sequestration, and other potential geological innovations.

Additionally, we are seeking papers dealing with the ecological, socioeconomic, policy, and sustainability implications involved with the ethical exploitation of these energy transition targets. Contributions that can address multiple targets are encouraged. Both original research and review papers are welcome.

More information can be found on the journal website.

LC Czech Republic discusses hydrology and carbon cycling Dr Lee Slater from Rutgers University Newark was a guest speaker at an online meeting in February of Local Chapter Czech Republic with a talk entitled ‘Looking into the hydrology and carbon cycling of Northern Peatlands via geophysics’.

Dr Slater, author of some 230 Scopus-rated papers cited by more than 4000 other publications, summarised how near surface geophysical techniques have led to fundamental improvements in the understanding of critical zone structure and the processes associated with boreal peatland (organic sediment) systems.

He then highlighted elements of his work that demonstrate how the subsurface mineral sediment archi-

tecture regulates the hydrology and carbon cycling in boreal peatland systems. Dr Slater demonstrated how geophysical techniques have been used to image and monitor free-phase methane gas dynamics in peatlands.

Finally, he showcased recent results from ongoing work where geophysics and temperature sensing methods have been combined to gain novel new insights into the role of piping in regulating peatland hydrology, possibly by channelling mineralised groundwater. The lecture was co-organised with the Faculty of Science in Prague, as a part of a regular programme of applied geology in-person and online meetings.

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EAGE NEWS

LC Stavanger focuses on role of ILX offshore Norway Key challenges and opportunities facing infrastructure-led exploration (ILX) projects were the subject of the latest Local Chapter (LC) Stavanger series of meetings, on this occasion in the form of a panel discussion.

The panel featured a distinguished group of experts: Arne Jacobsen (lead for subsurface studies and technology, SODIR), Zoë Sobisch (BD project manager, Equinor), Alastair Welbon (chief exploration geoscientist, Aker BP), Roy Davies (VP exploration and subsurface, Harbour Energy Norway), and Carly Marshall (new ventures manager, Vår Energi). With their extensive experience in ILX and Norwegian exploration, they brought diverse perspectives and deep industry knowledge. Moderating the discussion were Alexandra Zaputlyaeva and Victor Aare Madsen from the Local Chapter team.

Arne Jacobsen set the stage by introducing ILX and its growing impact on the Norwegian Continental Shelf (NCS).

ILX wells are drilled in areas with existing infrastructure, allowing operators to leverage established assets and reduce costs. Over the past six years, ILX wells have accounted for approximately 80% of Norway’s exploration activity, with the remaining 20% focused on frontier areas. Jacobsen highlighted that ILX wells generally have higher success rates due to their proximity to known hydrocarbon systems, whereas frontier wells, though riskier, are crucial for long-term resource development.

Norway’s hydrocarbon system, with 50 years of robust infrastructure, provides a strong foundation for continued exploration. However, ILX wells typically target smaller reserves, necessitating a strategic approach, often integrating multiple prospects across different stratigraphic levels to maximise success. Advances in seismic data quality and resolution are improving the characterisation of complex reservoirs, allowing geoscientists to make more informed decisions. Panellists emphasised that accelerating data integration through AI and automation could further enhance efficiency, freeing geoscientists to focus on high-value interpretation and validation.

One of the biggest concerns surrounding ILX is the ageing infrastructure. Panellists stressed the importance of balancing ILX with frontier exploration to ensure long-term sustainability. Collaboration between companies is becoming increasingly essential, fostering shared knowledge and risk mitigation strategies. The panel also underscored the need for young geoscientists with fresh ideas to drive innovation and help shape the future of exploration.

Digitalisation emerged as a key enabler in optimising oil and gas operations. AI-driven technologies are transforming seismic interpretation, reservoir modelling, and predictive maintenance, leading to cost reductions and improved efficiency. However,

panellists acknowledged that adopting AI requires not only technological advancements but also a cultural shift within organisations. New skill sets are needed, and geoscientists must adapt to increasingly data-driven workflows.

Energy transition was another pivotal topic. While oil and gas remain integral to the energy mix, there is growing momentum toward carbon capture, utilisation, and storage (CCUS), as well as offshore wind developments.

The discussion acknowledged that achieving net-zero targets will require industry-wide collaboration, regulatory alignment, and continued technological innovation.

Navigating the evolving regulatory landscape also presents both challenges and opportunities for exploration companies. Panellists discussed how shifting political priorities and environmental policies influence investment decisions. While Norway continues to be a favorable environment for energy investment, companies must adapt to increasing transparency and sustainability expectations.

The panel discussion was both insightful and highly interactive, with strong audience engagement throughout. It exceeded expectations in reinforcing the importance of such gatherings for knowledge sharing and networking.

LC Stavanger has an exciting lineup of initiatives planned for 2025. To stay informed, follow on LinkedIn.

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!

D O N AT E T O DAY !

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PERSONAL RECORD INTERVIEW

Mahad Nadeem Janjua

Personal Record Interview

Getting off to a stellar start

When Mahad Nadeem Janjua arrived in Europe from Pakistan he swapped economics for geoscience and went on to a Master’s degree in Europe’s prestigious IDEA League joint university programme, all supported by scholarships. Now with Harbour Energy, he has switched to data science but is also emerging as a young professional representative and digitalisation advocate at international meetings including last year at EAGE Oslo. Lifetime ‘hobby musician’, he has even busked on the streets of Hamburg.

Upbringing in Pakistan I grew up moving around the country quite a bit because of my parents’ jobs, both being doctors. I went to private school, and my schooling years really lay the foundation for all my pursuits and passions in my life to date. I dabbled in different hobbies, from sports like football, cricket and table tennis to learning how to play the guitar, singing on stage, and even drawing and painting.

Overseas ambition From early on in school, I had the desire to study economics in the US. But this is an expensive option for international students, so I chose a German university in Bremen for my undergraduate studies.

There, my economist ambitions quickly gave way to an interest in geoscience.

Much of this had to do with the very cool field trips the university programme had on offer! But I always considered myself to be good at mathematics and physics too, so specialising in geophysics seemed like a perfect blend. I applied and got accepted on a full merit sponsorship to the IDEA League Applied Geophysics Joint Master’s Programm offered by TU Delft, ETH Zürich, and RWTH Aachen.

Learnings from IDEA years Sponsorship from Shell for the IDEA League programme was really a big moment in life. I won the only slot for a non-EU applicant, and so I knew I had to make the most of this opportunity. It

allowed me to experience three different universities, countries, cultures, within the space of just two years. In particular, I had a lot of fun at TU Delft, where I learnt a lot about wave equations and cheese sandwiches, and started to build a professional network resulting in a summer internship at Wintershall Dea (now Harbour Energy).

the opportunity to participate in a round table discussion with the Crown Prince of Norway and professionals from around the world to discuss how digital technology can play a role in addressing energy poverty and climate injustice. Being invited to a leadership development programme at Oxford, UK, was a recent highlight.

Career to date After my Master’s graduation in 2021, I briefly moved to Crawley, UK, as a seismic processing geophysicist at CGG (now Viridien). Returning to Wintershall Dea, I began working as a data scientist.

The motivation behind this career switch was two-fold. One, the Covid-19 pandemic and the repercussions on the oil and gas industry really highlighted the volatility in the job market prompting me to develop competencies that had applications across industries. Second, artificial intelligence was, and is even more so now, a very exciting booming sector where I could bring together my knowledge and skills to digital technology applied to the oil and gas industry. Now I work in different business units in Germany and Norway, developing digital tools and products to optimise workflows for subsurface specialists.

Young professional perspective I am a strong believer in driving change from within. Efforts for energy security and affordability need to be appropriately balanced with efforts towards energy sustainability, and I believe that as a young professional looking to contribute meaningfully, this industry has and will continue to offer a lot.

Achievements most proud of I have had numerous opportunities to visit places, attend conferences, and meet highly skilled professionals as part of my work. In August 2024 as part of the ONS conference in Stavanger, Norway, I had FIRST

Music in your life Outside work, I am a passionate hobbyist musician. It runs in the family. My father was a vocalist in a band back in his day, so were my brother and sister in their school days. I was a a vocalist and rhythm guitarist in school bands, and at university played solo and band shows. At the beginning of my career in Hamburg, I also explored busking/street performing for a while.

Public communicator role Having been a performer all my life, being on stage comes naturally. I often have the opportunity to speak at conferences and other events and really enjoy being able to contribute something of value. I also learn a lot from exchanges with the audiences.

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A century in the oil business Main sponsor of our Annual in Toulouse in June is TotalEnergies duction of five American companies and signing of the so-called which last year celebrated 100 years in business, a period in which Red Line Agreement (1928) governing the exploitation of oil and the oil industry and its role in society have witnessed a roller gas resources in the prescribed area, based on the former Ottoman coaster of fluctuating fortunes and public sentiment. The compaEmpire, a deal that persisted for 20 years. In France, CFP under ny’s current challenge in a world plunged into economic turmoil is Mercier then won a major political struggle to set up refining capacity run by Compagnie française de raffinage (CFR) at how to navigate through the uncertain world of energy transition.

The history of the company’s origins dates back to France’s Gonfreville in Normandy and La Mède, near Marseille, to receive experience during the First World War and French Prime Minister Middle East crude and remain a private enterprise (although the Georges Clemenceau’s understanding of the strategic importance government did increase its share to 35%, not to be diluted until of access to sources of oil. France in 1917 came within three decades late). months of running out of oil before the US answered its call for These developments had not quite been the intention in help. the original 1923 mission outline statement from Poincaré. He Daniel Yergin notes in The Prize that before the war Clemcommissioned CFP to get involved in ‘any enterprise active in enceau allegedly commented, ‘When I want some oil, I’ll find whatsoever oil producing region’ and ‘co-operate, with the support it at my grocer’s’. By the time Britain, France and the US were of the Government, in . . . exploiting such oil wealth as may be discovered in France, her colonies and her protectorates.’ Significant dividing the spoils of victory in 1918, a converted Clemenceau was clashing with Britain’s prime minister over a share of oil expansion would only come after the Second World War. in Mesopotamia, essentially today’s Iraq, at that time controlled In fact during the war CFP was fortunate to retain its investments in IPC which were vulnerable once France came under by the Turkish Petroleum Company (TPC), a British dominated consortium led by Shell. The San Reo Agreement in 1920 awarded German occupation and the Vichy administration.

France 25% of the oil in Mesopotamia (which was to become a Post-war, CFP embarked on a significant expansion. It faced British mandate under the League of Nations). Britain allocated to growing local competition from newly created French energy the French the share in TPC previously organisations as a result of intervention by held by the German Deutsch Bank. It President Charles de Gaulle. This culmi‘Not quite the intention had sequestered the stake in 1915 with nated in the development of what was to the promise of handing it over to France in the original 1923 mission become Elf Aquitaine, a rival integrated at the end of the war. energy conglomerate on a global scale, outline statement ’ It was left to Clemenceau’s successor that ended in a merger in 2000.

Raymond Poincaré to invite Ernest Mercier, already active The dramas experienced by these two companies in the restructuring France’s electrical power generating industry, to history of France’s energy industry, including numerous corporate form Compagnie française des pétroles (CFP), a private sector changes, are hard to encompass here. In its website history from company in which the state would initially be a 25% stakeholder the 1950s up to the end of the 20th century as it built into a major (a percentage which has changed over time). international integrated oil company, TotalEnergies points to some In the run up to the Second World World period, CFP was highlights in its evolution that it obviously views as significant. heavily dependent on Middle East oil beginning with supplies These include the 1956 discovery of major hydrocarbon deposits from the 1927 first major Baba Gurghur discovery in Iraq. TPC in the Algerian Sahara including the construction of the world’s soon became the Iraq Petroleum Company (IPC) with the introfirst natural gas liquefaction plant, an ongoing business for the

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company ever since (the history of the complications of partners stance in the US causing the company to pause projects off the and Algerian independence are not discussed); the 1969 entry US East Coast.

In a recent highly quotable interview in McKinsey Quarterly into the offshore Indonesia through acquisition of two licences held by Japanese company Japex; acquisition with Enterprise de Patrick Pouyanné describes walking a tightrope by committing recherches et d’activités pétrolières (ERAP) of an interest in Antar, to a shift of a fifth of its business to renewable-led intergrated power by 2030 stating this is considered ‘not enough oil and gas’ specialist in lubricants and motor oils with refineries and over 5000 service stations; partner in 1971 discovery of Ekofisk gas for traditional investors and not ‘enough renewables’ for green field in North Sea; taking control in 1974 of Hutchinson rubber stakeholders.

The French company claim to a leadership role in energy processing company; and the 1982 world record drilling of a transition rests on its record to date, superior annual spending deepwater well to a depth of 1714 m, 100 km off the Rhone delta, on energy transiton of $5 billion and the ambition of its 2030 forerunner of today’s deep offshore drilling. objectives.

In 1999 Total followed the trend of industry consolidations by In the past, Total has made key moves like acquiring Saft merging with Belgian company Petrofina, and the following year Groupe, the world leader in the design and production of in a hotly contested takeover battle acquired Elf Aquitaine. With high-tech batteries for industry; taking a 60% more than 132,000 employees, a turnover of €114 billion, and production of 2.1 million ‘TotalEnergies climb stake in Sunpower, America’s second-largest manufacturer of solar panels; and acquiring barrels per day, TotalFinaElf (soon shortened to Total) became the world’s fourth-largest into the top ranks of Direct Energie, France’s third-largest supplier of green gas and electricity. Among recent hydrocarbon producer. With 17,500 service the majors’ initiatives, the company agreed a 300 MW stations worldwide and a refining capacity of renewable energy agreement in Oman, is collaborating with Air 2.6 million b/d, it also became Europe’s number one downstream Liquid to decarbonise its refineries in Northern Europe with green operator. And the new group was the world’s fifth-largest producer hydrogen, and with its partners launched the second phase of the of chemicals. Fortuitously, Elf Aquitaine four years earlier in Northern Lights CCS project in Norway. It also closed its acqui1996 had discovered the massive Girassol oil reserves in Block sitions of VSB Group, a European wind and solar developer with 17 offshore Angola to be followed by a succession of other finds. extensive operations in Germany, and SN Power, which develops How Elf (now a TotalEnergies brand of oils, notably visible hydropower in Africa, particularly Uganda. in motor racing) got to be such a major player was down to The big picture is that TotalEnergies plans on 100 TWh the forming in 1939 of the agencies Régie Autonome des of electricity generation by 2030 with significantly increased Pétroles (RAP), Société Nationale des Pétroles d’Aquitaine renewable production, especially solar and wind, and will expand (SNPA), and Bureau de Recherches de Pétroles (BRP) in various its flexible assets including CCTG and storage. Other tragets are roles initially to exploit the Saint Marcet gas field and later near 1.5 Mt of sustainable aviation fuel by 2030, 40% net reduction in Lacq in south-west France. RAP and SNPA expanded into French Scope 1+2 emissions in 2030 (already -26% in 2024 and -36% dependencies including Algeria after some famous disappointin oil and gas), and 25% lifecycle carbon intensity reduction of ments), Congo and Gabon. energy products sold (-16.5% in 2024 vs 2015). The full story These all eventually morphed in 1976 into Elf Aquitaine can be found in the company’s extremely comprehensive 2025 (now with petrochemical, plastics and pharmaceutical interests) Sustainablity and Climate 2025 Progress Report. in which the French government had a majority stake until the For 2025 the company foresees a net investment budget of mid-1990s. The latter years of the company were marked by a between $17 billion and $17.5 billion. However, the portion controversial acquisition spending spree and tainted by the Great allocated to low-carbon energy is being reduced from $5 billion Oil Sniffer Hoax losing $150 million in 1979 and a later huge to $4.5 billion, particularly in the electricity sector. This reflects corporate corruption and kickbacks scandal involving more than a trend among other European oil majors like Shell, bp, and $400 million in illegal payments.

Equinor, all of whom have scaled back their commitments to In the intervening years since 2000 TotalEnergies has climbed renewable energy. CEO Pouyanné justified this pragmatic shift into the top ranks of the majors. Adjusted net income in 2024 by pointing to the declining profitability of low-carbon energy, was $18.3 billion with cashflow of $29.9 billion achieved with explaining that energy prices were less volatile in 2024 compared nearly a 15% return on average capital employed in 2024, the best to the exceptional levels of 2022 and 2023. Declining refining among the majors for the third consecutive year. Having ridden margins were also a factor. the 2008 financial crisis, the 2013/14 oil price shock and the Predictably environmental groups were not happy that the Covid pandemic, it has had to deal with unfounded accusations company increased its dividend to shareholders. However, even that its assets (with unrealisable dividends) have been used to fuel they would be churlish to denounce the company’s 2021 rebrandRussian war planes in Ukraine hostilities. Then there is President ing to TotalEnergies and the implied aspirations.

Trump’s unsettling administration including an anti-wind power Views expressed in Crosstalk are solely those of the author, who can be contacted at andrew@andrewmcbarnet.com.

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Oil majors to drill seven wells offshore Namibia

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RGS shoots seismic for Australian offshore wind

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TGS launches US CO2 storage assessment

TGS warns of weakening global wind energy market

TGS has warned of a potential global installation shortfall of 26 GW of global wind capacity by 2035 on previous forecasts as a result of the US’ shift in policy.

Its latest Quarterly Market Overview Report said: ‘The withdrawal of a major market like the US has significant implications globally, with developers and members of the supply chain forced to rethink investment strategies. Another key topic shaping the industry is heightened security concerns across global supply chains, driving a strategic shift toward localised manufacturing.’

Despite these challenges, floating offshore wind continues its upward trajectory, with new auction awards defying broader market uncertainty, says the report. It forecasts installations to grow from the current 0.5 GW to 26.5 GW by 2035. ‘The technology remains resilient,

benefiting from innovation and governmental support, particularly in Europe and the Asia-Pacific region,’ said TGS. However, leading developers’ ambition overall shows signs of weakening due to increasing financial pressures and regulatory uncertainties. The report reveals that up to 70 developers will begin construction on their first project by 2030, showing a new wave of smaller, often more local, players.

‘We enter the second half of the 2020s at a turbulent time, with political uncertainty becoming ever more consequential,’ said Patrick Owen, lead author of the report. ‘As major developers’ ambitions waver, smaller and newer players are taking on greater roles in meeting national targets. Security risks also remain a hot topic. In this evolving landscape, having access to reliable intelligence is more important than ever.’

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Meanwhile, TGS unveiled its MDE platform last month, which used wind and metocean data model to tackle critical inefficiencies in offshore wind data management, and replace manual handling which currently consumes up to 50% of project timelines.

Industry experts and offshore wind developers collaborated to design the MDE, integrating proprietary, public and multi-client datasets, or commercialise unused wind and metocean measurement data from past projects.

‘The Measurement Data Ecosystem is the result of an industry-wide effort to streamline data workflows,’ said Will Ashby, EVP New Energy Solutions at TGS. ‘By simplifying data access, reducing manual handling, and integrating automated workflows, we are giving developers the tools to make more confident decisions.’

Jens Riechert, an in-house expert on measurements at EnBW, who contributed as an industry adviser, said: ‘The lack of transparency and data integrity in offshore wind measurements has been a real industry challenge. It is encouraging to see a platform developed with input from industry experts to address these issues.’

TGS has also been collaborating with Equinor to shape the MDE platform’s approach to improving data management efficiency by reducing manual processes and enabling API-based, high-integrity data streams.

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Viridien wins reimaging contract in Algeria Viridien has won a contract from Groupement Hassi Bir Rekaiz, a Sonatrach and PTTEP joint venture, to reimage two legacy 3D seismic data sets totalling 2400 km2 in the Hassi Bir Rekaiz concession in the Berkine Basin, Eastern Algeria.

During the 13-month project, Viridien scientists are completely reimaging and merging the two legacy seismic

datasets, originally acquired in 2011 and 2013. To meet the client’s challenging imaging objectives, Viridien is applying the latest technology to deliver more detailed seismic velocity modelling and improved reliability of seismic amplitude, phase and frequency attributes for quantitative interpretation and enhanced fault imaging.

Peter Whiting, EVP, Geoscience, Viridien, said: ‘Another award from Algeria shows client confidence in our experience and differentiation in this growing market.

We continue to develop and refine our technology, allowing us to extract more and more useful information from seismic data.

This allows our clients to do much more with the survey data they already have.’

STRYDE sells latest Mini Seismic System in Colombia STRYDE has sold its first Mini Seismic System in Latin America to Energy Geophysical Services SAS (EGS) in Colombia.

After EGS’ deployment of STRYDE’s seismic technology across mining, civil engineering and oil and gas exploration surveys in 2024, EGS will integrate the mini-system into its operations for upcoming geophysical projects in Colombia.

Launched in Q4 2024, STRYDE’s Mini System is a compact, all-in-one nodal seismic acquisition solution designed for recording and producing

seismic data deliverables from up to 1500 nodes (channels). ‘With industry-leading cost per channel, it makes seismic acquisition more affordable, enabling efficient survey design that helps to optimise field operations,’ said STRYDE in a statement. ‘The Mini System leverages STRYDE’s ultra-lightweight, compact, and autonomous seismic nodes to capture high-resolution subsurface images with minimal environmental impact— empowering EGS to expand into new exploration opportunities.’

‘The adoption of STRYDE’s nodal

technology in Latin America has grown rapidly over the past three years, with successful deployments in Mexico, Brazil, Chile, Colombia and Bolivia. This latest sale is a testament to the region’s increasing demand for technology that delivers faster, more precise subsurface imaging,’ said Víctor Villamizar, head of business development – Latin America, Caribbean and Angola at STRYDE. Rodolfo Ardila, managing director at EGS said: ‘We’re excited to be the first in Latin America to adopt this cutting-edge Mini Seismic system.’

Oil majors to drill seven wells in Namibia this year Namibia’s offshore oil and gas industry is set for significant growth in 2025, driven by new licensing opportunities, seismic acquisition and drilling of seven wells.

Development is accelerating on two of Namibia’s most significant discoveries. TotalEnergies’ Venus project in Block 2913B remains on track for a final investment decision (FID) in 2026, with new seismic data confirming better density and permeability compared to surrounding blocks. On Galp’s Mopane discovery, 3,500 km2 of high-density seismic data have been collected to refine volume estimates and advance the project toward FID. On Shell’s PEL 39 discovery – where the company recently wrote down $400 million – Shell and its partners are analysing data from the nine wells drilled so far.

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‘The scale is enormous – there’s 220,000 Km2 of offshore licence acreage,’ said Ian Thom, research director for Sub-Saharan Africa upstream at Wood Mackenzie. ‘With just over 20 exploration and appraisal wells drilled, this area is still hugely underexplored.’

‘The resources are definitely there,’ said Verner Ayukegba, senior-vice president of the African Energy Chamber. ‘The big questions now revolve around sub-surface conditions, gas content and how best to commercialise these discoveries.’

BW Energy plans to drill at the Kharas prospect within the Kudu licence, while Rhino Resources is awaiting results from two high-impact wells in PEL 85. In South Africa’s Orange Basin, TotalEner2025

Oil rig in Namibia.

gies is expected to drill in Block 3B/4B, and Shell may drill in an ultra-deepwater block near the maritime boundary with Namibia.

Namibia’s petroleum commissioner Maggy Shino said the country was awaiting applications from its latest licensing round.

INDUSTRY NEWS

Equinor reports 2 billion barrels of oil equivalent a day in 2024

Johan Sverdrup field. Photo: Hilde Oterhals

Equinor’s annual report has reported equity production of liquids and gas of 2067 mboe per day in 2024, on par with the year before. Equity production of renewable power increased by 51% to 2935 GWh. Return on average capital employed was 21% for 2024. Organic capital expenditures were $12.1 billion.

On the Norwegian Continental Shelf, Equinor acquired 39 licences and received approval of the PDOs for the Eirin, Irpa, Verdande and Andvare projects. The Johan Castberg FPSO arrived at the field and started preparations for startup.

The company exited from Nigeria and Azerbaijan and acquired US Onshore gas assets close to premium markets. In the UK it established an incorporated joint venture with Shell.

The renewables market was ‘challenged by cost inflation and regulatory delays’. However, in the UK the world’s largest offshore wind farm, Dogger Bank, continued to progress towards commercial start-up. Production commenced at the Mendubim solar plants in Brazil.

Through an acquisition of a 10% stake in Ørsted, Equinor has a stake in a ‘premium portfolio of offshore wind projects and assets in operation’.

In Norway, Northern Lights, the first commercial CO2 transport and storage infrastructure, was completed and is expected to receive and store CO2 in 2025.

In the UK, Equinor has started executing two of the UK’s first carbon capture and storage infrastructure projects.

In 2024, Equinor achieved a year-onyear reduction of 5% in operated scope 1+2 greenhouse gas emissions, bringing the total down to 11 million tonnes CO2

equivalents. This is a 34% reduction from 2015, which is the reference year for Equinor’s ambition to reduce emissions by 50% by 2030. Throughout 2024 emissions were reduced with the partial electrification of the Sleipner field, the Gudrun platform, as well as the Troll B and C fields.

Average upstream CO2 intensity of Equinor’s operated portfolio was 6.2 kg of CO2 per boe in 2024, an improvement from 6.7kg of CO2/boe in 2023 and ‘well below the industry average’. Scope 3 GHG emissions were 251 million tonnes in 2024, on a par with the level in 2023.

Equinor improved in the net carbon intensity of energy produced (including scope 1, 2 and 3 emissions) in 2024, which is 2% below the 2019 baseline. The reduction was mainly driven by increased renewable energy production and lower scope 1+2 emissions.

The updated Energy Transition Plan, published on 20 March 2025, outlines Equinor’s strategy of creating value in the transition.

Meanwhile, Danske Commodities and Equinor were ordered by the Commission de Régulation de L’énergie (CRE) on 20 January to pay for infringement of Article 5 of REMIT Regulation prohibiting market manipulations. Danske Commodities has been fined $8.8 million and Equinor $4.4 million for manipulations committed on the wholesale market in 2019 and 2020, with regard to natural gas transmission capacity between France and Spain. ‘Equinor does not agree with the decision and will appeal the case to the Higher Administrative Court in France,’ the company said in a statement.

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INDUSTRY NEWS

UK pledges to forge ahead with two delayed North Sea projects

BRIEFS bp has started the process of selecting a new chair, after Helge Lund informed the Board of his intention to step down. The process is being led by senior independent director Dame Amanda Blanc. The successful candidate will work with Lund to ensure an orderly transition before he steps down in 2026.

UK chancellor Rachel Reeves has pledged that the Jackdaw and Rosebank projects in the North Sea will get the go ahead as she stressed the importance of North Sea oil and gas to the British economy ‘for decades to come’.

Earlier this year, Scotland’s Court of Session determined that the approvals granted for Jackdaw and Rosebank were unlawful because they did not account for the greenhouse gas emissions resulting from the eventual combustion of the extracted oil and gas, known as ‘scope 3’ emissions.

This decision aligns with a prior UK Supreme Court judgment mandating that such downstream emissions be considered in environmental assessments.

The court’s ruling means that both Shell’s Jackdaw gas field and Equinor’s Rosebank oil field must undergo new approval processes that include comprehensive evaluations of their environmental impacts, particularly concerning scope 3 emissions.

Chevron is selling a 70% interest in its East Texas gas assets to TG Natural Resources (TGNR) for $525 million, with $75 million in cash and $450 million as capital to fund Haynesville development. Chevron will retain a 30% non-operated working interest in a joint venture with TGNR and an overriding royalty interest in the assets.

SLB sells Petrel software to Shell

Norway’s production figures for February 2025 show an average daily production of 1.938 million barrels of oil, NGL and condensate. Total gas sales were 9.9 billion Sm3 (GSm3), which is 0.8 (GSm3) less than the previous month. Average daily liquids production in February was: 1.723 million barrels of oil, 198,000 barrels of NGL and 18,000 barrels of condensate. Oil production in February is 1.3% more than the NOD’s forecast. Total petroleum production so far in 2025 is about 39.1 million Sm3 oil equivalents (MSm3 o.e.). Total volume is 2.6 MSm3 o.e. less than 2024.

Shell has signed a deal to deploy SLB’s Petrel subsurface software powered by advanced AI to deliver seismic interpretation workflows.

The deployment aims to standardise infrastructure and workflows and accelerate scalable digital solutions, helping to improve cost operating efficiencies. The collaboration will use the deployment as the foundation for integrated geoscience workflows to further advance understanding of the subsurface across the asset lifecycle.

‘With a common focus on joint innovation, including seismic interpretation for both traditional E&P and energy transition workflows, the partnership will support Shell’s digital transformation journey,’ said Rakesh Jaggi, president, digital and integration, SLB.

RGS provides seismic data for Australian offshore wind project

US secretary of the interior Doug Burgum has directed the Bureau of Ocean Energy Management to hold the next scheduled oil and gas lease sale in the Gulf of Mexico. BOEM’s latest estimates of technically recoverable oil and gas resources in undiscovered fields in the Gulf of America include 29.59 billion barrels of oil and 54.84 trillion cubic feet of gas.

Revive Geoscience Services (RGS) has been selected by Iberdrola for its first offshore wind farm repurposing project in Australia.

Iberdrola Group is expanding its operations in Australia with the Aurora Green project. The Australian government has recently granted feasibility licences to offshore wind farm developers. The Aurora Green project, a 700 km² fixed-bottom offshore wind farm more than 25 km off the Gippsland coastline, aims to generate 3 GW of clean energy.

RGS, a UK geophysical services company, will reprocess multiple vintages of long-offset 2D and 3D seismic surveys, coupled with detailed interpretation and ground modelling. ‘The objective is to

EMGS has won a contract for a $10 million CSEM survey in India.

Sercel has launched the WiNG DFU-3C, a three-component version of its WiNG land seismic nodal solution. Features include QuietSeis broadband digital sensor and Pathfinder transmission management technology.

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deliver insights into the near-subsurface of this wind energy new frontier, said RGS. RGS will repurpose legacy seismic data to support offshore wind farm development. ‘By leveraging advanced seismic processing and interpretation techniques, the project aims to enhance the geological understanding of the site, reducing uncertainty and mitigating investment risks,’ added RGS.

INDUSTRY NEWS

TGS starts multi-client OBN project in Gulf of Mexico TGS has started a multi-client ultra long-offset ocean bottom node data survey in the Gulf of Mexico. The Amendment 4 project will expand node coverage in TGS’ multi-client library, adding more than 1100 km2 in the Mississippi Canyon, Ewing Banks, and Grand Isle South areas.

Amendment 4 will feature TGS’ Gemini enhanced frequency source, offering lower frequency and improved signal-to-

noise for ultra-long offset OBN seismic compared to conventional seismic sources, said TGS. The advanced frequency source will enhance input data for TGS’ elastic full waveform inversion (eFWI) algorithm, resulting in more accurate subsurface imaging of the complex subsalt geology in the region, TGS added. Acquisition is scheduled for completion in Q2 2025 and final data in Q2 2026.

Kristian Johansen, CEO of TGS, said: ‘The project will deliver industry-leading subsurface imaging, enabling oil and gas operators to make more informed decisions and mitigate drilling risks.’

Meanwhile, TGS has won a shallow water OBN acquisition contract in Trinidad & Tobago. The 80-day 3D baseline contract is scheduled to commence in early Q3.

Wood opens energy transition centre in Abu Dhabi Wood has launched a centre for technical, strategic and economic energy transition solutions in Abu Dhabi. The ‘energy transition hub’ serves clients in the Middle East region, ‘bringing together the advisory and technical expertise required to deliver energy diversification and net zero goals’.

Its technical experts specialise in carbon advisory, renewable energy, hydrogen, carbon capture and storage and renewable

power generation and decarbonisation at large. Wood will help clients to integrate transition solutions including flare and emission reduction and asset emissions reviews.

The launch of the hub follows critical focus on achieving regional objectives, including UAE Net Zero 2050 and Saudi Vision 2030. The initiative addresses escalating demand for sustainable energy

solutions, with capital project investment in clean energy in the region anticipated to triple within the next five years.

Gerry Traynor, president of projects Eastern Hemisphere, said, ‘With global investment in the energy transition surpassing $2 trillion, Wood’s experts will play a key role in advancing pragmatic, scalable and sustainable energy solutions for our clients and the region’.

Oil and gas round-up DNO has made an ‘important’ oil and gas discovery in Northern North Sea licence PL1182 S in which the company holds a 40% interest. The discovery was made in Paleocene injectite sandstones of excellent reservoir quality with preliminary estimates of gross recoverable resources in the range of 39 to 75 million barrels of oil equivalent (MMboe), with a mean of 55 MMboe. The Kjøttkake exploration well encountered a 41-m oil column and a 9-m gas column. It is located 27 km northwest of the Troll C platform and 44 km southwest of the Gjøa platform. Partners include Aker BP (30%), Concedo (15%) and Japex (15%).

Shell, has taken a final investment decision for Gato do Mato, a deep-water project in the pre-salt area of the Santos Basin, offshore Brazil. The Gato do Mato Consortium includes Shell (operator, 50%), Ecopetrol (30%), TotalEnergies (20%) with PPSA acting as the manager of the production sharing contract (PSC). Estimated recoverable resource volumes of the Gato do Mato development are approximately 370 million barrels.

Wildcat Petroleum has signed an agreement with The Strategic Fuel Fund Association (SFF) owned by the South African government to evaluate petroleum assets in South Sudan previously held by Petronas. The partners will explore acquisition of all or parts of the assets. The agreement expires on 5 August 2025. Both parties can terminate with five days’ notice.

Petronas withdrew its operations in South Sudan in August 2024. Mandhir Singh, chairman of Wildcat said: ‘SFF is one of only a handful of companies that has signed a petroleum deal in South Sudan since the country gained independence in 2013. It has a well-established technical team in Juba which can assist Wildcat in any technical work it needs to conduct.’

APA Corporation (50%) and partners Armstong (25%), and Santos (25%), have announced preliminary results of the Sockeye-2 exploratory well. The Sockeye-2 well was drilled to a depth of approximately 10,500 feet and successfully encountered a high-quality reservoir with approximately 25 feet of net oil pay in FIRST

one block, Paleocene-aged sand with an average porosity of 20%. The porosity and permeability are both better than expected.

Additional zones of potential pay were also encountered in the shallower Staines Tongue formation. The Sockeye prospect is amplitude-supported across 25,000 to 30,000 acres, and confirms the partners’ geologic and geophysical models, derisking numerous additional prospects in the area. bp has received final government ratification for its contract to invest in the redevelopment of several giant oil fields in Kirkuk, northern Iraq. The contract between North Oil Company (NOC), North Gas Company (NGC) and bp includes the rehabilitation and redevelopment of the fields, spanning oil, gas, power and water with potential for investment in exploration.

Petrobras has identified hydrocarbons in the Campos Basin pre-salt, in an exploratory well in the Norte de Brava block. Well 1-BRSA-1394-RJS is 105 km from Rio de Janeiro, at a water depth of 575 m.

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TGS launches final mega Central Gulf Coast CO2 storage assessment

ENERGY TRANSITION BRIEFS The UK is investing £20 million into ‘Starmaker One’, a British fusion fund which will help fusion start-ups and is expected to leverage £100 million investment into the UK. The funding will help small fusion companies to develop technologies and capitalise on the opportunities of fusion energy in markets such as magnetics, industrial AI, robotics, healthcare, transportation and energy storage. Fusion uses the same process that powers the sun by combining two forms of hydrogen and heating them at extreme temperatures, releasing vast amounts of energy.

TGS has released the Central Gulf Coast-Haynesville CO2 Storage Assessment, the final segment of the Mega Gulf Coast Assessment offshore US. This assessment builds on previous releases for the East Gulf Coast and Gulf Coast assessments in 2024, culminating in a dataset covering more than 16,000 key wells with core-calibrated petrophysical and stratigraphic interpretation across more than 166,370 square miles in the Gulf Coast region.

The Central Gulf Coast-Haynesville CO2 Storage Assessment integrates petrophysical and stratigraphic analysis from 2326 wells and utilises more than 150 core analysis reports to refine geological interpretations. The stratigraphic framework includes 35 stratigraphic tops, from the Anahuac Formation down to the Triassic stratigraphy to provide a detailed understanding of storage capacity, reservoir quality, and sealing integrity.

Two RWE projects have been successful in the latest Italian renewables auction: the 45 MW Venusia wind farm in the province of Potenza, Basilicata region and the 48 MW Serra Palino wind farm in the province of Foggia, Apulia region. The start of construction is planned for the second half of 2025, with commissioning planned for next year.

The UK has shortlisted 27 green hydrogen projects in its HAR2 application.

Successful developers include: Aldbrough Pathfinder, Hygen Energy, Binn Ecopark, Green Cat Hydrogen, Hynamics, RWE Generation, Green Hydrogen 5, Grenian Hydrogen, Carlton Power, Uniper Hydrogen, Scottish Power, Lhyfe, Magor Net Zero, European Energy, Stratkraft Hydrogen, Centric, South Tees Net Zero, Four Zeros Energy, Strthallan Hydrogen, EDF, H and 2 Energy Ecosystem; Motive Fuels.

Cegal signs deal with Qumlo to enhance cloud architecture Cegal and Qumlo have signed an agreement to integrate Cegal’s subsurface data management and Cetegra capabilities with Qumulo’s cloud native architecture.

Qumulo’s file service platform, including Cloud Native Qumulo, Azure Native Qumulo, and Cloud Data Fabric will be merged into Cegal software.

Cegal chief technology officer John Henrik Andersen said: ‘Cegal is known for delivering energy workflows in Microsoft Azure and private clouds, especially with Cegal Cetegra. Now, integrated with the full suite of Qumulo’s cloud native services, optimised for oil and gas workloads, our customers will benefit from faster elastic performance and better economics, significantly reducing the time to decisions and increasing value.’

Qumulo president and CEO, Doug Gourlay, added: ‘With this technology, Qumulo and Cegal can offer up to three times the performance of competitive products in the cloud while delivering

Denmark has received 16 applications for its $4.2 billion CCS fund for carbon capture and storage. The Danish Energy Agency will select 10 companies. The money will be paid out in 2029-2044.

Equinor, Shell and TotaalEnergies have made a final investment decision to progress phase two of the Northern Lights development.The decision to invest some $680 million was made after the partners signed a commercial agreement with Stockholm Exergi to transport and store 900.000 tonnes of biogenic CO2 annually for 15 years.

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Will Ashby, executive vice-president of New Energy Solutions at TGS, said: ‘By leveraging our extensive well data library and expertise in petrophysical and stratigraphic analysis, we provide a comprehensive view of subsurface storage potential tailored to the needs of CCS stakeholders operating in the Gulf Coast region.

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improved economics. Cegal’s expertise and technology integrations in petrotechnical applications enhance this value for our mutual energy sector customers.’

Applications like Petrel, DecisionSpace, ArcGIS will be able to perform operations faster with data stored in the Qumulo file systems.

The Qumulo cloud-native architecture uses fast NVMe (Non-Volatile Memory express) and Managed Disks, as well as object storage, and supports multiple file protocols simultaneously. Qumulo Predictive Caching detects the user’s workflow, predicts what files are required by the workload next, and pre-fetches data into a cache that reduces file system latency and increases application performance.

Customers will save between 20% and 50% on the total cost of ownership for their file storage and performance environment by switching their existing cloud or on-premises solution to one designed

by Cegal and Qumulo, the partners said.

TECHNICAL ARTICLE

Reservoir characterisation of compacted sandstones in the Osmancık Formation, Thrace Basin, Türkiye Taner Arpacı1*, İsmail Ömer Yılmaz 2, Serhat Akın2 and Emin U. Ulugergerli3.

Abstract The Thrace Basin houses the main gas-producing fields of Türkiye. The gas reservoirs in the basin are mostly located in deltaic sediments of the Oligocene Osmancık Formation where the hydrocarbon-bearing sandstone reservoirs generally reflect class 3 type of amplitude-versus-offset (AVO) anomalies. Our results indicate that AVO behaviour changes from Class 3 to Class 2 response due to the ascending compaction trend of the lithology with increasing depth.

Acoustic impedances (AI) show an abrupt increase, because of higher compaction of the sandstones of the Osmancık Formation. Bright spots are the distinctive characteristics of gas sands encased in shale lithology in seismic stack sections. However, at higher depths of the Osmancık Formation, sweet spots tend to disappear due to lower porosity and permeability at the producing reservoir intervals. We propose a workflow to integrate pre-stack seismic analysis and lithology prediction of the field to characterise the gas-producing reservoirs. Spatial distribution of gamma ray values obtained with neural network prediction indicates highly lateral variation of shaliness, which is directly related to reservoir quality in the deeper Osmancık Formation. Therefore, diagenesis in sandstones and increase in shaliness play a crucial role in terms of evaluation of petrophysical properties of the reservoir, such as porosity and permeability.

Keywords: Seismic Reservoir Characterisation, Compacted Sandstones, Osmancık Formation.

Introduction The Thrace Basin is the main gas production site located in northwest Türkiye (Figure 1). The basin has been explored extensively; sedimentary aspects (Turgut et al. 1991; Siyako 2006), stratigraphic evolution (Sakınç et al. 1999; Turgut and Eseller, 2000; Siyako and Huvaz, 2007) and tectonic evolution (Okay et al., 1996; Görür and Okay 1996; Yılmaz et al., 1997) of the basin have been well-established. In addition, the properties of formations and hydrocarbon potential of the basin by the means of geological and geophysical techniques have also been investigated (Siyako et al., 1989; Gürgey, 2009; Perinçek et al., 2015; Şen and Yıllar, 2016; Yılmaz et al., 2016; Baytok et. al., 2017; Arpacı and Özdemir, 2020).

In this paper, we have focused on the Oligocene Osmancık Formation (Figure 2). Oligocene formations in the basin are deposited in a fluvial and wave dominated deltaic system. This deltaic system consists of progradational deltaic lobs in the Danişmen, Osmancık and Mezardere Formations. Delta front sandstone facies are potential reservoirs where productive gas pockets have been detected as bright spot reflectivities in seismic data. However, increasing depth causes decreasing porosity and permeability values. In this respect, bright spots in seismic sections are replaced by dim spots, which makes it harder to

locate hydrocarbon-bearing reservoirs. Even if the presence of hydrocarbons has been detected, due to deteriorating petrophysical properties production rates decrease rapidly.

The main focus of this study is to explain the reason behind non-suitable reservoir conditions at deeper sections of the Osmancık Formation. For this purpose, the Karaçalı-Yulaflı Field, located in the eastern part of the Thrace Basin, was studied.

This paper consists of both qualitative and quantitative seismic interpretation of the Osmancık Formation. The results are coupled with probabilistic neural network application and geological setting to identify the petrophysical characteristics of producing reservoir intervals.

Figure 1 Geology map of Thrace basin (modified from Siyako and Huvaz, 2007).

1

Turkish Petroleum Corporation (TPAO) | 2 Middle East Technical University (METU) | 3 Çanakkale Onsekiz Mart University (COMU)

*

Corresponding author, E-mail: tarpaci@tpao.gov.tr

DOI: 10.3997/1365-2397.fb2025031

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Figure 2 Generalised stratigraphy of the Thrace Basin showing reservoir and source rock properties including petrophysical properties, depositional environment, geological events and total organic carbon content (modified from Huvaz et al., 2005).

Study area and datasets The Karaçalı-Yulaflı Field is in the east of the basin, shown with a red rectangle (Figure 1) and was selected for a detailed geophysical characterisation of the deeper the Osmancık Formation.

The dataset used in this study consists of 3D vibroseis seismic data covering an area of 104 km2. There are 28 wells with a full set of logs in the study area. The wells are categorised into three groups: ten wells in group-1, nine wells in group-2, seven wells in group-3 and two wells are outside of these well groups. Figure 3 shows the well groups and locations in the field.

Methodology A detailed workflow covering stages of this study is given in Figure 4. Both seismic interpretation and reservoir characterisation studies were conducted. Following the editing well logs, well-to-seismic ties for each well were assessed. Seismic data were then interpreted and a velocity model was developed using well logs and interpreted seismic horizon followed by a structural model generation. The shear wave velocities at the wells without shear measurements were generated using a linear

relation derived from crossplots of measured p- and s-sonic log at three wells.

Quantitative seismic interpretation, referred to as seismic reservoir characterisation or reservoir geophysics, is a widely used method to reveal reservoir properties and fluid indications of a formation. AVO, pre-stack seismic inversion and application of neural network modelling to understand reservoir properties were mainly utilised in this work. AVO analysis was implemented for evaluation of the fluid content. Prestack impedance inversion of seismic data was also run to obtain several elastic parameters to evaluate the presence of hydrocarbon-bearing sandstone intervals. Finally, a probabilistic neural network (PNN) application was run to understand the distribution of gamma ray values to detect shaliness intensity of the deeper Osmancık Formation.

Conventional (qualitative) seismic interpretation of study field Seismic horizon and fault interpretation helped to create the initial structure of the sedimentation. Accurate velocity modelling and time-to-depth conversion was a key aspect to evaluate structural

Figure 3 Well groups and locations in base map.

Location is red square in Figure 1.

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Figure 4 Study workflow for the deeper Osmancık Formation in the Thrace Basin. Red arrow indicates techniques applied in the workflow to achieve the goal.

Figure 5 Seismic interpretation of A and A’ section (left) and gridded top of the Osmancık Formation (right). Red horizon on the seismic section represents entrance of the Osmancık Formation. Location is red square in Figure 1. Two main reverse faults are displayed with red and green colours.

Figure 6 The outlines of the workflow to generate a structural model in depth.

behaviour. To correlate well logs and seismic reflections, synthetic gathers were created using well logs and matched with real seismic data. Correlation between real and synthetic data varies between 70% and 90% for available wells. Well-to-seismic tie process is followed by the interpretation of faults and horizons. The north branch of the Terzili Fault Zone includes two main reverse faults in the field (Figure 5). The main fault with red colour, which is a reverse fault, discriminates well group 1 and 2. Another main fault shown in represents a structural trap for shallower producing zones around well group 1 within the shallower part of the Osmancık Formation. Addition to the entrance of the Osmancık Formation (red horizon), top of the Danişmen (pink colour) and Mezardere (green colour) formations were also picked. Horizons were picked in every fifth inline and fifth crossline. A display of a seismic

section at a certain inline is given in Figure 5a. After picking of the horizons, each picked event was gridded to cover the whole field.

Figure 5b, shows the entrance of the gridded Osmancık Formation.

Next, the velocity model was generated using sonic logs and interpretations to convert time domain into the depth domain.

After time-to-depth conversion was applied to the seismic volume and interpreted horizons and faults, a structural model in depth was built. The visual outlines of workflow showing how we have generated the structural model is given in Figure 6.

Data preconditioning for Quantitative Seismic Interpretation In the theory of seismic techniques, all available reflections are assumed as horizontal while reflectors are shifted residually. To FIRST

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implement quantitative seismic methods and obtain robust and reliable results, CDP gathers were conditioned. To flatten the gathers, a statics-based method called ‘trim statics’ was applied.

After a flattening process, to eliminate parabolic noises and to increase S/N ratio, a mild ‘parabolic radon transform’ was performed. These conditioned gathers and RMS velocity volume were utilised to create angle gathers. These angle gathers were calculated between 2-42 degrees. Next, near (2-14), mid (14-28) and far (28-42) angle band stacks were generated.

Well log quality is an important parameter to create accurate initial impedance models for the inversion process. Therefore, well logs should be conditioned, and missing parts are required to be filled, using either empirical equations or measured available logs in the field. In the study field, while p-sonic and density logs are measured at all wells, only three wells have measured s-sonic log data. These wells are Well-111, Well-112 and Well-36. For Well-111, there was a very limited shear sonic measurement in the Danişmen Formation even though the measured logs cover the Osmancık Formation. For this reason, shear sonic log was estimated for the missing parts of the Danişmen Formation using a linear relationship which represents the lithology. Therefore, it should be noted that Well-111 is a mix of real and synthetics data. From the log measurements, it is observed that while VP/ VS ratios of Well-36 and Well-111 are between 2.4 and 3.0, this ratio is between 1.5 and 2.5 for Well-112 because of a calibration issue with measured shear sonic data. Different sonic tools were used during the shear measurement process, and these tools were not calibrated with expected lithology, resulting in very low shear sonic values. This difference in shear values will cause an unbalanced distribution of elastic properties. To ensure which values are within a correct range, VP/VS ratios from surrounding wells were also compared to the wells which measured s-velocity is available in the field. The comparison shows that VP/VS ratio

varies between 1.5 and 2.5, which also represents the theoretical ranges. Using all wells with measured s-sonic logs, P-S velocity crossplots were generated and a linear relation was obtained for each (Figure 7). Obtained relations from these crossplots show that Well-36 and Well-111 have lower s-velocity values (Figure 8, left). Therefore, these velocities were normalised to an optimum range for these wells (Figure 8, right) with the equation below and the results were compared.

(1)

where

is the normalised log curves and are the minimum and maximum log values.

Relationship between elastic properties and lithology Crossplots of elastic parameters were used to link rock properties, lithology and fluid content. Figure 9 shows AI versus VP/VS ratio crossplots for the wells having s-sonic logs. The same colours represent similar lithologies in the plots. Blue areas include background points for Osmancık sands. Hard shales are also available in these polygons. Although the trend of magenta-coloured ellipses varies, the data points fall into low AI and high VP/VS ratio zone, which represents soft lithology dominated with shale.

This variation in the shale trend, especially for Well-111, could be accounted for by the lack of shear-wave data representing the shaly Danişmen Formation. Since different VP/VS ratio trends of the shaly intervals at the well locations exhibit uncertainty for reservoir characterisation, the measured well logs and missing parts are calibrated throughout this study. Red circles indicate a low-medium range of AI and a low range of VP/VS ratio values for gas-bearing sandstones in the Osmancık Formation.

Figure 7 Mathematical relationships of P-wave versus S-wave velocities for each well are shown. Well-A, B and C are the wells around the study field.

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Figure 8 Comparison of the Crossplots of P-velocity versus S-velocity before (left) and after (right) normalisation of S-velocity values for Well-111 and Well-36. Note that after the normalisations P-S relationship for all wells are almost at the same trend.

Figure 9 Crossplots of AI versus VP/VS ratio for Well111 (upper-left), Well-112 (lower-left) and Well-36 (upper-right). Cut-off values for different zones cannot be specified directly. However, it is observed that specific colours show distinct characteristics for similar lithologies.

AVO analysis for sweet spot mapping AVO analysis provides an important Direct Hydrocarbon Indicator (DHI) (Shuey, 1985). AVO anomalies are generally observed in producing Osmancık sands in the Thrace Basin. Especially, Class 3 AVO anomalies causing bright spots are clearly identified, and most of the production is from these sweat spots. However, bright spot reflections lose their strength with increasing depth within the formation, and detection of hydrocarbon-bearing sands becomes harder.

One of the producers from the shallower Osmancık Formation, such as Well-18, shows an AVO Class 3 response at reservoir zone while Well-12, a deeper formation producer, indicates a Class 2 anomaly with polarity reversal. Figure 10 shows two

hydrocarbon-producing zones at a different range of depths.

The reservoir zone within Well-18 is detected as a bright spot at 780 ms on stacked seismic data. However, the Class 2 producer at 1100 ms in Well-12 is almost a flat reflection. Therefore, it is not possible to detect this reservoir interval for Well-12 using only stack seismic data. The most distinctive feature in terms of seismic data between the shallower and deeper Osmancık Formation is relevant AVO classes because each class type represents a different AI relationship. AVO Class 3 type indicates high impedance contrast between gas sand and encasing shale lithology. However, because AVO Class 2 indicates near zero impedance contrast between producing sand and shale, impedances and reflections are not distinctive for the deeper Osmancık Formation.

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Pre-stack seismic inversion for lithology and pore fluid discrimination Prestack seismic inversion was run to obtain rock properties all over the field (Özdemir et al., 2001). Although log data provides higher resolution than seismic data, elastic rock properties

represent variations only at the well location. Also, stacked seismic data do not contain any information other than zero offset reflections and provide no pore fluid identification. S-impedance (SI) besides AI is required for effective fluid identification (see, for example, Özdemir et al., 2006).

Figure 10 Top-left panel shows the angle gather at Well-18 location and Class 3 AVO response of an event around 770 ms, in which red and green curves are the top and base of the reservoir. Stack section (top-right panel) confirms the AVO anomaly as a bright spot, pointed out with a red rectangle, around the shallower Osmancık Formation. Bottom-left panel includes the angle gather at Well-12 and Class 2 AVO response of an event around 1100 ms, which is at the deeper Osmancık Formation. On the contrary, the stack section has almost no reflection at reservoir level, shown with another red rectangle, due to polarity reversal with increasing offset.

Figure 11 (A) Arbitrary line passing through well group 2 wells, (B) stacked seismic data, (C) AI and (D) VP/ VS ratio sections created from arbitrary line are shown in this figure. The unit of AI is m/s x g/cm3 and VP/VS ratio is unitless. AI discriminates soft (green colour, low impedance values) and hard lithologies (purple colour, high impedance values) successfully. VP/VS ratio is affected by fluid content; therefore, it is not an indicator of compaction. Even, high gas saturated reservoirs (pointed out with dash lines) show lower VP/ VS ratio as it is displayed in the VP/VS ratio section.

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volume at 1000, 1200 and 1400 ms are given in Figure 12.

Higher values of impedances with increasing depth represent an increasing compaction trend within the formation. This result also supports the changing AVO responses from Class 3 to Class 2 with increasing depth as a result of an increasing compaction trend.

Figure 12 Figures represent impedance variation from 1000 ms to 1400 ms from top to bottom. P-impedances are in the m/s x g/cm3 unit. Black rectangles indicate footwall of the reverse faulting system, in which the wells of group-2 are situated. The shallower Osmancık Formation for this group is around between 1000-1200 ms. After around 1200 ms. the lithology becomes more compacted with increasing depth.

The angle band stacks 0o-15o, 15o-30o, and 30o-45o and extracted wavelets from each angle stack were used as input for a simultaneous prestack inversion scheme. Inverted AI values were used to understand the compaction trend from shallower to deeper section of the Osmancık Formation while the VP/VS ratio computed from the ratio of inverted acoustic and shear impedances (AI/SI) were utilised to compare productive and non-productive reservoir intervals from different well locations.

Low impedance values represent unconsolidated and porous sandstone reservoirs while higher values are related to compacted and less porous reservoirs. Figure 11 indicates a composite stacked seismic section passing through Group 2 wells with a corresponding inverted AI section and the section VP/VS ratio computed from AI/SI. AI values show an abrupt change (Figure 11 C) while VP/ VS ratio is still low (Figure 11 D) in the productive zones. The variation of AI within the Osmancık Formation covering a 3D

Probabilistic neural network – gamma ray distribution In the deeper section of the Osmancık Formation shaliness plays an important role due to lower grain sizes in deeper sections related to reservoir properties. Thus, lateral shaliness was studied to understand sandy areas representing possible prospective locations. Shaliness can be distinguished clearly using the VP/ VS ratio, especially for Danişmen and shallower Osmancık Formations (magenta zones in Figure 9). However, at higher depths of the Osmancık Formation, the difference in VP/VS ratio between sand and shale becomes harder to discriminate (blue zones in Figure 9). Additionally, we have limited shear sonic data while we have measured the gamma-ray (GR) log in each well in the field. For this purpose, neural network modelling was performed. Three types of data sets were utilised to achieve distribution of GR values using PNN: (1) a type of the log curve representing the parameter aimed to be distributed, (2) seismic stack data as an internal attribute, (3) seismic inversion outputs and attributes generated from the seismic data as external attributes. Selected log parameter, which is GR, was correlated with seismic attributes using a signal operator. Length of the operator is tested during the implementation of this method. All data sets were trained and cross-correlated to obtain an optimum result.

During this process, several error plots were utilised.

In this research, GR distribution of the 3D seismic field was targeted. Firstly, the multiple attribute list was created to be trained. A step wise regression technique was applied to find the best fitted attributes with GR log. After the training of data sets, well logs from each group were selected and the ones which are not suitable were extracted. To decrease computational cost, six attributes were utilised (Table 1). The crossplot of actual gamma ray values versus predicted values (Figure 13) shows that the correlation coefficient was calculated as 82%. Finally, PNN was performed and computed and GR values are mapped for the deeper Osmancık Formation (Figure 14). Results indicate that shaliness increases from south west to north east of the field.

Attribute Number

Attribute

Training Error

Validation Error

1

Average Frequency

10.576

10.937

2

(S-impedance)2

9.756

10.026

3

Dominant Frequency

9.411

9.796

4

Filter 15/20-25/30

9.345

9.774

5

(Density)

9.23

9.735

6

(Lambda*Rho)2

9.058

9.657

2

Table 1 Used attributes for the training and validation of gamma-ray distribution in the field.

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Figure 13 Actual and predicted gamma ray values are crossplotted. Correlation between actual and predicted gamma ray after PNN is around 81%.

Figure 14 Gamma-Ray distribution representing the deeper section of the Osmancık Formation is given. GR values are higher in the north east of the field. Well group-2 and group-3 sands (on the west and south of the area) seem to be clearer than the sediments of Well group-1.

Conclusions In the Karaçalı-Yulaflı Field, gas production is performed from both the shallower and deeper part of the Osmancık Formation.

Interpreted seismic data show that while the group-1 wells are located at the upper block of a reverse faults system, group-2 wells are situated at the lower block.

Measured shear wave velocities in Well-111 and Well-36 were very low due to the difference in log tools and missing lithology calibration issues. Calibration of measured s-sonic logs affects the inversion results directly as much as the accuracy of shear wave estimation. To eliminate undesirable results of prestack seismic impedance inversion, s-sonic logs were normalised in this study. The result of the ratio of inverted impedances was found to be successful for the detection and discrimination of hydrocarbon and non-hydrocarbon bearing zones.

In the shallower parts of the Osmancık Formation, producing intervals indicate a Class 3 AVO response resulting in bright spots in the seismic stack section. On the other hand, no reflection or week reflections are observed in deeper parts of the formation resulting from the Class 2 AVO response with increasing offset/ angle of incidence. Change in AVO response is the reason for increasing the compaction and consolidation trend.

Inverted acoustic impedances from seismic inversion discriminate between shallower and deeper parts of the Osmancık 34

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Formation clearly. While shallower parts are characterised by low impedance values, impedances show an abrupt change at higher depths. Higher impedances are the indicator of compacted and low porous sediments.

Gas-bearing sandstones show lower impedances at shallower depths while impedance values are considerably higher at deeper parts. Discrimination of gas sand reservoirs from dry zones were achieved by using VP/VS ratio. To understand the relationship between AI and VP/VS ratio values of different lithologies and gas-bearing sediments, crossplots of these elastic parameters were evaluated. AI values for gas intervals change from 3000 to 6000 m/s x g/cm3 according to burial depth while VP/VS ratio is around 1.5-1.6 for any depth of reservoir.

GR variations in deeper parts of the formation are mapped to reveal shaliness variations using probabilistic neural network studies. The GR predictions indicated that shaliness increases towards the north of the field. These results were confirmed by low porous sediments for group 1 wells.

Acknowledgement This manuscript is one of the outcomes of the PhD thesis of the lead author (Taner Arpacı). The authors are grateful to the TPAO for permission to publish the data sets that appear in this publication.

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References

Shuey, R.T. [1985]. A simplification of Zoeppritz Equations. Geophysics,

Arpaci, T. and Özdemir, H. [2020]. Step-out well positioning using hydrocarbon indicators from seismic inversion: a case study. First Break, 38(1), pp.43-51.

50, 609-814.

Siyako, M. [2006]. Trakya havzası Tersiyer kaya birimleri. Trakya Bölgesi Litostratigrafi Birimleri’nde, Maden Tetkik ve Arama Genel

Baytok, S., Selek, B. and Özdemir, H. [2017]. Cross-equalization and prestack seismic inversion of time-lapse land seismic data, Central Thrace Basin, Turkey. The Leading Edge, 36(7), pp.588-597.

Müdürlüğü, Stratigrafi Komitesi, Litostratigrafi Birimleri Serisi, 2, 43-83.

Siyako, M., Bürkan, K.A. and Okay, A.İ. [1989]. Biga ve Gelibolu

Görür, N. and Okay, A.I. [1996]. Fore-arc origin of the Thrace basin, northwest Turkey. Geologische Rundschau, 85, 662-668.

yarımadalarının Tersiyer jeolojisi ve hidrokarbon olanakları. TPJD Bülteni, 1(3), pp.183-199.

Gürgey, K. [2009]. Geochemical overview and undiscovered gas resources generated from Hamitabat petroleum system in the Thrace Basin, Turkey. Marine and Petroleum Geology, 26(7), pp.1240-1254.

Siyako, M. and Huvaz, O. [2007]. Eocene stratigraphic evolution of the Thrace Basin, Turkey. Sedimentary Geology, 198, 75-91. Şen, Ş. and Yıllar, S. [2016]. Nature, Genesis, and Significance of the

Huvaz, O., Sarikaya, H. & Nohut, Ö.M. [2005]. Nature of a regional

Gaziköy and Kesan Formations (Thrace Basin, Turkey): Eocene Tur-

dogleg pattern in maturity profiles from Thrace basin, northwestern

bidites and Olistostromes Formed on an Active Tethyan Margin. The

Turkey: A newly discovered unconformity or a thermal anomaly. AAPG Bulletin, 89, 1373-1396.

Journal of Geology, 124(4), 463-479.

Turgut, S. and Eseller, G. [2000]. Sequence stratigraphy, tectonics and

Okay, A.I., Satir, M., Maluski H., Siyako, M., Monie, P., Metzger, R. and Akyüz, A. [1996]. Paleo- and Neo-tethyan events in northwestern

depositional History in Eastern Thrace Basin, NW Turkey. Marine and Petroleum Geology, 17, 61-100.

Turkey: geologic and geochronologic constraints. In: Yin A, Harrison

Turgut, S., Türkaslan, M. and Perinçek, D. [1991]. Evolution of the

TM (eds). The tectonic evolution of Asia, Cambridge University

Thrace sedimentary basin and its hydrocarbon prospectivity. Spencer

Press, pp 420–441.

AM (ed) Generation, accumulation, and production of Europe’s

Özdemir, H., Hansen, J.W. and Tyler, E. [2006]. Rock and reservoir parameters from pre-stack inversion of surface seismic data. First Break, 24(10), 83-87.

hydrocarbons. Special Publication of European Association of Petroleum Geoscientists, 1, 415-437.

Yilmaz, K., Umul, B., Davis, J. and Nilson, G. [2016]. Tight gas develop-

Özdemir, H., Ronen, S., Olofsson, B., Goodway, W. and Young, P. [2001]. Simultaneous multicomponent AVO inversion. 71st SEG Conference and Exhibition, Expanded Abstracts, 269-272.

ment in the Mezardere Formation, Thrace Basin Turkey. Journal of Natural Gas Science and Engineering, 33, 551-561.

Yılmaz, Y., Tüysüz, O., Yiğitbaş, E., Genç, Ş.C. and Şengör,

Sakınç, M., Yaltırak, C. and Oktay, F.Y. [1999]. Palaeogeographical

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oclimatology, Palaeoecology, 153, 17-40.

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GLOBAL EXPLORATION Explorers have a good idea of where global hotspots are globally, but excellent multi-disciplinary geoscience strategies are need to identify sweet spots. They are focusing on areas where new sources of oil and gas are required to keep the world supplied with energy during the transition to renewables. Geoscientists are also identifying areas for carbon capture and storage, offshore windfarms, hydrogen and geothermal projects.

Mark Hamilton gives an overview of recent drilling in Egypt’s western delta as the Eastern Mediterranean emerges as a key region for hydrocarbon exploration.

Tad Choi et al put the exploration spotlight on Malaysia, Indonesia and India.

Bob Fryklund et al demonstrate why hotspots will help to provide some of the most advantaged oil and gas — lowest cost, highest margin and lowest emissions.

Carl Fredrik Gyllenhammar argues that a report showing that licence PL 993 offshore Norway has only an 18% chance of success is worth revisiting with a chance of success more closer to 50%.

Neil Hodgson et al cast their eyes on the last great global exploration play to be tackled – the counter regional dipping clastic fan play on the basin floor of the Earth’s passive margins.

Sindre Bull-Jansen et al demonstrate how quantitative interpretation techniques have shown potential AVO anomalies, providing valuable guidance for prospect identification.

Erling Franzen et al discuss how advanced geoscience technologies and data are successfully supporting global exploration.

Mike Lakin identifies plays around the world that will be looked at again in a rapidly changing global energy landscape.

Submit an article

Special Topic overview January

Land Seismic

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

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

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Egypt’s West Mediterranean Sea – a global exploration hotspot Mark Hamilton1* gives an overview of recent drilling and exploration activity in Egypt’s west Mediterranean as it emerges as a key area for hydrocarbon exploration.

Introduction There has been a rush of exploration activity in Egypt this year with two high-impact Nile delta wells completed before the end of February and substantial 3D acquisition in 2024 meaning the western delta will be almost entirely covered in 3D seismic data once processing is finalised. In the last decade, the Eastern Mediterranean has emerged as a key region for hydrocarbon exploration, with Egypt playing a leading role due to its well-developed infrastructure and strategic location. Egypt has been at the forefront in terms of exploration and production, with development in Egypt’s Mediterranean beginning in the 1970s (Abu Madi – El Qara field, 1975) leading to extensive well-developed infrastructure, network of pipelines, oil refineries and gas processing plants, including LNG facilities. This makes Egypt an ideal hub in the Eastern Mediterranean and adds to its reputation as an exploration hotspot.

The Nile Delta Basin can be regarded as a mature hydrocarbon province, although new plays continue to rejuvenate the region (Lottaroli and Meciani, 2022). Exploration drilling began onshore in the 1950s, with initial discoveries being made in the 1960s. The Nile Delta Basin is largely a gas and condensate province, with shallower Plio-Pleistocene-aged clastic reservoirs typically yielding drier gas and deeper Oligo-Miocene-aged clastics reservoirs containing more condensate and some liquids.

The deeper-water regions and stratigraphically deeper reservoirs have only been targeted in more recent decades as the continued technology advancements allow. This includes discoveries

in the Levantine Basin (including in Israel and Cyprus), where significant gas volumes have been found in pre-Messinian clastic reservoirs (e.g. Leviathan), as well as within pre-Messinian carbonate buildup structures (e.g. Zohr).

The northern onshore Western Desert Basins in Egypt are Mesozoic-to-Tertiary rift systems, and are very mature in terms of exploration, with the first discoveries made in the mid-1960s (Alamein 1, 1966). There are source intervals at multiple levels, with reservoirs present throughout the Jurassic to Lower Cretaceous succession. This northern Western Desert Basin extends into the offshore region and has not been extensively tested in this domain. The 1976 Sidi Barrani 1 well is one of the few offshore shelf tests, which targeted Cenomanian clastics, the Alamein Dolomite and possible reefal and clastic developments within the Lower Cretaceous and Jurassic sections. The well encountered oil staining in the Cretaceous and Jurassic, as well as fair reservoir quality in both the Barremian-aged Sidi Barrani Formation and Jurassic Khatatba Formation sands. It is thought to have failed due to the trap not being well defined on 2D seismic data a risk that should be mitigated in areas with recent 3D seismic acquisition.

Surrounded by the mature Nile Delta and onshore Western Desert areas, is Egypt’s West Mediterranean Sea (EWMS) a frontier area in terms of hydrocarbon exploration (Figure 1).

There are undoubtedly several reasons why this region has been neglected until very recently, some of which include the relatively deep water, lack of infrastructure, lack of seismic data and com-

Figure 1 Overview of structural elements and geological domains, modified after Baer et al. (2017).

EWMS includes the western part of the Nile Delta Cone, the Herodotus Basin, the southeastern part of the Mediterranean Ridge, as well as the offshore extension of the onshore Western Desert Basin (shelf, transform margin and canyon systems). Also included are locations of some of the exploration wells referenced.

1

TGS

*

Corresponding author, E-mail: mark.hamilton@tgs.com

DOI: 10.3997/1365-2397.fb2025032

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Figure 2 An example of the improved imaging gained from 3D seismic (lower panel) versus 2D seismic (upper panel). While the 2D data are suitable for regional-scale work, the 3D data are essential for trap definition and detailed stratigraphic work. Some examples of areas of uplift are indicated by the blue arrows in the lower panel.

paratively challenging seismic imaging. The last two aspects have been vastly improved over the last decade.

New data Until approximately 2015, the region was covered by very little seismic data that was readily available to the industry. Approximately 10,000 km of legacy 2D data and 10,000 km2 of legacy 3D data were reprocessed and made available to the industry in 2016.

This reprocessing was followed up with two regional broadband multi-sensor 2D seismic data acquisition campaigns during 2016 and 2018, totalling 7300 km and 22,400 km respectively.

These 2D seismic data formed the basis of a regional geological understanding and were used by companies to secure hydrocarbon exploration concessions in EWMS. This was a significant development in an area where there were no held concessions and little past exploration activity. Since the award of concessions and between 2020-2024, eight broadband multi-sensor 3D seismic surveys were acquired spanning over 29,400 km2 in areas where there was no existing 3D seismic data and over both held concessions and open acreage. Along with improved imaging (e.g.

Figure 2), these 3D data allow explorers to focus on stratigraphic elements and have more confidence in structural interpretation than is possible with 2D data.

New technologies Seismic imaging in EWMS / Herodotus Basin is generally more complex compared to the Levantine Basin, despite a Messinian evaporite section of similar thickness. Figure 3 illustrates an example of a seismic section through the Levantine Basin, compared with some examples in EWMS. Although generally tabular in the deeper water areas, the evaporites are not simply clean high 38

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velocity halite as observed in other salt provinces but contain a significant amount of complexity and heterogeneity, as discussed in detail by other authors (e.g. Roveri et al. 2014; Feng et al.

2016). High amplitude events within the Messinian evaporite section are likely clastic layers. The level of deformation of these layers can give an indication of the deformation that this layer has undergone and the broader tectonics influencing the region (e.g. Evans and Jackson, 2021). The Messinian interval provides a significant challenge to the underlying seismic image due to distortion, attenuation, and complex diffractions.

Depth imaging has proven critical for high quality seismic imaging in the Eastern Mediterranean (e.g. El-Bassiony et al., 2018). An important factor in obtaining an accurate velocity model is obtaining a reasonable velocity for the complex Messinian evaporites, discussed above. As observed in Figure 3, the thickness of the layer, the amount of clastic inclusions, the deformation of the layer and the vertical level at which the clastic inclusions are located differ throughout the area. It is therefore essential that there is a variable velocity used within the Messinian evaporite layer to flatten the seismic gathers and have a reliable velocity model for the imaging, resulting in a more accurate pre-salt image. Velocity analysis of the Messinian salt reveals an interval velocity range from 3900 to 4800 m/s.

Mobile shales are recognised as an additional challenge for seismic imaging in the Herodotus Basin (e.g. Van Simaeys et al.

2021). They have an unclear seismic expression as they generally have a low acoustic impedance contrast with many other sedimentary rocks. Typically, they appear as transparent bodies on the seismic. They can have complex geometries and spatial variations and their seismic response and velocities can depend

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on the overpressure and fluid content, which are difficult to predict and may change quickly within a survey area. These shales can be both intruded into the base of the Messinian evaporites, extruded above them, and in some cases in the Mediterranean, extruding to seabed to form present-day mud volcanoes. In terms of velocity model building, the larger shale bodies are mapped and included in the velocity model-building process during imaging and a range of velocities are tested to obtain an optimal representation.

Imaging tools that are typically utilised for updating the velocity model and interpretations in areas with these evaporites and mobile shales include manual velocity insertion using interpretation, velocity scans, tomography, and Full Waveform Inversion (FWI) (e.g. Davies et al., 2024). More recently, elastic FWI has proven to solve some of the shortcomings of the acoustic FWI in areas with strong velocity contrasts. This is the capability to remove a halo above the Top Messinian and resolve the Messinian layer complexity more accurately due to a more complete description of the physics that accounts for mode conversion from the top of the layer. The increase in model resolution at Messinian level has been shown to a have hugely beneficial effect on the structure and residual move-out of the pre-Messinian targets (Romanenko et al., 2025). Another imaging technique that has been successfully applied in the region to improve seismic volumes is mode conversion removal (Kumar et al., 2018). Recorded converted mode energy is generated where there are strong acoustic velocity contrasts (e.g. where we have Messinian salt) and can sometimes cause interference in the vicinity of pre-Messinian exploration targets.

While high-end imaging workflows and migration algorithms are one way to address the seismic imaging challenges in this

frontier area, another option that can be used in conjunction with this is to utilise alternative acquisition options. The benefits of multi-azimuth acquisition have been recognised for many years in this region, such as over the Raven field (e.g., Marten et al., 2007). Baptiste et al. (2024) describe the benefits of a recent node survey over the Atoll field, a first for the Nile Delta.

Donaldson et al. (2024) outline the advantages of a wide-azimuth configuration with multiple vessels and low-frequency sources to better define subsalt reservoir presence. The lower frequencies and longer offsets from these higher-end innovative acquisitions allow for deeper FWI updates and a better image, particularly in the pre-Messinian section. They are typically applied in more targeted and field-specific surveys and mostly on a proprietary basis to better define targets and follow up drilling.

High impact exploration Geophysically and geologically, with the improved data coverage as well as the improved data quality, the EWMS region has started to become an exploration hotspot. The region offers a diversity of plays depending on location, with three main sub-areas that will be the immediate focus for exploration.

The eastern part of the area is essentially the deep-water Nile Delta (Figure 1), where the primary targets are likely to be pre-Messinian clastics, and would need to contain substantial hydrocarbons to be economic in deeper waters. Secondary Plio-Pleistocene targets may add further volumes for any discovery that gets developed. It is possible to identify channel systems in the Pre and Post-Messinian stratigraphy using seismic attributes extracted on interpreted surfaces (e.g. Figure 4). In both the Oligo-Miocene and Plio-Pleistocene sections, the channels are generally weakly confined, low gradient slope channel systems

Figure 3 Example seismic sections through the evaporite layer in the Levantine Basin (panel D) compared with examples in EWMS (panels A-C). All examples are KPSDM imaging in depth. The evaporite inclusions are less complex and less deformed in the Levantine when compared with panels B and C. Combined with a less complex postevaporite section, this leads to easier imaging of the pre-Messinian section, despite panel D being an example of an older survey with a lower end imaging workflow. Panel A shows an example of the very west of the EWMS, where we start to see the influence of the Mediterranean ridge. In this area, the evaporites tend to be inflated/thicker and cleaner or more halite-rich. However, the imaging remains challenging as the post-evaporite section is severely deformed due to compression related to the Mediterranean ridge subduction.

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with moderate sinuosity. The reservoir presence risk should be low, but there could be high variability in reservoir quality in this kind of system. Very similar Oligo-Miocene reservoirs have proven successful in other parts of the Nile Delta at this level, for example the Atoll and Nargis discoveries.

Farther to the west of the area, in the deeper Herodotus Basin, it is expected that these channel systems transition to lower gradients and become less confined, with the potential for terminal fan systems with sheet sand lobes becoming increasingly likely.

The Kiwi-1 well is the only exploration well located within this deeper basin area (Figure 1). It was drilled in 2010 and targeted a pre-salt structural closure. The well encountered no reservoir within the structure, but did encounter a good quality Early Oligocene (Rupelian age) reservoir in a deeper secondary target that appears to have lacked a valid trap. This well penetrated approximately 3000 m below mud line and so details on the deeper stratigraphy of the basin (more than 15 km in places) is still unknown.

The third sub-area is the offshore continuation of the onshore Western Desert rift systems. Here, Mesozoic to Tertiary rift systems are expected to extend onto the shelf area in the offshore (Figure 1). The Sidi Barrani well results should be encouraging with oil staining and suitable reservoirs encountered. Recent drilling campaigns, including the Khendjer-1 well (2024 in the North Dabaa concession) and Nefertari-1 well (2025, in the North Marakia concession) have targeted this region, though the exact plays these wells targeted have not been detailed.

The Khendjer-1 well was reported as dry. However, details on which play elements were proven have not been disclosed. The Nefertari-1 well was announced as a gas discovery at relatively shallow depths (~1km below mud line), likely indicating a Cretaceous or younger-aged reservoir. The advantage of this area

is the shallow water and therefore comparatively reduced drilling and development costs for any discoveries. There are numerous untested faulted traps within this shelfal domain (e.g. Figure 5), with the potential for multiple stacked reservoir intervals within these traps, as is observed in many discoveries onshore in the Western Desert. An interesting question is whether the charge for this discovery is biogenic or thermogenic, and if so, whether it is coming from a source rock similar to that of the Western Desert or charged from a kitchen within the deeper water Herodotus Basin. The latter would confirm a working source rock in the deeper-water area, derisking other areas of the EWMS for further exploration.

Summary Looking ahead, EWMS is primed to build on its recent activity and success. With extensive data coverage and open acreage, there is opportunity for new entrants to the area. If the Nefertari discovery is developed, new offshore infrastructure may allow follow on discoveries to be developed at lower cost. It is likely that the deep-water west Nile Delta area will have Oligo-Miocene clastics targeted, similar to proven analogue discoveries in the Nile Delta Basin. Lastly, the deeper basin is more frontier and exploration may progress at a slower rate given the process of derisking observation driven exploration ideas, but it certainly holds high potential over a vast area.

Acknowledgements The authors would like to thank the Egyptian Ministry of Petroleum and Mineral Resources and the Egyptian Natural Gas Holding Company (EGAS) for their continued support in the region. We thank colleagues, TGS imaging and clients who have contributed to the various projects discussed here.

Figure 4 Example of a spectral decomposition (RGB blend) extracted on a horizon in the Pliocene section (panel A) and in the Oligo-Miocene section (panel B). Channel systems with potential reservoir facies can be clearly observed at both levels, with some examples indicated by the blue arrows in panel B.

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Figure 5 Examples of some structural traps in the offshore extension of the onshore Western Desert. Panels A and B are mapped depth surfaces within the Cretaceous section on the shelf. Panels C and D are seismic sections through a fast-track KPSDM depth volume, indicating the structural trapping potential at multiple depth intervals.

References Baer, S., Lie, Ø., Pyett, M., Davies, C., Sakariassen, R. and El Morshedy, A. [2017]. Frontier Exploration in Egypt’s Mediterranean Sea. GEOExPro, 12(5), 58-59.

Baptiste, D., Khattab, M., Lawrance, D., Butterworth, V., Southgate, J., Mahmoud, M., Fawi, E. and Rashidy, M. [2024]. Solving East Nile Delta’s imaging challenges through new ocean-bottom-node acquisi-

deep Levant Basin, eastern Mediterranean. Marine Geology, 376, 118-131.

Kumar, J., Bell, M., Salem, M., Martin, T. and Fairhead, S. [2018].

Mode conversion noise attenuation, modelling and removal: case studies from Cyprus and Egypt. First Break, 36(12), 113-120.

Marten, R., Rietveld, W., Benson, M., Khodeir, A., Keggin, J. and Cook,

tion and advanced imaging. The Leading Edge, 43(9), 615-622.

P., [2007]. Seismic-attribute analysis utilizing multiazimuth seismic

Davies, D., Brown, P., Agnisola, P., Valler, V., Romanenko, M., Fruehn,

data in the offshore Nile Delta — A case study. SEG Technical

J., Raffle, J., Nicholson, M. and Pan, S. [2024]. Unlocking the Nile Delta subsurface via advanced processing and imaging. The Leading Edge, 43(9), 596-605.

Donaldson, L., Ou, S., Guillois, M., Ouzounis, A., Tapie, C., Brytik, V., Fabuel-Perez, I., Moreton, D., Lawrence, Z., Martinez, A., Neelam-

Program, Expanded Abstracts, 941-945 Romanenko, M., Valler, V., Hart M., Fruehn, J., Saxton, L., Li, Q. and De Lemos, I. [2025]. Improved Imaging through application of elastic FWI in the Nile Delta. Accepted for the 86th EAGE Annual Conference and Exhibition.

ani, R., Hardy, C., Baranov, S. and Hasner, K. [2024]. Innovative

Roveri, M., Flecker, R., Krijgsman, W., Lofi, J., Lugli S., Manzi, V.,

solutions to frontier exploration in Eastern Mediterranean salt basins.

Sierro, F., Bertini, A., Camerlenghi A., De Lange, G., Govers, R.

The Leading Edge, 43(9), 606-614.

Hilgen, F., Hübscher, C., Meijer P. and Stoica, M. [2014]. The

El-Bassiony, A., Kumar, J. and Martin, T. [2018]. Velocity model building in the major basins of the eastern Mediterranean Sea for imaging regional prospectivity. The Leading Edge, 37(7), 519-528.

Evans, S.L. and Jackson, C.A.-L. [2021]. Intra-salt structure and strain partitioning in layered evaporites: implications for drilling through Messinian salt in the eastern Mediterranean. Petroleum Geoscience, 27(4), petgeo2020-072 Feng, Y., Yankelzon, A., Steinberg, J. and Reshef, M. [2016]. Lithology and characteristics of the Messinian evaporite sequence of the

Messinian Salinity Crisis: Past and future of a great challenge for marine sciences. Marine Geology, 352, 25-58.

Lottaroli, F. and Meciani, L. [2022]. The rejuvenation of hydrocarbon exploration in the Eastern Mediterranean. Petroleum Geoscience, 28(1), petgeo2021-018 Van Simaeys, S., Sullivan, M., Fabuel-Perez, I. and Abdelfattah Mohamed Khalil, M. [2021]. Messinian evaporites at the southern edge of the Eratosthenes Continental Block – worth your salt! Third EAGE Eastern Mediterranean Workshop, Extended Abstracts.

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Oil and gas exploration hotspots in Asia Pacific: Data-driven opportunities in Malaysia, Indonesia, and India Tad Choi1*, Nicolas Hand1, Subodh Notiyal1, Verity Agar1 and Duncan Woolmer1 put the exploration spotlight on Malaysia, Indonesia and India.

Exploration trends across Asia Pacific Upstream exploration is making a strong comeback across Asia Pacific with recent successes sparking renewed industry enthusiasm. In 2023 material discoveries in Malaysia and Indonesia have reinvigorated interest in basins once thought mature, showing that significant upside potential remains​. New significant discoveries continued to emerge across the region as recently as last year.

Exploration drilling spanned from Sumatra to East Java in Indonesia and across Malaysia’s offshore basins, yielding notable discoveries such as the Bekok Deep gas/condensate discovery in Malaysia’s Malay Basin​. These discoveries also highlight how modern seismic data, whether newly acquired or reprocessed, is allowing explorers to image and access deeper plays.

Government agencies are responding by promoting new licensing rounds and acreage offerings, opening overlooked established and frontier areas to investors. For example, Malaysia’s latest bid round offered five exploration blocks across Malaysia and newly offered Technical Evaluation Assessment (TEA) blocks over the Layang Layang and Langkasuka basins​. An industry-supported extensive new 2D seismic acquisition campaign in 2024 allowed Bangladesh to launch its first offshore licensing round in more than a decade, inviting bids on 24 blocks covering its largely unexplored offshore waters​ . India continues its Open Acreage

Licensing Program (OALP X launched in Feb 2025), and Indonesia continues exploration activities through its Joint Study Agreement (JSA) blocks across all the basins coupled with regular tender blocks. This surge of opportunities reflects a clear regional strategy, boosting domestic reserves, increasing production and meeting rising energy demand, especially for natural gas. India, now the world’s third-largest energy consumer, is pushing to increase natural gas from about 7% to 15% of its energy mix by 2030.

This aggressive target shows strong government backing for new gas exploration. In parallel, companies are embracing advanced geoscience technologies to derisk these exploration opportunities.

Modern multi-client seismic surveys, expansive well data libraries, and interpretation tools enable explorers to quickly explore and high-grade areas. Across Asia Pacific’s diverse geology – from mature shallow provinces to high-potential deepwater frontiers – access to modern high-fidelity seismic data and access to acreage will help to unlock further hydrocarbon resources.

Malaysia: Revitalising mature and frontier basins with modern data Malaysia offers exploration opportunities across established basins and frontier areas. In Peninsular Malaysia’s mature Malay Basin, recent drilling based on reprocessed seismic data has

Figure 1 Legacy seismic showing attenuation below the existing Bekok discovery (left). PSDM reprocessing significantly improved imaging, allowing for drilling and discovery of Bekok Deep (right).

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Corresponding author, E-mail: tad.choi@tgs.com

DOI: 10.3997/1365-2397.fb2025033

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existing discoveries such as Mutiara Hitam-1, Kuda Terbang-1 and Nymph-1. Most of the basins in Sandakan are still considered frontier with limited seismic data, until now. TGS has embarked on a multi-phase 2D seismic acquisition and reprocessing campaign, with the latest phase (Phase 7, initiated in late 2023) having acquired 5000 km of new long-offset 2D seismic, reprocessed 2600 km of legacy lines and generated 2800 km² of 2Dcubed volume from the new 2D data​​. The aim of these datasets is to deliver a modern regional seismic dataset to unravel the complex geology and enable the mapping of further prospects in this frontier basin. The results of this new dataset show a clear resolution of the entire basin and enable tracking of the Miocene-Pliocene fan systems and deeper carbonate plays where the short offset legacy data had struggled to image below the shallow carbonate platforms and steep dips (Figure 3).

Figure 2 An example TWT structural map from the current PSDM reprocessed area of the Malay Basin.

confirmed a deeper play. In 2024 Petronas announced a significant discovery at the Bekok Deep-1 well (Figure 1), tapping new hydrocarbon reservoirs beneath an established field​. This well encountered excellent flows from Middle Miocene Group I sands and importantly proved a new deeper play in the Malay Basin (Group M reservoirs) with significant upside potential​.

This success underscores that revisiting mature basins with newly enhanced data can yield sizable discoveries.

The Bekok-1 discovery was mapped and drilled on the TGS 3D MegaMerge seismic data, which integrates more than 70 vintage surveys (around 40,000 km² of coverage) into a single seamless volume​using modern noise attenuation, multiple elimination, and updated velocity model-building technology (including Full Waveform Inversion and Q Tomography/Migration). The resulting time and depth migrated datasets provide consistent, high-resolution imaging of the Malay Basin’s stratigraphy – a significant uplift over the legacy data. This 3D MegaMerge volume allows explorers to continuously map structures (Figure 2) and stratigraphic features across vintage surveys and block boundaries, identifying new leads and deeper plays beneath existing fields. Imaging of the deeper section has opened up new plays (including the Bekok-1 discovery) for further exploration drilling in a basin critical to Malaysia’s domestic oil and gas supply.

In East Malaysia’s Sabah province, focus is growing on the Sandakan Basin. This is a proven hydrocarbon basin with

Indonesia: Unlocking deeper potential in East Java Indonesia is another hotspot in Asia Pacific’s exploration resurgence, where data-driven approaches are breathing new life into mature basins. A prime example is the East Java Basin, a geologically complex but hydrocarbon-rich province. Historically, exploration in East Java (both onshore and offshore Madura Strait) has centered on shallow carbonate pinnacle reef plays – notably the prolific Miocene Kujung Formation. However, deeper targets below the carbonates remained challenging due to the lack of imaging resolution of the legacy seismic data .​ The thick Wonocolo limestone platform and intricate channel systems in the shallow section generate strong velocity contrasts and imaging artifacts, blurring the deep section on vintage surveys​. This left uncertainties regarding the potential of the Eocene petroleum system (Ngimbang Formation) and the pre-Tertiary section in East Java.

Today, modern seismic acquisition and processing workflows can clearly image the deeper Eocene system. New long-offset 2D and 3D data have been acquired in the East Java Basin. Modern processing flows now include high-resolution model-building with Full Waveform Inversion (FWI), allowing geophysicists to derive much more accurate velocity models in geologically complex zones​. The impact has been dramatic: where legacy data struggled to image below the Kujung carbonates, the newly processed seismic data reveals clear imaging into the Eocene section. The deeper Ngimbang Formation and even the top of basement are now confidently interpretable across large areas.

This breakthrough further opens up the Eocene section as a viable play in a basin long thought to be fully exploited at the shallower levels​. The L-46-1 is an older oil discovery in the Ngimbang

Figure 3 PSDM reprocessing has enhanced existing and revealed new plays in the Sandakan Basin.

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geometries, a feature previously unrecognised. If charged by Eocene source rocks, these deeper reservoir targets could add a new tier of exploration prospects below the established plays.

Industry interest is indeed shifting to test these ideas – Indonesia’s exploration in 2024 included wells targeting deeper or underexplored objectives in basins like East Java and North Sumatra.

While the largest Indonesian discovery of 2024 was in North Sumatra (Mubadala’s Tangkulo gas discovery in deep water, a new Oligocene syn-rift play)​, East Java and Kutei basins remain high in activity with continuing drilling and studies. The presence of a modern seismic dataset combined with available well data has been interpreted to produce GDE maps in a Facies Map Browser tool (FMB) which can help to derisk these new plays.

It is worth noting that Indonesia has strategic reasons to push exploration now. The country’s oil production has been in decline, and it aims to boost output (with an ambitious target of 1 million barrels per day of oil and 12 Bcf/d of gas by 2030). Achieving this will require developing known discoveries and making new ones, especially gas for domestic use and LNG export. That imperative has the government and SKK Migas (the regulator) encouraging exploration in both proven core areas and high-risk, high-reward frontiers. Modern data has essentially become a catalyst for Indonesia’s exploration drive, reducing geological uncertainty in a way that enables companies justify the risk of wildcat drilling in deeper or remote zones.

Figure 4 Extensive new 2D and 3D acquisition combined with reprocessing and 2DCubed now allows rapid local or regional structural evaluation with enhanced resolution, as demonstrated by this isochron map covering East Java, South Makassar and Kutei Basins.

formation and further discoveries can be anticipated from the new modern seismic data. The initial interpretation of the reprocessed seismic volume identified large gently folded structures and stratigraphic pinchouts in the deeper syn-rift sequences, which were invisible in legacy data.

New imaging technology-driven projects such as TGS’ East Java Sea and Kutei 2DCubed, where thousands of kilometres of legacy 2D lines from multiple vintages have been phase, amplitude, and time-matched and interpolated into a 3D- volume. This 2Dcubed technology uses structurally conformable interpolation to infill the gaps between 2D lines, effectively creating a 3D seismic cube that can be sliced, visualised and interpreted as any other 3D volume. The motivation is to spur exploration in areas like the Madura Platform and the neighbouring Makassar Straits, where extensive 2D data exists, but few wells have tested deeper objectives​​ . Harmonising these datasets creates a ‘big picture’ view of basin architecture and potential leads that cross individual block boundaries. This regional screening tool that covers multiple basins provides an extremely valuable insight into the wider regional structural development and play types.

The East Java and Kutei 2Dcubed (Figure 4) has already yielded tangible results. Seismic interpreters are now confidently mapping the Ngimbang Formation pinchouts and basin floor fan

India: Data-driven exploration on the east coast In the Indian subcontinent exploration attention is converging on offshore basins that promise substantial new reserves. India’s east coast, bordering the Bay of Bengal, is a prime area of interest due to its multiple sedimentary basins (Cauvery, Krishna-Godavari, Mahanadi, and the Bengal Fan area) where discoveries in vast untested areas have been proven. India’s government has prioritised increasing domestic hydrocarbon production – particularly natural gas – to fuel its growing economy. With India now the fourth-largest LNG importer, there is a strong impetus to find more gas at home, aligning with the target to raise natural gas to 15% of the energy mix by 2030​. These policy initiatives are driving new offshore licensing rounds and increased exploratory drilling. However, one challenge for explorers has been the heterogeneous nature of data coverage on India’s margins – historically, data quality and availability varied widely by basin. This is precisely where modern subsurface imaging technology makes a difference by combining disparate datasets into unified, modern products that can accelerate exploration activities.

A cornerstone of TGS’s strategy in India has been the creation of a 2Dcubed seismic volume spanning the entire offshore India East Coast. This 2Dcubed project, completed in 2022, merged more than 250,000 kilometres of legacy 2D seismic data (from numerous vintages) across an area exceeding 500,000 km²​. This is a megascale project – it stretches from the Krishna-Godavari Basin in the central east coast, through the Cauvery Basin in the south, all the way to the Bengal Fan in the north east (Figure 5)​. By applying TGS’s proprietary structurally conformable interpolation processes, these 2D lines were interpolated into a continuous 3D volume, enabling geoscientists to traverse the data from any orientation FIRST

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Figure 5 Regional near-basement structural map extending from the entire east coast of India to Bangladesh.

and perform rapid regional interpretations. This 2DCubed dataset is unrivalled in its coverage and consistency, effectively offering the first complete subsurface picture of the entire passive margin in one contiguous volume​. Such a comprehensive view is invaluable for regional prospectivity analysis: it allows exploration teams to correlate stratigraphy and structure from one basin to the next, understand how major tectonic elements like shelf breaks or hinge zones extend along the margin, and pinpoint underexplored sectors that analogously resemble known productive areas.

To complement the seismic, TGS has deployed its powerful Facies Map Browser (FMB) tool for east coast India, marking the first application of this advanced geological interpretation

Figure 6 GDE map from the web-based facies map browser for one of the potential reservoir intervals with an inset block diagram highlighting the depositional environment.

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product in the region​. The east coast India FMB integrates an extensive library of well data (from exploration and appraisal wells that have been drilled offshore India over the decades) with the seismic interpretation in a sequence stratigraphic framework​.

Geoscientists have built a unified stratigraphic column for the east coast basins and mapped depositional facies for each sequence/ age, leveraging well logs, biostratigraphy, core data, and regional seismic markers. The result is a series of Gross Depositional Environment (GDE) maps and facies distribution maps that are tied to actual well observations and constrained by seismic data​ (Figure 6). For example, the FMB can show the extent of Late Cretaceous fluvial-deltaic sands in the Cauvery Basin versus time-equivalent marine shales in the deeper Krishna-Godavari Basin, all in a consistent stratigraphic context. This gives explorers a head start in identifying where reservoir-quality sands or viable source rocks are likely to be present, even in areas with sparse drilling.

Such data-driven interpretation is supporting operators in derisking assets and identifying new prospects in India’s offshore. For instance, consider the frontier deepwater areas of the Mahanadi Basin and the Bengal Fan (offshore Odisha and West Bengal). These areas have very few wells, but the regional 2Dcubed seismic and FMB work together to model the basin fill. Geoscientists can identify large submarine fan complexes on seismic and then use the FMB’s calibration from wells to infer likely sand presence and reservoir quality. This helps in delineating leads for further 3D seismic or eventual drilling. In proven basins like Krishna-Godavari (KG), where major gas fields (e.g., the Dhirubhai deepwater fields) have been found in Miocene-Pliocene turbidites, the focus is shifting to both shallower plays (e.g., Pliocene channels in slope settings) and deeper plays (e.g., synrift Early Cretaceous prospects). TGS’s Mega 3D reprocessing project in the KG Basin (announced in 2025) will reprocess ~16,900 km² of legacy 3D data with the latest PSTM/PSDM and FWI methods. The goal is to obtain contiguous, high-resolution images of both the main reservoir targets and the deeper basement-involved structures that could host secondary plays. When complete by 2026, this mega-merge volume will further enhance subsurface imaging in KG, analogous to the Malay Basin project in Malaysia. It is anticipated that such data will be crucial for companies to evaluate blocks on offer in future OALP bidding rounds and to plan appraisal campaigns on existing discoveries.

Overall, India’s east coast exploration is being transformed.

Instead of relying on an isolated patchwork of surveys or partial data, operators now have access to an integrated platform (seismic + wells + depositional models) covering the entire margin. This accelerates exploration and reduces uncertainty significantly – companies can make informed decisions on which play segments to chase and which to avoid. Bringing global best practices to India means the upcoming exploration campaigns can leverage decades of geoscience innovation, focusing the drill bit on the highest potential targets and helping India meet its energy ambitions.

The Critical role of modern subsurface data in derisking Asia Pacific exploration Modern subsurface data is fundamental to successful exploration today. Enhanced seismic datasets and innovative geoscience

SPECIAL TOPIC: GLOBAL EXPLORATION

methodologies have dramatically improved exploration outcomes by reducing uncertainty and identifying viable targets. Key contributions include: • Regional context and play identification: Comprehensive regional datasets (2Dcubed volumes, mega-merged reprocessed 3D seismic surveys and TGS’ FMB databases) provide critical insights into basin architecture and petroleum systems. Examples include the seamless 3D seismic volumes in peninsular Malaysia, which revealed previously overlooked deep targets such as Bekok Deep, and the India East Coast 2Dcubed-volume, highlighting deltaic sequence continuity across block boundaries.

• Improved imaging and new targets: Advanced processing technologies, such as broadband acquisition, deghosting, high-density velocity analysis, and Full Waveform Inversion (FWI), significantly enhance seismic imaging. These methods have successfully identified deeper reservoir targets in East Java, improved imaging beneath complex carbonate overburden offshore Sabah, and delineated subtle stratigraphic traps in Malaysia’s Malay Basin. Enhanced seismic imaging directly correlates to improved geological confidence and new exploration opportunities.

• Data integration and accessibility: Integrating seismic and well data into cohesive, user-friendly interpretation tools, such as Facies Map Browser (FMB), allows rapid analysis and geological prediction. This integrated approach accelerates the identification of high-quality reservoirs and source rock potential across large underexplored regions, significantly streamlining exploration decisions and collaborative analysis.

• Risk mitigation and faster decision cycles: High-quality subsurface data reduces exploration risk by improving geological certainty, allowing companies to prioritise prospects with higher potential and minimise futile exploration activities.

• Cross-border insights: Comprehensive datasets spanning national boundaries offer strategic advantages by providing a regional geological context across borders, enabling operators to reduce geological risks and avoid surprises. Cross-border

seismic datasets, such as those covering the Bengal Fan from Bangladesh to India or those spanning Malaysia and Indonesia, support informed decision-making and enhance exploration efficiency.

Outlook: Data-shaped exploration ahead The role of advanced seismic data in exploration will grow increasingly critical in Malaysia, Indonesia, India, and other Asia Pacific regions. In Malaysia, improved data coverage in Sabah and continuing seismic enhancements in the Malay Basin will continue to fuel exploration interest. Indonesia’s exploration will increasingly target deeper plays and frontier basins, benefiting from enhanced data resolution and integration. Exploration of India’s East Coast will leverage comprehensive seismic data and interpretation tools to meet ambitious hydrocarbon production targets. Similarly, Bangladesh’s frontier exploration potential in the Bengal Fan will be increasingly realised through advanced seismic data applications, significantly reducing geological uncertainty.

In conclusion, the effective application of advanced subsurface data remains core to future exploration success in the Asia Pacific region. The combination of modern seismic acquisition, sophisticated data processing, and integrated interpretation platforms significantly enhances geological understanding and exploration success, reinforcing the essential role of data-driven approaches in uncovering new oil and gas resources.

References Farouki. M., Bromley, A. and Cavalin, D. [2019]. Modern seismic data reveals potential for a deeper play in North Madura, East Java, Indonesia. APGCE 2019, Extended Abstracts.

Gillbard, E. [2024]. Unveiling the petroleum potential of the Bengal Fan, offshore Bangladesh. First Break, 42(5), 59-65.

Patnaik, G. [2024]. Asia Pacific’s transforming energy landscape. Oilfield Technology, December 2024.

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Global exploration – what role do hotspots play?

Bob Fryklund1*, Bill Mynatt1 and Clare Barkere1 demonstrate why hotspots will help to provide some of the most advantaged oil and gas — lowest cost, highest margin and lowest emissions.

For the last 15 years, global exploration has been searching for a new norm. Activity has reset twice since its high in 2008 when we averaged 1841 new field wildcats and now averages at around 450 new field wildcats per year (Figure 1). Seismic and leasing, other bellwethers of exploration activity, have followed a similar pattern. Some of this can be attributed to the arrival of shale which diverted both manpower and spending away from conventional exploration in favour of lower risk, more flexible investment resource plays. Post 2014, companies have also forsaken high risk frontier exploration for exploration in proven basins.

Yet despite having to do more with less, explorers have opened nine new ‘superbasins’* since 2000 - something must be working. S&P data and analysis shows that a new ‘superbasin’ is opened almost every seven years. The latest of these is the

Orange River Basin in southern Africa discovered in 2022. Most of these new ‘superbasins’ result in hot spots. Hot spots have provided many benefits to the industry and the host countries. For the industry, they often lead to the evolution of new technologies such as the development of 20,000 psi wellheads. They help the development of new methods for reducing emissions often simply via electrification. And for the host governments both a revenue stream and source of energy and its byproducts. Thus, providing energy security and in many cases a huge boost to the economy.

Additionally, S&P data shows that most of these new basins are in deepwater and ultra-deep water and that they favour historical passive margins for geologic settings. This trend appears to be continuing as the chart below shows (Figure 2) 65% of resources discovered came from deep water in the top 20 basins over the past five years.

Figure 1 Global discovered volumes by new field wildcats (Billions barrels equivalent).

Figure 2 Top basins in the past five years by discovered volumes.

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S&P Global

*

Corresponding author, E-mail: bob.fryklund@spglobal.com

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Figure 3 Top 10 operators by number high impact wells drilled (HIW’s).

Figure 4 Exploration basin hotspots and future high impact wells.

In addition to the decrease in activity and spending, S&P has seen a dramatic reduction in both number and size of companies.

Analysis shows that a 45% reduction in companies overall since 2014 and a drop of more than 50% for small companies. The latter is one of the most important issues as small independents prior to 2014 drilled the majority of the high-risk frontier wells, which were often the high impact wells. However, in the last five years majors and NOCs have stepped in to backfill for some of the missing independents and drilled the majority of the top 10 discoveries but not solely in frontier basins (Figure 3). Data shows that most of the new discoveries are in proven basins — either emerging or maturing. This once again slgnals a move away from high risk.

2. SW Atlantic coastal basin - Orange, Walvis and Luderitz basins 3. Alaska North Slope basin 4. Southern deformed belt – Colombia deep water 5. North Sumatra/ Andaman 6. Gabon/ douala – Gulf of Guinea and Sao Tome 7. Pelotas 8. Pearl River Mouth, South China Sea. 9. Ivory Coast – Tano basin 10. Norway offshore

Conclusion Future hotspots will be a mix of those in proven basins and frontier. A review of recent leasing and seismic activity shows that the majority will continue to be in deep water. The main exceptions are the Middle East, North Africa and CIS. S&P analysis shows 10 future new hotspots to watch for the coming years: 1. Eastern Mediterranean - Herodotus, Levantine and Nile delta basins

Yet, for all the exploration success I offer a word of caution.

Over the past five years several of the top 10 discoveries (Brudpala, Lepierd, and Graff) totalling >10 Bboe have been declared non-commercial and returned undeveloped.

As exploration settles into its new pace, it still has an important role to play in providing hydrocarbons for the future.

And hotspots will help to provide some of the most advantaged oil and gas — lowest cost, highest margin and lowest emissions.

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Furthermore, a look at upcoming 2025-2026 high impact wells shows 35 key wells, several of which are in the potential hotspot basins listed above, Figure 4.

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Intra-Draupne sandstone. Is it present in the Marulk Basin, just north of the Statfjord field?

Carl Fredrik Gyllenhammar1* argues that a report showing that licence PL 993 offshore Norway has only an 18% chance of success is worth revisiting with a chance of success closer to 50%.

Introduction Norwegian licence PL 993 in the North Sea was awarded to Neptune Energy in the 2018 APA round. The area was covered by the recent CGG18M01; CGG broadband 3D mega survey. The interpretation and the seismic inversion revealed a turbidite fan sourced from north to south just SE of the undeveloped Morkel discovery (33/2-2S). Neptune relinquished the licence in March 2021.

The interpretation as presented in the relinquishment report appears very solid and well documented. All I want to do is put a question mark behind the conclusion: only 18% chance of success. There is more than 70 mmbbl of recoverable resources near infrastructure. Is there anything to add that can bring the chance of success up to justify a well?

Regional tectonics The area of interest, Norwegian blocks 33/5 and 33/6, are situated in the Marulk basin just southeast of the Morkel discovery well 33/2-2S and north of the Statfjord North field still on production.

The East Shetland Basin is a half-graben consisting of Permo-Triassic and Jurassic tilted fault blocks overlain by Cretaceous and Cenozoic sediments. The basin is bounded to the west by the Palaeozoic East Shetland Platform, to the east

and south by the Viking Graben, where north-south trending faults predominate, and to the north by the ENE-WSW Magnus Embayment in which NE-SW faults predominate.

The northernmost North Sea rift basin, the Viking Graben, and the adjacent platforms and basins, including the Marulk basin, were formed by at least two episodes of lithospheric extensions. First, the late Permian-early Triassic extension, and then the middle Jurassic to early Cretaceous extension. (Eynon, 1981, Badley et al. 1984, Beach et al 1987, Giltner, 1987, Lervik et al, 1989, Blunell and Gibbs, 1990, Gabrielsen 1990, Ravnås et al, 2000). The northern North Sea formed due to multiple stretching episodes during the Mesozoic period, with the two main rifting episodes dated as Permo-Triassic and Jurassic, followed by episodes of passive post-thermal subsidence within the early-middle Jurassic, and the Cretaceous-Cenozoic, respectively.

To the south are the Murchison, Statfjord and Snorre discoveries at the Tampen Spur; to the west just over on the UK side, the Penguin and Magnus discoveries. Both these fields have been sourced from the Viking Graben to the east. The migration pathway is assumed to be up the Marulk and the Magnus basins. So far, the exploration success on the Norwegian side of the Marulk has been limited, in an area one can observe a hydrocarbon migration highway (Gyllenhammar et al. 2022).

Figure 1 To the right, a tectonic cartoon of the North North-Sea. To the left, a contour map of BCU with the Jabba prospect posted.

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Camgeo

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Corresponding author, E-mail: cfg@camageo.no

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Well

Group / Formation

Group / Formation

Depth (m)

Porosity (%)

33/5-2

Brent

4165

10

33/6-1

Brent

3605

10

3489

‘4 - 16

3613

10 - 20

4114

24

Nansen

4267

14 - 18

33/9-10

Brent

3351

10-17

33/9-11

Brent

3126

16 - 24

33/6-2

Intra-Daupne Sand

33/6-2

Brent

33/6-3 S

Intra-Daupne Sand

33/6-3 S 33/6-4

TD in Paleocene

33/9-19

Intra-Draupne Sand

3051

20 - 26

UK 211/13-6

Intra-Draupne Sand

3390

10 - 17

3418

8 - 21

UK 211/13-7

Brent

Table 1 Exploration wells used in this evaluation.

Database The most important data/information is the Neptune relinquishment report and released well logs/reports downloaded from DISKOS. The wells used in detail are listed in Table 1. The 3D seismic survey used for the interpretation of Base Cretaceous Unconformity (BCU) (Figure 1) is a multi-client mega-merge

built by AGGS, including all released 3D surveys from DISKOS in Norway and some cross-border 3D seismic released by NDA. Seismic 3D surveys have been conditioned, pre-processed, and finally merged. The seismic used by Neptune is the CGG18M01.

A mega 3D broadband survey.

Nine important offset wells are listed in Table 1. All released exploration wells posted on the map in Figure 7 have been evaluated.

Jabba prospect Neptune’s final interpretation suggests more than 200 mmbbl of oil in place as base-mean case in an area near infrastructure in operation today.

Neptune used Spectral decomposition to develop a depositional model. The study concluded that the reservoir within Jabba was likely to be a slope apron complex and associated turbidites fed from multiple entry points from the Makrell Horst to the north. Deposited within Late Oxfordian to Early Kimmeridgian.

The Morkel discovery (33/2-2 S) is sitting on the Markel Horst.

33/2-2 S discovered oil in the Triassic, Lunde Fm (Figure 1).

The oil in the cuttings from 33/5-2 suggest sourcing from the local Draupne and Heather formation. The study also concluded that the Heather Fm was in-situ, the base and lateral seal of the Jabba prospect was therefore assumed to have been derisked. They also claim that none of the wells in the adjacent area have penetrated such a reservoir. With the midpoint depth of the reservoir approximately around 4000 m, the reservoir was

Figure 2 An arbitrary line E-W across the Jabba prospect, a) the geological cross-section, b) the associated seismic inversion (Neptune, 2022).

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Figure 3 Norwegian exploration well 33/5-2. A well having only shows. This CPI suggest Intra-Draupne and Intra-Heather siltstone stringers with 10-20% oil.

considered deep and predicted to have high risk on reservoir effectiveness.

This alternative interpretation shows that Intra-Draupne sands have been penetrated by several offset wells and that the reservoir properties at 4000 m vary a lot. In Table 1 one can see that the porosity at 4000 m varies from 10 to 24% which is quite normal, and yes, will always be a risk as well as an upside at such depth.

There are two wells very close to the Jabba prospect, 33/5-2 is close to the crest but outside the closure; 33/6-4 is southeast of the prospect with TD in Paleocene and therefore has no relevance in this interpretation.

33/5-2 has a 100m-thick Draupne shale. At about 3943 m depth there are some Draupne siltstone stringers, if present, where one would expect the Intra-Draupe sand would be (Figure 2).

If the Jabba prospect is water-filled, one would expect these siltstones to be water-filled. But these siltstones have 10-20% oil in them.

The nearest offset well to the Jabba prospect with a thick Intra-Draupne sandstone is 33/9-17 23 km south. 33/9-17 has 50 m net reservoir quality water-wet Intra-Daupne sandstone.

Just 3.5 km SE is the Statfjord North discovery, an Intra-Daupne sandstone discovery, discovered by Mobil in 1977 with exploration well 33/9-8.

Log interpretation All wells have been interpreted in a consistent way. The volume of clay (Vcl) was calculated using the neutron density cross plot and the gamma-ray curve (Gyllenhammar, 2022). The water saturation (Sw) was calculated using the dual-water method (Clavier et al., 1984).

In a clean formation with volume of clay (Vcl) = 0 the Dual-Water equation becomes the simple Archie equation.

Archie came with his famous formula in 1942 (Archie, 1942) where he showed that the oil or gas saturation (So or Sg) is a function of the porosity (ɸ), the deep resistivity (Rt) and the resistivity of the formation water (Rw). In his equation he uses the saturation of water (Sw); Sw = 1 – So (or Sg)

(1)

So is the oil saturation and Sg the gas saturation.

(2) Equation 4 is simplified by using n=2, m=2 and a=1; (3) In the article Missed-pay or Overlooked-play (Gyllenhammar, 2022) I argued that the biggest uncertainty with respect to the Archie equation is determining the resistivity of the formation water, Rw. Using Interactive Petrophysics (by GeoActive) the Apparent Rw is calculated. The Apparent Rw is the resistivity that calculates Sw = 1. Column nr. 8 is called Salinity in all the CPIs (Figures 3, 4, 5 and 6). The dotted green line is the AppRw. The straight green line is the selected Rw and should overlay the AppRw in the water-wet zones.

On the map (Figure 7) the formation water salinities calculated from the well logs are posted in red, while the salinities posted in dark-blue are from laboratory analysis of formation FIRST

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water sampled during drill steam testing (DST). This ‘salinity map’ is used to decide what salinity to use to calculate the Sw in the Draupne formation in the wells. There is only one well with thick enough Intra-Draugen sand where the salinity can be calculated, 33/9-11. In that well the salinity is about 30000ppm.

Equally important, the salinity in Brent sandstones is the same as in the overlying Intra-Draupne sandstone. The Brent in 33/5-2 has a calculated salinity of 24600ppm, which was used in this interpretation in the overlying Intra-Draupe siltstones to calculate the Sw.

Figure 4 Well 33/6-3 S. The yellow box shows a possible Intra-Draupne silt/sandstone stringer with 60% oil. The calculated Sw, in the Sw column has the total mudgas plotted (black dotted line).

Figure 5 Well 33/9-17, showing an 80 m-thick Intra-Draupne sandstone (gross thickness) and 50 m net sand.

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Figure 6 UK well 211/13-6. A mudgas peak at 11100ft corresponds with a sand/siltstone stringer with in the Draupe Fm.

Ideally there should be a close correlation between the show’s description, mudgas measurements and the oil/gas saturation (Sw) calculated from the electrical logs (Gyllenhammar, 2020).

All four CPIs (Figures 3, 4, 5 and 6) show mudgas data displayed/ combined with the petrophysical interpretation. The CPIs for 33/5-2 (Figure 3) and UK211/13-6 (Figure 6) have no digital mudlogging data, so I have just inserted a scan of the mudgas at scale in the CPI. Well 33/9-27 had a digital total gas that is posed as a black-dotted line in the Sw track. It is interesting to see how well the gas peaks correlate with the log calculated Sw. Well 33/6-3S (Figure 4) has all mudlogging data in digital form. That CPI has in addition to the other columns, a gas-ration column.

The gas-ratio is calculated using the equations published by Haworth et al in 1986 (Haworth et al., 1986) (Dolson, 2016). The gas-ration equations is a module in Interactive Petrophysic basic software from GeoActive.

The challenge in this case is that the important well, 33/5-2, is an old well, drilled by Norsk Hydro in 1981. They used Gearhart Geodata for mudlogging. At that time Gearhart had just started using gas chromatography to measure the mud gas wellsite. Before that, all they had was the hotwire instrument that could only measure the total gas content, not the elements.

The mudgas in this old well does not appear to add much value to interpretation. One can also see the general low gas reading measured during coring. Not only in well 33/5-2, but equally in UK211/13-6 (Figure 6).

Summary This interpretation shows that the risk associated with the Jabba prospect is considerably lower than suggested by the PL 993 partnership. Identifying offset wells proves the nearby presence of the Intra-Draupne sand. As well as showing that the reservoir

Figure 7 Prospect map with the wells posted. The number in red close to each well is the formation water salinity from log analysis in ppm total dissolved solids (TDS).

The dark-blue numbers with yellow TDS from laboratory measurement of formation water from Drill Stem Test. 33/9-14, Statfjord North field is an Intra-Draugen discovery where the salinity in Draugen is 10000 ppm less than in the underlying Brent Gp.

quality at 4000 m has the same risk as elsewhere. The calculated water saturation, based on the regional formation water salinity FIRST

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trend, shows the presence of hydrocarbons in all the Intra-Draupe silts/sands stringers identified in the area.

In summary, I would argue that the chance of success is much closer to 50% than 18%.

It is interesting to learn that the same area was applied for and awarded to Equinor and AkerBP in the APA 2021 licensing round.

Now it is the active licence PL1152, where they are currently deciding whether to drill or not, but not necessarily on the same prospect.

D. (eds). Petroleum Geology of the Continental Shelf of Northwest Europe, Institute of Petroleum, Heyden, London, 765-774.

Gabrielsen, R.H.F., Erseth, R.B., Steel, R.J., Idil, S. and Klovjan, O.S. [1990]. Architectural styles of basin fill in the northern Viking Graben. In: Blunell, D. J. & Gibbs, A. D. (eds). Tectonic Evolution of the North Sea Rifts, Oxford University Press, 158-179.

Giltner, J.P. [1987]. Application of extensional modes to the Northern Viking Graben. Norsk Geologisk Tidsskrift, 67, 339-352.

Gyllenhammar, C.F. [2020]. Missed-Pay or Overlooked-Pay. What if your well wasn’t dry? First Break, 38(12), 87-93.

References

Gyllenhammar, C.F., Baig, I., Eide, A.I., Keller, P., Fawad, M. and

Archie, G.E. [1942]. The electrical resistivity log as an aid in determining

Sandvik, J. [2022]. Marulk Basin, just north of Statfjord? Is it really dry? First Break, 40(5), 59-66.

some reservoir characteristics: Trans. Amer. Inst. Mech. Eng., 146(01), 54-62.

Gyllenhammar, C.F. [2022]. Calculation volume of clay and/or shale from wireline logs. First Break, 40(9), 59-65.

Badley, M.E., Egeberg, T. and Nipen, O. [1984]. Development of rift basins illustrated by the structural evolution of the Oseberg feature, block 30

Haworth, J.H., Sellens, M. and Whittaker, A. [1986]. Interpretation of

6, offshore Norway. Journal of the Geological Society, 141, 639-649.

Hydrocarbon Shows Using Light (C1-C5) Hydrocarbon Gases from Mud-Log Data. AAPG Bull, 69, 1305-1410.

Beach, A., Bird, T. and Grabs, A.D. [1987]. Extensional tectonics and crustal structure: deep seismic reflection data from the northern North

Lervik, K.S., Spencer, A.M. and Warrington, G. [1989]. Outline of

Sea Viking Graben. In: Coward. M. P. Dewey. J. F. & Hancock. P. L.

Triassic stratigraphy and structure in the central and northern

(eds) Continental Extensional Tectonics. Geological Society, London,

North Sea. In: Collinson, J. D. (ed.). Correlation in Hydrocarbon

Special Publications, 28, 467-476.

Exploration, Norwegian Petroleum Society, Graham & Trotman,

Blunell, D.J. and Gibbs, A.D. [1990]. Tectonic Evolution of the North Sea

London, 173-189.

Rifts. Oxford University Press.

Neptune Energy and Petoro. [2022]. Norwegian Relinquishment report

Clavier, C., Coates, G. and Durmanoir, J. [1984]. Theoretical and Exper-

for license PL 993, parts of blocks 33/5 and 33/6. PL 993 Laps report.

imental Bases for the Dual-Water Model for Interpretation of Shaly

Ravnås, R., Nøttvedt, A., Steel, R.J. and Windelstad, J. [2000]. Syn-rift

Sands. Soc. Petroleum Eng. Journal, 24(02), 153-168.

sedimentary architectures in the Northern North Sea. In; Nøttvedt, A.

Dolson, J. [2016]. Understanding Oil and Gas Shows and Seals in the

et al. (eds). Dynamics of the Norwegian Margin, Geological Society, London, Special Publications, 167, 133-177.

Search for Hydrocarbons. Springer Int. Publishing, pp 468.

Schlumberger. [1989]. Log Interpretation Principle / Applications:

Eynon, G. [1981]. Basin development and sedimentation in the Middle

Schlumberger Wireline and Testing. Houston, SMP-7017.

Jurassic of the Northern North Sea. In: Illing, L. V. and Hobson, G.

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Ultra-deepwater: The lowest risk exploration Neil Hodgson1*, Karyna Rodriguez1 and Lauren Found1 cast their eyes on the last great global exploration play to be tackled – the counter regional dipping clastic fan play on the basin floor of the Earth’s passive margins.

Although largely unreported by the majority of mainstream media, at CERAWeek in March 2025, Fatih Birol, the director of the International Energy Association, said, “I want to make it clear … there would be a need for investment (in oil and gas exploration), especially to address the decline in the existing fields.” So, rather than oil and gas exploration being the work of the devil, it would seem that at least the IEA believe there is a role for oil and gas exploration in helping humanity bridge the energy gap during the transition to carbon-free, available and affordable energy for all.

These new hydrocarbons to fill the gap between developed reserves and the ubiquitous new carbon-free energy will not be found where we have looked before – our data and knowledge is too good for anything but ‘tidying up’, – they will be found in the remaining frontier areas, namely the Earth’s deepwater passive margins. Although deepwater exploration has a reputation for being risky, there are two very different reasons for this. Firstly, because we never have enough hard data in ultra deepwater basins to allow us to remove play risk elements or even reduce

the uncertainty in the plays we chase, and secondly because to date we have mostly been drilling the riskiest deepwater confined channel plays. Regarding the latter, we should perhaps look for lower risk alternatives, but the former is a characteristic of the arena which forces us to explore in a new way.

Proof of life The lack of proof of risk elements in deep water can be a refreshing freedom from the tyranny of realism (‘believe only what I can prove’). The art is to know what is likely but unproved from what is crazy but possible. Being deepwater, the exploration drilling costs are high, but 3D seismic costs are low, so caution with drilling and investment in 3D is the right strategy here. Yet if we are successful, finding big simple and permeable accumulations (you need all three to make deep water commercial), then the rewards are high too.

As Aristotle said, science in our risking mindset abhors a vaccuum of hard data as it then relies on analogues and models

Figure 1 ‘Venus’ analogy. The proven Source rock, reservoir and trap on a magma-rich margin.

1

Searcher

*

Corresponding author, E-mail: n.hodgson@searcherseismic.com

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(A)

(B)

Figure 2 (a) Brazil’s Espirito Santo: Magma-poor margin beyond the outer high. (b) Angola’s Kwanza Magma-poor margin beyond the outer high.

all the way through prospect evaluation. We suggest that for frontier basins it is time to relook at our risking philosophy, from a reductionist approach based on realism (it’s only true if we have proved it) or pessimism (all things being equal, it will go wrong), to an outcome-based approach based on potential value released if the uncertainty due to lack of data unfolds favourably. This is also known as an optimism-based approach.

The Earth’s largest and highest potential opportunities lie in one geography alone – the basin floor and base of slope plays of the Earth’s Passive margins (Figure 1). Unreachable due to their water depth until this decade they have been ignored and dismissed as less commercial than the alternatives until now – when we stand with new developed weapons of deduction to address the technical commercial risks, and of course when we have no alternatives.

The way we approach play and prospect risking in the ultra-deepwater is exactly the same as the way we approach risking in data-rich basins. And this is potentially a huge mistake – as, unlike the hydrocarbon systems in basins where everything is known, we often have almost no direct hard data in deepwater to address the key exploration risk elements. Here the interaction of uncertainty with risk is particularly stark. Risking based on the possibilities both within the uncertainties and availability of hard data and in analogues is the surest way of avoiding ‘insufficient data bias’ and capturing the opportunity of ultra-deepwater.

Take for example the risking of source rock in deepwater plays. In the deepwater of the Atlantic we know so few facts about the available source rocks because so few wells have been drilled to target them. Comprising only a small number of wells, drilled very far before their time (1970s-80s) the DSDP and ODP wells were drilled often in extraordinary water depths even for today.

Yet even these wells were only 10% or so drilled into the pre-Late Cretaceous, where key source intervals lie. The wells that did so were rather clumped together, and the lateral correlatability from basin to basin is questionable due to variability in Atlantic margin architecture. Margin architecture has controlled the depositional setting of syn-transition (rift-drift) Early cretaceous 58

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(South Atlantic) or Jurassic (North Atlantic) which are deposited in shallow water on magma-rich margins, and in deepwater in the syn-transition setting of magma-poor and hyperextended margins (beyond the outer high) (Figure 2).

A lack of Aptian source rock penetration beyond the outer high on the South American margin is a huge problem for riskers, and this is considered the primary risk in many other deepwater basin margins. Risk realism takes this absence of evidence as evidence of absence, which it is not. Indeed, the recent penetration of Aptian source rock in the Venus discovery of the Orange Basin in Namibia (albeit preceded by a much thicker penetration in DSDP 361 in 1974) brought a huge step forward in confidence in the hydrocarbon systems of the Orange Basin in 2022, which has now been followed by many exploration wells chasing (and usually finding) reserves fed from this source rock.

If another country’s government were to ask – how could we get the sort of investment attention that Namibia has got over the last three years – one might reasonably recommend funding a stratigraphic test in the ultra-deepwater to prove the presence of a source rock.

Despite this, a cloud still hangs over the South American margin. It’s surprising, yet after the success of Venus’s Aptian source rock, exploration riskers still had issues extrapolating into the blocks north and south of Venus, let alone across the Atlantic – even though the basin will have been exactly the same.

The exact conjugality to Namibia of this long and thin restricted basin, where shallow water source rocks onlap onto sub areal SDR sets on either margin, is of course irrelevant; it’s the same basin. One approach would be to turn the question around in Bayesian style – if you had source deposited on one margin of a 100km-wide embayment how difficult would it be to keep it away from the other margin? Answer – really difficult!

Fortunately for explorers, we can support a Bayesian conclusion regarding this lack of ‘penetration’ issue by using seismic data as a proxy for well data. Multi-client 3D data is now available over the Aptian source rock both in the Orange Basin of Namibia and the Pelotas basins of Brazil and Uruguay (Figures 3

SPECIAL TOPIC: GLOBAL EXPLORATION

and 4). On these data we can categorise the Aptian in terms of its geological appearance and morphological character, and also its seismic response where proven in Namibia and compare this to the similar quality data in Pelotas Basin. We have to thank our partner Shearwater for acquiring and processing fantastic data in the Orange and Pelotas basins that allows us to do this comparison so readily.

In the Orange Basin the Aptian source rock is thickest slightly offshore from the onlap onto SDRs that sweep down from the outer-high. The basal part of this Aptian thick are the sediments deposited during the first marine transgression of the previously sub-areal flood basalt plateau. The section is narrow, but as the water depth increased and the basin widened during drift, the Aptian onlaps quickly both inboard onto SDRs (eventually overspilling the outer high into the inner basin where it is the source rock for the Mopane-1 discovery) and outwards across oceanic crust. The Aptian is relatively evenly layered and has a high amplitude soft kick at the top and is characterised by both low frequency and Type IV AVO (rapid decrease in amplitude with offset). This set of observations is very typical of organic-rich layers in many basins around the world, from where we understand that it may be possible to use amplitude variation to inform on the sweet spots for maturity and generation.

In Pelotas the Aptian source rock is actually thickest near the onlap onto SDRs that sweep down from the outer-high. Here it is ca 300m-thick comprising three cycles. The Aptian in Pelotas was contiguous around the basin, which had a median spreading centre. The section is narrow, but as the water depth increased the Aptian onlaps quickly both inboard onto SDRs and outwards across oceanic crust.

The Aptian is relatively evenly layered, has a high amplitude soft kick at the top and is characterised by both low frequency and Type IV AVO (rapid decrease in amplitude with offset).

Now when we see these characteristics either elsewhere in Namibia, South Africa or across the Atlantic in Pelotas we can suggest that we are imaging an Aptian source rock. As Mr Bayes

might say ‘if it isn’t then why does it have all these characteristics that are so similar?’ That this isn’t proven by offset wells is an issue as we are using the physics of the seismic data to confirm the presence of source, where we have modern seismic data with gathers so flat that an ultra far angle offset response is a reliable tool. The risking of source, corroborated in this way, suggests the source presence is now as certain as we need it to be. To deny that the source is present just because it isn’t proven (or explored yet) in half of what was a contiguous basin would be perverse, and shuts a door to the possibility of the hypothesis; ‘were source rock to be present in Pelotas this would unlock a fantastically prolific basin as it has done in Namibia’.

In the deepwater hard-data poor setting the same approach of using seismic as a proxy for offset drilling can be applied to all the other risk elements. We are of course very used to using seismic to quantify the other risk elements, such as reservoir presence, but with trap – here’s where the story turns around. The slope plays are still characterised by confined channels that head up-slope towards the shelf and are frankly very hard to accurately risk. Yet this is the play in deepwater that the industry has focused on for 15 years. We now have a better and more accessible alternative as on the basin floor the ubiquitous counter regional dip of oceanic crust creates a stratigraphic trapping configuration where basin floor fan sands dip up out to sea. These are just huge, tilted, basin-floor sand fans – so they tick the boxes of ‘big, simple and permeable’. In the deep water this play is common to certainly the magma-rich margins and, although completely unexplored to-date, likely to be the configuration for magma-poor margins outside the outer-high too.

For the counter regional deepwater play (CRDP Figures 3 and 4), we’d argue, it’s low risk, and diametrically different to the high risk deepwater plays being drilled on the margin slope. Taking an optimist’s view of the likelihood of success of the CRDP, Source Presence can be proven even from a near conjugate penetration using proxy seismic data. Source Effectiveness is provable perhaps

Figure 3 Pelotas: the undrilled Source rock on the conjugate magma rich margin.

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Figure 4 Pelotas Brazil source rock reservoir and trap: ready for UDW exploration.

from direct hydrocarbon indications, yet at least this can be basin-modelled. Key parameters are heat flow (unknowable except through seismic-temperature inversions, curie point inversion and BSR analysis), so high and low model inputs are required. The rate of depositional blanketing (gradualism vs punctuated equilibrium) is an important factor which can be addressed using modern seismic images. Trap is a given (ie certain) in the counter regional basin floor fan play, so needs to be treated as such. Ask the Bayesian question – how is this trap not going to work? Reservoir presence can be determined from acoustic impedance variations on seismic, leaving one play element that you just cannot touch – reservoir effectiveness. While one can look on seismic for thick-stacked sand character etc, even fancy inversion isn’t going to reliably tell you about grain size or diagenesis in an undrilled basin. Nor will looking at conjugate margins, nor provenance studies of the reservoir hinterland. In deep water, though, the sands will not have been buried and inverted, so, compared to most of the exploration we do, having just one unconstrainable risk variable (reservoir effectiveness) is a much less riskier than almost anything we do.

Conclusion Explorers have had a tough time of late as the ‘blame magnates’ for the world’s climate ills. Now, without ceremony or apology, it seems our role in the future transition is recognised and it’s time to be redeemed. We have been recharged to go and find the oil and gas that will bridge the energy transition. Conventional shallow water drilling is high risk, and as we look for oil in more cryptic traps – despite better tools, it’s getting riskier all the time.

The lowest risk plays in the world are in the plays on the basin floor where to-date we have the least penetrations. Humanity needs the exploration industry to embrace a mindset-shift in risking, away from realism and pessimism towards a pragmatic optimism that embraces the elegant simplicity of the last great global exploration play to be tackled – the counter-regional dipping clastic fan play on the basin floor of the Earth’s passive margins. Humanity needs us to be brave and start drilling here because this is the only place to find accumulations that are big simple and permeable, fuelling the transition into a more equitable world.

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The Pelotas Basin: A rising global exploration hotspot Sindre Bull-Jansen1*, Javier Martin1, Christian Strand1, Karen Purcell1 and Mustafa Al-Waily1 demonstrate how quantitative interpretation techniques have shown potential AVO anomalies, providing valuable guidance for prospect identification.

Abstract The Pelotas Basin in south east Brazil is rapidly emerging as one of the world’s most promising regions for hydrocarbon exploration. This paper examines the impact of the recent exploration successes in its geological conjugate, the Namibian Orange Basin, where multi-billion-barrel discoveries have been made over the past four years. The success in the Orange Basin is particularly significant in addressing key uncertainties related to source rock presence and maturation, as well as reservoirs in the Pelotas Basin. Shearwater, in collaboration with Searcher Seismic, is leveraging critical insights from the Orange Basin to unlock the exploration potential of the Pelotas Basin. Seismic analysis clearly identifies striking similarities between the two basins within the Early Cretaceous target interval, helping to derisk key uncertainties related to source rock and reservoir presence. Similar to the Orange Basin, quantitative interpretation techniques have shown potential AVO anomalies, providing valuable guidance for prospect identification.

Introduction Driven by the recent success along the Orange region of Namibia, the Pelotas Basin, located offshore southeast Brazil, is rapidly emerging as a high-potential frontier for hydrocarbon exploration. However, the limited availability of geophysical and geological data implies a degree of uncertainty regarding the key elements of the petroleum systems along the basin. This uncertainty has, in turn, traditionally affected exploration activities in the region. Recent advancements in high-end seismic acquisition and processing technology targeting known Cretaceous plays in Namibia and Pelotas have led to renewed interest. This growing confidence is reflected by the successful 2024 licensing round and, more recently, by the high number of blocks nominated in the Pelotas Basin under the 5th Cycle of the Permanent Offer Acreage in Brazil.

The hydrocarbon potential of the Orange Basin and its relevance to the Pelotas Basin

Despite the recent seismic acquisition campaign, the Pelotas Basin remains a frontier region due to the limited geological knowledge derived from sparse drilling activities and geo-

physical data acquisition to date. However, driven by its strong geological similarities with the conjugate Orange Basin, Pelotas stands as a very promising region for future exploration efforts.

Evidence for these basins being conjugate is the emplacement of the large Parana-Etendeka Igneous Province (LIP) on both sides of the Atlantic during the Western Gondwana break-up.

Further support comes from extensive geochronological analysis (Turner at al, 1994; Renne et al, 1992 and 1996), which supports the conjugate relationship between the Pelotas and Orange basins.

Following multiple discoveries along the Orange Basin, beginning with Graff (Total, 2022) and Venus (Total, 2022) and followed by La Rona (Shell, 2022), Mangeti (Total, 2022), Jonker (Shell, 2023), Lesedi (Shell, 2023), and Mopane (Galp, 2024), the Orange Basin is now one of the most promising petroleum basins globally. The interplay between basin evolution, source-to-sink sedimentation, and tectonic configuration has contributed to putting the ingredients in place to make the case for this basin to be defined as one of the most prolific in recent decades.

Starting with the Early Cretaceous break-up and associated large volumes of lava extrusion (which presumably influenced the prolific Kudu Aptian Source Rock maturation), the high Aptian reservoir heterogeneity and diverse paleo-depositional environments (ranging from microbial carbonates to deep marine turbidites and fluvial to lacustrine clastic) have shaped the petroleum system configuration throughout the basin.

The geological similarities allow the prolific Early Cretaceous play in the Orange Basin to be traced effectively along the Pelotas Basin. An extensive stacked volcanic flow system, manifested as Sea Dipping Reflectors (SDR) formed during rifting, has been unequivocally identified in the same tectonostratigraphic interval in both basins. This volcanic configuration is presumed to play a crucial role in the overlying Aptian Source Rock maturation.

The mature type II Aptian source rock encountered in ultra-deep marine settings within the Orange Basin and overlying the SDR was originally deposited in a restricted anoxic shallow marine environment, analogous to the conditions observed in the Pelotas Basin. The paleomorphology developed by basinal tilting related to gradual thermal relaxation created the physiographic

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Corresponding author, E-mail: sbulljansen@shearwatergeo.com

DOI: 10.3997/1365-2397.fb2025037

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Figure 1 Location of the Pelotas Basin (left) in relation to Orange Basin (right) showing overview of licences, fields and existing and ongoing MC 3D seismic surveys.

conditions to develop effective trapping mechanisms pinching out towards the paleo relief.

The similarities between the two basins, including the potential for structural and stratigraphic traps, provide a promising outlook for future exploration campaigns. As exploration continues to evolve in both regions, understanding the shared geological frameworks and petroleum systems will be key to unlocking the full hydrocarbon potential of the Pelotas Basin.

In partnership with Searcher Seismic and NAMCOR (National Petroleum Corporation of Namibia), Shearwater has acquired and processed more than 12,000 km² of multi-client (MC) 3D seismic data of prospective acreage in the Orange Basin shown to the right in Figure 1. Building on the learnings from the Orange Basin,

Searcher Seismic and Shearwater commenced a multi-year program in 2024 to acquire and process more than 10,000 km² of high-quality MC 3D seismic in the Pelotas Basin shown to the left in Figure 1.

Quantitative interpretation Derisking reservoir and hydrocarbon presence by Amplitude Versus Offset (AVO) analysis is common within the Orange Basin. Strong AVO sensitivity in the subsurface arises due to pronounced contrasts in properties, such as P-wave velocity, S-wave velocity, and density, across lithological boundaries or fluid contacts. These contrasts create variations in reflection amplitude with offset, making AVO analysis a powerful tool for fluid versus lithology discrimination.

Figure 2 The starting velocity model (upper-left) was perturbed with a grid of +/-3% scalars (upper-right), and FWI using diving waves was performed on the real data with 8 km (lower-left) and 10 km (lower-right) offsets, quantifying the benefit from the extra offsets. A 2000 xline increment corresponds to 12.5 km.

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Figure 3 Common channel display showing complexity in seafloor structures. The complex water-bottom-related multiple is well modelled by 3D SRME and successfully attenuated using curvelet domain subtraction. a. input, b. output, c. model.

In this paper, we take a simplified approach to Extended Elastic Impedance (Whitcombe et al., 2002) using pre-conditioned angle stacks to calculate the AVO intercept and gradient based on Shuey’s two-term AVO equation (Shuey et al., 1985). Based on the work presented by Went et al. (2025), intercept and gradient are used to project out to a chi (χ) angle of 27 degrees (rEEIχ27), which is considered optimal for discriminating sand from shale and deriskign fluid content in this environment.

Acquisition and processing – Optimal data for depth imaging and AVO

The 3D survey acquired in the Pelotas Basin was specifically designed to target the Cretaceous plays in deep-water settings.

To optimise the survey, a wide streamer spread was deployed, consisting of 10 streamers spaced 150 m apart, along with triple sources, providing a 25-m crossline bin size. Long offsets were essential to achieve a broad range of angles at the target depth for AVO analysis and to provide deeper penetrating diving waves, crucial for building an accurate velocity model through full waveform inversion (FWI).

To understand the impact of the streamer length on velocity model-building a chequerboard test was run. The starting velocity model was created for the test by smoothing the imaging velocities and then adjusting with a grid perturbation of +/-3%.

FWI was performed on forward-modelled seismic data using offsets of 8 and 10 km. As shown in Figure 2, adding the extra 2 km of offset significantly increased the penetration depth of the diving waves, allowing for deeper updates to the velocity model. Extending the offsets from 8 km to 10 km enhanced the overall seismic data quality, providing more accurate velocity profiles essential for subsequent processing and interpretation.

Shearwater and Searcher Seismic are currently acquiring the second season of multi-client 3D seismic data in the Pelotas Basin as part of a multi-year program. In the first season, two streamers were extended from 8 km to 10 km. In the second season, the full spread of 10 streamers was all deployed with 10

km due to increased water and target depths to further enhance data quality.

Utilising the processing experience from the Orange Basin, a robust and state-of-the-art processing sequence is applied to these data. These techniques included sparse inversion de-blending, shot-by-shot de-signature with NFH data, 3D de-ghosting and de-multiple, with a particular focus during these stages on denoise, due to conditions encountered during acquisition.

The complexity of the seafloor structures required the use of curvelet domain subtraction for the model-based de-multiple techniques, along with high-resolution radon de-multiple and diffracted multiple attenuation as shown in Figure 3.

Results Conjugate Margin – Derisking source rock and reservoir presence

The newly acquired 3D seismic data from the Pelotas Basin reveal striking geological similarities with the Orange Basin, reinforcing the potential for hydrocarbon exploration. Figure 4 compares a depth-processed full-stack seismic section from the Orange Basin with a fast-track time-migrated seismic section from the Pelotas Basin at a similar scale, highlighting key indicators of Aptian source rock presence. Both basins exhibit strong seismic reflectivity associated with Aptian-Albian marine shales, which have proven to be effective source rocks in the Orange Basin. This correlation suggests the presence of an excellent source rock in the Pelotas Basin, derisking one of the primary uncertainties in the region.

Quantitative Interpretation – FWI Velocity Model QC and validating reservoir presence in frontier exploration

The normal derivative of an FWI velocity model, often referred to as the FWI image, highlights rapid changes in the velocity model. As illustrated in the 12 Hz FWI example from Pelotas Basin in Figure 5 (right), it reveals geological discontinuities and FIRST

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stratigraphic boundaries. By comparing the normal derivative to the seismic, interpreters can validate whether observed velocity variations align with actual geological features or result from inversion artifacts. This quality control (QC) process is particularly valuable in improving velocity model reliability, ensuring better depth positioning, and enhancing subsequent imaging and quantitative interpretation workflows.

AVO intercept is linked to pressure wave velocity variations in the subsurface because it represents the zero-incidence angle reflection amplitude. At zero incidence angle, the reflectivity at an interface is a derivative of the acoustic impedance (P-wave velocity X density) variation across that interface. Based on this, AVO intercept can serve as an effective QC tool for the normal derivative of an FWI velocity model, especially in frontier areas with no well control. In Figure 5 we demonstrate this by comparing the Pelotas Basin 12 Hz FWI normal derivative and the 12Hz low pass filtered AVO intercept. The strong correlation suggests that the 12Hz FWI is nicely picking up the details we should expect to see based on acoustic impedance variations in the subsurface. This approach can also allow

us to highlight discrepancies between the two, potentially indicating valuable information about density variations in the subsurface.

AVO analysis further strengthens confidence in the hydrocarbon prospectivity of the Pelotas Basin. By applying a simplified Extended Elastic Impedance (EEI) approach using pre-conditioned angle stacks and Shuey’s two-term AVO equation, intercept and gradient projections were made to a chi (χ) angle of 27 degrees (rEEIχ27). This methodology, based on the findings of Went et al. (2025), has demonstrated its effectiveness in discriminating sand from shale and identifying fluid content variations. In Figure 6, we compare a dip line from the Orange Basin Gap MC 3D pre-SDM (see Figure 1) against a dip line from the Pelotas Basin fast-track at a similar scale. Overlain is the rEEIχ27 attribute highlighting AVO class 2/3 anomalies at primary target levels. Examples from both basins exhibit a strong AVO response, potentially indicating lithology and fluid variations.

To verify some of the anomalies observed in Figure 6, RMS amplitude at the primary target level is extracted

Figure 4 Dip lines in time at a similar scale from Pelotas Basin full stack fast-track 3D (left) and the Orange Basin full stack pre-SDM (right).

Figure 5 Comparisons in time between fast-track full stack, 12 Hz FWI, fast-track AVO intercept low pass filtered to 12Hz and 12 Hz FWI normal derivative. A reference surface is included as a red stippled line.

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Figure 6 Seismic dip lines in time from Orange Basin (top) pre-SDM full stack and Pelotas Basin (bottom) fast-track full stack. Overlain is the rEEIχ27 attribute highligting potential AVO class 2/3 response as a soft response.

Figure 7 3D view in time of approximately 500 km2 area of Pelotas Basin (left) and Orange Basin (right) showing RMS rEEIχ27 amplitude extraction at the primary target interval indicated in Figure 6. High-amplitude continuous reflections, indicative of potential deepwater turbidite systems, slope channel complexes and basin floor fans can be seen in both basins.

from the rEEIχ27 and shown in a 3D view for each basin in Figure 7. The examples show high-amplitude continuous reflections, indicative of potential deepwater turbidite systems, slope channel complexes and basin floor fans. These are proven reservoirs in the Orange Basin (e.g., Venus and Graff discoveries), and the fast-track rEEIχ27 comparisons highlight the potential presence of similar reservoirs in the Pelotas Basin.

Conclusion The Pelotas Basin is emerging as a compelling exploration frontier, supported by its geological similarities to the highly prospective Orange Basin. Key uncertainties related to source rock and reservoir presence are addressed through advanced seismic acquisition and processing, quantitative interpretation, and comparative analysis with the Orange Basin’s proven hydrocarbon plays.

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Recent seismic data from the Pelotas Basin reveal strong correlations with the Orange Basin, including Aptian source rock indicators, stacked volcanic sequences, and analogous depositional environments favourable for high-quality reservoir development. The application of integrated FWI velocity model-building and AVO analysis, has provided robust insights into subsurface characteristics. Preliminary results demonstrate that Class II and III AVO anomalies in the Pelotas Basin align with known hydrocarbon-bearing sands in the Orange Basin, reinforcing its exploration potential.

The collaborative efforts between Shearwater and Searcher Seismic are driving a transformative shift in the understanding of the Pelotas Basin. As exploration advances with continued seismic acquisition and interpretation, the region is positioning as a rising global exploration hotspot.

Hodgson, N., Found, L. and Rodriguez, K. [2024]. Delivering Sands to Venus and all the Traps between: Orange Basin, Namibia. First Break, 42(7), 55-57.

Mello, M.R., Mohriak, W. and Silva, J. [2021]. Source Rock Potential of the South Atlantic Basins: A Comparative Study with the Orange Basin. AAPG Bulletin, 105(4), 675-690.

Renne, P.R., Glen, J.M., Milner, S.C. and Duncan, R.A. [1996]. Age and Petrogenesis of the Etendeka Volcanic Rocks of Namibia. Geology, 24(7), 659-662.

Renne, P.R., Milner, S.C. and Duncan, R.A. [1992]. 40Ar/39Ar Geochronology and Geochemistry of the Etendeka Volcanic Province, Namibia. Journal of Volcanology and Geothermal Research, 50(1-2), 77-94.

Shuey, R.T. [1985]. A simplification of the Zoeppritz equations. Geophysics, 50(4), 609–614.

Turner, S., Regelous, M., Kelley, S., Hawkesworth, C. and Mantovani,

Acknowledgements We would like to thank Shearwater P&I, along with our partners on the data, Searcher Seismic and NAMCOR in Namibia, and Searcher Seismic in the Pelotas Basin, for their valuable contributions to the development of these datasets and the insights they provide in understanding the respective basins.

Went, D., Bamford, M., Rogers, J., Brown, S. and Turner,

References

Whitcombe, D.N., Connolly, P.A., Reagan, R.L. and Redshaw,

M. [1994]. Magmatism and Continental Break-up in the South Atlantic: High Precision 40Ar/39Ar Geochronology. Earth and Planetary Science Letters, 121(3-4), 333-348.

G. [2025]. Characterizing hydrocarbon discoveries and prospects in the Tay Sandstone using relative elastic inversion: Greater Pilot area, Central North Sea. Energy Geoscience Conference Series, 1(1). https://doi.org/10.1144/egc1-2023-37

Hedley, R., Intawong, A., Winter, F. and Sibeya, V. [2022]. Hydrocar-

T.C. [2002]. Extended elastic impedance for fluid and litholo-

bon play concepts in the Orange Basin in light of the Venus and

gy prediction. Geophysics, 67, 63-67. https://doi.org/10.1190/

Graff oil discoveries. First Break, 40(5), 91-95.

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Supporting global exploration trends with geoscience insight Erling Frantzen1*, Anna Lougon1 and Joe Zhou1 discuss how advanced geoscience technologies and data are successfully supporting the search for hidden opportunities in the world’s hotspots.

There has been something of a return to frontier exploration in the past few years, with several key energy players recently announcing a change in direction towards increasing their oil and gas reserves to ensure the world’s future energy needs are met.

This trend will have an impact not only on countries and regions that have seen little recent exploration activity but also on the industry, which will need the support of high-end geoscience technologies, data and expertise to better understand prospectivity, reduce risk and increase the success rate of future exploration initiatives.

Geoscience technology companies (GTCs) play an integral part in the exploration process by applying their in-depth geological knowledge and high-end imaging technologies to offer timely multi-client earth data projects. These provide energy companies with the best possible and most accurate subsurface seismic images, helping them to reduce uncertainties and interpret and understand new plays.

This article summarises the extent of the critical role GTCs play in supporting energy companies in the search for hidden opportunities in the world’s hotspots.

Strong partnerships drive resource development An often-overlooked key driver of successful multi-client surveys supporting new resource development is the nurturing of good, long-term relations between GTCs and governments/authorities, national/international oil companies (NOC/IOCs) to ensure the

right regulatory, fiscal and environmental framework and other appropriate local conditions are in place to deliver positive outcomes. Such relationships can take years or even decades of commitment; rather than drift in and out of a country as industry activity waxes and wanes, it is better to fully support governments as they work to meet these energy challenges.

To develop a successful partnership, it is important that a GTC understands the culture and needs of a country and its relevant agencies. While it will bring best practices, gained through many years of in-depth experience working in different settings around the world, to a frontier area in both the technological and environmental arenas, the GTC will also benefit from decades of experience and regional knowledge available within the ministries and NOCs. The relationship needs to be positive for all parties, so that everyone feels comfortable and confident about the undertaking, working together to realise a country or region’s energy potential.

The importance of a stable regulatory environment is not just relevant to frontier exploration areas. Norway, for example, has continued to be a ‘hotspot’ in the industry for many years, with regular licensing rounds, a transparent and predictable fiscal regime and supportive authorities, making it easy for both oil companies and technology experts to invest in the area. However, if regulations change over relatively short periods of time, as has happened recently in the UK and the US Gulf, it can upset the stability needed for successful operations.

Figure 1 Example of a Viridien long-term partnership, through data acquisition and imaging projects with Côte d’Ivoire’s Direction Générale des Hydrocarbures (DGH) and PETROCI Holding (PETROCI).

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Corresponding author, E-mail: erling.frantzen@viridiengroup.com

DOI: 10.3997/1365-2397.fb2025038

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The energy industry is based on effective relationships, not just with governments and authorities, but also between key industry players. GTCs often team up with each other, as well as with oil and gas companies or with several partners, to share knowledge and develop innovative methodologies and projects to address industry trends.

Advanced technology unlocks the subsurface It is important that the industry continues to develop innovative techniques that can help derisk new plays. One challenge is to incrementally improve high-end seismic imaging, to deliver the most accurate images of the Earth’s subsurface, thereby delineating geological structures which will help to reduce uncertainties and reveal previously undiscovered resources.

In the past decade, the most important imaging technology development is Full-Waveform Inversion (FWI). This technology, aided by FWI-friendly acquisition design (long offsets and low frequencies), is particularly effective for imaging beneath the salt and has been successfully utilised in the US Gulf as well as many other locations with a complex overburden.

Although it is only about ten years since it was widely used in seismic projects enabled by exponentially growing computing power, FWI has continued evolving and maturing.

One advancement is Time-lag FWI, which minimises FWI cycle-skipping issues and is used for delineating very complex geology, including sub-salt, carbonates and thrust belts. A further enhancement to this technology is elastic-FWI. This combines an elastic modelling engine with the time-lag cost

Figure 2 Laconia in the Garden Banks area of the US Gulf: Streamer 15 Hz RTM image overlaid with 6 Hz Streamer AFWI velocity (top) and OBN early-out 5 Hz AFWI Image overlaid with corresponding velocity (bottom). The early-out OBN FWI provides a significantly improved image of the deep basin architecture. Of immediate significance are the updates to the imaging of the salt, the recognition of low-velocity shales, and the impact on the imaging of minibasins and salt welds. The imaging of deep structural features, including autochthonous salt and the pre-salt basement, are also significantly enhanced (courtesy of Viridien Earth Data).

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Figure 3 Seismic section from the Amapa Basin, offshore Brazil, with an overlay of the FWI velocity model. The model effectively characterises the Amapá carbonates on the shelf and at the shelf break, while also distinguishing different stratigraphic intervals. The improved imaging beneath the thick carbonate interval even allows for the identification of new prospects (courtesy of Viridien Earth Data and TGS).

function, with benefits such as a reduced salt halo, sharpened salt boundaries and better structural continuity.

FWI technology relies on a clear low-frequency component in the recorded data, so for the highest quality results a good low-frequency marine seismic source such as the Sercel TPS™ (Tuned Pulse Source) is ideal. An innovative broadband source like this can help to improve images in complex areas such as sub-salt or sub-basalt and has the added advantage of being more environmentally friendly than conventional airgun sources, as the low frequencies minimise impact on marine life.

Advanced imaging techniques also help to maximise value extraction from legacy data. Reimaging years later provides excellent resolution and significant uplift in image quality, and in some cases has led operators to fundamentally change their ideas on the reservoir model. Moreover, this approach promotes sustainability by maximising the use of existing data and minimising the need for new acquisitions, thereby reducing cost and environmental impact.

While FWI technology is still rapidly evolving, its benefits are evident and we expect to see it mature with wider applications and greater impact, which could well lead to success in regions that have so far been unproductive.

In addition, AI and machine learning (ML) are beginning to transform new seismic imaging, shifting from manual processes to AI-driven models that generate subsurface insights rapidly, freeing experts to focus more on high-end analysis. As these technologies evolve, they demand greater compute power for advanced data handling, making it crucial for the industry to invest in both cutting-edge innovation and a skilled workforce to sustain future exploration and discovery.

Seabed nodes and FWI Returning to acquisition innovations, one of the most exciting technologies of recent years is the wider-scale deployment of long-offset low-frequency ocean bottom node acquisition (LOLF

OBN), where receivers are placed on the seabed instead of being towed in streamers behind a vessel. The use of sparse OBNs and a low-frequency source, which gives extra-long offset and rich low frequency, allows for deep diving wave penetration which maximises FWI’s power in sub-salt velocity updating and imaging.

Our recently completed Laconia acquisition in the Garden Banks area of the US Gulf in water depths of more than 2000 m is the largest ever low-frequency sparse OBN survey. The early-out 5 Hz Acoustic FWI imaging results are said to have completely revolutionised thinking about petroleum systems in the Gulf and possibly identified plays down to basement level. The survey used nodes spread over 8000 km2, a source coverage of over 19000 km2, and deployed five vessels and about 300 people at the peak of the survey. One of the main challenges facing the use of this technology, therefore, is how to bring its cost down.

In fact, the cost of OBN, particularly in deep water, has limited the use of OBN to field development in places like Brazil, even though the technology would be ideal for exploration, to delineate that region’s complex pre-salt geology. At present, in Brazil, exploration of the subsalt has been enhanced using long-offset seismic combined with FWI processing of both new and legacy data.

There has also been a shift in recent years from streamer to OBN acquisition to obtain better images in more mature exploration areas. Viridien, for example, has invested in OBN surveys for near-field exploration in Norway, both because towing a long streamer around a production area is not feasible and because OBN acquisition and imaging allows for better illumination potential of subtle and small prospects. It does, however, impose the logistical and operational issues of a node-laying and recovery operation, and has cost implications.

Looking ahead, in proven global hotspots the number of OBN surveys are expected to increase while new streamer acquisition FIRST

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Figure 4 A comparison between the conjugate margin of Uruguay (left, courtesy of Viridien Earth Data) using newly completed 2024 3D PSDM reimaging and Orange Basin, Namibia (right, courtesy of NAMCOR, Viridien Earth Data & TGS) using 2D PSTM (2018) reimaging, highlighting similarities across the margin in terms of structural evolution, basin geology and hydrocarbon potential.

will decrease in volume, but there will also be a movement towards hybrid acquisition.

Exploration trends in the Americas Offshore Americas, exploration is moving into deep and ultradeep waters, with increasing interest in the equatorial margin of South America and into the Caribbean, as well as the US Gulf.

While many giant fields have been found, companies are still keen to make large new discoveries, driven by the use of modern technologies, both in data acquisition and imaging.

The US Gulf is traditionally thought of as a mature exploration area, but focus is now moving from the well-explored shallower Miocene to the complex geology of the deeper Paleogene intervals. With improvements in seismic imaging technologies such as FWI, it is now possible to image these deep layers, and although little exploration has been undertaken in these intervals in the last few years, there is a growing interest in exploring the deep geology of the Gulf.

Similarly, interest all along the southern Atlantic margin has been increasing and this trend is expected to continue. Uruguay, for example, received little attention until recently. However, after discoveries in Namibia’s Orange Basin raised industry expectations that a similar success could be replicated in its Conjugate Margin, Uruguay now has 100% of its acreage under licence. Viridien’s recently completed reimaging of 25,000 km2 of its offshore legacy seismic 3D data – using advanced imaging technologies such as TL-FWI, to enhance the existing data – provides previously unseen details of the country’s deepwater formations. Adjacent to Uruguay, the Brazilian Pelotas Basin could well be the next exciting region to open up for that country, encouraged by discoveries in the conjugate margin in Namibia.

Viridien started acquiring the first seismic data there more than 10 years ago and there is a lot of interest in the area. In fact, discoveries in Brazil and Guyana have encouraged exploration throughout the Atlantic margin, from Argentina and Brazil to Suriname and Trinidad, even in countries like Aruba, where we are undertaking new 2D reimaging (PSTM) focused on the Western Curaçao Basin, and Curacao that have received little interest until now.

Meanwhile, in Brazil, the pre-salt remains prolific and promising, and companies continue to look for new prosects and plays.

Two exciting deepwater discoveries last year have generated interest in the Potiguar Basin in north-east Brazil, continuing the trend from Guyana and Suriname. The latest imaging technologies have been used to achieve substantial improvements in both 70

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pre- and post-salt images, which can potentially help to drive further activity in these regions.

Successfully exploring these relatively new territories is aided by large libraries of legacy 3D seismic data, which are being reimaged with the most recent methodologies, including FWI and TL-FWI. These innovative technologies are allowing companies to image the geology more accurately, to go deeper into the formations and ultimately to derisk their prospects.

Africa and Europe exploration trends Frontier exploration is on the rise again in Africa, with deepwater Namibia garnering considerable attention after several discoveries in recent years. In this region, application of the latest imaging FWI technologies has revealed new opportunities that had not been evident with original data, increasing interest in the country.

Cote d’Ivoire is also creating excitement after a couple of significant recent discoveries and production has already started from its 2021 Baleine discovery. Promising geology and good government support make it an attractive destination for energy companies and a number of them are looking to enter the country.

Exploration will be aided by both re-imaged legacy data and newly acquired multi-client seismic data, which has opened up new opportunities that were not previously visible on the legacy data.

Viridien’s PSDM reimaging of more than 6400 km² of seismic data has generated new insights and uncovered further prospectivity within the new carbonate and proven clastic plays on the Ivorian side of the Tano Basin. Building on this, and, in collaboration with Côte d’Ivoire’s DGH and PETROCI, two new multi-client 3D reimaging programs, CDI24 and CDI25, have been launched. The merging of all three programs creates a seamless and contiguous volume of more than 16,000 km², providing a comprehensive and unified dataset crucial for optimising exploration and development efforts in the region.

Application of the latest seismic imaging technologies has also achieved some substantial improvements in the imaging of the pre-salt of Angola, which is likely to help to drive further activity there.

There is also a growing interest in near-field exploration, particularly in Europe. Finding smaller fields that can prolong the life of ageing infrastructure has been hugely enhanced by the application of new technologies such as OBN, particularly where towing a long streamer in an area crowded with rigs, platforms and servicing vessels is not practical.

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Figure 5 Final data results from the continuing CDI23 reimaging project reveal improved imaging of the syntransform and post-transform plays, along with higher resolution, thanks to the application of deghosting, demultiple, and time-lag FWI (courtesy of Viridien Earth Data, DGH and PETROCI).

The gradual improvement in seismic data quality has significantly aided the derisking of prospects in the busiest exploration hotspot of the Norwegian Continental Shelf (NCS). In the Northern North Sea, our company acquired more than 36,000 km² of new broadband data from 2014 to 2016, leading to numerous discoveries. Between 2017 and 2024, 21 potential economic discoveries were made. Over the past decade, Viridien acquired 53,700 km² of 3D data, 25,500 km² of dual-azimuth data, and 3700 km² of dense OBN coverage, resulting in 28 discoveries within its Northern Viking Graben surveys. These advancements have enabled companies to optimise well locations, identify new targets, and ensure the NCS remains a dynamic exploration hotspot.

Sustainable energy future The skills that have been developed over many years to support exploration of oil and gas are now being used in the field of carbon capture and storage (CCS) and renewable energy sources as the world seeks to reduce its carbon emissions. For example, imaging technologies such as FWI can help to find suitable locations for CO2 sequestration. Using legacy data, reimaged with a focus on aspects of the geology important for CCS, like an excellent seal, is a very cost-effective way of recognising potential carbon storage sites. This advanced processing can also help to identify other important elements in CCS, such as aquifer porosity and permeability and the existence of faults which could cause leakage.

Multi-client screening studies using reimaged proprietary legacy data combined with public databases have identified key storage sites across the world, including in the US Gulf,

the North Sea and the Far East. Reprocessed legacy data is also being used to screen regions in more detail to nominate areas for CCS licences, a much cheaper option than running a new seismic survey. It is also interesting to note that many recently awarded storage licences include a commitment from developers to reprocess legacy seismic data.

Figure 6 New dual-azimuth imaging using FWI frequencies up to 15hz. This image illustrates the RGB colour-blending of frequencies 10, 20, and 30 Hz from the Brent Group, located west of the Troll field. The areas highlighted in orange have been interpreted as fluvial channel belts, which range in width from 1 to 2 km and cross the main fault trend. (courtesy of Viridien Earth Data).

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Figure 7 NVG dual-azimuth, oriented north-west to south-east, full stack displaying enhanced image of the deeper Jurassic-rotated fault blocks and the Paleocene injectites (courtesy of Viridien Earth Data).

Figure 8 Comparison of legacy seismic and FWI image data based on a reprocessing pilot study in the High Island offshore area of the US Gulf. Improved fault definition in the overburden and potential shallow subsurface hazards helps to better derisk the containment component and build a more accurate 3D model of the subsurface storage complex for carbon storage site characterisation (courtesy of Viridien Subsurface Imaging, data courtesy of Seitel).

As a business that is still in its infancy, carbon capture and storage is going to take time to develop, particularly with respect to the relevant environmental regulations which differ from country to country. It is important that the best possible imaging technology is applied to CCS activity from the beginning to ensure the most accurate results going forward.

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Conclusion: future exploration challenges The industry is changing and while E&P companies are refocusing more towards petroleum, they remain mindful of the world’s energy transition challenges. Meanwhile, oil and gas can still provide a key support for a nation’s economy; many countries must import 100% of their energy needs and want to achieve energy security and the ability to improve their infrastructure, education

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and living standards. A variety of energy sources is envisaged in these countries, and the exploration industry should be ready to help them develop their resources in a responsible way.

Committed to a sustainable future, the industry will continue to seek solutions that mitigate its impact and to research methods that reduce its carbon footprint. The success of future exploration will depend strongly on the continuing development of innovative subsurface imaging technologies, such as FWI, TPS and OBN, to ensure the maximum advantage is gained from all data gathered, while efforts continue to reimage existing data that will reveal the hidden resources. These technologies will not only be used to find

oil and gas, but will help industries focused on the energy transition, by, for example, identifying sites for carbon sequestration or for offshore wind farms.

While the future holds uncertainties with unpredictable energy markets and potential political instability, the energy industry stands at a pivotal crossroads. The focus must be on providing the energy required now while simultaneously innovating to meet the future’s energy needs. By embracing cutting-edge technologies and fostering strong partnerships, the industry can navigate these challenges and drive a sustainable, secure energy future for all.

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SPECIAL TOPIC: GLOBAL EXPLORATION

What does the energy mix look like in a truly achievable transition and where will the secure energy needed come from to power the world?

Mike Lakin1*, building on his personal view of the rapidly evolving energy landscape, identifies hydrocabon plays around the world that may be looked at again.

Introduction ‘The world can only achieve energy transition with a proper plan.

Achievable and affordable resources, predominantly oil and gas at present, will still be relied upon until a ‘secure’ replacement and the infrastructure to provide it are available. Crisis appears to be needed for the many uninformed decision-makers to realise that unsecure wind and solar alone (though an increasingly important part of the energy mix able to reduce the dependence on the more emissive fuels when it is windy and sunny) simply can’t just replace hydrocarbons. So, where are the future global hotspots which could securely produce the existing and new sources of energy, if and when the markets wake up to fund the new exploration still desperately needed.’

After the 2014-15 oil price crash, there was a huge reduction in western funding for the upstream sector and renewal of oil and gas exploration linked to new ESG (Environmental, Social and Governance) funding guidelines, due to climate change concerns.

This led to unrealistic ‘knee-jerk’ decisions based on a belief that renewables (mostly wind and solar) could securely replace all the emissive fuels including coal, oil and gas on which 80% of the world’s energy and products were (and 10 years on still are) dependent.

The graph in Figure 2 posted in an article on Westwood’s Linkedin pages clearly shows the subsequent decline in E&P

Figure 1 Graphs showing total number exploration deals completed vs oil price globally over 10 years (2014 - 24). (Source: Linkedin)

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Envoi Limited

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Corresponding author, E-mail: mikelakin@envoi.co.uk

deals over the last decade. Historically this would have increased after the oil price picked up again, but this did not really happen as the influence of ESG kicked in and has not yet recovered. My previous articles in this publication (including in May 2022 and May 2023) focused on the energy transition dilemma in anticipation that some reality might creep into the world’s decision making. Achieving net zero in five to 25 years’ time, although an honourable target, would be measured as part of a realistic and scientifically supported energy transition plan. This would actually achieve some material reduction of emissions and limit any damage to the world’s climate, its economies and in turn to its population’s prosperity.

Transition science and timing I have to state right up front that I am not anti-transition and believe that based on the ‘science’ of climate change, we can’t afford to be wrong. If nothing else, cleaning up our planet is a good thing regardless. The issue is that whilst all the ‘knee-jerk’ decisions and net zero goals are based on supposed scientific evidence of climate change, why has the transition plan to achieve those goals not been based on the ‘science’ of being able to practically and economically generate the energy needed?

I’m equally not dismissing that all the hype has led to positive progress, with many western countries and particularly those in Europe, having successfully reduced their home-grown emissions due to the determined new emissions policies. Many can show that their renewables have replaced a substantial amount of emissions. The reliability is still a work in progress, as a lack of wind or sun reduces their capability. The issue is that with current technology and installations, they can’t be relied upon and are not secure sources of energy. Some countries which have reduced their measurable emissions with demand reduction have simply outsourced the emission-heavy industries to become reliant upon others whose emissions have therefore increased.

The evidence of the damage already done by the lack of a proper achievable and integrated plan, with many likely unintended consequences still to play out, remains crystal clear to those who take the time to ‘look, listen and understand’.

DOI: 10.3997/1365-2397.fb2025039

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Figure 2 Chart showing UK power shortage event on 8 January, 2025 when available sources of energy were critical to maintain the 50 Hz needed by the grid to prevent enforced country-wide power cuts.

Unintended consequence Take Germany as a good example. It implemented a determined green policy decommissioning its nuclear plants and its domestic oil and gas exploration, only to become reliant on Russia for 80% of its gas. Since the start of the Ukraine conflict, it is once again exploring for oil and increasingly gas, and relying on power imported from Poland, which is generated by brown coal (lignite). This makes Germany’s energy more emissive than it was before the implementation of its green initiatives, far less self-sufficient and dependent on others. The emissions have simply moved and are no longer German but Polish.

Britain has arguably done the same. Although it has become less emissive, it’s now dependent upon Qatar and the USA for its gas via LNG. The government sees fit not to record the carbon footprint of producing and transporting it to the UK. If it did, this would be more emissive than if the authorities had not increased the tax and allowed and encouraged new exploration and exploitation of the remaining gas resources offshore in the North Sea and untapped potential onshore. I love the passion for change and the proactivity of determined political decision-making. But have we not learnt from what Germany did and applied science and economics to find the most sustainable and secure solution rather than basing it on emotion and seemingly being economical with the real facts to back up the emotion and political agenda?

To put this in clear context, supply shortages in the UK are now likely if and when the unintended crisis occurs (which is rarely predicted and inevitably occurs).

To show how close such a crisis is already in the UK, it was reported by Kathryn Porter on her Watt-Logic blog (www. watt-logic.com which covers UK energy supply and demand), that the ‘8th January 2025 was the tightest day the GB electricity market has seen since 2011. Wind power was 2.5 GW through the evening peak, solar was (obviously) zero and there were significant interconnector outages leaving expected capacity at just 5.7 GW. Had just one large power station tripped that evening, demand control would have been a real prospect, and how close the UK came to wide-scale loss of load (demand 76

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control means the National Energy System Operator, NESO, will disconnect parts of the country to avoid uncontrolled blackouts)’.

The UK has an increased risk of blackouts in the immediate future, as nuclear retirements, and replacement of conventional gas generation with intermittent wind and solar, stress the electricity grid. This risk can only increase with the decrease in the amount of power generation that can immediately respond to potential shortfall across the grid. The issue centres around the UK’s power grid having to be maintained at a constant 50 Hz. If this diverges by more than <1%, due to the lack of energy to maintain this, a collapse of the system is possible unless parts of the network are shut down. The graphic shows what is known as an ‘event’ when there is not enough source of power to maintain the 50 Hz during times of high demand.

The stress of the grid is illustrated by the graphic in Figure 2 which shows such an ‘event’ in January 2025 when the grid was struggling to maintain the correct frequency and only narrowly avoided a significant shutdown due to not having enough available energy. Porter predicts that: ‘As the energy transition progresses, and the (UK) Government pushes on to its Clean Power 2030 ambition, the risk of blackouts will rise.

These become significant from the winter of 2027–28 onwards, as nuclear retirements and a push to replace conventional gas generation with intermittent wind and solar, alongside possible effects of electrification, stress the electricity grid, potentially to breaking point”. For the complete story, see watt-logic.com.

Possible cause of crisis History shows that crisis is one of the only ways that realistic decision-making happens in a truly democratic society, which understandably tends to avoid having to make tough and unpopular decisions before they are seen as really needed. As an unintended consequence of this and the decisions in energy evident over the past decade or so, what crisis could cause a change of tack?

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Figure 3 Image showing the Rossby Wave jet stream cycle which can cause extreme weather events including very cold European winters every 9-12 years.

Weather could be the ultimate cause of the crisis in NW Europe, related to the 9-12 year cycles caused by ‘Rossby Waves’, a meteorological phenomenon that causes freak weather patterns (Figure 3). Here in the UK, after several very mild winters and nice summers the greater sinuosity of the jet streams is likely to now bring much colder weather further south and could lead to a series of much colder winters. Just such a cold snap was partly responsible for the ‘event’ described by Watt-Logic in the section above. With the declining state of our domestic gas sector, already stretched and outdated power infrastructure capacity, an increased reliance on gas imports and unsecure wind, the risk of longer spells of cold weather simply increases the chance of large power blackouts.

Whatever the crisis, an energy supply crunch could well be what is needed to encourage our leaders to seek the scientific expertise on offer and accelerate the creation of the three ‘A’s, involving a truly Achievable, Affordable and therefore Acceptable energy transition plan.

Future energy demand Global population growth is a primary reason for future energy demand and remains the one controlling factor rarely discussed.

Statistics show that some two thirds of the world’s population currently use around 2 bbls oil energy equivalent per person per year. China uses around 4 bbls/p/yr, Europe around 8 bbls/p/yr and North America over 15 bbls/p/yr. So, if half the developing world’s populations aspire to be as affluent as China, the global energy demand will only rise and quite markedly so.

Figure 4 Graph showing historical increasing use of oil and gas since 1940 and expected future need during fast energy transition scenario.

Back in early 2024, Pandreco suggested that, even in the fastest conceivable energy transition scenario, the world would need an estimated 750 billion more barrels of oil by 2040, and before alternatives could truly start securely replacing them.

Let’s remind ourselves of where the energy comes from and where less emissive energy can realistically come from to fill the secure energy currently provided by hydrocarbons (i.e. oil and gas).

The current and future energy mix If we look at the main sources of the cleanest energy currently available, its clear one can separate these into secure and unsecure categories: Secure Energy • Natural gas • Nuclear • Geothermal • Hydropower • Biofuels • Hydrogen?

Unsecure (without storage) • Solar • Wind The UK’s belief that renewable energy from wind and solar can replace the dependence on hydrocarbons and replace gas to generate all the electricity as and when it’s needed is clearly flawed without the development of significant storage technology and facilities to even out the highly variable solar and wind power generation. Bearing in mind that to achieve the aims of COP 29, a reduction in emissions by 81% over the next decade is required to meet their targets, the path to this target is not straightforward and arguably impossible with the current democratic approach, largely unconnected and unscientific. The following are the pros and cons of the key energy sources of energy currently and most likely to be available in the time frame being considered: Wind is not ‘secure’ as it is completely dependent upon the weather so when it’s not windy it cannot generate the power when needed without secure and dependable back-up of a secure energy source (i.e. coal, oil, gas, geothermal, and nuclear in descending order of the emissions they generate). The screen shot (Figure 6) of the UK’s energy sources from two days in December 2024 clearly show this. Though on different days, FIRST

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Figure 5 Chart showing historical global use of energy by fuel type and current dependence on secure fossil fuels and nuclear.

such a change can happen very quickly in the UK. The stats show that wind generating 50% of the country’s power needs can reduce to less than 10% within a 24-hour period. Without any current ability to store excess wind energy when not needed or having enough gas to fill the gaps, we’d all be sitting in the dark, with no IT, phone charging, heating nor the ability to cook, for those without gas, until the wind blows again. Wind turbines also generally only work when wind speeds are between 7–11 miles per hour (mph) but are shut down when wind speeds exceed 55–65 mph to prevent damage. The other big issues with wind include, i.) the fact that wind project economics currently offer much lower returns, even with subsidies, than gas so the new investment needed is often way short of what is needed to grow as much wind capacity as is wanted by the government.

Also, take a look at your utility bill and note the 10+% subsidy in the UK you pay to grow this less economically attractive source of wind energy. ii). Wind turbines are set in huge concrete bases which are extremely carbon intensive. Hugh blades also cannot be sustainably recycled so most used blades are simply cut up and buried after their 20-year life span (….. not so green then!).

Solar: There is no doubt that solar is a great source of free energy with limited emissions other than their manufacture and installation. However, a photovoltaic (PV) solar panel is dark-coloured and so is designed to absorb much more heat than would normally be reflected by the ground they are placed on. In the desert (Figure 7) where the sun shines more than most, and only a fraction of the energy is converted to electricity, the area

around a large number of solar panels causes much more ground heat as the sand cannot reflect the energy it normally would. This has the potential to alter local climate with simulations showing that noticeable local climate change would occur with large solar farm installations.

Geothermal: This can play its part where the geology comprises right rocks hot enough at depth sufficient for power generation. Geothermal is therefore a very localised resource that still (like oil and gas exploration) requires deep drilling with the risk that the rocks are not appropriate for geothermal. An obvious positive is that the equipment and skills are interchangeable between the two sectors with both involving drilling for, and extracting, fluids. It is therefore a very effective and sustainable replacement to hydrocarbons but only in the few places where the geology is right.

Hydrogen: Most people do not seem to realise that the majority of hydrogen currently comes from gas (i.e. CH4 = methane) where the extraction of the H generates CO2 as a byproduct which then needs to be captured and stored as an emissive gas. Its generation via electrolysis is possible but requires large quantities of mostly fresh water which is generally already in short supply.

The process of extraction also needs lots of electrical energy to power the electrolysis and is only 60%-80% efficient, i.e., it takes 130+% of the energy to generate 100% of the equivalent hydrogen energy! Also, hydrogen is a very small molecule, leaks easily and is highly combustible so very dangerous when mixed with air. Hydrogen is a very clean and effective fuel when used to power public transport or power an industrial zone, but it’s unlikely to be available for domestic use, based on currently available technology. For hydrogen to be generated efficiently, hydrocarbon gas still needed to generate it efficiently, the high cost to capture and sequestrate the CO2 byproduct and dangers of its combustion have to be addressed. New initiatives to drill for and find naturally occurring hydrogen are being proposed but it’s questionable if sufficient resources can be found to replace hydrocarbons.

Nuclear: The new energy mix almost certainly has to include more nuclear power. Rather than the huge conventional reactors, Small Modular Reactors (SMRs) could be a viable alternative.

The new technologies being developed are still relatively new but could generate substantial amounts of power with almost zero emissions. This still relies upon a massive upgrade to all the power infrastructure and the huge increase in capacity needed before it can truly replace all the hydrocarbon energy which

Figure 6 Source of the UK power on 2 days in Feb/ March 2025.

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Figure 7 World’s largest solar farm - Gansu Province (China):equivalent to size of Chicago (USA).

relies on pipelines and tankers to transport it. This is likely to take 10-30+ years, even if it were to receive immediate political endorsement and huge funds to prove, perfect, build and generate the power more locally. There is little doubt, however, that ‘new nuclear’ and the use of the new SMR technologies will be capable of replacing the power currently generated by gas and with zero emissions. The justifiable concerns over large-scale nuclear are based on the global disasters we all know about, whether its Windscale in the UK in 1957, Three Mile Island in the US in 1979, Chernobyl in Ukraine in 1986 or Fukushima in Japan in 2011. All of these involved either fire or reactor meltdowns with nuclear fallout due to particles being released into the atmosphere. The issue is largely related to the water used to cool these older reactors where the latter melt at 800°C+ but water boils at 100°C. If the the ability to cool with water is lost, the intense heat by a reactor meltdown cracks the hydrogen from the water which can then explode and causes the devastating atmospheric fallout. Some of the modern SMR designs involve either salt or helium which are much safer. Helium is an element and noble gas so can’t split into anything explosive so nowhere near as dangerous. Nuclear does come with the radioactive waste issue but one has to ask if this is more or less of a problem than climate change! Effective methods of recycling or storing the waste are not insurmountable where a solution will almost certainly be found if and when the right research is appropriately funded. The key is that the new helium SMR design (based on HTMRs – High Temperature Gas Cooled Reactors) incorporates significant new fail safes and would enable emission-free power generation for at least seventy years and with minimal reactive waste at the end of this term. It’s no wonder many of the huge global data companies

Figure 8 Image showing design and modest size of SMR (Small Modular Reactor).

are now looking at SMR as independent power sources rather than reliance on increasingly unstable third-party grid providers.

Gas remains the only scalable, ‘secure’ and most affordable source of currently available energy (assuming one has the resources and available supply), which is able to be transported globally and switch on and off when needed. Though still emissive, other than geothermal and nuclear, it is the least emissive of the currently achievable sources of secure energy. The key question is whether the world has enough to meet its demands over the next few decades without a huge new cycle of exploration to replace reserves used over the past ten years and expected increase in global energy demand.

The current transition status Few populations have realised that the only way to truly reduce emissions is to change their lifestyles and pay much more for the energy and products used on a daily basis. It often surprises me how many people simply do not appreciate that all the plastic they use comes from oil! At present too many also do not consider that climate change is ‘their problem’.

However, it is increasingly evident that many scientists, and I’m pleased to say an increasing number of non-industry pundits and market makers now understand that net zero and green targets are not likely to be achievable without technology or significant consumption change. Tax alone is not a deterrent either. Many more are also now realising that although an increase in affordable renewable energy can reduce emissions, it’s very unlikely to be able to fully replace the current sources of secure energy anytime soon.

Economics of transition (‘carrot or stick’) The major energy companies are showing clear signs of returning to exploration of oil and gas, even in the face of recent political and market sentiment with bp, for example, publicly stating its intention to renew its search for new exploration projects after a material move to renewables the last six years or so. This is after it’s become clear that the alternatives do not generate anywhere near the same returns. Until the transition becomes commercially attractive, hydrocarbons, and increasingly gas, will be needed for decades to come and until the time when a secure energy source is ready and available to generate the electricity, with the necessary infrastructure to effectively distribute it.

The economics of exploration will always include ‘risk’.

The stats over the last 30+ years show that exploration well success is around 20% globally (i.e., with up to 80% failure) of which less become truly commercial developments after appraisal. Exploration successes therefore require participation in enough projects in a portfolio of opportunity based on the 10%-20% in order to find a potentially commercial resource that can generate significant returns. This also covers the cost of failure.

History of past downturns, however, suggests that E&P companies often need to relearn how to build a risked exploration portfolio to maximise the chance of success and take sufficient risk to generate the big returns. When money becomes tight during a downturn it’s understandably the financial, legal and engineering management which takes the lead in ensuring FIRST

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Figure 9 Map showing Global geological provinces by basin type & author’s selection of current & potential future hydrocarbon ‘hot spots’.

a company’s survival when funds need to be preserved. A return to more exploration needs the involvement of seasoned technical leadership able to properly help manage the increased risks as part of an E&P company’s management team.

Many of the mid-cap companies during the recent downturn have tried to grow through acquisition and participation in lower risk ILX (Infrastructure Led Exploration) but this is mostly in proven producing basins where the risks are lower. The resources of peripheral and infill exploration are also smaller with lower returns. The biggest shareholder returns from growth of the most successful E&P companies have more often than not involved successful high-risk frontier exploration.

M&A creates bigger and bigger companies but often linked to the value of reserves where shareholder value is often not materially increased other than through dividends due to more production revenues. This does not replace or increase a company’s reserves or value.

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generate the same returns that come from their existing hydrocarbon portfolios to pay the dividends expected annually by the same shareholders that wanted a switch to renewables. The returns have in fact mostly come from the increased cash flows from existing hydrocarbon production bolstered by higher commodity prices.

The low margins being achieved from renewables appears to be leading to an increased return to exploration and higher risk, higher return projects again with E&P companies now wanting to regrow and bolster their portfolios, hoping for success to replace and increase revenues.

In contrast, most of the smaller E&P companies, historically reliant upon the markets for funding, remain cash constrained as the appetite for new investment in the E&P sector has not yet recovered from ESG and the renewables boom. Few investors, other than some private equity players have yet to return as the markets remain averse to investment in fossil fuels linked to the greenwashed investment criteria. It’ll be interesting to see if the new interest in E&P companies will be followed by a new breed of market makers with little or no experience of oil. After the last big E&P cycle many investment houses and banks closed and let their upstream investment teams go. Perhaps a potential energy supply crisis will accelerate this, endorsed by a change

SPECIAL TOPIC: GLOBAL EXPLORATION

of political sentiment when the voting populations ask why they have no energy, which can’t then be as easily blamed on the energy industry.

An additional issue is that historically these smaller companies were run by experienced industry folk including many more technical G&G (geological and geophysical) staff that had trained and cut their teeth with the majors. Their experience from the Seventies, Eighties and Nineties was arguably key to unlocking many of the big new plays which they sold and promoted to the bigger companies through farmouts. It’s questionable if the few remaining large E&P companies and majors have the same level of expertise now that will be required to find, create and build the risked exploration portfolios needed again.

Frontier hotspots Assuming the focus on new exploration continues to increase, funded by the majors and other larger E&P companies with existing cash flow, and even the smaller companies when new investors potentially jump back on the new exploration cycle, where can the E&P companies go in the world to create a successful, risk balanced exploration portfolio today ?

The map highlights a selection of key areas of the world which the author feels has large unexplored hydrocarbon potential although, as the key shows, several are classed as either environmentally or politically and/or security sensitive. As there is simply not enough room in this article to discuss all the world’s potential ‘hotspots’, three have been selected which highlight (see red outlines featured in map in Figure 9.) several key areas. These

include recent success and potential follow-on areas, comprising offshore southern Namibia and its potential conjugate peer offshore Uruguay. Also, an example of a huge and highly prospective undrilled frontier play area is Jamaica, a potential ‘gem’ yet to be unlocked after the last decade of exploration slowdown. Lastly, two areas offshore Australia offer both new play potential in a mature basin in SW Australia and totally undrilled potential offshore with environmental sensitivities albeit immediately next to energy hungry markets in SE Australia.

South Atlantic: Starting with Namibia, work by the author on the Luderitz Basin, situated midway between the Walvis Basin offshore to the north and the new Orange Basin hotspot in the south, highlighted a potential reason for some of the more recent exploration failures. Before the recent discoveries, Namibia’s offshore plays were all considered ‘high risk’ due to the fact that they are south of the Walvis Ridge where the stratigraphy does not contain the thick upper salt that dominates the many proven producing west African plays to the north. Evidence of hydrocarbons existed to the south but were limited to the oil recovered from the Wingate-1 well in the Walvis and the single, stranded and uneconomic Kudu gas discovery in the Orange Basin. The fact that a large commercial discovery had not been found at that time did not concern some. It was simply that the geology and plays were clearly going to be different without the salt, but how different did not seem to have been unlocked. What became more obvious was the fact that the hydrocarbons that had been found were below the potential Upper Cretaceous Aptian source rocks.

Several unsuccessful wells were drilled in 2018 (Cormorant and

Figure 9 Montage showing well evidence for local / regional Aptian seal and incidence of current oil and gas offshore Namibia.

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Figure 10 Montage showing South Atlantic conjugate margin and potential for a new hot spot offshore Uruguay / Argentina as Namibian analogue.

Prospect-S) targeting the Upper Cretaceous sand plays which were largely dry. The evidence of large upper Cretaceous sliding events offshore, however, offer clues and such sliding is known to be dependent upon a decollement surface which can include overpressured shales. Further review of historical well data confirmed that the ‘Aptian’ was the likely candidate. Although the potential source was over pressured with oil and gas, it was unable to escape, so was acting more as a local or even regional ‘seal’ rather than a source rock to the overlying upper Cretaceous reservoir sands.

A cross-section N-S through the offshore (Figure 10) shows the only wells that penetrated reservoir were trapped below the possible Aptian ‘seal’ were the Kudu discovery and Wingat-1 wells. As a result, the chance of making new discoveries in the middle and lower Cretaceous remained a distinct possibility and appear to have been proven by the host of recent discoveries in the Orange Basin by Total, Shell, Galp and their partners with the basin-opening Venus discovery, followed by Mopane and Graff.

It appears that faults have locally provided a migration pathway through the Aptian as potentially very large commercial resources have been reported. The jury is still out about reservoir quality but it’s assumed at this stage that this will still allow development due to the sheer size of the closures reported. These have an estimated combined resources of around 10 billion bbls oil and up to 9 Tcf of gas discovered so far. Further discoveries are likely as more wells are drilled.

Looking at the potential influence of these play-opening discoveries offshore Namibia, the question is where else might this take new exploration. Obviously south across the border into South Africa, but future hotspots further afield are also likely. Looking across the South Atlantic and the conjugate margin, offshore Uruguay and Argentina is perhaps next. The fact that all the acreage has been licensed in the past few years and by many of the majors, tells you its potential has already been recognised.

Jamaica (Caribbean): An area the author has become very familiar with is the Caribbean, which compared to most other 82

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prolific, proven and producing play areas of the world is clearly different. Different due to its geological evolution, as it’s not a ‘passive margin’, a ‘continental rift’, nor an ‘overt thrust zone’, but a ‘plate creation zone’. What’s that you may ask, well it’s simply the fact that the Caribbean plate has grown and evolved since Cretaceous times when paleogeographic reconstruction indicates the deposition of an extensive back arc source basin occurred.

This has has now been split like a jigsaw into smaller but still big pieces as the Caribbean plate has evolved and expanded eastwards over time (reference Montage).

The present-day island of Jamaica is now the uplifted portion of the play area linked first to dextral and then later sinistral sheer along the strike slip fault that separates it from the Cayman trough to the north. All of the 11 historical wells drilled between the 1950s and early 1980s onshore found hydrocarbons and all the elements of the play including reservoir, source and seal have been defined, but but most were located by surface geology and now deemed to be off structure.

The key to the prospectivity today are the two preserved but totally undrilled play areas offshore to the south of the uplifted island area including the Walton and Morant basins (Figure 11).

The existing 2D and 3D seismic data have highlighted some 40+ prosects and leads surrounded by mature source rocks with much evidence of active hydrocarbon generation by numerous features on seismic in addition to active surface seeps and other hydrocarbon indicators. The combined resource potential of the existing prospects and leads is estimated to be capable of more than 7 billion bbls ‘recoverable’. The very attractive Jamaican fiscal regime and access to energy-hungry markets in the region, mean that even the prime 3D defined prospect containing an estimated 400 MMbbls of recoverable resources would still be independently economic at a $25/bbl oil price!

Frontier exploration risk has not of late been attracting the necessary investment but does offer the very big returns and huge new resources now predicted to be needed to fuel the world until a secure replacement can be secured and the infrastructure this will need is built, The evidence is that such projects are, however,

SPECIAL TOPIC: GLOBAL EXPLORATION

Figure 11 Montage showing present incidence of Cretaceous hydrocarbons across Caribbean plate and paleo-geographic reconstruction of original source rock deposition.

Figure 12 Montage showing relative size of proven producing ‘Golden Lane’ play trend offshore Suriname-Guyana and totally undrilled but highly prospective play area offshore Jamaica.

beginning to attract new interest in which a material participation can be acquired on very attractive and highly competitive terms.

Two majors reviewed all the data on the opportunity there and

recommended it technically and commercially to their Boards in 2024. A commitment was delayed for ‘strategic’ and ‘budgetary’ reasons but it’s more likely that the issue of a new country entry was the main reason. There is no doubt as exploration returns this area will be picked up by a smaller company in order to progress it through the next level of G&G evaluation to the drilling phase.

It will end up being carried by a larger E&P or major when they realise the modest frontier risk involved to control the huge resource potential and upside in two frontier plays. It can also be accessed on excellent deal terms with EMV economics. With hindsight, how many companies would have liked to have owned even a small carried or controlling interest in the huge frontier acreage offshore Guyana back in 2010? I wonder how many companies reviewed and turned that down before its discovery in 2015 and the 16+ billion bbls of resources defined since in the ‘Golden Lane’ play fairway.

Australia: Finally, two plays have been selected in Australia including the undrilled frontier play offshore Sydney Basin in south east Australia that may surprise many, albeit in an environmentally sensitive area but technically fascinating. Also, an undrilled deep play offshore already proven and producing in the Perth Basin of southwest Australia.

The Sydney Basin offshore is totally undrilled and therefore classified as ‘frontier’ even though the Sydney Basin onshore confirms an active Triassic gas play. Huge gas potential is now predicted off the Queensland coast, and the large energy-hungry conurbation around Sydney, and indeed the whole east coast gas market currently reliant upon declining supply from its ageing FIRST

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basins onshore. These have been declining due to the stringent green policies in Australia for the past decade. Only in the last 12 months has gas been suggested as a ‘clean’ energy source due to the looming supply shortages. It’s lucky that Australia can rely

more on solar to reduce use of emissive fuels, but still, like most developed countries, gas is the only available secure fuel able to fill the inevitable gaps in energy supply that come with most renewables and without a nuclear industry.

Figure 13 Montage showing location and totally undrilled play prospectivity offshore Sydney Basin, SE Australia.

Figure 14 Montage showing deep Lower Permian prospectivity of Perth Basin (SW Australia) which is proven onshore but as yet undrilled offshore.

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The main target play offshore Sydney Basin is the Triassic.

This has been drilled extensively onshore and found gas, but generally in smaller quantities due to reservoir quality. The depositional model, however, suggests that the sands could become substantially better developed offshore, where it was deposited from the north along the rift axis as New Zealand separated from the Australian continent. The existing seismic data indicates potentially very large closures, associated with active gas generation from satellite seepage, and ground truthed gas bubbling from the seabed. This is associated with large seabed ‘pockmarks’ caused by sediments reacting to large-scale seepage. Time will tell if a supply crisis leads to exploration offshore Sydney basin in view of opposition from environmentalists against any offshore exploration over the past 20 years. This is not unexpected and perhaps understandable. It remains a highly prospective undrilled play area which could help to provide resources if a supply crisis does at some point arise.

By contrast, the Perth Basin, situated in the south western part of Western Australia, is already a proven producing basin with earlier phases of exploration in the Forties, Sixties, Eighties and Nineties with oil and gas having been discovered in the Triassic and Upper Permian, mostly onshore. A more recent phase of exploration onshore, targeting deeper Lower Permian sandstone, was originally seeking industry investment in 2014 when it was considered high risk due to concerns over a compacted reservoir.

Drilling, however, has since confirmed the discovery of several hundred Bcf in quality reservoir with commercial flow rates due to preservation of the porosity-permeability by the Lower Permian’s clay mineral content that has prevented diagenesis.

Offshore, the existing 2D seismic data has highlighted large prospects in the same deeper Lower Permian ‘Kingia’ play, which has not yet been penetrated by any of the historical wells and so remains untested.

This is a very good example of new G&G work unlocking deep potential in a mature basin. The potential uptick in exploration activity will no doubt lead this new offshore play potential to be actively explored in the near future.

The challenges Future challenges still remain to realise a potential new cycle of exploration with quite a few things likely to limit the ability of the upstream sector to fully engage.

Firstly, there are far fewer established E&P companies than there were historically. Many of the medium-to-large companies have merged in the last downturn, so there will simply be fewer companies with established teams to explore. This equally assumes that the equity markets and new private investors have the expertise, knowledge and foresight, or economic comfort to help fund new exploration after the huge swing to renewables over the last decade. They are simply out of practice. It may be that this will become easier when the finance sector sees large new returns from the early movers, albeit with higher risk than they have been used to.

As exploration is by nature higher risk, this will also require the E&P company management to understand the risk-taking required and motivation to authorise riskier exploration projects. This is equally challenging to many companies which have been run by financial, legal and engineering management during the downturn and which will naturally be averse to funding such risks. In this regard, technical G&G (geologists and geophysicists) are often the first to be cut during a prolonged downturn and now means there are fewer people with the skills and experience to help manage the risks, generate and manage successful portfolios. Many non-technical people understandably find it difficult to consider an exploration well, often in very large licences (>5,000 to 10,000 km2) costing upwards of $10 million to more than $100 million with a 10-20% chance of historical success. Let’s hope AI will in time be able to help and reduce the risks.

The service sector has also shrunk after mergers of all the big consultants and service companies during the downturn, including in particular the seismic companies. The resulting availability and competition for such services will clearly be an issue if there is a rush to explore. Rig availability and associated drilling services and lead times for equipment are potential issues.

As there is nothing more certain than ‘change’ it will be interesting to see over the next few years how the energy sector evolves and the potential for a new and potentially last big new cycle of exploration unfolds. I’ll hopefully see some of this before I retire with 40+ years of experience gained since leaving Cardiff University as a geologist in 1984. The industry crashed then until 2003 when the price of oil rose above $20 /bbl for the first time for 19 years. Such cycles are not new, just different.

History does repeat, albeit in different ways.

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