First Break May 2024 - Global Exploration

Global Exploration

EAGE NEWS Annual Conference preview

CROSSTALK Oil and global conflict

TECHNICAL ARTICLE Derisking North Sea CCS operations

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CHAIR EDITORIAL BOARD

Gwenola Michaud (gmichaud@gm-consult.it)

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, PGS (anthony.day@pgs.com)

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

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

• Stephen Hallinan, CGG (Stephen.Hallinan@CGG.com)

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

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

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

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

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

EAGE EDITOR EMERITUS Andrew McBarnet (andrew@andrewmcbarnet.com)

MEDIA PRODUCTION Saskia Nota (firstbreakproduction@eage.org)

PRODUCTION ASSISTANT

Ivana Geurts (firstbreakproduction@eage.org)

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FIRST BREAK ON THE WEB www.firstbreak.org

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

Jerv, a recent Palaeocene discovery at the UK-Norwegian border. Is it so small?

31 A unified earthquake catalogue for the North Sea to derisk European CCS operations

Tom Kettlety, Evgeniia Martuganova, Daniela Kühn, Johannes Schweitzer, Cornelis Weemstra, Brian Baptie, Trine Dahl-Jensen, Annie Jerkins, Peter H. Voss, J. Michael Kendall and Elin Skurtveit

37 Increasing P-wave and S-wave velocity resolution with FWI — a North Sea shallow water case study

Alireza Roodaki, Loic Janot, Manuel Peiro, Hao Jiang, Wenlei Gao, Hervé Prigent, Ziqin Yu, Nabil Masmoudi, Andrew Ratcliffe, Per Eivind Dhelie, Vidar Danielsen, Knut Richard Straith and Arnstein Kvilhaug.

Special Topic: Global Exploration

45 Detailed mapping of sand injectites integrating seismic attribute analysis and machine learning techniques in the Norwegian North Sea Anna Rumyantseva, Jaswinder Mann-Kalil, Sara Mitchell, Dean Macaulay and Alaa Triki

53 Understanding tectonic development and the implications for prospectivity offshore Côte d’Ivoire and Ghana

Avril Burrell

59 Unveiling the petroleum potential of one of the world’s last frontier petroleum provinces: the Bengal Fan, offshore Bangladesh

Elisabeth Gillbard

67 Arriving early to the party: finding hotspots before they’re hot Neil Hodgson, Lauren Found and Karyna Rodriguez

71 Jerv, a recent Palaeocene discovery at the UK-Norwegian border. Is it so small?

Carl Fredrik Gyllenhammar, Ivar Meisingset, and Birger Dahl

78 Calendar

cover: Sunrise over a rocky beach in the Bay of Bengal. This month we focus on the potential of the Bengal Fan, offshore Bangladesh.

European Association of Geoscientists & Engineers

Board 2023-2024

Near Surface Geoscience Circle

Esther Bloem Chair

Andreas Aspmo Pfaffhuber Vice-Chair

Micki Allen Contact Officer EEGS/North America

Adam Booth Committee Member

Hongzhu Cai Liaison China

Deyan Draganov Technical Programme Officer

Wolfram Gödde Liaison First Break

Hamdan Ali Hamdan Liaison Middle East

Vladimir Ignatev Liaison CIS / North America

Musa Manzi Liaison Africa

Myrto Papadopoulou Young Professional Liaison

Catherine Truffert Industry Liaison

Mark Vardy Editor-in-Chief Near Surface Geophysics

Florina Tuluca Committee Member

Oil & Gas Geoscience Circle

Yohaney Gomez Galarza Chair

Johannes Wendebourg Vice-Chair

Lucy Slater Immediate Past Chair

Wiebke Athmer Member

Tijmen Jan Moser Editor-in-Chief Geophysical Prospecting

Adeline Parent WGE & DET SIC liaison

Matteo Ravasi YP Liaison

Jonathan Redfern Editor-in-Chief Petroleum Geoscience

Robert Tugume Member

Anke Wendt Member

Aart-Jan van Wijngaarden Technical Programme Officer

Sustainable Energy Circle

Carla Martín-Clavé Chair

Giovanni Sosio Vice-Chair

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Laura Valentina Socco Vice-President

Edward Wiarda President

Aart-Jan van Wijngaarden Technical Programme Officer

Esther Bloem Chair Near Surface Geoscience Circle

Maren Kleemeyer Education Officer

Yohaney Gomez Galarza Chair Oil & Gas Geoscience Circle

Carla Martín-Clavé Chair Sustainable Energy Circle

Caroline Le Turdu Membership and Cooperation Officer

Peter Rowbotham Publications Officer

Pascal Breton Secretary-Treasurer

EAGE Annual 2024: Pioneering the future of energy and geoscience technology

In just a month, the EAGE Annual Conference & Exhibition will open its doors in Oslo. As we gear up for this June event, there’s a sense of anticipation for what is expected to be an enlightening experience for all attendees. With the exhibition space almost fully booked, it’s clear this event is not to be missed.

The journey begins at the EAGE Hub, right after the Opening Ceremony. This is your go-to spot for everything you need: daily plans, details on workshops, and help from our team. It’s also the perfect place to ask about EarthDoc, plan your day, or learn about membership benefits. In the evening, the Icebreaker Reception in the Exhibition Hall is where everyone meets to chat and check out new tech and innovations. Networking opportunities abound, allowing attendees to connect in an informal setting. The conference’s social programme also includes a unique Conference Evening at Bygdøy, offering insights into Norwegian history and maritime exploration.

The exhibition floor will buzz with innovation, showcasing companies from around the world. Special areas, such as the Digital Transformation and Energy Transition zones, will offer insights into forward-thinking technologies and sustainability solutions. These areas are not new, but they are more important than ever for propelling our industries towards a sustainable future. The Digital Transformation Area will show you how tech and data are changing our industry, including special talks on digital subsurface technologies and the journey businesses take as they become more digital. It will also host hackathons and offer many activities for students and professionals who want to develop their skills and make new connections.

The Energy Transition Area will discuss the importance of offshore wind and energy storage solutions, showcasing the role of startups and AI in moving towards a cleaner world.

Adding a new dimension to the conference, the International Prospect Centre (IPC) will serve as a platform for licensing agencies and national oil companies to present exploration and investment opportunities. This space will not only inform the

industry about current and upcoming exploration activities but also display new licensing rounds.

Innovation continues with the Start-Up Area, where emerging companies are eager to connect with potential customers and investors. It is a space for innovation, with start-ups showcasing disruptive ideas fuelled by positivity and enthusiasm.

Parallel to the start-up hub is the University Area, a gathering place for academia’s brightest minds. Here, institutes and universities from around the world will share their latest research and projects, offering attendees a glimpse into the cutting-edge developments shaping the future of energy and technology.

The Exhibition Theatre complements the Exhibition, running alongside the main EAGE technical agenda. It will feature a diverse programme of presentations from participants in the Digital Transformation, Energy Transition, and International Prospect Centre areas, along with pitches by start-ups.

In summary, this year’s EAGE Conference & Exhibition in Oslo is shaping up to be an exciting event for anyone interested in the future of energy and technology. With nearly full exhibition space and a focus on digital and energy transitions, it promises to be an insightful and connecting experience for all. The regular registration deadline is 15 May, secure your All Access pass by visiting www.eageannual.org.

Nuclear waste discussion at Annual 06

Data processing makes headway in Cairo 10

Five communities for energy transition era 13

Chance to catchup is just around the corner.

Boost your professional knowledge with the short courses at the EAGE Annual 2024

The EAGE Annual 2024 is just around the corner, and this year promises an exceptional line-up of short courses designed to enhance your expertise in the energy industry. Whether you’re a seasoned professional or an emerging talent, these courses offer unique insights and opportunities.

Dive into the principles of microseismic monitoring with Dr Leo Eisner (Seismik) during the Microseismic Mon-

itoring for the Energy Industry course on 9 June 2024. Explore applications ranging from conventional to unconventional production, through geothermal energy extraction to CO2 sequestration.

Led by Dr Dariusz Strąpoć (SLB), the Exploration of Subsurface Natural Geologic Hydrogen course compares different sources of hydrogen, examining their carbon footprint, energy output, and global occurrences. Join the course on 10 June and

discover global occurrences and seepages of natural hydrogen along with worldwide ongoing and planned exploration activity.

On 14 June 2024, Dr Denis Voskov (TU Delft) delivers a hands-on course on Reservoir Engineering of Geothermal Energy Production covering the fundamentals of geothermal energy production and reservoir simulation techniques, accompanied by practical exercises in Jupyter Notebooks using an open-source simulator. Participants should have prior knowledge of basic Python programming.

Finally, Prof Philip Ringrose (NTNU) will guide you through the science and technology behind CO2 storage in deep saline aquifers in the SEG DISC course Storage of Carbon Dioxide in Saline Aquifers on 14 June. He will review the main concepts involved in the engineered storage of CO2 in saline aquifer formations, dispelling some common misunderstandings along the way.

Secure your spot today and earn CPD points valuable for your professional development. Visit the www.eageannual.org for more information and registration details.

All sorts of environments to learn about.

GAME CHANGER

Conventional processing and imaging workflow DUG MP-FWI Imaging

The game has changed. DUG Multi-parameter FWI Imaging completely replaces the conventional processing and imaging workflow, delivering high-resolution reflectivity images for both structural and quantitative interpretation using field-data input. No more dealing with the ups and downs of a time-consuming, subjective, multi-step workflow. Just a direct pathway to superior results. Now that’s winning.

Nuclear waste management workshop to feature at Annual

We are excited to present a workshop programme to the EAGE Annual on ‘Moving forward with deep geological repositories for high-level nuclear waste – Contributions from geophysics’.

Dirk Orlowsky (DMT), former EAGE president and one of the convenors, welcomes the initiative. ‘This will be the first of its kind with contributions from important European players in this area’, he says.

In many countries, radioactive waste is temporarily being stored in various forms of dry containers, silos or vaults of which the safety and longevity are questioned. Thus, deep geological storage is widely agreed to be the best solution for the most radioactive waste produced. As each country has its own geological setting, it is obvious that each country must develop its own strategy for the final treatment of their nuclear waste. As a result, many countries have developed their own programmes to find suitable techniques for the exploration of final storage sites for nuclear waste in the Earth’s subsurface.

Geoscientists recognise that European and national organisations play a particularly prominent role in researching the geological conditions for deep geological repositories for different levels of radioactive waste, regarded as the most effective long-term solutions.

Finland, for example, has already begun the construction of an underground research facility in 2004 after an extensive exploration programme. The facility is now part of the final disposal site for spent nuclear fuel. To ensure long-term safety, continuous geophysical site investigations of different scales are required. Multi-disciplinary monitoring programmes and surveys aim to continually characterise the state and changes of rock mechanical, hydrogeological and hydrogeochemical conditions in and around the facility. Geophysical techniques are used to provide

further information regarding the stability and suitability during the construction and operation, for site monitoring, rock suitability classification studies, excavation damage zone investigations, and engineered barrier system in situ test site monitoring.

In Switzerland, the site selection process has been carried out in three stages. Starting with a ‘blank map’, potential areas and rock strata throughout the country were considered. Less suitable areas were gradually excluded, eventually leading to the identification of the most suitable sites by exclusion. The search, applying a multitude of geophysical exploration programmes, has focused on Opalinus Clay as the host rock, which occurs at a suitable depth, particularly at a site in northern Switzerland. This preselected area seems to be the most suitable for the construction of a combined repository for all types of waste.

Sweden began the search for a suitable site for a spent fuel repository in the early 1990s. The site selection process was preceded and ran parallel with geophysical and geological research and development works. These included the so-called ‘three barriers’ concept, as well as the investigation and modelling of possible site conditions and the characterisation of the bedrock conditions. Based on the results, a suitable site for the spent fuel repository was selected in 2009.

In France, the search and development of a deep geological repository started in the 1980s with preliminary investigations including seismic and borehole surveys on several sites with different geological settings. After considering the results of these investigations and political compromises, a site in the eastern part of the Paris Basin was selected for further studies. The geology of the site is composed of a sedimentary pile down to 2000 m depth. The potential host rock is a clay-rich layer sequence known as the Callovo-Oxfordian formation.

In Germany, the process of a disposal site selection was resumed a few years ago and is ruled by the StandAG Repository Site Selection Act, a law enforced in 2017 stating that it should be a ‘participative, science-based, transparent, self-questioning and learning process’. A particular challenge and unique characteristic of the chosen procedure is the necessity to inter-compare sites with three different host rock types (rock salt, claystone and crystalline rock). Starting with a ‘blank map’ (comparable to the process in Switzerland), a first step includes the whole German federal territory and will then be progressively narrowed down. The process is basically implemented in the three steps — identification of sub-areas, surface exploration and underground exploration. During all these steps geophysical investigations will play pivotal roles.

In the Czech Republic, a deep geological repository will be constructed in a suitable crystalline rock mass. Nine potential sites were originally selected for consideration, all of which were subjected to detailed assessment via comprehensive geophysical and geological surveys.

While looking forward to the insights that will be shared during the workshop, we can already see that different countries

Aerial view of Chooz, France, one of the largest operational nuclear power plants in Europe.

are at various stages of searching for a solution in which crystalline rock, rock salt and clay rock are the favoured host rocks for the final storage of radioactive waste. National and international research programmes have been going on for decades. Tests to determine the integrities, water solidity and mechanical properties of different rock formations have been analysed. ‘In this context, geosciences and especially geophysics play a pivotal role to present measuring methods that enable mapping and characterisation of the geological structures with minor influence on the integrity of a possible storage site’, explains co-convenor Andreas Schuck (GGL). In addition to the respective suitability of any of the methods, the limits and uncertainties of the individual measurement methods

need to be investigated in relation to each national storage strategy.

Co-convenor Stefan Buske (TUBAF) adds: ‘One of the goals of our workshop is to exchange experiences with common and different strategies for the exploration of possible nuclear waste storage sites’. Representatives of important European players will present the strategies implemented in their countries and case histories, as well as procedures and possible collaborations in the framework of deep geological repositories for high-level nuclear waste.

We look forward to a rich discussion and to connecting with the wider EAGE community that can bring a contribution to this field. If you are interested, make sure to join the workshop on 9 June or write to communities@eage.org to learn how you can get involved.

Student possibilities at EAGE Annual 2024

The upcoming EAGE Annual 2024 will provide a range of educational, networking, and professional development opportunities for students and young professionals.

At the Laurie Dake Challenge final on Sunday 9 June six finalist university teams will present their findings to a distinguished panel of experts promising a showcase of talent and ingenuity.

For competitive students there’s also the opportunity to participate in the Global Geo Quiz on 11 June. Here they can test their geoscientific knowledge against peers from around the world. The Education Hunt, Exhibition Tour, and Students Dedicated Field Trip further enhance the learning experience, offering hands-on exploration and insights into the industry.

sessions such as the Networking Café and the Student Chapters The meeting will provide platforms for interaction and collaboration. Students can connect with industry representatives, explore job opportunities, and gain valuable insights into emerging trends and technologies.

For those looking to enhance their skills and career prospects, we recommend the interactive session on ‘Skills for the Energy Transition’ offering invaluable insights into the evolving landscape of energy transition and related career paths. Additionally, the CV Check sessions provide expert guidance on crafting impactful resumes that stand out in today’s competitive job market.

As preparations for the event continue, attending student participants are encouraged to register early to secure their spots. With a lineup of engaging activities, esteemed speakers, and networking oppor-

tunities, EAGE Annual 2024 promises to be a not-to-be-missed experience.

For registration and more details, visit the official EAGE Annual 2024 website. You can also write to students@eage.org for additional information.

Knowing the answer at the Geo Quiz in Vienna 2023.

Check out what mentoring could do for you

One of the biggest benefits of attending the EAGE Annual Conference & Exhibition is that you will get acquainted with other professionals from all over the world and all disciplines of geoscience and engineering. So why not take advantage of the opportunity to connect with other delegates at our Speed Mentoring, a career development opportunity in which you can seek guidance on the achievement of specific goals and skills, learn about different fields, and ask for advice on the most appropriate sessions to attend according to your professional interests.

Rafael Valadez Vergara, University of Miskolc, Hungary, explains how the programme helped him. ‘We exchanged experiences about our respec-

tive research projects and professional trajectories. It was highly enriching to share perspectives with someone going through similar challenges as me at this stage. Without a doubt, Speed Mentoring proved to be an excellent space to engage in open dialogue, establish valuable contacts, and gain confidence for networking — all dynamically and enjoyably. I’m grateful for this opportunity for mutual learning and professional development in a relaxed environment. A very positive experience that I highly recommend.’

You can sign up at eageannual.org, and meet with an assigned mentor/mentee at the EAGE Community Hub on Tuesday 11 June at 11:00 CEST.

Skills for energy transition

At the Annual’s ‘Interactive Session: Skills for the Energy Transition’, stu-

dents and young professionals interested in pursuing a career in energy transition-related fields may participate in a networking activity with representatives from companies, EAGE technical communities, and the Education Committee, to explore the requisite skills for successfully navigating a career in the evolving energy landscape and how they could fit into potential roles. Want to be

In parallel, the Committee of the EAGE Mentoring Programme 2024 will host a special Meet-Up that Marta Cyz, committee member, highlights as ‘an added value, providing a rare opportunity to expand your network, engage with mentors/mentees in person, and dispel any doubts about the programme’s significant benefits.’ Don’t miss it!

Iara Magali Rocha, geophysics student at Universidad Nacional de La Plata (Argentina), took advantage of this year’s Mentoring Programme and found it helped ‘to develop my personal brand, make decisions regarding my academic situation, learn about new tools, and more’. Similarly, Camila Castro, a recent BS in geology from the Universidad Nacional de San Agustín (Peru), says she received guidance on how to face the academia-industry transition: ‘My mentor allowed me to recognise that I need many other values to be competitive, such as the improvement of my networking skills.’

From a mentor’s point of view, Khouloud Jlaiel, researcher at the University of Miskolc, commented that ‘the opportunity to engage with each other has facilitated a rich exchange of knowledge and expertise. What’s more, the collaborative environment has paved the way to embark on various projects with my mentee.’

part of the conversation? Join us at the Energy Transition Theatre on Tuesday, 11 June at 16:00 CEST.

You can also help us to identify the skills necessary for the Energy Transition on the following survey.

Learn more

Connect with your peers to exchange career development advice, widen your perspectives, and attend the EAGE Annual in good company.

Plenty of interest at last year’s session in Vienna.

Kuala Lumpur conference to focus on digital transformation and analytics

EAGE’s latest Conference on Energy Excellence: Digital Twins and Predictive Analytics on 15-16 October 2024 in Kuala Lumpur, Malaysia promises an exploration of the evolving integration of digital twins, data science, and predictive analytics within the energy sector with a strong emphasis on sustainability and achieving carbon neutrality.

This conference is committed to enhancing operational efficiency, promoting interdisciplinary collaboration, and leveraging the power of data-driven strategies to not only advance technological innovations but also to drive the energy sector towards zero carbon goals.

The two-day technical programme will showcase new ideas, case studies, and research findings on the following themes: Digital twins for predictive maintenance resulting in cost efficiency and operation safety; Optimising field exploration, development, and management, resulting in higher extraction rates and increased profitability; Digital twins and predictive analytics for improving drilling operations; Digital twins for simu -

lating hazards and improving safety; Big data and digital architecture for enabling efficient and effective digital twins and predictive analytic; and Sustainability and environmental impact assessment and mitigation through digital twins and predictive analytics.

Industry professionals, technology innovators, and sustainability advocates are encouraged to participate and contribute to the discussions. Prospective contributors are encouraged to submit an abstract by 25 July 2024.

Learn more about the event and abstract submission information

Geophysical Prospecting (GP) publishes primary research on the science of geophysics as it applies to the exploration, evaluation and extraction of earth resources. Drawing heavily on contributions from researchers in the oil and mineral exploration industries, the journal has a very practical slant. A new edition (Volume 72, Issue 4) will be published in May. This is a Special Issue on ‘Seabed Prospecting Technology’.

Petroleum Geoscience (PG) publishes a balanced mix of articles covering exploration, exploitation, appraisal, development and enhancement of sub-surface hydrocarbon resources and carbon repositories. A new edition (Volume 30, Issue 2) will be published in May.

Vivid view of Kuala Lumpur.

Successful conclusion to first data processing workshop held in Cairo

EAGE’s inaugural data processing workshop was held earlier this year in Cairo, Egypt, on 26-28 February. This is the report.

The Technical Committee consciously chose Egypt as the hosting country for the inaugural workshop of this new series because of the opportunities the country offers in terms of business and the strategic location of its processing facilities providing services across all geophysical domains.

Over the three days, more than 70 local and international delegates enjoyed positive interaction during a programme of eight technical sessions with extensive presentations, poster papers, a number of open discussion sessions and a panel discussion involving the session chairs at the end of each day and all centred in the fine location of the Fairmont Hotel overlooking the iconic River Nile. Motivation for the event was sparked by the idea that there had been many workshops on specific elements of data processing but nothing bringing the whole science together.

Dr Abdel Hameed El Gewaily, vicechair, exploration & agreements, EGAS gave a stimulating introduction to the event, highlighting the level of exploration activity in Egypt and the substantial investment the government is making in the hydrocarbon industry. This was followed by a technical keynote given by distinguished academic, Prof Kees Wapenaar of Delft University of Technology summarising the work conducted

by the Delft team on data conditioning prior to FWI. Specifically, Prof Wapenaar described the work ongoing with the Marchenko multiple elimination method.

The workshop covered a comprehensive range of topics, starting from the fundamental principles of data acquisition in both land and marine environments to an exploration of the latest advancements and their implications for processing methodologies. Furthermore, it dived into innovative methodologies in seismic processing, along with effective strategies for data pre-processing and quality improvement.

The main programme kicked off with the provocative theme of ‘Pushing the boundaries of data processing’. The focus was the relationship between acquired data and model-building strategy. Efficient use of data and automation were strong themes throughout the presentations with one of the key takeaways being the understanding of technology improvements in acquisition and how they are linked to processing.

A return to this theme later in the programme had many heads scratching among the less academic of us, with a keynote and papers dealing with the mathematical building blocks of data manipulation in multiple domains.

Seismic data processing has evolved to accommodate various well-established

methods of acquiring geophysical field data. As novel and/or radically different acquisition patterns or engineering solutions are developed and introduced, the processing algorithms and workflows need to be modified to accommodate the changed forms or geometries of the data. In this context the discussion was enhanced by papers covering simultaneous sources, acoustic sensing, OBN nuances and a revisit to the old chestnut of marine vibrators which have been around in some shape or form for 50 years.

Turning attention to local imaging challenges there were examples from the Mediterranean and further afield demonstrating how acquisition and imaging technologies have harnessed the richness of azimuths, offsets and frequencies in tackling the local challenges such as the Messinian salt horizon. We were also reminded of the value that can be delivered from reprocessing vintage data with new technologies and also the importance of solving near surface complexity as a precursor to harnessing the serious imaging workhorses.

Aside from all the ‘glamorous innovations’, incremental advancement was a strong theme. Innovation, diligence and excellence combined with improvements in conventional workflows are providing enhanced results that also contribute to

More than 70 local and international delegates attended the inaugural EAGE Data Processing Workshop in the capital of Egypt.

‘Pushing the boundaries of data processing’. In this current climate it was also appropriate for the programme to turn its attention to AI/ML with clear evidence of improved project turnaround and data quality control. However, we were reminded that we humans are not redundant yet!

The final wrap-up open session pinpointed several positive outcomes. These spanned the opportunity provided by novel seismic acquisition technologies able to

eventually exploit the elastic domain utilising the astonishing computing power now available, to the advantages that new approaches will bring to seismic pre-processing steps. Bringing us all back to the point, we were reminded that Mother Earth is elastic.

The audience also noted the opportunity provided by the insights emerging from the proliferation of UHR seismic used in the prospecting for offshore wind farms which attracts geoscience data processing

players outside the traditional field of the seismic applications. Last but not least, a deep concern was expressed about the disaffection of students worldwide with regard to geoscience studies at university level.

There was resounding agreement among participants that the inaugural data processing workshop was a success, and that planning should begin on the second workshop with some interesting views on the next host location. Watch this space!

How our events will guide you through Caribbean and Latin American exploration developments

The First EAGE Conference and Exhibition on Energy Opportunities in the Caribbean is scheduled for 6-8 November 2024 at Port of Spain, Trinidad and Tobago. Set against the backdrop of azure waters and pristine beaches, the conference promises to be a melting pot of ideas and insights into the energy potential of the Caribbean region and how its vast untapped resources can be unlocked by sustainable development.

Following closely on the heels of the Caribbean conference will be the eagerly anticipated Second EAGE Guyana-Suriname Basin Conference, slated for September 2025. Building upon the success of its predecessor in 2022, the conference aims to delve deeper into the exploration potential of the Guyana-Suriname Basin, one of the most promising hydrocarbon provinces in the world. With recent discoveries propelling the region into the spotlight, industry stakeholders are eager to explore the untapped reserves lying beneath the basin’s pristine waters. The conference will feature technical sessions, workshops, and networking opportunities, providing attendees with valuable insights into the geology, reservoir characterisation, and

exploration strategies tailored to the unique challenges of the area.

Rounding off our exploration odyssey is the Second EAGE Conference on Offshore Energy Resources in the South Atlantic, scheduled for October 2025. Stretching from the coast of Brazil to the shores of West Africa, the South Atlantic region boasts immense offshore potential, with significant discoveries attracting global attention. This conference serves as a forum for industry experts to exchange knowledge, share best practices, and explore collaborative opportunities in harnessing the region’s offshore resources. From deepwater drilling technologies to renewable energy solutions, the conference will spotlight the diverse array of energy resources that lie beneath the South Atlantic’s vast expanse. By fostering dialogue and collaboration, the conference aims to accelerate the responsible development of offshore energy projects while safeguarding the region’s marine ecosystems.

Follow the EAGE website for latest event news in the Latin America region.

Explore with us the abundant offshore resources of the South Atlantic, promising energy prospects in the Caribbean, and the exciting exploration opportunities in the Guyana-Suriname region.

Cast your vote in our 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 essential as it is when you have a say in how our Association operates on your behalf.

Voting will be conducted online during May 2024, allowing you to cast your vote from anywhere. The results will be announced at the Annual General Members Meeting on Wednesday 12 June in Oslo.

To help you make informed decisions, detailed biographies and motivational statements from all candidates are available on the EAGE website. Take the time to review their credentials and visions for our Association.

Check your inbox for a personalised invitation with instructions on how to vote. Your input is invaluable in shaping the future of our community.

This year’s candidates for office Sanjeev Rajput –Vice-President Dr Sanjeev Rajput (general manager & global head-reservoir geoscience, PETRONAS Upstream) has for over two decades been an industry leader, a pioneer of the first digital oil field concept and a champion of carbon capture and storage.

Passionate about technological innovation and its role in shaping the future of energy, Dr Rajput is eager to leverage his extensive experience on the Board of EAGE. His vision is centred on harnessing innovative solutions to address the pressing challenges of the energy sector, promoting sustainability, and driving systemic change.

Dr Rajput says: ‘It is both a distinct privilege and a profound responsibility to be nominated as Vice-President of EAGE. My diverse experience in environmental protection and resource exploration has deeply influenced my appreciation for our community’s capabilities. I am eager to leverage this potential to address the urgent global issues of our era. Together, we can ensure that EAGE remains a leader

in innovation and a bastion of sustainable progress, dedicated to the monumental task of transitioning to a net-zero energy future.’

Martin Widmaier –Technical Programme Officer

Martin Widmaier is chief geophysicist for PGS Sales & Services with over 25 years of experience in addressing subsurface challenges with geophysical technology. Widmaier is an active member of EAGE and SEG and has been part of EAGE’s Technical Programme Committee for several years. He is also serving on the Local Advisory Committee for the EAGE Annual Conference 2024 in Oslo. In recent years, Widmaier has chaired/co-chaired programme committees for EAGE and SEG technology workshops both in Europe and Asia.

Widmaier says: ‘I will be committed to: 1) ensuring EAGE provides conferences with high-quality technical agendas that embrace the Association’s mission to promote the global development and application of geosciences and related engineering subjects; 2) facilitating technical agendas that foster cross-disciplinary learning and cooperation; 3) promoting innovation, technology advance and knowledge transfer that secures both affordable access to hydrocarbons, mitigation of carbon emissions, as well as the transition to energy solutions based on renewables; 4) providing ample opportunities for our young professionals to share their work and to grow their network on their career path and route towards a sustainable future; and 5) maintaining and enhancing collaboration and exchange between international geoscientific societies.’

Diego RovettaMembership and Cooperation Officer

Diego Rovetta is a team lead and senior research scientist developing multi-geophysics, data integration and joint inversion technologies

for Aramco since 2011. He is currently the high performance computing for reservoir technologies champion at the Aramco global research centre in Delft. He previously worked as a researcher for Politecnico di Milano, collaborating with different companies, including Eni, Saipem, SLB, Aresys, SolGeo, and as a geophysicist at the WesternGeco Centre of Excellence for electromagnetics.

Rovetta is author of several technical publications and patents on geoscience and engineering applications, and has received awards from different geophysical, engineering and O&G related organisations.

Rovetta is an active member of the EAGE, contributing to interest communities such as Geohazards. He founded the EAGE Local Chapter Netherlands in 2019. In five years (four under his presidency) the local chapter reached more than 200 members with more than 50 events organised. The chapter was awarded ‘Best Local Chapter Newcomer’ prize in 2021 and the ‘Best Local Chapter’ in 2023.

Rovetta says: ‘From this experience, I learnt how to use my skills to foster communications and cooperation among the local community, staying active also during challenging times, exploring new topics, encouraging team-building and engaging new members with the Association. I believe it is a natural step forward for me now to get more involved with EAGE at the Board level and I am eager to bring my experience and energy for the benefit of the members of the Association.’

Florina Tuluca –Vice-Chair, Near Surface Geoscience Circle

Dr Florina Tuluca is lecturer at the Faculty of Geology and Geophysics of the University of Bucharest. She is involved in studies and didactic and scientific research programmes that use geophysical methods for issues of infrastructure vulnerability, efficient management of municipal solid waste deposits, strategies for the protection of the geological environment

and ensuring sustainable development supported by non-destructive geophysical investigation and monitoring techniques.

Dr Tuluca plays an active role in the EAGE Near Surface Geoscience Circle and in our associated societies, e.g., president of the Romanian Society of Applied Geophysics (SGAR) and vice-president (previously president) of the Balkan Geophysical Society (BGS) She actively contributes to the development and implementation of activities that aim to promote the use of geophysical techniques in various fields to identify sustainable solutions regarding natural resources, the environment, resilience to earthquakes and other natural hazards that destabilise the geological environment.

Maren Kleemeyer –Continuing Education Officer

Maren Kleemeyer (learning adviser geophysics, Shell Global Solutions) has been an EAGE member for more than 30 years. Her engagement in the Association has evolved over time from conference presenter to contributions as technical reviewer, chairperson, mentor, and active member of the Education Committee for several years. Serving as the Education Officer for the past two years, Kleemeyer has contributed with her professional skills and experiences and her passion for learning. She has helped us to diversify our educational programme in terms of topics, instructors, and formats. As the industry moves through the energy transition, Kleemeyer has broadened the spectrum of our education portfolio, with new course offerings including new energies, energy storage, CO2 sequestration and storage, to name a few. She has also leveraged the expertise and insights from the EAGE Decarbonization and Energy Transition Technical Community ensuring that the combined knowledge is well reflected in our course offerings. In parallel, she has worked with other members in the Education Committee on initiatives to provide maximum flexibility to our learners and enhance the knowledge and skills of instructors when developing courses for the EAGE, such as the newly released How-to videos series on ‘How to teach a good course’.

EAGE introduces five new Technical Communities focused on energy transition

EAGE is taking another big step forward in reflecting the emerging energy transition landscape and how it impacts our professional membership. To meet the rapid evolution in relevant technologies, the EAGE Technical Community on Decarbonization and Energy Transition (DET) is dividing into five new communities covering all the main areas of current geoscience and engineering interest — Carbon Capture & Storage (CCS), Geothermal Energy, Wind Energy, Hydrogen and Energy Storage, and Critical Minerals.

Giovanni Sosio, Vice-chair of the Sustainable Energy Circle, explains the reasons for this transition. ‘When the DET Community was launched in 2019, it vowed to serve as a network for all members interested in sharing and receiving knowledge and experiences related to the application of the geosciences and engineering to the energy transition industries. Five years later, this transition has become real for many of us, as crucial to our career as the more traditional sectors where we have operated in more than 70 years of the Association’s life. The debate has grown outside of the technical questions, involving career choices, skill transfers, and the role of geoscientists and engineers for a more sustainable use of the Earth’s resources, and has been featured as a component in all of the EAGE’s publications and events.

The EAGE DET Community has upgraded itself into five new specialised groups: CCS, Hydrogen and Energy Storage, Geothermal Energy, Wind Energy and Critical Minerals.

For this reason, a new Sustainable Energy Circle was created by the EAGE to respond to the members’ needs. With its broad scope – and the support of the DET committee in shaping it – it has naturally taken over the role of representing the Association’s energy transition strategy. This allows us to spread the increasing technical interest in several, more focused communities, serving the desire to share knowledge in specific aspects, technologies and industries which are becoming more and more relevant in their own right.’

The new communities will serve as dynamic hubs where experts, professionals, and enthusiasts converge to share insights, exchange ideas, and drive innovation.

They also provide an opportunity for all professionals involved in energy transition technologies or businesses to contribute and make a difference. Step up and volunteer to be part of the new committees by expressing your interest to communities@eage.org.

The new technical communities will be formally introduced at the 85th EAGE Annual during the Dedicated Session ‘Decarbonisation and Energy Transition’ (Thursday, 13 June at 14:30 CEST).

Learn more and join the new communities

Students in Argentina on a mission

In Argentina, the EAGE Student Chapter of the Universidad Nacional de La Plata (UNLP) reports that it continues its mission to ease the transition of students into the professional workforce.

During the past year, our group of 15 geophysics and one geology student managed to foster soft skills and leadership skills through the organisation of four thematic talks. The meeting benefited our members and the general community of our faculty, FCAGLP creating a bridge between professionals and young professionals with students and promoting EAGE in the process.

In other highlights five of our members were involved in the Association’s mentoring programme interacting with professionals from around the world and benefiting from their counsel. Also last year for the first time a member of our chapter was selected to participate in an IPTC Student Programme, represent-

ing UNLP and EAGE. In February she managed to win third place in the SLB Challenge together with her team in February 2024. We see this as a way forward for other members in international programmes.

We are now looking forward to a number of projects that promise to further strengthen our mission. These include talks in collaboration with other EAGE chapters and associated organisations, company visits, the creation of a podcast and the organisation of specialised courses. These initiatives are designed not only to deepen understanding of geoscience but also to provide valuable professional development and networking opportunities.

We invite all students with a passion for geoscience and professionals in the field to join us on this journey. Together, we can build a future where the transition is inspiring and full of opportunities.

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!

EAGE UNLP Student Chapter in collaboration with SEG UNLP Student Chapter organised a talk about the first work experiences of a young professional and four students who were doing internships in the energy industry.

Gustavo J. Carstens presented his talk entitled ‘What did I do, what do I do, and what can I do as a geophysicist?’ in collaboration with EAGE UNLP Student Chapter and SEG UNLP Student Chapter.

Juan Alberto Tavella presented his talk on ‘The traces of anisotropy in seismic response’. The talk was given in collaboration with EAGE UNLP Student Chapter and SEG UNLP Student Chapter.

The student chapters of the SEG and EAGE organisations of the UNLP collaborated in the development of a series of talks on topics such as seismology on Mars (NASA project), seismic acquisition and processing, and the experience of Argentines doing PhDs in other countries.

Personal and career challenge of the desert Personal Record Interview

In his mid-thirties, Sean Siegfried is already CEO of Saudi Geophysical having previously worked mainly for a US wireless seismic company. His career journey started on seismic surveys in Argentina equipped with a business degree and fluent Portuguese and English becoming a party manager in Brazil aged 24. Ultra-marathon running in the desert has been a recent personal challenge.

Family background

I was born in Brazil during Western Geophysical glory days. Mother worked as a temp in the Rio office and father was working rotation as a crew supervisor. My parents relocated to Portugal where I spent my childhood. I vividly remember my father leaving with a suit and tie to work but coming back with an orange coverall after visits to Western vessels. That was fascinating to me.

Career choice

After a business degree in the UK, I applied unsuccessfully to various energy companies. Then my father connected me with Global Geophysical Services (GGS). The company was opening an office in Brazil and needed someone who spoke Portuguese and English. My first job was assistant party manager (PM) in Argentina until Brazil operations opened up where I started work as a PM shooting 2D regional seismic.

Party manager in Brazil

In seismic you need to learn on the job. I was surrounded by ex-Western Argentinean PMs who had no time for a young gringo. I worked hard and was selected to run Shell’s first wireless project in South America with full authority to set up my own crew. After that I was promoted to country manager of Brazil, running four crews and overseeing over 1000 people at the age of 24.

Learning on the job

Starting work with a company like GGS was an incredible foundation for my

career, especially at the very end of the Sercel cable era and the shift towards wireless. It was why I moved to Texas to help build Geophysical Technology (GTI) in its development of autonomous nodal seismic recording technology. It also opened the door to worldwide travel and meeting as many geophysical and oil companies as possible.

Break for MBA

I made a hard decision to leave GTI and focus on running two seismic crews in the US for Breckenridge while doing my MBA at Rice University. It was perfect timing as no one was buying equipment due to Covid and the low price of oil.

Saudi move

Abdulwahab Alahmari, owner and chairman of Saudi Geophysical (SG), reached out to me while I was at Rice. We knew each other as he would host me at MEO GEO every year and was a critical partner of our company in the region. Saudi Arabia was not really my scene, but after 10 months of negotiations, I cracked and accepted the challenge. He promised me a CEO role once I met the first year’s targets. We set aggressive objectives to triple the company’s revenue in less than three years; we did it in two. SG diversified its services, bought new technologies, created international partnerships and is now looking to grow into adjacent markets such as mining, infrastructure and beyond.

Working in the Middle East

It was a serious cultural shock at the beginning where I wanted to complete tasks quickly but was faced with so many bottlenecks. Internally we had to make various changes, especially in the work environment conditions. Externally, I had to understand the size of a client like Saudi Aramco. My expectation of executing quickly was dead on arrival and I had to adapt. However, it was a good change and made me realise things cannot always be the way you want.

Endurance sport

I guess I have always been up for a challenge. A few years ago after working on seismic crews and being on planes for so long I started to gain weight and felt incredibly unhealthy. I started to run in 2016. After completing my first marathon the following year alongside my Dad, I decided to push my body and try an Ironman triathlon, not just one but several, and ultra marathons. In 2023 I ran 220 km through the Jordanian desert. I am not sure what is next but I have this need to keep feeding this curiosity about taking body and mind to the absolute limit.

What lies ahead

I am a seismic addict, but soon to be a husband and father, so who knows what’s in store. For now I am committed to continuing a strong US and Saudi relationships as we deploy new technologies and conquer adjacent markets.

Sean Siegfried

CROSSTALK

BY ANDREW M c BARNET

BUSINESS • PEOPLE • TECHNOLOGY

Blame

it on oil

It’s hard to look away from the cruelty of war manifested today by ongoing hostilities in Ukraine and Gaza, and even more difficult to imagine how a peaceful resolution can come about (mercifully not in the remit of Crosstalk).

However, from the safety of afar, we can try to fathom what led to these and many other territorial conflicts in recent history. The explanation is never as simple as it looks. But one thing you can be sure of is that oil will somehow be implicated, sometimes along with other energy or mineral resources.

In essence provoking major international conflicts merely to seize oil resources is an overrated strategy.

‘Any turmoil in the Middle East cannot fail to have oil implications.’

The most cogent examples would be Iraq’s invasion of Kuwait in 1990 and the US-led international response and the 2003 US intervention under President George Bush ostensibly to oust the regime of President Sadam Hussein of Iraq. Both seem incontrovertibly about access to oil. In a widely quoted passage from his memoirs, Alan Greenspan, former chair of the Federal Reserve, wrote that ‘…the Iraq war (2003) is largely about oil’. In a more colourful confirmation, Chuck Hagel, US Secretary of Defense (2013-15) reportedly told a gathering of law students in 2007: ‘They talk about America’s national interest. What the hell do you think they’re talking about? We’re not there for figs.’

In her well received study The Oil Wars Myth: Petroleum and Causes of Interntional Conflict, Emily Meierding, assistant professor, Department of National Security Affairs at the Naval Postgraduate School in Monterey, California provides a nuanced corrective to these long-standing and largely unquestioned assumptions about ‘classic oil wars’. She argues that for almost a century (1912–2010), countries launched no major conflicts in order to grab petroleum resources. Many of the historical conflicts that are commonly identified as oil wars, including wars. Surprisingly she includes World War II as well as the, the Iran–Iraq War, Iraq’s invasion of Kuwait, and the Chaco War between Bolivia and Paraguay, as wars actually fought for other reasons. In addition she argues that the benefits of seizing foreign oil are far less than most people imagine.

In what may be something of a stretch, Meierding divides ‘classic oil wars’ into four types of militarised conflicts in oil-endowed territories: In the case of ‘red herrings’, states fight in areas with oil, but for other reasons, such as hegemonic aspirations, domestic politics, national pride, and contested territories’ other strategic and economic assets. She cites the Chaco war in 1932-35 between Bolivia and Paraguay and Iran–Iraq wars as examples, to which Afghanistan could be added with minerals as the hidden resource asset. In their occupations of Afghanistan both Russia and the US had over-riding strategic objectives, but the country happens to have immense mineral wealth still to be effectively exploited. In ‘oil spats’ and ‘oil campaigns’, states are motivated by oil ambitions. ‘Oil spats’ such as the Falklands conflict between Argentina and UK are said to be minor confrontations whilst ‘oil campaigns’ occur in the midst of ongoing international wars started for other reasons. In the oil ‘gambit’, exemplified by Iraq’s march on Kuwait, the aggressor targets foreign oil in order to achieve a broader, political aim.

If classic oil wars never actually occur, Meierding asks why is the belief in these conflicts so widespread? She believes that classic oil wars exist at the intersection of two dominant narratives about the causes of violent conflict: the ‘Mad Max Myth,’ which claims that people fight because of resource scarcity and existential need, and the ‘El Dorado Myth,’ which claims that people fight because of greed. Each of these narratives has persisted for centuries, she writes, and because of them we believe in them and in classic oil wars.

You can find a less complicated, but not entirely contrarian view from the likes of Michael T. Klare, five-college professor emeritus of peace and world security studies at US liberal-arts Hampshire College and a senior visiting fellow at the Arms Control Association.

Writing well before the latest hostilities erupted in Gaza, Klare has claimed that at first glance upheavals in regions such as Iraq, Syria, Nigeria, South Sudan, Ukraine, the East and South China Seas appear to be independent events, driven by their own unique and idiosyncratic circumstances. ‘But look more closely and they share several key characteristics, he says, ‘notably, a witch’s brew of ethnic, religious, and national antagonisms that have been stirred to the boiling point by a fixation on energy’.

In Iraq and Syria, it is a clash among Sunnis, Shiites, Kurds, Turkmen, and others; in Nigeria, among Muslims, Christians, and assorted tribal groupings; in South Sudan, between the Dinka and Nuer; in Ukraine, between Ukrainian loyalists and Russian-speakers aligned with Moscow; in the East and South China Sea, among the Chinese, Japanese, Vietnamese, Filipinos, and others. Klare states: ‘It would be easy to attribute all this to age-old hatreds, as suggested by many analysts; but while such hostilities do help drive these conflicts, they are fuelled by a most modern impulse as well: the desire to control valuable oil and natural gas assets. Make no mistake about it, these are 21-century energy wars.’

($30 billion) and 16% of natural gas fields/wells ($12 billion and $3.5 billion for associated gas concentrate). As of July 2022, Ukraine had also lost control over a significant array of rare earth and precious metal deposits.

SecDev concludes that Russia has several motives to invade Ukraine, some of which are clearly economic. Denying Ukraine mining and oil revenue are certainly Russian priorities since this effectively degrades their military capacity. But also Russia clearly understands the geopolitical and economic advantages of controlling some of the world’s richest mineral, coal, and oil and gas deposits. Even if Russia were to do nothing and sit on Ukraine’s mineral resources and infrastructure, it benefits by controlling supplies and rising prices.

‘These are twenty-first-century energy wars.’

One curious anomaly, not part of SecDev’s brief, is that throughout the war so far a fiveyear pipeline transit agreement between Moscow and Kyiv, means Russia exports gas to Europe via Ukraine and pays Ukraine for the use of its pipeline network. The arrangement is unlikely to be renewed when it expires at the end of this year.

Put these theories to the test in the context of Ukraine’s war with Russia and the strife in Gaza and you can arrive with some surprising observations.

SecDev, a Canadian global digital risk and resilience company, started mapping critical minerals and rare earths (as well as agriculture and oil and gas) in Ukraine just before Russia invaded in February 2022. The analysts were not convinced that perceived Russian grievances over NATO expansion, disputes over pipelines, or revisionist interpretations of Russia’s territorial reach were sufficient motivation for the impending attack. Before much of the open source access to the data was shut down, SecDev had assembled a Ukrainian and Russian language dataset on critical minerals and rare earths in Ukraine, subsequently demarcating areas occupied by Russia in 2021 and at various stages of 2022.

Notwithstanding a declining coal sector, Ukraine is a mining super power ranking in the top 10 globally in terms of stores of iron, manganese, titanium, graphite, and uranium as well as having some of the largest coal and oil and gas reserves in the world (63% of the coal in the Donets basin, eastern Ukraine under Russian control). The Russian invasion significantly disrupted mining operations which had reached historic levels in 2021. For example, coal production collapsed by over 50% in 2022 compared to the previous year, iron ore exports declined by 44% .

The total estimated value of the coal reserves occupied by Russia in current prices is approximately $12 trillion. SecDev estimates that Russian-occupied areas contain as much as 27% of the country’s iron ore deposits (15% of total explored reserves), 50% of manganese ore deposits (99% of total explored reserves) and 10% of titanium ore deposits as of July 2022. Ukraine also appears to have lost as much as 11% of its oil fields/wells

Meanwhile any turmoil in the Middle East cannot fail to have oil implications since it is the lifeblood of the region, and that indeed turns out to be the case as far as Israel’s campaign in Gaza is concerned. Mainly offshore gas rather than oil is the issue. Most obviously the international oil industry and Israel’s neighbours must be nervous about any escalation that might disrupt the growing interest in exploiting the wealth of prospects in the Eastern Mediterranean basin particularly to serve the European market.

So far everything seems to be in course. For example, Eni (operator) and Total Energies announced in February a full evaluation of the development potential of the Cronos gas discovery, offshore Cyprus, and Chevron okayed a $24 million investment to complete a final phase development of the Tamar field offshore Israel. There is also no sign yet of any breakdown in operations offshore Lebanon where a third round of licensing is due to conclude in July. A US brokered deal between Israel and Lebanon in 2022 enabled TotalEnergies to drill a well in Block 9 last year that proved dry.

The more contentious and toxic issue is the future of the suspected oil and gas reserves offshore Gaza and to whom the benefits would accrue should they ever become subject of development. Much has been made of a seemingly respectable 2020 report from the UN Conference on Trade and Development provocatively entitled The Economic Costs of the Israeli Occupation for the Palestinian People: The Impoverishment of Gaza under Blockade. Purportedly the report ‘…seeks to stimulate debate on the research topic’. One recommendation to put the territory on track to sustainable development includes ‘utilising the valuable oil and natural gas resources off the shore of Gaza’.

Reluctantly one must conclude that where there’s war, there’s almost certainly oil somewhere in the mix.

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

INDUSTRY NEWS

UK publishes carbon capture injection guidance

The UK North Sea Transition Authority (NSTA) has published two sets of key guidance which will help the developing carbon storage industry prepare for first injection.

The Guidance for Measurement of Carborn Dioxide for Carbon Storage Permit Applications provides licensees with information on NSTA expectations regarding the proper measurement of CO2 being injected in a storage site and suggestions on how that can be achieved.

‘It is important that injection flow rates are accurately determined, as this information is used in modelling the behaviour of the CO2 in the reservoir,’ said the NSTA. ‘In addition to the overall volume being injected, the exact composition of the gas is also measured. This ensures that the correct payment is made under the Carbon Trading Scheme.’

NSTA has also published Requirements for the Definition of a carbon storage site, storage complex and hydraulic unit to provide clarity on determining the extent of subsurface storage site and focus for licensees on the area they must manage to prevent/detect leakage.

The guidance advises licensees of the requirement to provide precise definitions of the spaces in which carbon dioxide will be stored and the surrounding areas that it must be contained within.

‘This precise definition is required so that any deviations from the expected CO2 movement and containment are clearly identifiable so that preventative or remedial action can be taken,’ said the NSTA in a statement. ‘The NSTA does not instruct independent businesses on how they should operate, but planned monitoring for such events is a requirement for each carbon storage application.’

The two sets of guidance will help the licensees of the Track 1 clusters at Hynet and Northern Endurance, and Track 2 at Acorn and Viking, which are the most far advanced projects in the UK, as well as new licensees.

In the past year the NSTA has awarded 21 licences after running the UK’s first-ever carbon storage licensing round; established a dedicated NSTA carbon storage development team to work with operators in the growing sector; and made significant progress on the Track 1 and 2 projects on permit applications with decisions on 4 Track 1 applications expected to be taken in 2024; a consultation to determine what carbon storage data should be shared and to what timescales is also underway and will assist the development of future sites.

The UK government last year set out its vision for the carbon storage industry pledging up to £20 billion investment and suggesting that it has the potential to store the carbon equivalent of taking 6 million cars off the road, and support 50,000 jobs, by 2050.

EMGS reactivates its Atlantic Guardian vessel

EMGS took the vessel Atlantic Guardian out of warm stack on 19 February 2024 and began mobilisation for a fully prefunded multi-client survey in the North Sea.

The company’s vessel utilisation for the first quarter was 27% compared with 0% for the first quarter 2023. EMGS

had one vessel in operation and recorded three vessel months in the quarter.

The company had earlier recorded fourth quarter revenues of $1.1 million, down from $15.2 million in Q4 of 2022 and $1.6 million in the third quarter of 2023. EBITA was a loss of $1.7 million, down from a profit of $8.2 million in Q4 2022.

Shearwater wins Norwegian Sea 4D surveys

PGS releases offshore Egypt data

Seagreen shoots wind survey offshore Scotland

Atlantic Guardian vessel.

Global wind auctions to offer 33 GW this year

TGS’ latest Market Overview Report on the global offshore wind industry for the rest of 2024 has presented a mixed picture after last year’s report anticipated a record-breaking auction year for the sector.

The offtake auction schedule continues to reflect a healthy outlook after more activity last year, said TGS. Notably, 32.9 GW of capacity is set to be included in offtake auctions globally in 2024, with Europe accounting for 24.5 GW of this figure.

In 2023 the global offshore wind sector fully commissioned 7 GW, and this has been followed by 592 MW in Q1 2024. This includes Vattenfall’s 344 MW Vesterhav Nord/Syd, the first commercial-scale project in the USA (Ørsted’s 132 MW South Fork), the 112 MW Ishikari Bay New Port project in Japan and China’s 4 MW Longyuan Nanri Island floater.

Additionally, the report predicted that in 2024 there will be a surge in corporate power purchase agreements (PPAs). Nearly 1

GW of offshore wind capacity has already been transacted through long-term contracts, and corporate demand for PPAs is expected to remain robust.

In the first quarter Germany launched tenders for 8 GW of capacity, albeit facing grid delays that pose challenges to the 2030 pipeline. In the UK, discussions continue around the application of reference prices in Allocation Round Six (AR6) and in Norway the Ventyr consortium of Parkwind and Ingka Investments won the Sørlige Nordsjø II lease area.

Meanwhile, the United States’ first commercial-scale project in federal waters, and East Coast states secured record amounts of new and rebid capacity, with New York and New Jersey taking steps to address setbacks from offtake withdrawals last year. In Asia Pacific, India initiated its first offshore wind tender in Tamil Nadu after years of delays, while Taiwan reviewed its environmental impact assessment process.

However, the report also notes that this is the first Q1 since 2017 that no investment decisions have been made, although imminent announcements are expected.

Richard Aukland, director of research at TGS - 4C Offshore, said, ‘We observe a resilient industry with a significant long-term pipeline, with some markets, for example the US, reclaiming lost ground. However, the UK’s pipeline risks further delays unless adjustments are made to this year’s auction parameters. Global political ambition remains strong and steady, now exceeding 758 GW, with approximately half of this capacity targeted in Europe.’

Despite a slight downward adjustment in TGS’s 2030 forecast, which now stands at 261 GW under construction or operational, there is a notable increase in the longer-term prediction to 2040, reaching 563 GW. While this adjustment reflects some delays and shifts in project timelines, it underscores the industry’s strong ambition and commitment to growth.

Shearwater wins 4D surveys in the Norwegian Sea

Shearwater GeoServices has won two 4D monitoring projects for Equinor in the Mariner field in the UK North Sea and the Heidrun field in the Norwegian Sea.

Shearwater will deploy its Isometrix technology for both surveys, applying 4D seismic monitoring to detect reservoir dynamics over time, for optimising reservoir management and enhancing production efficiency.

This will be the fourth Isometrix deployment for Mariner, complementing previous monitor surveys in 2020 and 2022, and the third for Heidrun, after surveys in 2018 and 2021.

The surveys are expected to take two months and will be carried out by the vessel SW Amundsen and an undershoot vessel.

‘These projects underscore our shared ambition for pioneering and repeating production monitoring solutions, and we look forward to once more supporting Equinor in navigating towards the efficient optimisation of resources. Our dedication to providing top-tier seismic technology and expertise will provide Equinor with the insights needed to continue delivering long-term, sustainable value creation from the Mariner and Heidrun fields,’ said Irene Waage Basili, CEO of Shearwater.

SW Amundsen vessel.

Some 261 GW will be built or will be built by 2030.

PGS releases offshore Egypt data

PGS’s early-out data is now available for the EGY23 Merneith and Luxor multi-client program offshore Egypt. This provides the first 3D seismic data over the deepwater area between the Nile delta and the Herodotus Basin.

In partnership with the Egyptian Natural Gas Holding Company (EGAS), PGS has worked on the 6175 km2 EGY23 Merneith and Luxor survey to provide the first 3D seismic data available over an underexplored and unlicensed deepwater area that was previously only covered by 2D seismic data.

A Messinian evaporite layer of variable thickness extends across most of the area. The survey is tied to the Kiwi-1 well, one of the few wells in this deepwater area, and primary targets are likely to be presalt Oligo-Miocene structures with clastic reservoirs.

Meanwhile, PGS has won a large 3D contract offshore South Atlantic margin from a multi-client company. A Ramform Titan-class vessel is scheduled to mobilise in June, with a forecast acquisition duration of up to 300 days.

‘Seismic activity offshore South Atlantic margin is increasing as a result of recent exploration success. The award extends visibility for one of our Ramform Titan-class vessels well into 2025,’ said PGS Rune Olav Pedersen, president and CEO.

Finally, PGS has won a 4D contract in Northern Europe. The vessel Ramform Tethys is scheduled to mobilise for the survey in late April and the project has a total duration of approximately 30 days. ‘The contract award marks the start of the Northern Europe summer season for the Ramform Tethys, said Pedersen.

Zanzibar launches first licensing round

Zanzibar has launched its 1st Licensing Round, which invites bids for eight blocks totalling 31,883 km2

The blocks, situated offshore to the east of the Unguja and Pemba Islands within water depths between 500 m and 3000 m, represent a large frontier area and form part of a five-year exploration road map, said the government’s energy ministry. The blocks offered under the 1st Licensing Round include Block 1-A, Block 1-B, Block 1-C, Block 1-D, Block 1-E, Block 1-F, Block 1-G, and Block 1-H.

Bid submissions are due on September 16, 2024. Awards will be announced on 17 November, 2024.

The Ministry of Blue Economy and Fisheries has defined the bid round areas

through prospectivity assessment with ‘encouraging results’ with exclusive data supplier, SLB. A total of 10,145 linear km of 2D seismic data is available pertaining to the blocks.

President of Zanzibar Dr Hussein Ali Mwinyi said: ‘Strategically located, and benefiting from political, social and economic stability, Zanzibar aims to build a resilient economy for the benefit of its people through the sustainable development of its offshore petroleum resources. That strong political will to drive investment is coupled with renewed fiscal terms to enhance the investor environment in the oil and gas sector, including the constitutional protection of private investments.’

Ramform Tethys vessel.

Sulmara performs geophysical CCS survey in Texas

Subsea geodata specialist Sulmara has helped Bayou Bend CCS generate data from a towed-streamer uncrewed surface vessel (USV) during a high-resolution geophysical survey at the Bayou Bend carbon capture and storage project in Texas.

Bayou Bend CCS commissioned Sulmara to conduct an archaeological and geohazard assessment of the proposed Bayou Bend CCS pipeline route from the landfall to the future offshore platform locations.

Sulmara utilised an electric WAM-V 16 USV for the offshore data acquisition to help significantly lower the overall carbon footprint of the project by reducing the number of diesel-burning vessels offshore, as well as shortening the time required to conduct the survey.

Sulmara project manager Darius Rivera said: ‘The quality of the data gathered is some of the best we’ve seen from a USV. The quality of information, as well as the operability of the equipment and relation-

ship that has been developed, has been key to the project’s success.’

The project utilised the SpaceXbacked Starlink satellite system to ensure strong communications between the shore and the USV.

Rivera added: ‘With the survey area around 15 km from shore, we integrated the WAM-V with Starlink to achieve higher speed communications with the mobile remote command centre. This is the first time we have been able to go beyond the 3 km mark with this size USV, ensuring improved quality of data and reducing the time needed to collect the information when compared to a conventional survey vessel.’

RockWave wins contract for subsurface data reprocessing in Poland

RockWave has won a seismic reprocessing contract from Equinor and Polenergia at their offshore wind development area, the ‘Bałtyk 1 Wind Farm’ in the Polish Baltic Sea.

The company will reprocess sparker ultra-high resolution seismic (UHRS)

data to create an optimised subsurface image.

The new data will help to upgrade the engineering ground model and WTG (Wind Turbine Generator) foundation designs for the Bałtyk 1 Wind Farm. RockWave aims to help its clients minimise

the risk of unforeseen ground conditions by enhancing the accuracy and reliability of data in the offshore wind development project.

The Bałtyk 1 Wind Farm is located approximately 80 km north of the Polish coast in the Baltic Sea.

TDI-Brooks completes site investigations for US offshore wind farms

TDI-Brooks has completed an extensive site investigation in two offshore wind blocks in US state and federal waters.

It surveyed in excess of 20,000 line-km of analogue and either single or multi-channel seismic data in lease blocks and cable routes along the coasts of New York and New Jersey. The programme included offshore geophysical surveys, UHRS detailed surveys, archaeological identification surveys, light geotechnical coring, and benthic sampling.

TDI-Brooks utilised the R/V Brooks McCall, R/V Miss Emma McCall, and M/V Marcelle Bordelon survey vessels. The geotechnical survey involved more than 150 pneumatic vibracores (pVCs) and more than 150 Neptune 5K cone penetration tests (CPTs) gathered from both lease areas and along the offshore cable route (OCR). Along with multiple export cable route surveys, it conducted a reconnaissance survey covering the entirety of the lease area with 150-m spaced survey lines, followed by a more detailed archaeological survey with 30-m

spaced lines. It also utilised survey sensors including dual head multibeam sonar, side-scan sonar, sub-bottom profiler, UHRS seismic, single-channel seismic, and Transverse Gradiometer (TVG).

The goals were to assess the conditions of the seabed and sub-seabed, which may include potential risks (geohazards or man-made hazards) that could impact the installation of wind turbines and subsea cables in the future. The investigations conducted involved measuring variations in water depth and slope changes, examining the morphology (composition of the seabed and lithology in the formations below in relation to local geology), identifying any natural or man-made obstructions on or below the seabed, such as rock outcrops, channels, depressions, gaseous fluid features, debris (natural or manmade), wrecks, industrial structures, cables and assessing any shallow geohazards that could affect the sites and future deep geotechnical soil studies within the top 100 m beneath the seabed.

Sulmara used an electric WAM-V 16 uncrewed surface vessel (USV) for the survey. Credit: Sulmara.

TGS, PGS and SLB shoot 3D survey offshore Malaysia

TGS, PGS and SLB have launched a multi-client 3D seismic project in the Penyu Basin, offshore Peninsular Malaysia.

In partnership with Malaysia Petroleum Management (MPM), Petronas aims to provide insights on the exploration opportunities in a broader play

fairway and to assess the carbon storage potential across Penyu Basin area. The acquisition of seismic data will enable clients to effectively conduct evaluation on the exploration and carbon storage potential for the upcoming Malaysia Bid Round.

The Ramform Sovereign vessel was mobilised to the acquisition area in early March 2024 and the area coverage is approximately 7800 km2. Acquisition completion is anticipated in July 2024, and processing completion is projected for June 2025.

Kristian Johansen, TGS CEO, said: ‘The Penyu Basin is one of Southeast Asia’s most exciting yet underexplored frontier exploration hotspots, with the potential of uncovering new exploration plays and CCS opportunities. We are pleased to spearhead exploration in this region through a Geostreamer multi-client 3D acquisition. We continue to increase our footprint across Malaysia as it develops into a key part of our multi-client seismic data library.’

Rune Olav Pedersen, PGS president and CEO said: ‘The survey marks a change in how clients use newly acquired multi-client seismic data. In addition to the traditional oil and gas exploration activities, the data will be used to facilitate assessment of carbon capture and storage (CCS) potential. By acquiring multi-client seismic data with our Ramform vessels and GeoStreamer technology we will provide high quality regional scale seismic data that will improve regional understanding of the subsurface.’

Sercel sells 528 system to Turkish client

Sercel has announced the first major sale of its next-generation 528 cable-based land acquisition system to the Turkish Petroleum International Corporation (TPIC) for deployment in Turkey..

The client will deploy the system, representing a total of 8000 channels, on a 3D seismic survey in Turkey across challenging, semi-arid terrain. Delivery of the system commenced at the end of March, with the survey expected to start in Q3 2024.

The sale follows the recent launch of Sercel’s 528 and VE564 land seismic

solutions, which it claims reduce downtime and boost productivity even in the harshest of terrains.

Jérôme Denigot, Sercel CEO, said: ‘The 528 is the most advanced cablebased system available today, boasting the lightest weight and the lowest power consumption. With its scalable architecture, the system offers maximum flexibility to adapt to different-sized projects, whether mega-crew surveys or smaller projects, with the same efficiency.’

Ramform Sovereign vessel.

Picture: Harald M. Valderhaug.

ENERGY TRANSITION BRIEFS

Chevron is investing in ION Clean Energy that provides post-combustion pointsource capture technology through its third-generation ICE-31 liquid amine system. The capital raised will fund ION’s deployment of its ICE-31 liquid amine carbon capture technology for hard-to-abate emissions. Chevron wants to use ION’s ICE-31 technology to service customers with high volume and low concentration CO2 emissions.

The US Interior Department has approved more than 10 GW of offshore wind after approving the New England Wind offshore wind project.

Petronas has signed an agreement with JERA to evaluate the feasibility of the entire carbon capture and storage (CCS) value chain including separation and capture of CO2 emitted by JERA in Japan, cross-border transportation, and CO2 storage in Malaysia.

Ventyr, a consortium of Parkwind and Ingka Investments has successfully bid for for the Sørlige Nordsjø II phase 1 development in the Southern Norwegian North Sea. The first turbines of the 1.5GW wind farm are expected to be operational by 2030.

TotalEnergies is acquiring 100% of Talos Low Carbon Solutions (TLCS), an American company focused on carbon capture and storage. TotalEnergies will own a 25% share in the Bayou Bend project, alongside Chevron (50%, operator) and Equinor (25%). The Bayou Bend project is a major CO2 storage project along the Texas Gulf Coast. The Bayou Bend project is a carbon transportation and storage solution for industrial emitters. Comprising licenses dedicated to CO2 storage, offshore and onshore, covering about 600 km2, it could enable the storage of several hundred million tons of CO2.

The Angel CCS Joint Venture will collaborate with Yara Pilbara Fertilisers to study the feasibility of using carbon capture and storage to decarbonise Yara Pilbara’s existing operations near Karratha in Western Australia.

PGS to report increase in first quarter revenues

PGS expects to report IFRS revenues for Q1 2024 of $217 million, compared to $143.1 million in Q1 2023. The company expects produced revenues for Q1 2024 of $223 million, compared to $172.2 million in Q1 2023.

Contract revenues are expected to be $116 million in Q1 2024, compared to $94.1 million in Q1 2023. Multi-client late sales revenues are expected to be $56 million in Q1 2024, compared to $25.6 million in Q1 2023.

Estimated produced multi-client pre-funding revenues in Q1 2024 are expected to be $46 million, compared to $45.5 million in Q1 2023. Multi-client pre-funding revenues based on IFRS are expected to be $41 million in Q1 2024, compared to $16.4 million in Q1 2023.

PGS president and CEO Rune Olav Pedersen, said: ‘I am very pleased to see a good start for multi-client late sales in 2024, with progress in Q1 and a strong basket of active transactions leading into Q2. Our multi-client acquisition activity

was mainly in South America and the Mediterranean in the quarter, and we had a pre-funding level of approx. 100% of the capitalised cash investment.

‘We used 44% of available vessel capacity for contract work,’ he added. ‘Contract activity was slow over the winter season. However, revenue generation for our active vessels in Q1 was strong. Entering the summer season, bidding activity and visibility are increasing. Our offshore wind site characterisation contributed with $13 million of the Q1 contract revenues. The opportunity basket for more offshore wind site characterisation work is encouraging.’

TGS expects Q1 revenues of $152 million

TGS expects IFRS revenues for Q1 2024 of $152 million, compared to $173 million in Q1 2023.

POC revenues are expected to be $227 million, compared to $229 million in Q1 2023.

POC multi-client revenues are estimated at $150 million versus $143 million in Q1 2023, with early sales of $78 million, down from $98 million in Q1 2023, and late sales of $72 million, up from $46 million in Q1 2023. Multi-client investments are expected to be $67 million, compared to $133 million in Q1 2023.

Proprietary revenues are expected to be $77 million versus $86 million in Q1 2023.

Kristian Johansen, CEO of TGS, said: ‘We are pleased to see that late sales of completed multi-client data in Q1 2024

showed good progress compared to the both preceding quarter and the same quarter of last year. Further, we saw strong sales of surveys in the work-in-progress phase, supporting the early sales rate of 116% in the quarter.

‘We continue to show good operating performance in our OBN business, although the activity level, as expected, remained seasonally low in Q1 2024,’ he added. ‘The strong start to the year, combined with a continued tight global oil market and increasing exploration ambitions among our customers makes me optimistic for the remainder of the year. With the PGS merger, which is expected to close in the latter part of Q2 2024, TGS will be perfectly positioned to support our customers exploration ambitions and capitalise on what we think will be a multi-year upcycle.’

PGS Rune Olav Pedersen, president and CEO.

Shearwater raises $700 million for refinancing

Shearwater Geoservices has refinanced its long-term secured debt after raising $700 million.

The company issued a five-year $300 million senior secured first lien bond and executed a new $300 million five-year bank term loan with net proceeds used to repay previous secured debt facilities. Shearwater has also established a $50 million revolving credit facility (RCF) and a $50 million guarantee facility.

‘Shearwater has established a strong foundation for growth and value creation as a global leader within the marine seismic industry. We are positioned to generate significant free cash flow in coming years to the benefit of our shareholders. This is supported by substantial operational leverage as we control

the worldwide swing capacity combined with limited capex requirements and low leverage,’ said Andreas Hveding Aubert, CFO of Shearwater.

The term loan was provided by DNB Bank, Sparebank, Export Finance Norway and Sparebanken Møre. The term loan has a scheduled annual amortisation of $50 million and was priced at SOFR +4.10%.

The senior secured bond issue was substantially oversubscribed and priced at a fixed rate of 9.5%. The bonds will be listed on the Oslo Stock Exchange in the second half of 2024. DNB Markets acted as global coordinator and joint bookrunner for the bond issue with Pareto Securities, SpareBank 1 Markets and Carnegie.

CGG appoints sensing and monitoring leader

CGG has appointed Jérôme Denigot as executive vice-president, sensing and monitoring. Denigot will lead CGG’s global Sensing and Monitoring business line (SMO), marketed under the Sercel brand name.

Denigot joined CGG in 2003, holding various positions of increasing responsibility in SMO. In 2017 he was appointed executive vice-president, human resources for CGG. He graduated with a master’s

degree in corporate finance from Université Paris Dauphine-PSL and holds an executive MBA in business administration and management from Audencia Business School.

Meanwhile, CGG has started a worldwide natural hydrogen screening project. Chris Page, VP, Geoscience, CGG, said: ‘This natural hydrogen screening project builds on our track record of developing valuable global resource screening studies for geothermal energy, critical mineral

exploration and carbon and energy storage, combining our geoscience, data science and technology expertise.’

Finally, S&P Global Ratings has upgraded CGG’s credit rating to B- from CCC+ after noting the company’s ‘markedly stronger 2024-2025 financial performance’. ‘We believe that S&P’s rating upgrade aligns with our recently communicated financial roadmap’, said CGG CFO, Jérôme Serve

US launches second Gulf of Mexcio wind energy auction

The US Department of the Interior has announced a second offshore wind energy auction in the Gulf of Mexico. The proposed lease sale includes four areas offshore Louisiana and Texas, totalling 410,060 acres, which have the potential to power 1.2 million homes.

Since the start of the Biden-Harris administration, the Department has

approved the nation’s first six commercial scale offshore wind projects, held four offshore wind lease auctions – including a record-breaking sale offshore New York and the first-ever sales offshore the Pacific and Gulf Coasts, initiated environmental review of 12 offshore wind projects, and advanced the process to access and establish additional Wind Energy Areas in Oregon, Gulf of Maine and the Central Atlantic.

BOEM is seeking feedback on various aspects of the proposed lease areas, including size, orientation, and location of the four lease areas and which areas, if any, should be prioritised for inclusion or exclusion from this lease sale. BOEM is also seeking comment on potential lease revisions to include the production of

hydrogen or other energy products using wind turbine generators on the lease.

It is proposing to conduct simultaneous auctions for each of the four lease areas using multiple-factor bidding. BOEM will use new auction software for enhanced efficiency, with minor adjustments to auction rules used in previous offshore wind lease auctions.

Meanwhile, the US Bureau of Ocean Energy Management (BOEM) has published details of its proposed Gulf of Mexico Oil and Gas Lease Sales 262, 263, and 264. On Dec. 14, 2023, the Interior Department announced the 2024–2029 National Outer Continental Shelf Oil and Gas Leasing Program (National OCS Program) The first proposed sale under that program, Lease Sale 262, is scheduled for 2025.

TGS appoints WesternGeco veteran as imaging leader

TGS has appointed Wadii El Karkourias EVP of imaging and technology. Wadii will lead a combined, global imaging and technology business unit that will include Imaging (marine and land imaging, proprietary software sales, R&D) and data analytics (AI, software development, and data management).

Wadii has more 25 years experience in the energy and technology industries with SLB and Amazon Web Services. He has served in a range of leadership roles in the US, Africa, Asia, Europe and the Middle East, including leading SLB’s Geosolutions business as global vice-president WesternGeco Geosolutions, overseeing the sales and commercial aspects for SLB’s seismic product line as global vice-president WesternGeco sales and commercial, and managing executive relationships with global energy companies at AWS as a global sales director AWS Energy and Utilities.

Kristian Johansen, CEO of TGS, said, ‘We are eager to apply his expertise in digital along with his global seismic experience to lead our new, combined imaging and technology organisation and ensure TGS provides high-quality imaging and innovative, technology-based data solutions and intelligence to our clients.’

Seagreen completes geotechnical survey for windfarm offshore Scotland

Seagreen has completed the first geotechnical seabed survey for the proposed second phase to Scotland’s largest offshore wind farm.

The surveys, which were carried out off the Angus coast, examined conditions, ahead of up to 36 new turbines being added to the 114 already fully operational.

In the world’s deepest fixed-bottom offshore wind farm, with the deepest foundation installed at 58.6 m below sea level, the phase 2 project is known as Seagreen 1A.

Andrew Train, project director for Seagreen 1A, said: ‘The geotechnical works will enhance and broaden our understanding of the seabed conditions across the full project site.’

The vessel that carried out site investigation works, the 90m-long Connector, completed phase one works in 10 days during February.

This involved specialist cone penetrometer testing (CPT) at almost 100 locations.

Using dynamic positioning (DP) technology the vessel repeatedly held positions while thin rod sensors penetrated into the seabed at depths of up to 15 m to allow the team to learn more about the seabed composition and understand if the proposed turbine foundation locations are suitable for the technology proposed.

Proposals for the Seagreen 1A turbine foundations include using innovative and similar three-legged suction caisson

technology which allowed the original Seagreen project team to push boundaries and set new records.

The suction caisson technology allows the turbine foundation to fix securely to the seabed, penetrating to a depth of up to 11 m under the seabed.

Phase two of the geotechnical works is expected to commence later this year and should take around two weeks to complete. The second phase will involve Vibrocore (VC) works along the proposed export cable route from the offshore site to the landfall at Cockenzie.

Seagreen is a joint venture between SSE Renewables and TotalEnergies and forms part of SSE’s £20.5 billion NZAP Plus investment plan.

Six countries sign agreement to protect North Sea energy telecommunications infrastructure

Six North Sea countries have signed a cooperation agreement to protect energy and telecommunications infrastructure in the North Sea.

After damage to energy pipelines and subsea fibre-optic cables, Belgium, the Netherlands, Germany, Norway, the UK and Denmark have signed a joint declaration to work together to protect infrastructure in the North Sea.

Critical infrastructure in the North Sea includes subsea fibre-optic cables, gas and oil pipelines, electricity transmission cables and offshore wind installations. The subsea infrastructure in the North Sea is interconnected across national borders necessitating a joint initiative for safety and protection, said Norway’s minister of digitalisation and public administration Karianne Tung.

‘The submarine fibre cables are crucial for internet traffic between Norway and other countries, and I am pleased that we, together with five other countries, are now further protecting this. It is important for our interests, energy production and our maritime activities that we safeguard this digital infrastructure,’ she added.

The partners will exchange information and ‘implement measures’.

Connector vessel.

Shell hits emissions reduction landmark

By the end of 2023 Shell achieved more than 60% of its target to halve emissions from it operations by 2030, compared with 2016.

According to the company’s first energy transition update since the launch of its 2021 Powering Progress strategy towards achieving net zero in 2050, Shell achieved 0.05% methane emissions intensity – significantly below its target of 0.2% – in 2023.

In 2023 it also achieved its target of reducing the net carbon intensity of the energy products it sells, with a 6.3% reduction compared with 2016.

Wael Sawan, Shell chief executive officer, said: ‘Our focus on performance, discipline and simplification is driving clear choices about where we can have the greatest impact through the energy

transition and create the most value for our investors and customers. By providing the different kinds of energy the world needs, we believe we are the investment case and the partner of choice through the energy transition.’

To help drive the decarbonisation of the transport sector, it has set a new ambition to reduce customer emissions from the use of our oil products by 15-20% by 2030 compared with 2021 (Scope 3, Category 11).

It is planning to focus its power business, including renewable power, in Australia, Europe, India and the US, and has withdrawn from the supply of energy directly to homes in Europe. That will include selling more power to commercial customers, and less to retail customers.

‘We expect lower total growth of power sales to 2030, which has led to an

update to our net carbon intensity target. We are now targeting a 15-20% reduction by 2030 in the net carbon intensity of the energy products we sell, compared with 2016, against our previous target of 20%.’

Shell is investing $10-15 billion between 2023 and the end of 2025 in low-carbon energy solutions. In 2023 it invested $5.6 billion on low-carbon solutions, more than 23% of total capital spending.

These investments include electric vehicle charging, biofuels, renewable power, hydrogen and carbon capture and storage.

Customer emissions from the use of its oil products (Scope 3, Category 11) were 517 million tonnes carbon dioxide equivalent (CO2e) in 2023 and 569 million tonnes CO2e in 2021.

DUG signs seismic data deal with Wintershall Dea

DUG Technology has signed a deal with Wintershall Dea in which the European oil and gas company will utilise DUG’s seismic data processing and imaging expertise.

Each of Wintershall’s business units across the world will collaborate with DUG to create a virtual global processing centre..

‘The partnership has the added benefit of simplifying tendering and execution of Wintershall Dea’s seismic processing projects, also promoting efficiency,’ said DUG in a statement.

‘DUG’s geoscience experts will provide remote support ranging from advice and consultancy services to entire bespoke (re)processing projects using DUG

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Insight, DUG’s powerhouse processing and imaging toolkit, which includes DUG’s multi-parameter FWI imaging technology.’

DUG Insight is an interactive software platform for advanced seismic data processing and imaging, interpretation, visualization and QI.

DUG doubles power of its Houston data centre

DUG Technology has upgraded its Houston data centre to increase the company’s high-performance computing (HPC) capabilities.

The company has invested in 1500 AMD EPYC Genoa servers, each with 192 cores and 1.5 terabytes of DDR5 memory. Quebec-based Hypertec provided the immersion-borne hardware, enabling a seamless integration with DUG’s proprietary HPC framework.

This follows DUG’s recent deployment of 600 new Intel Xeon CPU Max Series machines, each equipped with 128 cores and one terabyte of RAM. In addition, all of the company’s existing servers had a RAM upgrade to 384 gigabytes.

In total the hardware upgrades more than double the effective horsepower of DUG’s Houston data centre, including its supercomputer, Bubba

DUG’s managing director Dr Matthew Lamont said: ‘The Intel machines are

Oil and gas round-up

Equinor has delineated the ‘Heisenberg’ oil and gas discovery in wells 35/10-11 S and A in the North Sea, and has also proven oil in the Hummer prospect. The discovery is estimated between 3.8 and 8.9 million Sm3 of oil equivalent. Well 35/10-11 S encountered a sandstone reservoir totalling about 10 m with good reservoir quality in the Hordaland Group. The reservoir was aquiferous with traces of hydrocarbons. In the secondary exploration target in the Balder Formation, the well encountered a 3-m oil column in sandstone totalling 23 m with poor-to-moderate reservoir quality. Well 35/10-11 A encountered a sandstone reservoir totalling about 12 m with moderate to good reservoir quality. This reservoir has a 12-m oil and gas column in the Hordaland Group. Well 35/10-11 S was drilled to a depth of 1853 m below sea level, and was terminated in the Rogaland Group in the Palaeocene. Well 35/10-11 A was drilled to a depth of 1690 m below sea level, and was terminated in the Hordaland Group in the Eocene. Water depth at the site is 364 m. Extensive data acquisition and sampling were carried out. Petrobras has discovered oil in the ultra-deep waters of the Potiguar Basin from the Anhangá exploratory well of the POT-M762_R15 Concession. The 1-BRSA-1390RNS (Anhangá) well is near the border between the states of Ceará and Rio Grande do Norte, about 190 km from Fortaleza and 250 km from Natal, at a water depth of 2196 m on the Brazilian Equatorial Margin. This is the second discovery in the Potiguar Basin in 2024, preceded by proof of the presence of hydrocarbons in the Pitu Oeste Well, located

in the BM-POT-17 Concession, around 24 km from Anhangá.

OKEA has made a final investment decision for the Brasse development in the northern North Sea. The field is estimated to contain 24 million barrels of oil equivalent gross in recoverable reserves and will be developed as a tie-back to the Brage field. The Brasse development (PL740) is 13 km south of the Brage field. OKEA is operator for both licenses. The plan for development and operation (PDO) will be submitted during April and Brasse will be renamed Bestla upon approval of the PDO. The field is expected to come on stream during the first half of 2027 and is anticipated to operate until 2031 with potential for extension. Plateau production is estimated at around 10 kboepd. The Brage Unit partnership consists of OKEA (operator 35.2%), Lime Petroleum (33.8434%), DNO (14.2567%), Petrolia Noco (12.2575%), and M Vest Energy (4.4424%).

Mitsui and Co has made a final investment decision on the ‘Block B Project’ encompassing an upstream gas field and a pipeline linking it to a gas-fired thermal power plant complex in Vietnam. Partners include the Vietnam Oil and Gas Group, PetroVietnam Exploration Production Corporation, PetroVietnam Gas Joint Stock Corporation, and PTT Exploration and Production Public Company Limited (PTTEP). Production capacity is estimated at 490 million cubic feet per day, with production scheduled to begin by the end of 2026.

Tag Oil has completed drilling of a horizontal well at the Badr Oil Field

already turbocharging our new MP-FWI imaging technology, which is having a transformative impact on the way we process seismic data. Delivering unsurpassed imaging with rapid turnaround for our clients, it is a complete replacement for the conventional processing and imaging workflow. The new Hypertec-supplied AMD machines are needed to accelerate delivery of both current and imminent projects, and to support the unprecedented demand we continue to see moving forward.’

(BED-1) in the Abu Roash F limestone formation (ARF) The well has penetrated an over-pressured reservoir with regions of exceptional porosity and permeability. During drilling operations, there have been clear signs of free oil flowing into the wellbore and to surface, accompanied by consistently elevated gas readings across the ARF formation. The company is now optimising the multistage hydraulic fracture completion design, poised to maximise the stimulated reservoir volume of the wellbore. The exceptional quality of the encountered reservoir section presents an exciting prospect, offering the potential for robust oil production performance following the hydraulic fracture stimulation of the ARF horizontal well, said Tag Oil.

ExxonMobil has discovered oil at Bluefin in the Stabroek block offshore Guyana, the company’s first discovery of 2024. The Bluefin well encountered 60 m of hydrocarbon-bearing sandstone and was drilled in 1294 m of water. The Bluefin well is located 8.5 km southeast of the Sailfin-1 well, in the southeastern portion of the Stabroek block.

Galp (80%), NAMCOR and Custos (10% each) have drilled the Mopane-2X well to its designed depth, in block PEL83. Drilling encountered a significant column with light oil in high-quality reservoirs. The AVO-3 exploration target, the AVO-1 appraisal target and a deeper target were fully cored and logged. The AVO-1 appraisal target found the same pressure regime as in the Mopane-1X discovery well located around 8 km to the east, confirming its lateral extension.

A unified earthquake catalogue for the North Sea to derisk European CCS operations

Tom Kettlety1*, Evgeniia Martuganova2, Daniela Kühn3, 4, Johannes Schweitzer3,8, Cornelis Weemstra2,9, Brian Baptie 5, Trine Dahl-Jensen 6, Annie Jerkins3, Peter H. Voss 4, J. Michael Kendall1 and Elin Skurtveit7,8.

Abstract

Carbon capture and storage (CCS) technology is essential to European decarbonisation efforts, and several offshore CO2 storage projects are being developed in the North Sea. Understanding the geomechanical response to CO2 injection is key to both the pre-characterisation and operation of a storage reservoir. A thorough assessment of seismicity gives critical insights into the stress field and faulting around reservoirs, both key controls on the geomechanical response to injection. Seismicity also illuminates potential hydraulic pathways for leakage, be it directly by revealing the extent of faults, or indirectly through fractures imaged by measurements of seismic anisotropy. High quality seismicity data is critical to underpin all of these methods of analysis. This paper presents the most complete catalogue of seismicity in the North Sea to date. The combined data are enabling revised assessments of seismic hazard and leakage risk in the North Sea, as well as a better understanding of faulting and stress. This study shows the value of unifying disparate seismicity data, allowing for more accurate seismological analyses. These lay the foundation for better management of risks for not only geologic CO2 storage, but other offshore industries and infrastructure.

Introduction

Currently, a number of CO2 storage projects are being developed in the offshore North Sea region to facilitate European emission-reduction efforts (Figure 1). Despite seismic hazard in the North Sea being comparatively low, it is still critical to assess the rate and size of local earthquakes. In addition, offshore wind projects are prevalent, being expanded to further decarbonise energy systems in Europe. Seismic hazard is a key environmental risk factor for both these industries, and high-quality data must be used to accurately characterise and quantify the size of that risk.

High quality seismicity data can highlight the location of faults and other pre-existing structures (e.g., dominant fracture trends) near prospective storage sites, some of which could act as hydraulic conduits for CO2 migration. Further, faults can impact in situ stresses in and around potential reservoirs, and measuring the propagation of seismic waves generated by earthquakes can act as stress indicators. Understanding the distribution of in situ stress is key to the safe and effective drilling of wells as well as injection of CO2. Measurements of stress can be found from borehole assessments, but also from seismicity: it can be inverted from earthquake faulting styles, inferred from earthquake stress drops, or measured from seismic anisotropy (e.g., Teanby et al., 2004). High quality earthquake data is required to conduct these

analyses. Combining earthquake observations from as many sources as possible leads to improvements in quality. It can thus provide a more robust, quantified, and complete assessment of seismic hazard, as well as the regional state of stress, the understanding of which is vital to securely inject CO2

The risk of injection-induced seismicity is also present for CO2 storage operations. The injection of fluids into the subsurface has been clearly associated with seismicity in a number of geologic and industrial settings (e.g., Keranen & Weingarten, 2018), and the occurrence of microseismicity has been linked to the injection of CO2 (Cheng et al., 2023) and gas storage (Cesca et al., 2014). Oil and gas exploitation in the North Sea was also associated with several earthquakes typically thought to be triggered primarily by depletion-induced stress changes (Zoback and Zinke 2002; Teanby et al., 2004; Jones et al., 2010). Several mechanisms were invoked for the triggering of faults by injection or depletion, along with several geological controls on the severity or prevalence of induced seismicity (e.g., Kettlety & Verdon, 2021). Seismological investigations provide both direct and indirect observations of many of these controls, and thus seismological data is key to the assessment of induced seismicity risk for CO2 storage sites (Verdon & Stork, 2016; White & Foxall, 2016).

1 University of Oxford | 2 Delft University of Technology | 3 NORSAR | 4 GFZ German Research Centre for Geosciences

5 British Geological Survey | 6 Geological Survey of Denmark and Greenland (GEUS | 7 Norwegian Geotechnical Institute (NGI)

8 Department of Geosciences | 9 Royal Netherlands Meteorological Institute (KNMI)

* Corresponding author, E-mail: tom.kettlety@earth.ox.ac.uk DOI: 10.3997/1365-2397.fb2024036

Operators and regulators require a clear understanding of the rate of natural seismicity to identify and distinguish induced events from natural as well as to assess the likelihood and severity of injection-induced fault reactivation. This requires a dedicated, site-specific background monitoring programme, as well as high quality seismicity data for the North Sea region as a whole. This study has produced the first dedicated combined catalogue of seismicity of the North Sea, based on all available data from each of the relevant seismological agencies. This study reports the dataset, how it was created, and how it is now enabling further studies into seismic hazard, leakage risk, and stress state in a region that will be vital for European CO2 storage efforts in the coming decades.

Tectonic background

The North Sea is located in a relatively stable tectonic environment. It is far from the mid-Atlantic ridge (MAR) to the west (>1500 km), and the African-Eurasian plate boundary (AEB) is >700 km to the south. Regional-scale tectonic stress patterns are controlled primarily by post-glacial rebound, ridge push force from the MAR, and subduction forces from the AEB. Furthermore, residual stress effects are evident in regions affected by the emplacement of magma and subsequent breakup of the North Atlantic Igneous Province in the Paleogene (~62 – 54 Ma). As a result, measures of seismic hazard (e.g., earthquake recurrence rates, peak ground velocity or acceleration) in the region are relatively low when compared to more tectonically active regions globally, though a few large magnitude events have been recorded (~M 6). There is also evidence for larger (M > 7) earthquakes associated with post-glacial rebound north of Norway (e.g., Bungum et al., 2005). Table 1 summarises the largest events that were recorded in the region. It should be noted that all but one of these events occurred before seismic instrumentation was ubiquitous

Figure 1 Map showing boundaries of CO2 storage licences (polygons) and location of other operating and nascent storage projects (circles). Licences granted by the UK are shown as black polygons, while those from Norway are shown in magenta. Locations of Danish (green) and Dutch (blue) storage projects and prospects are shown by the coloured circles.

across Europe (from ~1985), and so the sizes and locations of these events have greater uncertainty.

The geologic structure of the North Sea is primarily associated with the triple plate collision that occurred around 450 Ma ago (Late Ordovician to Early Silurian) during the Caledonian Orogeny. However, many of the largest structures in the North Sea that generate present-day seismic hazard were created in the Permian and Triassic. Volcanic rifting 250 to 150 Ma ago created horst and graben structures bounded by a series of large normal faults, which are spread across the north of the study region, and formed the Viking Graben. The graben is now oriented N-S and is located around 100 km to the west of Norway. Further rifting in the Late Jurassic through to the Early Cretaceous (160 to 140 Ma ago) created additional extensional structures further to the south, forming the Central Graben. Thermal subsidence in the Cretaceous, igneous activity in the Palaeogene, uplift of

Table 1 Events with a reported moment magnitude greater than 5 in the North Sea, sorted by moment magnitude. The largest event is located only tens of kilometres from the Endurance CO2 storage licence (albeit at a depth likely greater than 20 km). The three northernmost events (latitude > 60 deg) are probably associated with post-glacial rebound processes.

the basin margins later in the Cenozoic, and continued uplift and glacial erosion through to the Quaternary resulted in a thick series of sedimentary deposits that buried the Jurassic and Cretaceous rocks that sourced the considerable North Sea oil and gas reserves. More recently (in the last 2.5 Ma), changes in river sediment deposition and sea level, broadly associated with changes in glaciation, produced thick sedimentary sequences in the south of the North Sea. This gave rise to shallow seas over a large area off the east coast of England, in particular the Dogger Bank bathymetric high.

SHARP Storage

This data collection and study was conducted as part of the Accelerating CCS Technologies project SHARP Storage (Stress history and reservoir pressure for improved quantification of CO2 storage containment risks). SHARP involves investigators from 16 institutions and companies working in five countries: Norway, Denmark, the Netherlands, UK, and India (www.sharp-storageact.eu). This project aims to substantially improve leakage risk management of CO2 storage operations through several work packages. Geomechanical modelling, laboratory experiments, seismology, and probabilistic risk assessment is being integrated by a broad mix of industry and academic partners. The project will conclude in 2024, providing guidance for CO2 storage operators and regulators on reservoir pre-characterisation, modelling, monitoring, and risk quantification.

Data collection and curation

Seismicity data has been aggregated from the global database (of the International Seismological Centre, ISC) and seismological agencies in the region: the British Geological Survey (BGS); the Royal Netherlands Meteorological Institute (KNMI); the

Geological Survey of Denmark (GEUS); the Norwegian National Seismic Network (NNSN); NORSAR; the German Institute for Geosciences and Natural Resources (BGR); the GEOFON programme of the German Research Centre of Geosciences (GFZ); and Christian-Albrechts University (CAU) in Kiel. Whilst a number of these agencies do share some data between them, this study represents the first effort to wholly combine all available earthquake data in the region up to the end of 2021.

A polygonal area was chosen to capture only events that occur in the North Sea (Figure 2). Once events within the polygon were retrieved from each of the above agencies, an extensive process of database merging and cleaning was conducted. Firstly, erroneous events or data entries were removed from the dataset. Subsequently, several methods were used to find duplicate events in the initial merged dataset. Events that coincided in both space and time within defined thresholds were merged (following Jones et al., 2000; Jónasson et al., 2021), along with those that shared similar phase arrival times at the same seismic stations. Many marginal duplicate event candidates were manually inspected as a further quality control step. After the merging, an event association was performed, before an algorithm was applied to remove functionally duplicated, but non-identical, phase and origin information. Once the filtering was completed, each time and location entry was given a unique identifier, which embeds the agency from which the data originated.

Known and suspected explosions were identified and marked in the catalogue, such that further studies can exclude them. This was primarily done through comparisons of the individual agency’s lists of known explosions. Some agencies mark events in their respective catalogues as suspected explosions based on location, size, time of occurrence, and waveform type. Others also communicate with their corresponding national defence

Figure 2 Map depicting the events in the seismic catalogue, with event epicentres given by circles sized by local magnitude. Marker colour denotes the events’ origin times. The red polygon shows the boundary region used for the North Sea. The colour scale is limited to 1980-2020 for contrast. Differences in event detection capability are clearly visible, as well as the higher seismicity rates in the Central and Viking Grabens.

agencies, who report when and where munitions are detonated, allowing the seismological agencies to mark detected explosions with certainty (e.g, Ruigrok et al., 2019). In the combined catalogue, a relative increase in event number during daytime compared to nighttime can be readily observed, indicating that the excess is likely to consist of explosions.

In collecting and storing the event and seismic phase data for distribution, we use the standard International Association of Seismology and Physics of the Earth’s Interior (IASPEI) Seismic Format (ISF; detailed in IDC, 1999). When this information is combined into a single file, these data are referred to as a ‘bulletin’ A bulletin can have multiple entries for event time and location, reflective of the different seismic networks or methods used by different agencies to detect and locate earthquakes. A simplified version of bulletin data, showing just a single time, location, and size (i.e., magnitude) for each event is referred to as a ‘catalogue’. Waveforms for events with magnitudes greater than M 3.5 have been collected for various analyses, which are discussed further in the ‘Conclusions and future work’ section.

Along with event and phase data, focal mechanism (FM) data were also compiled in this study. The primary project aim is to better constrain the regional stress field, and thus slip orientation data are a critical component. Furthermore, velocity models for

Figure 3 Local magnitude of catalogued events through time. Note the decreasing time scales, which range from the earliest events in the catalogue (May 1382) in (a), to the advent of dedicated instrumental earthquake measurement in the region (from around 1900 on) in (b), to the modern era of earthquake detection and location (from 1980) in (c). There are clear changes in detection ability through the different time periods, representing an improvement in the magnitude of completeness for the catalogue.

the North Sea were compiled from several of the above agencies as well as the CRUST1.0 model (Laske et al., 2013). These velocity models are used primarily by the seismological agencies for the localisation of events through travel time inversion, but are also required for further studies (as detailed in the ‘Conclusions and further work’ section).

Results

After the filtering and cleaning process described above, the catalogue consists of 15,231 events, with 3223 identified as (suspected) explosions. The bulletin comprises 43,730 individual entries for origin time and location. In the subsequent figures, we present the prime (i.e., the first) entries. The compiled FM catalogue consists of 60 solutions from 50 different events.

Figure 2 shows a map of the event catalogue, and clearly demonstrates the spatial variability in both the seismicity rates and detection thresholds in different parts of the North Sea. The Viking and Central graben regions (annotated in Figure 2) have a higher seismicity rate, as expected, with generally larger events compared to most of the central North Sea. Also as expected, detection and location of smaller magnitude events (M<3) is greater near the coast due to proximity to the national seismic networks. Detection thresholds are particularly low (with M<1 detected) close to the Norwegian coast, due to the greater coverage of seismic stations operated by the NNSN through the last three to four decades, the higher seismic activity rate close to the Viking graben, and the multiple seismic arrays that are operated by Norsar (see Schweitzer et al., 2021). Since the installation of the Equinor-owned, Norsar-operated HNAR array in 2020, the detection threshold is expected to have further decreased in this area (Zarifi et al., 2023) .

Figure 3 displays the magnitudes of catalogued events through time. It clearly demonstrates the changes in the detection thresholds, with historical seismicity (pre-1900) usually much larger than M 4, the routine detection of M>4 from 1900, and the significant improvement in detection capability from 1980. The magnitude of completeness Mmin (the magnitude above which all events are reported) clearly varies through time, but, as indicated in Figure 2, also varies strongly in space. Events with M<3 are still unlikely to be routinely detected by national networks in areas far (>200 km) from any coastline (i.e., in the central North Sea).

Figure 4 shows the magnitude-frequency distribution for the events, together with the estimated Gutenberg-Richter (GR) b-value. This empirical GR relationship – log(N) = a-bM – relates the number of events N above the magnitude of completeness Mmin to the magnitude M, with b characterising the slope of the line in log space and a being the overall activity rate. Figure 4a shows the calculated b-value for the current catalogue when applying the stability method of Cao and Gao (2002) to estimate Mmin, resulting in a notably low value of b = 0.8±0.02. Lower b-values suggest a greater than expected number of large earthquakes relative to the number of small ones, and thus an increased seismic hazard in the region. However, the estimated Mmin of around M 1.5 is likely to be too optimistic due to the spatiotemporal variability of detection thresholds in the North Sea. In fact, the kink in the magnitude distribution, which is visible around ML 3.5, is indicative of the variations in detection thresholds across both space and time,

Figure 4 Magnitude-frequency distribution for the catalogue using local magnitudes. Gutenberg-Richter b-value is measured using the maximum likelihood approach of Aki (1965). (a) shows the b-value found when the b-value stability method of Cao and Gao (2002) is used to find the magnitude of completeness Mmin. (b) shows the b-value when a more realistic Mmin of ML 4 is imposed.

and potentially the differing magnitude scales used in the region. A reasonable estimate of Mmin for the entire catalogue would be around M 4, which produces a b-value of 1.0±0.2, comparable to many tectonic settings around the world (Figure 4b). Along with a thorough spatiotemporal analysis of Mmin, homogenisation of magnitudes is a goal of the subsequent work of the SHARP project.

Conclusions and future work

This enhanced North Sea seismicity catalogue will enable a greater understanding of not only earthquake occurrence in the region, but also fault locations and orientations, in situ stress state, and fracture density. Seismicity data as collected in this study are a clear asset to CO2 storage and offshore wind farm operators as well as regulators in assessing environmental risks associated with prospective projects, quantifying earthquake hazard, and identifying induced seismicity.

Producing a combined and cleaned seismological dataset is also of great interest for academic communities in developing new methods and reanalysing a more complete record of earthquake origins and phase readings. Those interested in North Sea earthquake source processes and hazards can use this dataset with confidence that this is the collection of all available data, from every agency which routinely records seismicity in the region. This is particularly novel for an offshore region with many overlapping agencies, and grants an opportunity to improve derivatives of this data by bringing together all available recordings of events.

The SHARP project consortium is continuing with the analysis and improvement of this combined data using numerous methods. The catalogue is being relocated using the newly combined list of phase readings from various seismic networks. This relocation method uses a probabilistic framework, sampling each of the possible origins from different velocity models to better constrain locations and associated uncertainties (see Schweitzer, 2001; 2018). Also using the enhanced spatial coverage, new focal mechanisms are being inverted using a Bayesian bootstrap-based

probabilistic joint inversion scheme (see Heimann et al., 2018). This study is focusing on the areas around nascent CO2 storage developments, in order to be used in stress inversion studies. Further, event magnitudes are being homogenised.

Stress drop measurements will be derived using an empirical Green’s function approach, using the increased coverage to give more accurate stress drops with better constrained uncertainty (using the method of Goertz-Allmann et al., 2011). These results in particular will be integrated in the definitions of stress in and around the prospective CO2 storage reservoirs, and the larger geomechanical modelling studies (as in Angus et al., 2010) of SHARP.

Ground motion prediction equations (GMPEs) are being derived for the onshore regions nearest the development CO2 storage projects, and an updated probabilistic seismic hazard analysis is being carried out on a regional scale. Results will be compared with the existing national hazard models and local scale studies of seismic hazard, providing an updated and comparable assessment of seismic hazard based on this newly analysed data set.

The SHARP program is also assessing the suitability and efficacy of the myriad of environmental monitoring technologies that could be used in the North Sea for CO2 storage. This includes active seismic, offshore passive microseismic, land-based microseismic arrays, ocean bottom seismic (OBS), distributed acoustic sensing (DAS), large-N permanent reservoir monitoring (PRM). This includes the ability for these technologies to detect earthquakes, locate them, determine their depth, and to distinguish induced from natural seismicity.

Each of these activities will feed into a larger analysis, improving quantification of risks to CO2 storage integrity, and the understanding of the state of stress and faulting in an area that will host many CO2 storage and offshore wind projects in the coming decades. This data and the subsequent work will significantly aid in quantifying risks from seismicity, induced seismicity identification, and storage integrity assessment. Each of these are key to facilitating the development and management of industries that are urgently needed to combat climate change.

Data availability

This seismic catalogue is currently (as of July 2023) available from the authors upon request. Once the SHARP project has been completed (December 2024), the final, improved catalogue will be made publicly available via the ISC data repository.

Acknowledgments

This work is a part of SHARP Storage (project no 327342). The SHARP project has been subsidised through ACT (EC Project no. 691712), by RCN and Gassnova (Norway), RVO (The Netherlands), DST (India), BEIS (UK), and EUDP (Denmark). The authors would like to thank the following partners for their contribution: ASN, BGS, BP, Equinor, GEUS, IIT Bombay, INEOS, NGI, Norsar, NTNU, University of Oxford, Risktec, Rockfield, Shell, TUDelft, and Wintershall Dea. TK was also supported by the University of Oxford’s Strategic Research Fund, through the Oxford Net Zero programme.

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Increasing P-wave and S-wave velocity resolution with FWI — a North Sea shallow water case study

Alireza Roodaki1*, Loic Janot1, Manuel Peiro1, Hao Jiang1, Wenlei Gao1, Hervé Prigent1, Ziqin Yu1, Nabil Masmoudi1, Andrew Ratcliffe1, Per Eivind Dhelie2, Vidar Danielsen2, Knut Richard Straith2 and Arnstein Kvilhaug2.

Abstract

Multi-component data recorded during Ocean-Bottom Seismic (OBS) surveys captures both PP and PS events. PP and PS images provide complementary information about reservoir properties. The quality of both these types of images depends on the accuracy of the P-wave and S-wave velocity models, V P and VS , respectively. In this paper, focusing on data from a shallow water OBS survey in the Central North Sea, we show, first, how a high-resolution 65 Hz V P model, obtained using Time-Lag FWI, can improve the imaging from the shallow to the deep. Similar improvements are then shown for PS data using a 30 Hz VS model obtained from PS reflection-FWI. The most remarkable achievement is the flattening of the undulating chalk and top reservoir surfaces on both the V P and VS FWI Images, obtained from PP and PS data, respectively, which was confirmed by drilling observations. These derived V P and VS FWI Images reduce the uncertainty in reservoir characterisation.

Introduction

Ocean Bottom Cable (OBC) surveys attract considerable industry interest for reservoir imaging as they record wide-azimuth broadband data with long offsets. They also ensure high repeatability which is an important parameter for reservoir monitoring. With four components recording PP and PS waves, they can bring more insight to reservoir characterisation and lithology analysis (Colnard et al., 2019). The quality of PP and PS images depends highly on the accuracy of the P-wave, VP , and S-wave, VS , velocity models.

Recent developments in Full-Waveform Inversion (FWI), such as Time-Lag FWI (TLFWI, Zhang et al., 2018), together with higher computational capabilities, allow us to produce high-resolution VP FWI models with frequencies exceeding 50 Hz (Salaun et al., 2021). By capturing lateral and vertical velocity variations, these high-resolution FWI velocity models improve the imaging of structures from shallow to deep. It is also possible to obtain a direct estimate of the PP reflectivity through FWI Imaging (Zhang et al., 2020).

Owing to difficulties in building a VS model honouring high-resolution vertical and lateral velocity variations in the overburden, the PS image is often of low quality compared to the PP image. Conventional VS model building from PS reflection data relies on PS (or joint PP-PS) tomography and event registration. This method has many limitations, particularly the fact that the updated VS model lacks high-resolution information. Full-wavefield-based methods make it possible

1 CGG | 2 Aker BP

* Corresponding author, E-mail: alireza.roodaki@cgg.com DOI: 10.3997/1365-2397.fb2024037

to achieve higher resolution. Elastic FWI would be the most accurate approach for retrieving a VS model, but it remains difficult owing to the computational cost of elastic full-waveform modeling at high frequency. As an alternative, quasi-elastic Born modeling can be used (Feng and Schuster, 2019). In this approach, the PS-reflected wavefield is approximated by a formula using acoustic wavefields propagating in the VP and VS background models. Based on an approximation of this quasi-elastic Born modelling, Masmoudi et al. (2021) proposed an adaptation of Reflection-FWI (RFWI; Xu et al., 2012) to PS data, which can be used to update the background VS model (V0S ). Later, Peiro et al. (2022) proposed an extension of the method to obtain a high-wavenumber perturbation model, δVS

Here, on a shallow water OBC data set over the Edvard Grieg field in the Central North Sea, we present results from an FWI VP update up to 65 Hz using P and Z components, and the results of PS-RFWI run to update the VS velocity model up to 30 Hz using a preprocessed radial component.

Edvard Grieg field OBC data

Edvard Grieg is an oil field in the Central North Sea, located approximately 180 km west of Stavanger on the Utsira High platform. The reservoir interval is less than 50 m thick, beneath a high-impedance chalk layer at a depth of approximately 2 km. Building an accurate velocity model for this field presents many challenges:

• There are not many vertical velocity variations down to the chalk (Figure 1-a). Long offsets (more than 10 km) are therefore required to record the diving waves needed for FWI to update the velocity down to the reservoir level. Fortunately, the OBC data presented here were acquired with offsets of up to 13 km.

• The presence of high-contrast geological features called injectites (yellow arrow in Figure 1-b). These are compressed sand bodies and their velocity can be 1000 m/s higher than the velocity of the surrounding rocks. They cause issues not only for velocity model-building but also for imaging, as a loss of illumination is generally observed below these features.

• Lateral velocity variations in the shallow part of the section due to the presence of gas pockets and channels (Figure 1-c). These features have a relatively low velocity compared to the neighbouring background velocity and need to be taken into account in the velocity model to avoid imaging problems in the deeper section.

Strong lateral velocity variations make imaging and reservoir characterisation challenging. In fact, not taking into account the shallow lateral velocity variations and the injectites resulted in deep structural undulations on legacy images. This led to confusion when comparing the PP reflectivity (Kirchhoff PSDM) with measurements from drilled horizontal wells. One example is shown in Figure 2, where the legacy image (top) led to the interpretation of a graben structure with fault displacement whereas when the distance from the wellbore to the top reservoir seal was

measured using a deep resistivity logging tool during drilling (bottom) it became clear that this graben was absent and that the reservoir structure was simpler (Dhelie et al., 2022).

These seismic depth undulations are very troublesome when it comes to the placement of future production wells as they affect definition of the reservoir structure. This has been an ongoing issue for a while, and no solution using seismic data was found until recently.

Regular OBC campaigns were acquired over this field (Twynam et al., 2020) for 4D monitoring purposes. In this article, we present results obtained from data acquired in 2018, with 44 receiver cables laid out on the sea floor with a receiver grid of 25 m x 200 m and a dense shot carpet of 25 m x 50 m with a maximum offset of 13 km.

High-resolution reservoir compartment delineation using FWI

FWI derives high-resolution velocity models by minimising the difference between observed and modelled seismic waveforms. It goes beyond refraction and reflection tomography techniques by using additional information provided by the full seismic wavefield, including diving waves, reflections and their ghosts and multiples. From this detailed velocity field, it is then possible to derive the reflectivity, called the FWI Image (Zhang et al., 2020).

Figures 3-a and 3-c, respectively, show the legacy VP velocity model, used as an initial model for FWI, and its corresponding Kirchhoff PSDM cube on two sections. We can observe on the seismic images that the chalk structure suffers from undulations

Figure 2 a) original seismic section indicating a graben structure with a possible fault displacement of more than 10 m. b) during drilling it became clear that this graben was not present and the Top Reservoir (red dotted line) was almost flat.

Figure 1 (a) V p sonic log, (b) RTM section featuring an injectite body, (c) depth slice at 360 m showing gas pockets.

3 Legacy V p velocity (a) and its corresponding Kirchhoff PSDM image filtered at 65 Hz (c). 65 Hz FWI V p velocity with white arrows indicating small features captured by the high-resolution FWI velocity update (b) and its corresponding FWI Image (d). Red and green arrows in figures (c) and (d) indicate areas where high-resolution FWI improved the imaging compared to the legacy image.

and discontinuity below the injectites. We ran FWI from PP data recorded by the hydrophone and the vertical geophone sensors.

Figure 3-b shows the high-resolution VP velocity model obtained up to 65 Hz. We can see that many geological features have been captured in this very detailed model, from low-velocity gas pockets in the shallow part to high-velocity injectites in the middle of the section and the high-contrast chalk reflector in the deeper part indicated by the white arrows. The resulting FWI Image (Figure

Figure 4 20 Hz FWI V p velocity (a) and its corresponding Kirchhoff PSDM filtered at 65 Hz image depth slice (b). 65 Hz FWI V p velocity (c) and its corresponding FWI Image depth slice. White arrows show examples of where resolution is gained.

3-d) exhibits a much-simplified reservoir structure and improved continuity of the chalk, particularly below the injectites. Note that, since FWI uses the full wavefield (with ghosts and multiples), it extends the imaging coverage and enhances imaging in the shallow section, noticeably filling the platform hole.

Figure 4 compares the FWI VP velocity models at 20 Hz (a) and at 65 Hz (c). It also compares the Kirchhoff PSDM filtered at 65 Hz (b) and FWI Images (d) using these two velocity models.

Figure

It illustrates the enhanced imaging of injectites and faults when inverting for a higher-frequency velocity model. We can observe that these high-resolution events are also easily detectable on the 65 Hz model.

Figures 5-c and 5-d compare Kirchhoff PSDM sections filtered at 65 Hz using the legacy velocity and the FWI model. We observe that using an accurate velocity model can significantly improve the imaging of structures and reduce the wobbling. The well trajectory (black line) coincides with the reservoir beneath the chalk, whereas it does not match in the legacy image. Moreover, the interpreted chalk horizon is smoother when using the FWI model (Figure 5-b) than when it was interpreted on the legacy image (Figure 5-a). Figure 5-e compares a well sonic profile to the legacy and FWI VP velocity models. Starting from a smooth initial velocity, FWI managed to capture fine vertical velocity variations and the obtained VP provides a good match to the sonic profile.

To better appreciate the high-resolution information brought to the velocity model by FWI up to 65 Hz at the reservoir level, Figure 6 (left) presents an overview of the field. Four different expected facies are displayed with their respective colours in the legend. The production and injection wells are drawn respectively in blue and green. Depth sections of the legacy and the 65 Hz FWI VP velocity models are shown in the middle and right panels of Figure 6. We observe that FWI honours the main geological trends in the reservoir and that the velocity contrasts on the section correlate well with variations in reservoir facies.

Reconciling VS and VP FWI Images using PS-RFWI

Having obtained a high-resolution VP velocity model that resolved many imaging issues, the next challenge was to generate a high-resolution VS velocity model with similar properties. The methodology used to estimate the S-wave velocity is based on a Born approximation-based PS-RFWI (Masmoudi et al., 2021; Peiro et al., 2022). As with other FWI methods, PS-RFWI minimises the difference between the observed and modelled PS data through optimisation of an objective function J. The FWI gradients for the background V0S and the perturbation δVS models can be obtained via the adjoint-state method, as follows:

where δS is the scattered S-wavefield propagating in the background V0S model, P is the incident P-wavefield propagating in the background V0P model, and R is the adjoint S-wavefield obtained by backpropagating the residuals of the PS-reflection data injected at the receiver positions.

The input seismic data to PS-RFWI was the preprocessed radial component of the receiver gathers, that were multiple- and ghost-free. Like all inversion methods, PS-RFWI is sensitive to the initial model. To build the initial VS model, we used a smoothed and edited version of the FWI VP model, scaled by a VP /VS ratio derived from P- and S-sonic logs. To refine the very shallow part of the VS initial model (down to 200 m), a multi-wave inversion step (Bardainne, 2018) was run using the surface waves recorded on the Z component. Finally, a PP-PS registration was performed to match the PP and PS interpreted horizons and to register the VS model with respect to the VP one.

The VS model was then updated in two steps: first, the background V0S model and, second, the high-resolution perturbation δVS model. The perturbation δVS update was then combined with the background V0S model to obtain the final VS model that should correct for kinematics and depthing of events while featuring high-resolution details.

Figure 7 compares the legacy VS model (a) and the final (b), fully updated, 30 Hz VS model, coming from the combined background and perturbation models, as well as their corresponding image sections. The final VS model, Figure 7-c, highlights rich vertical and lateral details consistent with the main geological events visible on the seismic sections and shows good agreement with the well-log data in Figure 7-e. The VS FWI Image is derived from the final VS model and is shown in Figure 7-d. This demonstrates a geologically consistent section, relative to the VP FWI Image, from the overburden to the deep, and can be compared with the 30 Hz converted-wave reverse time migration (PS-RTM) from the legacy

Figure 5 Interpreted chalk horizon on a Kirchhoff PSDM image using the legacy velocity model (a) and FWI model (b). Corresponding Kirchhoff images for the legacy (c) and FWI model (d), with the well trajectory indicated by the black line. (e) Comparison of legacy (orange line) and FWI velocity models (green line) with the well sonic profile (blue line).

model (Figure 7-b). Overall, in the new VS FWI Image the chalk appears flatter, the signal-to-noise ratio is improved at reservoir level and the Base Cretaceous Unconformity (BCU), indicated by arrows, is better imaged thanks to the least-squares process embedded in the PS-RFWI algorithm.

A comparison of the VS FWI Image with the legacy 30 Hz PS-RTM section (Figure 8) reveals that the new PS-based workflow led to similar improvements to those observed in the VP FWI Image (Figure 3) and shows good consistency with the VP FWI Image, also shown in Figure 8. Furthermore, we can see that the VS FWI image has comparable resolution to the VP FWI image above the chalk horizon (green line on Figure 8). We also observe imaging differences in some of the geological features. For example, the clean sands above the reservoir zone are brighter on the VS FWI Image, as expected from well data. However, the VP FWI image has a finer resolution beneath the chalk. We believe this is because of the higher signal-to-noise-ratio of the PP-data relative

to the PS-data in this deep region. This is evidenced by looking at either of the PS-RTM images (Figure 7-b or the middle panel of Figure 8), where we observe an absence of higher frequencies in the PS recorded data below the chalk, relative to the data quality above the chalk.

At this stage it is worth highlighting that the VP FWI image shown in Figure 8 was obtained at 65 Hz and subsequently filtered back to 30 Hz. Moreover, the VP FWI image uses all parts of the wavefield, i.e., primaries, multiples, and diving-waves. Therefore, in general, we would expect it to have better imaging properties compared to PS-RFWI that only uses primaries. Other known limitations of PS-RFWI are the need to correctly isolate the PS-reflections, the single-scattering assumption of Born modelling, and reliance on acoustically modelled PS data, with its known potential amplitude discrepancies between modelled and observed data. In our case, the impact of these issues could be handled with an appropriate FWI cost function and reliable well

Figure 7 Legacy VS model (a) and its corresponding 30 Hz PS-RTM migrated section (b). 30 Hz VS model (c) and its corresponding VS FWI Image (d). The green line on the seismic sections indicates the PP chalk horizon while arrows (red and green) indicate BCU. (e) Comparison of starting model (purple line), low wavenumber VS (yellow line) and high wavenumber VS (red line) with the well VS sonic profile (blue line).

Figure 6 Edvard Grieg reservoir facies (left), depth slice at 1900 m for the legacy V p velocity (middle) and for 65 Hz FWI V p velocity (right).

information. Finally, the crosstalk between VP and VS might not be fully addressed due to acoustic approximation, although our workflow endeavours to mitigate this by using the PP reflectivity obtained from the VP FWI.

Conclusion

The Edvard Grieg field turns out to be an exciting playground for new FWI developments. We have presented here how a sequential use of TLFWI – from the two vertical OBC components – and PS-RFWI – from the two horizontal components – can generate high-resolution VP and VS velocity models and resolve imaging issues. The most remarkable achievement is the flattening of the undulating chalk and top reservoir surfaces on both the VP and VS FWI Images, obtained from PP and PS data, respectively, which was confirmed by drilling observations. These derived VP and VS FWI Images reduce the uncertainty in reservoir characterisation.

As discussed above, PS-RFWI presents a few known limitations, leaving the door open to multi-component elastic FWI in the not-too-distant future. Nonetheless, the workflow presented here paves the way for obtaining high-resolution VS FWI models. More accurate VS models can reinforce the use of PS imaging for reservoir characterisation and field monitoring.

Acknowledgements

We would like to thank Aker BP and their partners in PL338, Wintershall Dea and OMV, and CGG for permission to publish this work. We also thank Nicolas Salaun, Daniela Donno, Adel Khalil and Zhigang Zhang for valuable discussions.

References

Bardainne, T. [2018]. Joint inversion of refracted P-waves, surface waves and reflectivity. 80th EAGE Conference & Exhibition, Extended Abstracts, We K 02.

Colnard, O., Loh, F.C., Doshi, R., Barkov, A., Lyandres, A., Lam Anh, N., Van Thanh, P., Van Khuong, V., Tien Vien, P., Gataulin, R., Geideko, O., Litunovsky, A. and Trong Khanh, N. [2019]. PP/PS Processing,

Inversion and Interpretation of Vietnam’s First 3D-4C OBC Survey in the Cuu Long Basin. 81st EAGE Conference & Exhibition, Extended Abstracts.

Dhelie, P.E., Danielsen, V., Haugen, J.A., Straith, K.R., Bakke, B.A., Janot, L, Roodaki, A. and Yu, Z. [2022]. Improved Reservoir Image and Well Placement Using Time-Lag Full Waveform Inversion. 83rd EAGE Conference & Exhibition, Extended Abstracts.

Feng, Z. and Schuster, G. [2019]. True-amplitude linearized waveform inversion with the quasi-elastic wave equation. Geophysics, 84(6), 827-844.

Masmoudi, N., Ratcliffe, A., Wang, M., Xie, Y. and Wang, T. [2021]. A practical implementation of converted-wave reflection full-waveform inversion. 82nd EAGE Conference & Exhibition, Extended Abstracts.

Peiro, M., Gao, W., Fotsoh, A., Masmoudi, N., Roodaki, A., Ratcliffe, A., Prigent, H., Leblanc, O. & Dhelie, P.E., Danielsen, V., Haugen, J.A. and Straith, K.R. [2022]. PS Imaging on the Edvard Grieg Field: Application of PS Reflection FWI and FWI Imaging. 83rd EAGE Conference & Exhibition, Extended Abstracts.

Salaun, N., Reinier, M., Espin, I. and Gigou, G. [2021]. FWI velocity and imaging: A case study in the Johan Castberg area. 82nd EAGE Conference & Exhibition, Extended Abstracts.

Twynam, F., Ford, R., Caprioli, P., Hooke, M., Whitebread, R., Dhelie, P.E., Danielsen, V. and Straith, K.R. [2020]. Improved reservoir monitoring with PP & PS time-lapse imaging utilising up/down deconvolution: Edvard Grieg field. 81st EAGE Conference & Exhibition, Extended Abstract.

Xu, S., Chen, F., Lambaré, G., Zhang, Y. and Wang. D. [2012]. Inversion on reflected seismic wave. 82nd Annual International Meeting, SEG, Expanded Abstracts.

Zhang, Z., Mei, J., Lin, F., Huang, R. and Wang, P. [2018]. Correcting for salt misinterpretation with full waveform inversion. 88th Annual International Meeting, SEG, Expanded Abstracts, 143-1147.

Zhang, Z., Wu, Z., Wei, Z., Mei, J., Huang, R. and Wang, P. [2020]. FWI Imaging: Full-wavefield imaging through full-waveform inversion. 90th Annual International Meeting, SEG, Expanded Abstracts, 656-660.

Figure 8 Comparison of the V p FWI Image filtered to 30 Hz (left), the legacy 30 Hz PS-RTM image (middle), and the 30 Hz VS FWI Image (right). The latter improves the flatness of the chalk (green line and arrows) and the reservoir below that matches with the image from the PP data.

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Explorers have a good idea of where global exploration hotspots are but excellent multi-disciplinary geoscience strategies are needed to identify sweet spots. They are focusing on areas where new sources of oil and gas that the world needs are expected to come from. And in the emerging energy transition explorers are identifying sweet spots for carbon capture and storage reservoirs, offshore wind farms, hydrogen and geothermal energy projects. The spotlight continues to fall on established hotspots in the Atlantic Margin such as offshore Guyana and Namibia but there are also new, and perhaps surprising, areas that are also emerging as hotspots that will be vital in years to come for the world to generate the energy it needs.

Anna Rumyantseva et al illustrate a methodology for achieving detailed mapping of sand injectites in the Greater Fram area by using seismic attribute analysis and integrating machine learning (ML) techniques specifically designed for detecting injectites and faults.

Avril Burrell presents the influence of transform tectonics during the development of the Côte d’Ivoire and Tano Basins and discusses the underexplored potential in the deepwater area.

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Neil Hodgson et al demonstrate how a source-focused strategy can help explorers to stay ahead of the competition offshore Namibia.

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Detailed mapping of sand injectites integrating seismic attribute analysis and machine learning techniques in the Norwegian North Sea

Anna Rumyantseva1*, Jaswinder Mann-Kalil1, Sara Mitchell1, Dean Macaulay1

and Alaa Triki1, illustrate a methodology for achieving detailed mapping of sand injectites in the Greater Fram area by using seismic attribute analysis and integrating machine learning (ML) techniques specifically designed for detecting injectites and faults.

Introduction

The Norwegian North Sea is an established oil and gas province where there continues to be sustained exploration and development efforts, with a focus on infrastructure-led exploration (ILX) strategies in recent years. Many discoveries within the remobilised sands of Paleocene and Eocene age have proven the injectite play. Large-scale sandstone intrusives have been actively explored in the South Viking Graben (SVG) since the first discovery in the Balder Field in 1967. Further north, in the North Viking Graben (NVG), the injectite play has recently been confirmed by discoveries such as Kveikje (2022) and Heisenberg (2023). For the 2024 exploration campaigns, operators have expressed interest in two new promising injectite prospects in the NVG area.

Recent advances in seismic imaging technology have significantly improved the understanding of the complex geometries of sand intrusions. This paper illustrates a robust methodology for achieving detailed mapping of sand injectites in the Greater Fram area (Figure 1), by using seismic attribute analysis, including RGB frequency blending from spectral decomposition analysis, and integrating machine learning (ML) techniques specifically designed for detecting injectites and faults. Combining these approaches enables a granular understanding of subsurface dynamics and facilitates enhanced reservoir characterisation. The key to our methodology is using newly processed dual-azimuth (DAZ) seismic data, characterised by advances in pre-processing, noise mitigation, and velocity model building (VMB) technologies. By leveraging reimaged north-south data with newly acquired east-west data we see uplifts in terms of illumination, resolution, signal-to-noise ratio, and demultiple (Buriola et al., 2023). Utilising ML to identify injectite geobodies provides deeper insights into these subsurface reservoirs, which allows a better understanding of the geometries of the injectites, and helps to increase the efficiency of hydrocarbon exploration and production.

Understanding the injectite play

Sand injectites are formed as a result of post-depositional remobilisation and injection of fluidised sands from the ‘parent

1 CGG

* Corresponding author, E-mail: Anna.Rumyantseva@cgg.com

DOI: 10.3997/1365-2397.fb2024038

Figure 1 Overview map of the study area indicating the locations of oil and gas fields where sand injectite reservoirs have been documented in the SVG, and where two recent discoveries were made in the NVG area.

sand’ into a mudstone-dominated, potentially sealing, sequence. This process can result in highly permeable reservoirs and can improve both the lateral and vertical connectivity of isolated reservoirs. The injected sands are complex and vary in geometry from being conical-shaped, wing-like, and saucer-shaped to highly irregular complex-shaped intrusions (Huuse et al., 2007). In the North Sea, large-scale sandstone injection complexes are

widespread within fine-grained deepwater mudstone deposits of the late Paleocene-early Eocene sections (Cartwright and Lonergan, 1996). Intrusions can be very thin with steeply dipping flanks, making them difficult to resolve with seismic imaging and evaluate during geological analysis.

The process of injection of fluidised sands typically follows along faults and fractures such as polygonal faults found in the North Sea. These faults are angular in nature and form due to stress variations and dewaterting in low permeable layers. As the sand is injected into these fractures, it can follow the path of least resistance provided by the fault planes. In other cases, the sand injectites cross-cut the polygonal faults and vice versa. This can result in the sand injectites being oriented parallel to the polygonal fault structures. The injectites often become encased within these low-permeability layers as they migrate through the subsurface, as seen in both the Kveikje and Heisenberg discoveries. In Figure 2, the Kveikje complex consists of two reservoir layers of the Late Paleocene-Early Eocene age connected by dyke-shaped injectites. The Heisenberg discovery is shallower in depth with a much stronger amplitude response and is more

laterally distributed. Age-equivalent analogues can be seen in the UK North Sea with the Gryphon Field and Fotla discovery, respectively.

In Figure 2, the Kveikje and Heisenberg injectite complexes exhibit variations in the top seismic amplitude response throughout their extent. Well results indicate a gas cap in both discoveries, which we can attempt to correlate to a soft seismic response indicating the possible gas-bearing intervals. To better understand these potential gas-bearing intervals and the complexity of the discoveries, a relative acoustic impedance (AI) attribute is shown in Figure 2b, commonly used to discriminate lithology and thickness variation. This has been obtained by integrating a zerophase trace and a low-cut Butterworth filter. The Kveikje injectite stands out as low relative AI values rather than a trough-peak pair with zero crossing in the centre of its position observed on the seismic section. This gives us a better estimation of the thickness of the softer sand layer. At the shallower depth of the Heisenberg discovery, the dyke-shaped and concordant sill-shaped injectites stand out as high relative AI features, possibly representing higher-density water-bearing sands compared to low-permeability

2 (a) Seismic section through the Kveikje and Heisenberg discoveries; yellow arrows indicate the areas where we observed a soft top of the sand injectites; (b) Relative acoustic impedance attribute section through the Kveikje and Heisenberg discoveries.

Figure

Figure 3 Southwest-Northeast DAZ seismic section passing through Wells A and B; colored gamma-ray wireline log shown at the well locations, which highlights sand intervals in yellow. In the seismic section, the interpreted surfaces correspond to the base (yellow) and top (magenta) of the Eocene fan 1, and the top of the Eocene fan 2 and the base of the Eocene fan 3 indicated in blue.

soft mudstone strata. A clear low relative acoustic impedance is observed at the Heisenberg discovery well location. This is seen where we identify the soft response in the seismic data, which correlates with the presence of the gas cap.

Analysing seismic attributes at the Kveikje and Heisenberg discoveries within the study area makes it possible to identify other injectites that show similar properties and responses. However, before going further, it is essential to establish the context by describing all key elements of the injectite play.

Identifying injectite bodies

To gain a deeper understanding of the complexities of the injectite systems in the study area, it is crucial to identify the sediment supply or the ‘parent sand’ body. Through our analysis of seismic data and attributes, we can interpret multiple levels of deep marine depositional sand systems. In Figure 3, three sand-rich packages are interpreted within the Eocene interval. A blocky, gamma-ray wireline log (Norwegian Offshore Directorate (NOD) well database) signature through the fans at the locations of Wells A and B indicates thick sandstone units with thin interbeds of mudstones. These sands can be linked to submarine fans originating from the Norwegian mainland which extend into the study area and terminate westwards. They tend to exhibit localised fan depositions that become more channelised basinward.

The base sand unit, Eocene fan 1, consists of low-amplitude, semi-continuous reflections that onlap onto the top boundary of the Balder Formation of Early Eocene age. Eocene fan 2 exhibits a different seismic response, which consists of relatively high-amplitude, partly chaotic internal reflections with discordant high-amplitude anomalies interpreted as sand injectites. The Heisenberg injectite discovery is located at the margin of this fan’s western termination. The third sand package, Eocene fan 3, is only present updip and can be seen in Well B. The characteristics of this system are very similar to those of Eocene fan 1 with more conformable, low-frequency reflectivity. This sequence pinches out between Eocene fan 2 and a mud-rich overburden consisting of polygonal faults and injectites. We can observe potential injectite routes from the interaction of these sand packages and mudstone units.

Three types of injectites are identified in the study area, as seen in Figure 4. Type 1 intrusions can be described as conical U, V, and W-shaped intrusions. Type 2 are flat-based bowl or saucer-shaped or wing-like intrusions. Finally, type 3 are irregular or complex sandstone intrusions mostly seen in the Oligocene interval (Nnorom et.al., 2021). The minimum amplitude seismic attribute extracted along horizons at different levels within the Cenozoic seismic units (CSU) illustrates the distribution of injectite complexes and individual injectites as an amplitude anomaly (Rumyantseva et al., 2023). Predominantly, type 1 (mainly V, W and occasionally U-shaped discordant amplitude anomalies) and type 2 (wing-like anomalies) sand injectites can be seen within the Eocene section.

RGB frequency blending from spectral decomposition analysis of an intra Eocene surface, representing the top of Eocene fan 1 and base of Eocene fan 2, illustrates the northeast-southwest direction of sedimentary supply. We see a brighter-frequency

Figure 4 Minimum amplitude seismic attribute extracted along the horizon through the Paleogene sequence showing the distribution of the injectite complexes in the study area: (a) Oligocene interval; (b) Eocene interval; (c) Paleocene interval; (d) seismic sections with different types of injectites identified.

blending response feeding in from the northeast and splaying out to the southwest. Well 35/10-6 confirms the presence of sand at the depth of the analysed surface (Figure 5a). The clear change between the bright, chaotic, undulating area in the north-east and the softer, channel-like frequency response in the central area highlights quite well where the Eocene fan 2 onlaps and pinches out and where the Eocene fan 1 continues to splay out in the central part of the study area.

The sweetness attribute map taken across the fan-splays of Eocene fan 1 shows the high amplitudes indicative of sand variations (Figure 5b). These bright amplitudes correlate with a bright response on the RGB frequency blending (Figure 5a). The seismic section seen in Figure 5c shows the relationship of this unit with the overlying V-shaped or conical type 1 injectites, with concordant sill-shaped elements.

Figure 5 (a) RGB frequency blending from the spectral decomposition analysis of an Intra Eocene surface. Seismic sections in the background of the image illustrate the Eocene fan 2 with highlighted MMU (Mid Miocene Unconformity) and URU (Upper Regional Unconformity). The white dots indicate wells that encountered sandstones at this level; (b) The lateral distribution of the parent sand is illustrated on this sweetness seismic attribute map extracted along the base of the Eocene fan. Black line shows location of the seismic section in image (c); (c) DAZ seismic section through the injectite and possible parent sand.

Identifying injectites and creating geobodies with machine learning

The previously described methods identify the presence of sand injectites but are constrained to the type of display indicating their presence. To fully appreciate their extent and complexity, it is helpful to represent them as 3D geobodies. In-house developed ML tools and the latest DAZ seismic data make this possible to achieve with a much quicker turnaround compared to manually picking the entire 2000 km2 area.

It is important to have good-quality indicators in the training dataset to ensure the viability of the ML algorithms. The seismic angle stacks were cleaned with deep neural network (DNN) denoise technology, and the time alignment of events was further improved from the near-stack reference point to enhance the amplitude versus offset (AVO). The data was then colour-inverted to Acoustic and Gradient Impedance (AI and GI respectively) and projected into chi values representative of lithology and fluid appropriate for the area.

The initial injectite mask is generated by a customised U-Net model, which has been pre-trained using a realistic synthetic dataset (Sancheti et al., 2023). Different injectite types were accounted for by tailoring this processing to four main areas

across the survey, encompassing the variability of size and shape. This preliminary injectite mask and the angle stacks formed the initial training dataset to fine-tune the model, which went through three passes of prediction, retraining, and validation in conjunction with input from in-house geoscientists to reduce erroneous predictions. Their input also proved useful in identifying areas where sampling limitations in the training sets had reduced the effectiveness of the fluid predictions. This was accounted for in later iterations and proved crucial when considering the Heisenberg and Kveikje discoveries.

Throughout these training iterations, the ML was upgraded from 2D training and inference to 3D training, which improved the continuity and reliability of the final injectite mask (Figure 6). Integrating DNN-based workflows into both the processing and interpretation stages of the seismic data analysis helped to obtain results much faster and with more detail (Sancheti et al., 2023). As a result, multiple injectites were created as ‘geobodies’ using the ML prediction mask. This allowed for a better understanding of the lateral distribution and complex geometries of the injectites (Figure 7). In map view, they vary from circular to oval and are occasionally segmented due to their occurrence within polygonal faults in the host rock.

In addition, a tailored DNN was implemented to assist with fault picking and to help highlight closely spaced polygonal faults in the study areas (Triki et al., 2023). A multi-task 3D UNet model was trained, using realistic noisy synthetic data, to predict both a fault probability and a structurally enhanced seismic volume with a higher signal-to-noise ratio. This approach generated improved fault probabilities with better surface continuity when compared to single-task learning. This was particularly apparent in challenging areas, containing low-resolution seismic events or imbalanced amplitudes within the polygonal faulted complex interval. The probability map predicted via ML was subsequently converted to a fault binary mask based on a user-defined threshold. Figure 8 shows an example of a seismic section and its corresponding fault mask prediction overlaid, both used by an interpreter to individually pick polygonally faulted structures.

To better understand the relationship between the polygonal faults and the injectites, an envelope seismic attribute can be seen in Figure 8e-f. This attribute, known as reflection strength, displays an acoustically strong (bright) response to both negative and positive events. In map view, injectites exhibit polygonal geometries due to their occurrence within polygonally faulted Eocene mudstone host strata. Various interactions between intrusions and fault planes have been observed in the study area. Injectites can be intruded along the fault plane; in other cases, they cross-cut the polygonal faults and vice versa. Additionally, instances have been observed where the propagation of the injectite terminates against a fault plane (Nnorom et al., 2021).

Prospective injectite identification

By analysing the seismic attributes at the location of the Kveikje and Heisenberg discoveries, other injectites of interest can be identified exhibiting similar characteristics and responses. In the map view, Figure 9 focuses on the response seen from the Heisenberg discovery through frequency blending and minimum amplitude results extracted from the upper part of the discovery.

At the Heisenberg discovery location, we observe the distribution of isolated high-amplitude anomalies, with a similar amplitude response in the northwestern corner. Both injectites are situated at the edge of the Eocene basin floor fan. This is where we anticipate facies variations and potential closures often associated with thick sealing mudstone intervals in the flanks of the Eocene fan, which thins westwards. The minimum

amplitude extraction made through the potential gas cap shows a similar response in the same injectite to the north-east.

A south-north seismic section (Figure 9c) reveals the identified injectite. It appears disconnected from a larger, brighter injectite to the north. The sandstone reservoir has been injected into the lower-permeability and surrounding polygonal faulted mudstones of the Hordaland Group, creating

Figure 6 (a) Full stack; (b) Full stack with initial picked injectite mask overlaid; (c) Full stack with final iteration ML 3D injectite mask prediction overlaid; (d) Full stack time slice; (e) Time slice with initial picked injectite mask overlaid; (f) Time slice with final iteration ML 3D mask overlain.

Figure 7 Injectite geobodies extracted from the ML prediction mask. These are conical saucer-shaped in the central part and wing-like types on the sides.

a potential ‘intrusive trap’. Analysing the seismic response seen at Heisenberg as an analogue, we observe both a hard and soft top of the injectite body (soft top highlighted with yellow arrows), where the soft reflector potentially indicates gas-filled parts of the reservoir. On the relative AI section, these parts of the prospective injectite depict lower values, whereas the bright injectite in the north stands out as a continuous sand body with high values (Figure 9d).

These lower relative acoustic impedance values correlate with the strong negative fluid and could indicate gas-filled sandstones (Figure 10a). The fluid attribute was created by combining AI and GI, projecting the data into chi-rotations, and maximising the differences between various fluids. However, it is important to note that brine sands might also contain oil, as oil and brine have similar densities. Therefore, we can suggest that the brine and oil sands are represented in yellow as shown in Figure 10a.

By utilising the ML injectite prediction mask, as described in the previous section, a geobody of the prospective injectite can be created. This extraction allows us to discern the intricate geometry of the feature (Figure 10b). Given the time saved by using the ML-generated injectite mask, we were able to commence the analysis promptly. Furthermore, the lateral distribution of the extracted injectite body is shown in Figure 10c, where we can see the connection of the prospective

Figure 9 (a) RGB frequency blending from spectral decomposition analysis of an Intra Eocene surface; (b) Minimum amplitude seismic attribute extracted along the horizon at the depth of the Heisenberg discovery; (c) A southnorth-oriented seismic section depicting the prospective injectite and the northern injectite complex; (d) Relative acoustic impedance attribute section through the prospective injectite and northern injectite complex.

injectite to the larger body in the west. This sand body can potentially be used for volumetric analysis in subsequent stages.

Conclusions

This study presents a valuable combination of approaches that can be applied to enhance the success rate of sand injectite prediction using seismic attribute analysis and RGB blending combined with DNN algorithms.

The resulting analysis of spectral decomposition and RGB blending allows a better understanding of the deposition pathways of deep marine sediments and the distribution of injectites in the study area. Sweetness, minimum amplitude, envelope, and relative acoustic impedance seismic attributes extracted from the DAZ seismic data provided valuable information about the geophysical properties of the injectites and hosting low-permeability mudstone strata.

Successive iterations of ML training and prediction of the injectites, utilising the seismic data and seismic attribute analysis, honed the results to significantly reduce any erroneous predictions. As a result, several clearly defined geobodies representing the sand intrusives were created. Combining the envelope seismic attribute with ML fault prediction gave a better understanding of the interaction of high-amplitude injectites with the polygonal fault network in the study area.

Figure 8 (a) DAZ seismic section; (b) the ML predicted faults; (c) DAZ seismic section with ML fault prediction overlaid and interpreted injectite body shown in yellow; (d) the ML-predicted faults at a 1.788-sec depth; (e) Envelope attribute; (f) Envelope attribute with ML fault delineation overlaid.

By comparing seismic attribute responses at the discovery location, we were able to identify other areas with similar properties to the extracted attributes and defined a prospective injectite. The time saved by using the ML-generated injectite mask enabled us to commence the analysis promptly and to create a geobody of the prospective injectite for volumetric analysis.

The proposed methodology has the potential to enhance the success rate of sand injectite prediction in hydrocarbon exploration. In the North Sea there are promising opportunities for near-field accumulations of hydrocarbons. Notably, recent discoveries like Kveikje and Heisenberg serve as excellent examples of this potential.

Acknowledgements

The authors would like to thank CGG Earth Data for permission to show data from the Northern Viking Graben 3D seismic dataset. We acknowledge the contribution made by our colleagues in CGG’s Subsurface Imaging and AI Lab teams. Special thanks goes to Professor Mads Huuse for sharing his injectite knowledge with us.

References

Buriola, F., Mann-Kalil, J., Latter, T., Kjølaug, I. and Rumyantseva, A. [2023]. How technological advances in seismic acquisition, process-

Figure 10 (a) Fluid volume section through the prospective injectite; (b) Seismic section through the injectite with overlaid ML injectite prediction mask shown in yellow; (c) Injectite geobody created from the ML prediction mask.

ing and imaging can bring new insights to near-field exploration. First Break, 41, 63-70.

Cartwright, J. and Lonergan, L. [1996]. Volumetric contraction during the compaction of mudrocks: A mechanism for the development of regional-scale polygonal fault systems. Basin Research, 8, 183-193, https://doi.org/10.1046/j.1365-2117.1996.01536.x.

Huuse, M., Cartwright, J., Hurst, A. and Steinsland, N. [2007]. Seismic Characterization of Large-scale Sandstone Intrusions. Sand injectites: Implications for hydrocarbon exploration and production: AAPG Memoir, 87, 21-35, https://doi.org/ 10.1306/1209847M873253.

Nnorom, S. and Huuse, M. [2021]. Three-dimensional seismic and quantitative geometrical characterization of sandstone intrusions in the Paleogene succession of the northern North Sea Basin; https//pure.manchester.ac.uk/ws/portalfiles/portal/250506344/FULL_ TEXT.PDF

Rumyantseva, A., Mann-Kalil, J., Mitchell, S., Macaulay, D. and Sancheti, O. [2023]. New Insights on the Injectite Play in the Northern North Sea using ML; AAPG ICE conference 2023, Spain; abstract for poster.

Sancheti, O. and Hou, S. [2023]. A generalized U-Net for injectite detection; 84th EAGE Annual Conference Exhibition, abstract.

Triki, A., Latter, T., Hou, S., Raju, A., Bourne, V. and Buriola, F. [2023]. Using DNNs to overcome challenges in seismic processing and interpretation; NCS Exploration 2023, abstract.

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Understanding tectonic development and the implications for prospectivity offshore Côte d’Ivoire and Ghana

Avril Burrell1* presents the influence of transform tectonics during the development of the Côte d’Ivoire and Tano basins and discusses the underexplored potential in the deepwater area.

Introduction

The Côte d’Ivoire and Tano basins form a prolific hydrocarbon-producing province with several large, high-profile discoveries made in recent decades including the discovery of the Jubilee (Kosmos, 2007) and TEN (Tullow, 2009) fields in Ghana, and the play-opening discovery and subsequent expansion of the Baleine structure (Eni, 2021/2022) offshore Côte d’Ivoire. The basins are located within the Gulf of Guinea transform margin and bounded by two transform fracture zones: the Saint Paul’s Fracture Zone to the north west and the Romanche Fracture Zone in the south east. The area formed during the opening of the Atlantic and this comparatively structurally quiescent location between two fracture zones has led to the consistent spatial-temporal deposition of marine clastic sediments. Using regionally extensive 3D seismic data, observations can be made on the influence transform tectonic development has had on the structural architecture of the basin and the inherent implications for prospectivity. Through these insights, remaining underexplored potential in the deep water can be highlighted drawing on analogues from the southern Atlantic.

Exploration history

Hydrocarbon exploration in the shallow offshore of the Tano Basin began in the 1970s, with two main international operators leading drilling efforts: Esso and Phillips. During this period, the majority of discoveries were made offshore Côte d’Ivoire (Lion, Panthere and Belier), with a smaller number of discoveries found

offshore Ghana (Tano South and Cape Three Points) (Figure 1). These discoveries highlighted the mixed oil and gas potential in structural traps in the Cretaceous section on the shelf.

Exploration efforts continued in Côte d’Ivoire in the 1980s with the discovery of large fields in Albian plays such as Espoir (189 MMboe recoverable) and Foxtrot (146MMboe recoverable) (S&P Global Basin Monitor Report, 2024). By 1986, after limited drilling success, all companies in Ghana had relinquished their licences. In the 1990s there was no exploration offshore Ghana. In the 1990s there was, with only one new field wildcat well (West Cape Three Points 1) drilled by Hunt Oil towards the end of the decade in 1997. Similarly, in the late 1990s there was a lack of discoveries in the shallow waters of Côte d’Ivoire.

The early 2000s kick-started the push into deepwater exploration with a focus on Upper Cretaceous turbidite channel systems in combination structural/stratigraphic traps. The largest discovery in Ivorian waters was made with the drilling of Baobab in 2001 (230MMboe recoverable), rapidly followed by Paon (213MMboe recoverable) (S&P Global Basin Monitor Report, 2024). The discovery of the Jubilee Field in 2007 (Kosmos) and the TEN fields (Tullow) in 2009 in Ghana lead to a revival of activity in the region, marking the basin as a global hotspot and inspiring the hunt for analogue plays across the margin.

Recent success in Cote d’Ivoire with the discovery of the Baleine Field (Eni, 2021) has expanded the Upper Cretaceous play to include carbonate shelf edge reservoirs. In Ghana, the

1 PGS

* Corresponding author, E-mail: avril.burrell@pgs.com

DOI: 10.3997/1365-2397.fb2024039

Figure 1 Map showing the PGS multi-client data library in the Gulf of Guinea used in this work, with key discoveries mentioned in the text indicated.

Eni Eban-1X discovery is reported to have found light oil in an 80m-thick section of Cenomanian sandstones. These large accumulations show that significant volumes of hydrocarbons are found in Cretaceous-aged plays over continental crust in this well-explored basin.

Understanding tectonic history

The Tano and Côte d’Ivoire basins developed during the opening of the Atlantic, with transform rifting beginning in the Late Jurassic to Early Cretaceous periods and finishing at the end of the Albian with the formation of oceanic crust (Brownfield and Charpentier, 2006). By the Late Albian to Early Cenomanian periods Brazil and West Africa had fully broken apart ending the major phase of tectonic development along the Gulf of Guinea margin (Antobreh et al., 2009). Intrusive volcanics are observed around the syn-transform regional unconformity from the Albian to Cenomanian-Turonian levels on 3D seismic near the Romanche Fracture Zone, but are unlikely to have significant effects on source rock maturity due to their limited extent.

The Tano Basin developed in an area of relative tectonic quiescence between the Saint Paul’s and Romanche Fracture Zones, resulting in pull-apart grabens with a thick clastic fill. The St Paul’s transform fault terminates into a curved coastal fault in the eastern Ivorian offshore and evolves into a horsetail splay structure at the connection with the Romanch Fracture Zone, offshore Ghana (Basile et al. 2005). Generally, this has created a broad shelf to deepwater profile in much of the basin, underpinned by thick continental crust, gradually thinning towards the continental to oceanic crustal transition (Figure 2). The continental to oceanic crustal transition between the St Paul’s and Romanche Fracture Zones in the western Tano Basin is not clearly defined by the Bouguer-corrected gravity data (Antobreh et al., 2009) but has been interpreted using PGS regional 3D seismic coverage.

In comparison, the Côte d’Ivoire Basin to the west has a narrow shelf to deep-water profile, characterised by transform faulting and initial graben development orientated sub-parallel to the present-day coastline. The continental to oceanic crustal transition is also more abrupt here and visible on the Bouguer-corrected gravity data. This is due to the underlying Saint Paul’s Fracture Zone creating a significant gravity contrast

Figure 2 Bouguer corrected gravity anomaly map (200km HP filter) (Sandwell et al. 2014) displaying the key tectonic lineaments along the Gulf of Guinea margin. The Saint Paul’s and Romanche Fracture Zones are highlighted, along with the Continental to Oceanic Crustal Boundary (COB).

between thick, high-density continental crust to the north and low-density oceanic crust immediately to the south.

The stratigraphic section of both areas can be divided into the pre-, syn- and post-transform tectonic phases, each with a distinct depositional history and related petroleum systems. The pre-transform succession outcrops onshore in Ghana and is composed of Precambrian to Triassic-aged strata. Within the Tano Basin, pre-transform Jurassic-aged conglomerates and shales deposited in a continental setting have been tested by drilling and are likely to have been sourced from the erosion of uplifted shoulders along the basin margins (Basile et al., 2005).

The syn-transform phase of transtensional opening in the Gulf of Guinea began around the Berriasian and ceased at the end of the Albian. A thick section of continental to marginal marine clastics was deposited during this period, providing potential reservoir units in the form of fluvial to marginal marine sandstones. (Brownfield and Charpentier, 2006). Source rocks transition from deeper Aptian lacustrine shales to shallower Mid-Albian marginal marine shales through the stratigraphic section as rifting progressed.

Extensional opening of the transform margin basins ceased at the end of the Albian and was followed by wide-spread deposition of Cenomanian-Turonian marine shales (MacGregor et al. 2003). The area formed a continuous anoxic seaway from the late Albian to Turonian (Tissot et al. 1980) in which a number of high total organic carbon content (TOC) oil prone source rocks developed.

Exploring the petroleum systems

Two main plays have been the focus for exploration in the Ivorian and Ghanian offshore, the syn-transform Lower Cretaceous and the post-transform Upper Cretaceous (Figure 3). The Lower Cretaceous play dominates the area around the shelf edge in the Tano Basin. A contributeng factor in this inboard dominance is the source rock maturation history. Berriasian to Albian source rocks sit within the gas maturity window around the shelf due to a relatively thinner overburden, whereas they are likely to be over-mature in more distal syn-transform basins where depth of burial is greater. These source rocks are paired with Albian-aged fluvial to shallow marine syn-transform sandstones, as proven in the Baobab Field (CNR, 2001).

The Upper Cretaceous system is most successful around and outboard of the present-day shelf edge due to the thick clastic section allowing for sufficient burial of shallower Cenomanian-Turonian-aged source rocks. These type II source rocks have mixed oil and gas potential (Tissot et al. 1980). Complementing this widespread source kitchen are Albian to Santonian-aged shallow to deep marine sandstone reservoirs deposited as turbidite channel and fan systems. The largest discovery in the Upper Cretaceous system is contained within the Baleine shelf-edge structure which is reported by Eni to contain 2.5 billion barrels of oil and 3.3 trillion cubic feet (TCF) of associated gas over two main reservoir levels. This discovery has also expanded the play to include carbonate shelf edge reservoirs. This inferred carbonate build-up is observed on seismic as a high amplitude, parallel layered sequence which developed on an isolated shelfedge terrace. The Paon (Anadarko, 2012) discovery has proven that the Upper Cretaceous play extends into the deepwater Tano Basin, with the Saphir-1X well (TotalEnergies, 2014) illustrating that the play extends to the west in the Côte d’Ivoire Basin.

Tectonic segment styles and sediment Input

Four main tectonic segments are identified as being present within a classic transform margin as classified by Cronin et al. 2023: 1. the transform margin sensu stricto, 2. local pull-apart segment on the transform margin, 3. narrow horsetail segment splaying off from the transform and 4. the extensional end at the horsetail structure. Each of these segments shows distinctive sediment routing characteristics owing to key differences between the shelfal staging widths, deep-water slope gradient and seabed topography across the four classifications. Due to the presence of two fracture zones and the well-preserved record of structural architecture, seismic

sections from three of these segments will be shown from the Côte d’Ivoire and Tano basins (Figures 5-7). The locations of the sections are indicated on a seabed depth surface generated from PGS

Figure 3 Tectono-stratigraphic column for the Ivorian Tano Basin (modified from Scarselli et al. 2019). Key reservoir, source and seals are highlighted across the synand post-transform stratigraphy.

Figure 4 Seabed depth horizon (seconds, TWT) from PGS multi-client merged 3D seismic data highlighting three of the tectonic segment styles present offshore Côte d’Ivoire and Ghana as classified by Cronin et al. 2023. The approximate location of the three seismic lines in Figures 5-7 are indicated by the orange polygons 1, 3 and 4.

merged 3D seismic coverage in Figure 4. As stated by Cronin et al. (2023), the authors were limited in their ability to share seismic examples throughout their work due to confidentiality restrictions; PGS multi-client data will be used to show direct examples.

Regional 3D seismic data coverage has been used to demonstrate the evolution in tectonic segment styles across the Côte d’Ivoire and Tano basins, highlighting the implications for reservoir distribution along the margin. Figure 5 shows a full-stack 3D seismic line from the Côte d’Ivoire Basin, where the St Paul’s Fracture Zone immediately underlies the section. The narrow, sand

prone shelfal staging width, high deep-water slope gradient and steep seabed topography from the first classification of segment styles (transform margin sensu stricto) are clearly observed. The transform margin sensu stricto results in bypass-dominated clastic depositional systems due to the steep, single-faulted margin where sediments bypass the slope through deep shelf-edge canyon systems (as evidenced on the seabed depth image in Figure 4). Sediments are sourced from the high-margin plateau and pond in deep water on the basin floor over a relatively short sediment transport distance due to lack of intra-basin terraces (Cronin et al., 2023).

Figure 5 Merged 3D full-stack prestack time migrated (PSTM) seismic dip line across tectonic segment classification 1: transform margin sensu stricto (approx. line location indicated by polygon 1 on Figure 4). This line shows the abrupt lateral change from thick continental crust in the northwest to oceanic crust in the southeast across the single faulted margin of the St Paul’s Fracture Zone.

Figure 6 Merged 3D full-stack PSTM seismic dip line across tectonic segment 3: narrow horsetail segment (approx. line location indicated by polygon 3 on Figure 4). This line shows the change in style from the single faulted margin in Figure 5 to the extension dominated tectonics of the narrow horsetail resulting in ramp-terrace profile.

Further to the east in Figure 6 is a typical profile from type three of the tectonic segment classifications: the narrow horsetail segment splaying off from the transform margin. Here we observe a relatively wider shelfal staging width, lower deepwater slope gradient and a gentler seabed topography. The extensional block faulting in this style of segment results in more terrace and ramp style paleo-bathymetry which has significant implications for ponding of clastic sediments on the terraces. Continental crust is thinned here through extension related to the horsetail structure, with a system of oblique-slip faults stretching continental crust away from the transform margin sensu stricto (Cronin et al., 2023).

In the centre of the Tano Basin, in Figure 7, is a typical profile from type three of the segment styles: the local pull-apart segment on the transform margin. Here we observe a relatively wide shelfal staging width, extended deep-water slope gradient and a gentler seabed topography. The extensional block faulting in this style of segment results in numerous alternating ramps and terraces with sand sequestration occurring along the slope profile within stacked frontal splays. Levee-confined slope channel complexes are also common (Cronin et al., 2023).

Implications for prospectivity

Due to the close relationship between transform segment style and clastic deposition patterns in a region dominated by combination stratigraphic/structural traps, there are clear implications for prospectivity from west to east across the Côte d’Ivoire and Tano Basins. To demonstrate this relationship, sediment distribution can be illustrated using an RMS amplitude extraction from the Upper Cretaceous as shown in Figure 8. This has been created from merged full-stack PSTM 3D datasets.

In the east of the Tano Basin, the area of transform segment style four: the extensional end at the horsetail segment dominates and we can observe the influence that the ramp-terrace style has on shelf to deep-water sand distribution. Sands are segregated within terraces as frontal splay complexes or sheet sands before bypassing the subsequent down-slope ramp and then being ponded in the next terrace. This low gradient, extended paleo-bathymetry over thinned continental crust allows for development of combination stratigraphic/structural traps at multiple levels on the shelf slope. This depositional pattern is more entrenched at segment four in the Tano Basin and becomes less prevalent to the west as the structural extension of the horse-tail splay decreases towards the transform margin sensu stricto.

To the west, in areas along the Saint Paul’s Fracture Zone the steep single-faulted margin of the transform margin sensu stricto results in clastic sediment bypassing the slope and being deposited in the deepwater basin floor. As demonstrated by the Bouguer-corrected gravity anomaly map in Figure 3 and the seismic interpretation in Figure 5, sediments here are deposited directly over oceanic crust. This deep-water area in both the Côte d’Ivoire and Tano basins is relatively underexplored although basin floor fans are clearly observed to be widely present along the margin (Figure 7). This lack of exploration may be attributed to a perceived absence of trap development where existing up-slope discoveries rely upon faults from the ramp/terrace structures to form the up-dip trap for Upper Cretaceous plays.

However, recent 2022 exploration success offshore Namibia with TotalEnergies’ Venus-1 discovery has suggested that Upper Cretaceous turbidite reservoirs at the base of slope can prove successful by utilising outer highs and counter-regional dip to

Figure 7 Merged 3D full-stack PSTM seismic dip line across tectonic segment 4: extensional end at horsetail segment (approx. line location indicated by polygon 4 on Figure 4). This line shows the extended lateral change from thin continental crust in the northeast to oceanic crust in the southwest with multiple ramp-terrace structures occurring along the shelf to deep water profile.

Figure 8 RMS amplitude extraction from the Upper Cretaceous created using PGS merged 3D full stack pre and post stack time migrated seismic data. The location of the three transform segment styles is highlighted showing the implications for sediment distribution across the margin. From left to right; segment style 1: steep shelf gradient and sediment bypass to deepwater over oceanic crust. Segment style 3: moderate deepwater slope gradient and wider shelf staging area: intra-slope terraces with deposition on shelf slope. Segment style 4: lowest slope gradient and widest shelf staging area: extensive intra-slope ramp/terraces and sediment ponding. Note the spatial/ temporal focus of sediments at the base of slope across the figure.

provide trapping mechanisms. Similar concepts can be applied to the outboard area of the Côte d’Ivoire and Tano Basins where deepwater sediments are observed to drape over oceanic crustal highs in four-way dip closures.

Drawing further on the Namibia play analogues, Cretaceous-aged source rocks deposited over transitional-to-oceanic crust in the deep-water Orange Basin are oil mature in outboard areas. The concept for hydrocarbon generation and expulsion from source rocks subjected to increased heat flux from the mantle (Doran et al. 2017) may also be applied to the deep-water offshore of Côte d’Ivoire and Ghana, expanding prospectivity beyond the area underpinned by continental crust. Cenomanian-Turonian aged shales are a proven source rock offshore Côte d’Ivoire containing high TOCs and are characterised by their low amplitude, planar response typical of deepwater shale deposits, as highlighted in Figure 5.

This regional scale understanding of petroleum systems highlights the exciting opportunities remaining over oceanic crust in the Côte d’Ivoire and Tano Basins, allowing exploration potential to be extended from analogs and existing in-basin discoveries into underexplored areas.

Conclusions

The shelf and slope areas of the eastern Côte d’Ivoire and Tano Basins are well explored with large, play opening hydrocarbon discoveries being made since the early 2000s with continued success as the plays have emerged. The region’s success can be directly attributed to the influence of transform tectonics. This location between the Saint Paul’s and Romanche Fracture Zones has produced favourable conditions for the two main Cretaceous-aged plays to develop resulting in the region becoming an exploration hotspot. Through extensive seismic data coverage, key authors from international operators have developed new insights into the influence transform tectonics have had on developing the basin architecture resulting in four classifications of transform segment styles. These have direct implications for prospectivity due to the way reservoir sands are developed and distributed across the shelf to deep-water profile in relation to the segment style. Through these insights, analysis of regionally extensive PGS seismic data

and by building on analogues from offshore Namibia, remaining underexplored potential in the deep water can be revealed.

Acknowledgements

PGS multi-client seismic data was developed in partnership with Petroleum Commission, Ghana and Direction Générale des Hydrocarbures and PetroCi Holdings, Côte d’Ivoire. The author would also like to thank geoscience colleagues at PGS for their assistance in preparing and reviewing the article.

References

Antobreh, A.A., Faleide, J.I., Tsikala, F. and Planke, S. [2009]. Rift-shear architecture and tectonic development of the Ghana margin deduced from multichannel seismic reflection and potential field data. Marine and Petroleum Geology, 26(3), 345-368.

Basile, C., Mascle, J. and Guiraud, R. [2005]. Phanerozoic geological evolution of the Equatorial Atlantic domain. Journal of African Earth Sciences. 43, 275-282.

Brownfield, M.E. and Charpentier, R.R. [2006]. Geology and total petroleum systems of the Gulf of Guinea province of West Africa. U.S. Geological Survey Bulletin, 2207-C.

Cronin, B.T., Nemčok, M. and Doran, H. [2023]. Transform margin source-sink clastic deposystems. Geological Society, London, Special Publications. 524, 387-419.

Doran, H. and Manatschal, G. [2017]. Breaking Up Is Never Easy. GEOExpro, 14(3).

MacGregor, D.S., Robinson, J. and Spear, G. [2003]. Play fairways of the Gulf of Guinea transform margin. Geological Society, London, Special Publications. 207, 131-150.

S&P Global [2024]. Cote d’Ivoire Basin, IHS Markit Basin Monitor Report.

Sandwell, D.T., Müller, R.D., Smith, W.H.F., Garcia, E. and Francis, R. [2014]. New global marine gravity model from CryoSat-2 and Jason-1 reveals buried tectonic structure, Science. 346(6205), 65-67.

Scarselli, N., Duval, G., Martin, J. and McClay, K. [2018]. Insights into the early evolution of the Côte d’Ivoire Margin (West Africa). Geological Society, London, Special Publications. 476, 109-133.

Tissot, B., Demaison, P., Masson, P., Delteil, R. and Conbaz, A. [1980]. Paleoenvironment and petroleum potential of Middle Cretaceous black shales in Atlantic Basins. AAPG Bulletin, 64(12), 2051-2063.

Unveiling the petroleum potential of one of the world’s last frontier petroleum provinces: the Bengal Fan, offshore Bangladesh

Elisabeth Gillbard1* presents high-resolution seismic imaging illustrating the extensive petroleum potential of the Bengal Fan, from shelf and slope to the deep-water domain.

Abstract

The Bay of Bengal contains the world’s largest deep marine fan and yet remains almost entirely unexplored for petroleum. Evaluation of more than 12,600 line km of 2D seismic, gravity and magnetics data acquired by TGS and their partners SLB in 2023 (Figure 1), alongside historic well data, has provided a regional framework for understanding the evolution of the whole geological history of the basin and insight into the extensive petroleum potential of this highly frontier region. In this paper, we will present high-resolution seismic imaging, characterising the facies and reservoir architecture within the fan and illustrating the extensive petroleum potential of the Bengal Fan, from shelf and slope to the deep water domain.

Introduction

The discovery of several large gas fields within the Bengal Fan between 2004 and 2016 (e.g., Shwe, Shwe-Phyu, Mya, Thalin gas fields) has proven the vast potential within this highly active petroleum system. In March 2024 the Government of the People’s Republic of Bangladesh and The Bangladesh Oil, Gas and Mineral Corporation (Petrobangla) announced an offshore bidding round for oil and gas exploration, the first since 2012. This highly anticipated licensing round offers 24 blocks extending from the shelf and slope to the deep water, a significant area of which is covered by 2D seismic data, which is the subject of this paper (Figure 1).

The 2D seismic data spanning the shelf, slope and deep water offshore Bangladesh were acquired with long offsets (10 km) and have been processed with modern preprocessing workflows (including deghosting, surface-related multiple-elimination (SRME), shallow-water demultiple) with particular emphasis on the shallow-water area on the platform. For the velocity model building, an integrated tomography and full-waveform inversion (FWI) workflow was implemented alongside geological interpretation to refine and improve the imaging of discrete features such as channel bodies and gas pockets and to constrain anisotropy.

Geological setting

The Bay of Bengal is a rifted passive margin initially established during the disintegration of Gondwana (e.g., Curray, 1982;

Powell, 1988; Curray, 1994). Rifting was initiated during the early Jurassic (~180 Ma) period, with the first oceanic crust forming in the Lower Cretaceous (120-130 Ma) as a result of the separation of the Indian and Antarctica plates (e.g., Gopala Rao et al., 1997). As India drifted northwards, it started its collision with Asia around 59 Ma, initiating the Himalayan uplift. However, the full hard continent-continent collision did not begin until around 15 Ma, resulting in the main Himalayan Orogeny and the major increase in sedimentation, which resulted in the deposition of

1 TGS

* Corresponding author, E-mail: elisabeth.gillbard@tgs.com

DOI: 10.3997/1365-2397.fb2024040

Figure 1 Location map of the 2D seismic data used in this study

2 Schematic geo-seismic dip section across the Bengal Fan, showing the regional sequences and key hydrocarbon plays discussed in this study.

the Bengal Fan. The Sunda Subduction Zone and Indo-Burman accretionary prism mark the eastern extent of the Bay of Bengal, active since approximately 20 Ma. Compression from this margin is evident in the eastern part of the area of interest (AOI), with structural deformation decreasing westwards.

The Bengal Fan is the largest submarine fan in the world, with a length of up to 3000 km, a width of 1200 km, and up to 16 km of sediment thickness (Curray et al., 2003). The primary sedimentary source is the Ganges-Brahmaputra and equivalent historic river systems, which are relatively sandy compared to major modern rivers (Coleman, 1969). The uplift of the Indo-Burman Ranges provided an additional secondary sediment input to the Bay of Bengal, increasing in influence during the Pliocene (Alam et al., 2001). Both erode from a mainly volcanic provenance, resulting in the deposition of clean and well-sorted sediments.

Initial fan sedimentation was likely started as early as the lower Eocene (Curray, 1994). However, the majority of the sediment has been deposited since the Lower Miocene period, with the development of prograding deltaic deposits on the shelf and linked deep-water sequences. The present-day sediment input to the fan is confined to a large submarine channel known as the ‘Swatch of no Ground’ (SoNG). Equivalent ancient feeder systems have migrated significantly over the geological past, with rapid migration of depositional centres from the east to the present position in the west. Although many studies have documented sedimentary processes relating to the SoNG (e.g., Curray et al., 2003; Schwenk et al., 2005) and around petroleum discoveries on the northeastern flank of the fan (e.g., Ma et al., 2020; Shoup et al., 2017), very little has been published on the rest of the fan.

Nearly 200 m of well-sorted Pliocene-aged silts and sands were encountered within pelagic sediments in Deep Sea Drilling Program (DSDP) Site 211, over 2800 km from the present-day shoreline (Curray et al., 2003). Site 218 cored 125 m of silty

sand in water depths of 3759 m over the 90-degree E ridge. Deep-sea sands have also been encountered in several wells offshore Myanmar (e.g., Shwe Field), with porosities up to 33%, maximum permeability of 653 mD and net to gross of 83% (Zhou et al., 2020). The presence of high-quality sand material within the deep-water distal fan, alongside a comparison with other large fan systems (e.g., Niger Delta, Mississippi Fan), offers high confidence in the transportation of coarse material considerable distances from the sediment source.

Bengal fan play concepts

Several play concepts are recognised within the Bengal Fan, offshore Bangladesh (Figure 2). Biogenic, and both proven and untested thermogenic, source rocks have been identified in the regional data (S1-S4). Predicted reservoirs can be divided into early fan, shelf, slope and deep-water facies (R1-R4). Intraformational sequences, channel muds and lateral pinch-outs provide seal and stratigraphic traps. Structural traps within low-wavelength anticlines and faulted structures have also been identified within the AOI. These plays will be discussed in the subsequent sections and leads at multiple stratigraphic levels have been identified.

Source Rocks and Petroleum Systems

All the recent discoveries within the Bengal Fan have been sourced from intraformational biogenic gas contemporaneous with the reservoirs (Shoup et al., 2017). However, there is also considerable evidence for several thermogenic systems. The gas source for the nearshore Sangu Field has been typed to Miocene interbedded shales, and equivalent sequences were drilled in the BODC and Bina wells further offshore, where they were found to be oil-prone Type III shales (Baric et al., 1977). Pre-fan, Late Eocene to Early Oligocene source rocks actively produce oil and gas in adjacent

Figure

Myanmar. Meanwhile, analogue basins offshore East India yield oil-prone source rocks of Upper Cretaceous age. Gas hydrates and direct hydrocarbon indicators (DHIs) are very common within the seismic data, proving an active gas system (Figure 3).

While the intraformational Miocene and Pliocene source rocks have been well documented, the presence of a Cretaceous source rock has not been proven within the Bay of Bengal. Cen-

omanian-Turonian syn-rift source rocks are producing gas from oil-prone source rocks offshore East India (Qin et al., 2017). The Turonian/Cenomanian Oceanic Anoxic Event (OAE II) resulted in global occurrences of black shales. Correlation of proven Cretaceous units from the east Indian basins shows the presence of a thin syn-rift unit overlying basement structures across the AOI. This unit is characteristically low amplitude and transparent

Figure 4

PSTM seismic dip line through from shelf to slope showing the three identified megasequences (MS I, MS II and MS III) and associated MRS. Associated low-stand features have been highlighted, such as the large-scale truncation relating to shelf collapse and downslope occurrence of basin floor fans and mass transport deposits within predictable sequences. Red arrows denote the direction of shelf break, showing progradation in MSI and MSII, downlapping progradation to aggradation in MSIII then retrogradation since the Pleistocene.

Figure 3 Pre-stack time migrated (PSTM) seismic images showing direct hydrocarbon indicators (DHIs) in the form of gas anomalies throughout the data.

and shows thinning onto structural and volcanic highs, with local restriction. Tectonic reconstruction of the mid-Cretaceous shows that although the Bay of Bengal sat in the open ocean, there was localised restriction due to the emplacement of the Kerguelen Hot Spot around 120 Ma, forming the 85-degree E and 90-degree E ridges (Scotese and Zumberge, 2007). These restrictions could have enabled the formation of high-class OAE source rocks within syn-rift basins overlying the basement.

Although no direct geothermal gradient data is available, imaging of the whole sedimentary unit to basement provides confidence that petroleum systems modelling would be relatively easy to constrain in the Bay of Bengal. Further work needs to be done to confirm regional modelling of potential and known source rock units.

Reservoir architecture and seismic facies

In order to develop a predictive reservoir model for the Bengal Fan, it is essential to understand how the system evolved within the AOI, from early fan deposition through to present-day bypass. By looking at the whole fan system, we are better able to see the changing character and architecture of the potential reservoir facies moving from shelf to basin floor.

Within the shelf area of the AOI, the fan can broadly be divided into three mega sequences (MS) (Figure 4): Lower Miocene (MS I), Middle Miocene to Pliocene (MS II) and Pliocene to Recent (MS III). These mega-sequences can be readily identified in the seismic data and represent the progressive facies changes within the prograding system, divided by regional maximum regression surfaces (MRS) relating to lowstand events. MS I is characterised by broadly prograding sequences with limited channelisation and numerous high amplitude features, particularly down-dip from the ancient shelf break. MS II is dominated by complex, erosive,

stacked canyons with a downstepping prograding shelf break. MS III is characterised by laterally continuous facies cut by rare, deeply erosive canyon features. The sequences show a transition from progradation to aggradation and then retrogradation since the Pleistocene.

The overall progradation of the fan since inception has resulted in the stacking of deep marine distal facies under slope and shelf facies within the present-day shelf. The identification of lowstand events within the ancient system can help to predict aggradational reservoir facies on the slope and sand-rich turbidites on the basin floor.

Figure 5 shows the characteristic features of a schematic single lobe of the Bengal Fan and the associated predicted seismic facies. Within the AOI, all the fan system elements are evident in predictable locations.

Giant fan systems are primarily fed by a single canyon system at a time, with avulsion processes resulting in the lateral and vertical growth of the system and progradation leading to down-dip migration (Schwenk et al., 2005). Unlike other modern fan systems, the Bengal Fan has been fed by different distinct submarine canyons in the past relating to changes in river location, sediment supply and sea level (Curray et al., 2003). These canyon systems were particularly active during MS II, where the whole shelf is cut by complex aggrading and meandering systems (Figure 4). The canyon complexes are generally mud-rich, but stacked internal sand-rich channels are common, often characterised by lenticular high amplitudes (Figure 5). The canyons often cut through high amplitude prograding facies, providing lateral seal and trap geometries.

As the slope increases, the characteristic complex stacked channels become more confined and develop into aggrading channel systems. These channels are wedge-shaped, the core

Figure 5 Schematic showing the basin play model for a single submarine fan system, from shelf to basin floor. Reservoir potential facies are predicted within the prograding shelf sands on the platform, within complex channel systems and levees on the slope and in isolated channels and basin floor fans in the deep water.

often infilled with chaotic and high amplitude seismic facies (Figure 5). Levee and overbank deposits can also be identified as dipping reflectors on the flanks of the channel and crevasse splays as bright amplitude laminar events on the flanks. 3D mapping of these channels shows them to be generally meandering with common abandonment (e.g., Schwenk et al., 2003; Thomas et al., 2012), resulting in sediment traps. The steepened slope also results in the common occurrence of mass transport complexes (MTCs) which can act as seals and intraformational source rocks as well as sediment and petroleum conduits (Lu et al., 2023).

All these shelf and slope canyon and channel feeder systems ultimately provide thick sand accumulation in unconfined basin floor settings (Figure 5). These basin floor fans commonly contain the cleanest sandstones and largest reservoirs. They are often characterised by gigantic, thin, high-amplitude and lobe-shaped bodies with updip channel feeder systems. Basin floor fans

have been identified at two stratigraphic levels within the AOI; Lower Miocene under the present-day shelf and within the Upper Miocene to Pliocene lowstand sequences off the shelf break. The optimal reservoir facies is usually found in the amalgamated sheets closest to the feeder system (Yang and Kim, 2013).

Identified leads

Using the predictive seismic facies and seismic stratigraphy, numerous examples of the key play types can be identified within the 2D data. Some features are of such a scale they can be traced across multiple strike and dip lines. On the shelf, low amplitude anticlines and deep-rooted faulting create structural traps within shelfal reservoir sands, with additional stratigraphic upsides in levee sands with lateral pinch-outs (Figure 6a).

Within the slope, the primary leads comprise complex stacked canyons and aggradational channels with associated mass

Figure 6 PSTM seismic images showing identified leads within the AOI, progressively from shelf to basin floor. 6a: high amplitude shelf sands laterally sealed by a large erosive mud-dominated complex channel system, containing stacked sand-filled channels. Trapped within a low amplitude anticline. 6b: Aggradational channel complex overlying high amplitude fan bodies and stacked channel sands. Detail within the channel complex shows high amplitude stacked channel sands within the core and elongate splays and overbank deposits. A chaotic MTC overlays the system providing lateral and top seal to some of the sand units. 6c: Large-scale basin floor fan with associated sediment waves indicative of lowstand deposition with high potential for coarser grained facies. The fan system can be seen in both strike and dip lines as a high amplitude soft-topped feature.

transport complex facies acting as lateral and top seals, often with a pinch-out component (Figure 6b).

There are frequent examples of giant fan systems on the basin floor, with lateral and updip pinch-outs (Figure 6c). These systems are large enough to be mapped across several strike and dip lines, and their associated canyon feeder systems are often evident. The association of these fans with lowstand depositional features such as sediment waves and collapse structures provides additional support to the potential for sandrich systems.

Giant basin floor fans have also been identified at Lower Miocene level under the present-day shelf break (Figure 7a). Some of these high-amplitude soft-topped bodies are up to 20 km across and extend 40 km downslope. They are often intrinsically connected to overlying and lateral MTCs.

Stacked plays are common, particularly under the present-day shelf and slope, where the progression and aggradation of the historic shelf break enables the stacking of multiple leads from early basin floor fans through to aggradational channel systems and canyon leads (Figure 7b).

Conclusions

The Bengal Fan has huge untapped potential for petroleum exploration, and the recent announcement of a licensing round offshore in Bangladesh has ignited significant interest. Regional studies will be vital in understanding the source, timing and optimal reservoir presence for successful petroleum exploration.

High-resolution regional 2D seismic data evaluation has offered insight into evolving reservoir architecture and seismic character, enabling potential reservoir prediction. There is extensive evidence of a working petroleum system at multiple levels, and further work to constrain this can be performed. Identification several leads at multiple stratigraphic levels,

Figure 7 PSTM seismic images showing stacked leads on the shelf and slope within the AOI. 7b: PSTM seismic image showing an example of a Lower Miocene basin floor fan. Complex channel systems overlay the fan proving additional targets at shallower levels. 7a: PSTM seismic image showing an example of stacked leads on the present-day slope.

including stacked plays on the shelf and slope and gigantic basin floor fans in the deep water, demonstrates the considerable potential of the Bengal Fan for future giant petroleum discoveries.

References

Alam, M., Alam, M.M., Curray, J.S., Chowdhury, M.L., R., Gani, M.R. [2003]. An overview of the sedimentary geology of the Bengal Basin in relation to the regional tectonic framework and basin-fill history, Sedimentary Geology, 155 p. 179-208.

Baric, F., Skaler, K., Buljan, Z. and Horvat, K. [1977]. Bina-2 Geological Report. Zagreb.

Coleman, J. M. [1969]. Brahmaputra river: Channel processes and sedimentation. Sedimentary Geology, 3, 129-239.

Curray, J. R. [1994]. Sediment volume and mass beneath the Bay of Bengal. Earth and Planetary Science Letters, 125, 371-383.

Curray, J.R., Emmel, F.J. and Moore, D.G. [2003]. The Bengal Fan: morphology, geometry, stratigraphy, history and processes. Marine and Petroleum Geology, 19, 1191-1223.

Gopala Rao, D., Krishna, K.S. and Sar, D. [1997]. Crustal evolution and sedimentary history of the Bay of Bengal since the Cretaceous. Journal of Geophysical Research, 102, 17747-17768.

Lu, Y., Shi, B., Luan, X., Fan, G-Z., Ran, W., Xu, X, Ma, H., Shao, D-L., Ding, L. and Wang, H. [2023]. Fine-grained deep-water turbidite gas reservoirs in upper Bengal Fan. Marine and Petroleum Geology, 158, 1-15.

Ma, H-X., Fan, G-Z., Shao, D-L., Ding, L., Sun, H., Zhang, Y., Zhang, Y-G. and Cronin, B. [2020]. Deep-water depositional architecture and sedimentary evolution in the Rakhine Basin, northeast Bay of Bengal. Petroleum Science, 17, 598-614.

Qin, Y., Zhang, G., Ji, Z., Li, Z., Wu, Y, Wang, X. and Liang, X. [2017]. Geological features, hydrocarbon accumulations and deep water potential of East Indian basins. Petroleum exploration and development, 44, 731-744.

Schwenk, T., Spieß, V., Hubscher, C. and Breitzke, M. [2003]. Frequent channel avulsions within the active channel–levee system of the middle Bengal Fan—an exceptional channel–levee development derived from parasound and hydrosweep data. Deep-Sea Research II, 50, 1023-1045.

Schwenk, T., Spieβ, V., Breitzke, C. and Hübscher, C. [2005]. The architecture and evolution of the Middle Bengal fan in vicinity of the active channel–levee system imaged by high-resolution seismic data. Marine and Petroleum Geology, 22, 637-56.

Shoup, R.C., Filipov, A.J. and Hiner, M. [2017]. Geological Interpretation of the Reservoir and Pay Distribution of the G3.2 and G5.2 series of the Shwe Field, Myanmar. Search and Discovery Article 20401

Scotese, C.R. and Zumberg, J. [2007]. The Gandolph Project: Year one report: Paleogeographic and paleoclimatic controls on hydrocarbon

source rock distribution, a report on the methods employed, the results of the paleoclimate simulation (FOAM), and oils/source rock compilation, conclusions at the end of year one. February 2007, Geomark Research Ltd, Houston, Texas, 142pp.

Thomas, B., Despland, P. and Holmes, L. [2012]. Submarine sediment distribution patterns within the Bengal Fan system, deep water Bengal Basin, India. Search and Discovery Article, 50756

Yang, S-Y. and Kim, J. [2014]. Pliocene basin -floor fan sedimentation in the Bay of Bengal (offshore northwest Myanmar). Marine and Petroleum Geology, 49, 45-58.

Zhou, L.H., Sun, Z.H., Tang, G., Xiao D-Q., Cai, Z., Wang, H.Q., Su, J.Q., Hua, S.J., Ge, W. and Chen, C.W. [2020]. Pliocene hyperpycnal flow and its sedimentary pattern in D Block of Rakhine Basin in Bay of Bengal. Petroleum Exploration and Development, 47, 297-308.

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Arriving early to the party: finding hotspots before they’re hot

Neil Hodgson1*, Lauren Found1 and Karyna Rodriguez1 demonstrate how a source-focused strategy can help explorers to stay ahead of the competition offshore Namibia.

Introduction

As the industrialist James J Ling said; ‘To be early is to be on time, to be on time is to be late’. In new venture exploration no-one wants to be late to a ‘hotspot’. Arriving after the lightning has struck, when expectations are high, acreage is taken, entry costs are astronomical, is no fun. The illusion of advantage of being a smart follower, arriving ‘on time’ when someone else has derisked a basin/play, is shattered in the press of the crowd chasing the remaining morsels.

There are multiple strategies to adopt that can keep one ahead of the competition, arriving on an empty beach before the sun rises. Perhaps the most generic of these for unexplored basins, or unexplored parts of explored basins, is to follow the source rock.

One striking example of the source rock-focused strategy, working inboard from proven source rock to accessible traps, has been played out by the recent discoveries offshore Namibia. There is an industry meme that deepwater Namibia was an unfashionable destination for a long time because it was doubted there was a working source rock south of the Walvis ridge. That isn’t the whole story but it is a meme that has at least shaped interest in the basin over the past five decades. Whilst some of the other concerns such as reservoir presence and trap have only slowly been addressed over the decades by improved seismic

1 Searcher

such as the MC 3D data acquired in the last two years (Figure 1a), understanding source presence has not been an issue for 50 years.

Namibia

A great boon in the eastern southern Atlantic is that there are a set of academically funded (open access) wells that penetrate the stratigraphy above basement hundreds of km offshore in over 4000 m of water, that prove source rocks were deposited on oceanic crust at the start of drift during the opening of the Atlantic. In 1974 in Leg 40 of the deep-sea drilling programme, a number of very deep-water wells were drilled off West Africa, including DSDP 361, which was drilled in more than 4000 m of water offshore Cape Town, South Africa (Figure 1b). This encountered several hundred metres of Aptian source rock above basement (oceanic crust) with high TOCs >5%, far to the west of the Outer High. Even by the mid-1970s the DSDP 361 source rock could be mapped on available seismic data around the Orange basin, partly onlapping onto the Outer High (ie Figure 3) or extending east over the Inner Basin. Figure 2 is a sketch of the basin with the main structural and stratigraphic elements referred to in this article. Please note that this is a sketch for illustrative purposes only.

The source story south of the Walvis ridge got even stronger in 1974 with the discovery of gas in the Kudu Field. The Outer High

* Corresponding author, E-mail: n.hodgson@searcherseismic.com DOI: 10.3997/1365-2397.fb2024041

Figure 1 Left; Map of the multi-client 3D survey acquired in Orange Basin 2021-2024. Right Map of Searcher’s Legacy 2D data in Orange Basin South Africa, locating DSDP 361.

is an important structure that separates the basin floor and slope from the inner basin, such that outboard and inboard sequences onlap in places onto the Outer High. The Kudu gas field discovery was made in the synrift of the inner basin, proving source presence at post-rift Aptian level (the Kudu shale) and strongly indicated a syn rift older Hauterivian source too. Additionally, by the 1980s many wells drilled in the Orange basin had encountered a thick and high TOC Turonian source rock which although it was ubiquitously immature, presents a third proven source rock in the Orange Basin (Bray et al., 1998).

Although we write with the 20:20 vision of hindsight, the distribution of the Aptian source rock outboard of the Outer High has been mapped from South Africa into Namibia since the mid-1970s, and using 2D and later 3D seismic data to map the thickness of the cover sequence, isopach mapping showed that a sediment thickness sufficient to generate oil pertained to much of the source area. Although the ability to drill exploration wells in 3000 m of water only stems from the early 2000s, we have been able to explore in 1500 m of water since 1980. Suggesting that the opportunity to arrive (super) early to this hotspot had been open for 30 years prior to HRT’s 2013/4 drilling campaign in Namibia, where significant thicknesses of Aptian source rocks were penetrated in board of the outer high and light oil was recovered from Wingat-1, thereby demonstrating that the Aptian could be a productive source rock. The drilling campaign was preceded by a groundbreaking time series study satellite Synthetic Aperture Radar data by HRT, with the specific objective of using this technique to identify repeated oil slicks and therefore a working hydrocarbon system (Mello et al., 2015).

Improvements in seismic imaging have been steady and dramatic through the last two or three decades, and for at least ten years this has made possible a new application of this technique to study source rocks. The variation in reflection amplitude with offset (AVO) and particularly an increase in amplitude with offset (Type II or III) is a brilliant though mercurial tool for derisking the presence of oil or gas in a reservoir, yet a sharp decrease of amplitude with offset (Type IV) can indicate the presence of a source rock interval (Loseth et al 2011). The Aptian source rock of Namibia has been shown to have a soft response with a strong AVO Type IV character, and this has now been mapped from the deep basin outboard of the outer high, to the inner basin inboard of the Outer High. When

Figure 2 Sketch of the main stratigraphic elements of the Orange Basin with the recent discoveries indicated relative to the structural and stratigraphic elements.

calibrated with all the appropriate wells in the basin this is considered to be another positive source rock indicator (Davison et al., 2018). Other seismic evidence included DHIs (direct hydrocarbon indicators), fluid escape and seabed features, as well as BSRs (bottom simulating reflectors) found at the base of methane hydrate zones, where the thickness of the methane hydrate stability zone can be used to estimate shallow geothermal gradients and associated surface heat flow (Vohat et al., 2003 and Rodriguez et al., 2021).

A lack of commercial success with the HRT wells in 2014 due to reservoir/trap issues meant that the Orange Basin was still only lukewarm, although surely the spectre of no-source had been put to rest. And so a second long period of access opportunity arrived prior to the Shell Graff-1 well drilled in late 2021. This well laid two pre-drill risk factors to rest – reservoir and source. Since the time of the Kudu wells which displayed a lack of Late Cretaceous sands, an idea had been prevalent that no sands were able to get out into the deeper water area past Kudu. Graff encountered two Late Cretaceous sand channel packages below the decollement of the Orange basin Gravity Driven Fold and Thrust Belt. Secondly, Graff-1 encountered light oil proving the effectiveness of the Aptian source down dip. Very shortly after Graff-1 was announced, TotalEnergies announced the Venus-1 well discovery in basin floor sands even further outboard of the Outer High on transitional and oceanic crust. Figure 3 is a fast-track processed line of 3D data acquired in 2023 over the extension of the ‘outboard of the Outer High’ Venus basin floor play to the southeast. After the spectacularly big Graff and Venus discoveries, the basin west of the Outer High was officially ‘Hot’ and buzzing and a flurry of acreage-access deals followed. Proving the effectiveness of the Aptian source had made the acreage outboard of the Outer High prime real estate.

However, it was not the end of the Orange Basin source story. Another frontier play entry opportunity existed in acreage inboard of the Outer High that has now been proven by the Mopane-1x discovery drilled by Galp in 2023/4 over the Inner Basin. This well, like Graff-1, has discovered light oil in two stacked Late Cretaceous slope sand channel sequences, where the oil has been generated from the Aptian source, but not the out-board basin floor Aptian deposit, this time the oil has come from the Aptian lying extensively over the Inner Basin east of the outer high. This has opened a new play fairway extending from north

to south in the Orange Basin – inboard of the Outer High. Figure 4 is a PSDM line over the extension of the ‘inboard of the Outer High’ Mopane play to the south east. A second flurry of farm-ins is expected into the now derisked inner basin exploration play.

As mentioned above, early identification of the source rock presence story is not the whole part of the new play entry puzzle into Orange Basin – but it’s a start. The arrival of new 3D seismic data over the inner basin is allowing the sedimentary processes of the inner basin to be fully understood, defining channels and ponded fans between the shore face sequences on the shelf and the Outer High, in addition to the mixed system channel plays of Graff and La Rona, and the fan plays of Venus on the basin floor. These include a play where sands are onlapping the Outer High, and also where they are pinching out in onlap stratigraphic closure onto counter regional dipping oceanic crust to the west. The water depth of these systems is still moot in some quarters as they are systems developed directly in front of shallow water prograding clastics, deposited directly onto the Aptian source rock which in places onlaps what may have been emergent Outer High, suggesting minimal water depths at that time. That’s important as it shapes our vision of the early development of the southern Atlantic.

The model proposed for the development of the Aptian Source rock is as follows. The first marine incursion into the basin (from which the Aptian source rock was deposited) cut across a sub-areal plain created by flood basalt eruptions from the

early mid-rift volcanism. It is these sub-areal plateau volcanics (such as one can observe in the Afar triangle today) that onlap the most distal crustal fragments, and sub-areal or lacustrine syn-rift marking Gondwana’s foundering, and form the Outer High whose origin may mark the beginning of true drift. These volcanics generally dip towards the sea, and have an arcurate geometry formed shortly after eruption as the underlying magma chambers collapse and extrude their magma as yet more plateau basalts as the basin width extends. When the sea first invades this plain, eroding SDR irregularities into a planar surface (Figure 3), it can switch off the plateau lavas as these do not propagate across water and new crust forming during drift becomes more recognisable as oceanic crust, comprising pillow lavas. Initially shallow water, the inundation would be very extensive along the axis of the rift and as the basin subsides further water depth would steadily increase, drowning the now mid-ocean ridge and working its way up the rift margins, onlapping the outer high as it went. It’s at this moment that the Aptian can pour over and around the emergent Outer High to flood the inner basin behind the Outer High and deposit a thick source rock in that basin, ready to charge Mopane1x. Whilst activity in the Early Cretaceous rift and drift phase dominates the Aptian source story, by the Turonian the Atlantic is a wide ocean well connected to the global ocean. It is at this time that the Turonian Global Anoxic Event (GAE) (Jenkyns 2010) allows the deposition and preservation of the Turonian shale.

3 A-A’: NE-SW Fast track PSTM in depth dip section through the Namibian Gap MC3D survey 2023 close to the South African border, mostly outboard from the Outer High.

4 B-B’ : W-E Final PSDM dip section through the 2022 Bridge survey inboard from the Outer High

Figure

Figure

over the Inner Basin.

This appears to be too shallow and cold in the Namibian Basin of today to be mature, at least in the Orange Basin.

Future hotspots still available

Although perhaps apocryphal, the trick of using DSDP data that defines source rock in super deep water and running in towards the continental shelf has also been used in the last 10 years to great effect in north-west Africa. In 1975 on Leg 41 DSDP 367 encountered Aptian/Albian and Cenomanian/Turonian black shales in 4700 m of water some 350 km offshore SE of Dakar, between Senegal and Cape Verde. These sequences can be shown on seismic to correlate in-board, where sediment thickness increases from 1100 m to more than 3000 m of sediment, at which point they would be oil mature, and up to 5 km of sediment by which point they may be overmature having expelled all their potential gas. However, it was only 30 years later that this evidence of source rock was chased into drillable water depths and the astonishing gas discoveries of Tortue, Anaheim, Terranga, Yakkar and Orca followed-on. The oil potential is yet to be proven, and deepwater acreage is becoming available in this play in both Senegal and the basin extension in Mauritania.

On the western side of the Atlantic there is a dearth of DSDP wells, which means that this strategy cannot be followed directly, and a conjugate jump is required. What is envisaged is a consequence of the initial marine incursion of the global ocean during late rift – early drift in the Southern Atlantic, creating a restricted Aptian Anoxic embayment. This shows that it may have deposited source rock not only on the east side of the Mid Ocean ridge but on the equivalent west side of the Mid-Ocean ridge (Hodgson et al., 2023). In the basins to the west its ‘conjugate basin’ of Brazil’s Pelotas, Uruguay’s Punta Del Esta and Argentina’s North Argentine Basins, we can map significant thicknesses of ‘Aptian’ with strong Type IV AVO source rocks deposited onto and onlapping Oceanic Crust in the east and thick SDR volcanic flood basalts to the west.

The Outer High is not developed so clearly in the Pelotas Basin, which may be telling us something about asymmetric rifting in the basin, or it may simply suggest the Outer High in Namibia is a local and unique structure developed during the SDR development in early drift on that margin. The conjugate model, with its implication that source deposited in a shallow anoxic Aptian basin might be present on both sides of the margin, is by no means proven because no wells have been drilled on the western margin into that stratigraphy over and east of the SDRs,

not even DSDP wells. The GAE-related Turonian source rock has been proven by drilling of the Brazillian Pelotas Basin well BPS0006 and in the deep-water setting, the thickest parts of the sediment load in Pelotas would put a Turonian source rock well into the oil window.

This does suggest that these West Atlantic basins, which do not yet have wells in water depths over 2000 m, have multiple plays and both structural and stratigraphic traps might represent some of the best ‘chase the source rock’ opportunities’ to arrive at the hotspot before it’s a hotspot on the planet today, although one suspects not for long. Later in 2024 a well will be drilled in Argentina that may turn the competitive temperature up in these basins, when Equinor drills the much-awaited Argerich-1 well. This may be a test of a play charged from Aptian source rock outboard of the outer high, although from its location it may also test a source from the Karoo syn-rift of the Colorado Basin. Promising acreage in Uruguay has been taken recently by a number of companies such as Shell, Apache and now Chevron, while the adjacent Pelotas Basin in southern Brazil has seen entries from both Chevron and Petrobras/Shell/CNOOC. It is here in the permanently open licensing round blocks of southern Brazil where the most obvious opportunity to ‘pick a spot and make it hot’ lies. Just now, it’s still possible to arrive at the party fashionably early.

References

Bray, R., Lawrence, S. and Swart, R. [1998]. Source Rock, maturity data indicate potential off Namibia. Oil & Gas Journal, 96(32), 84-89. August 1998.

Davison, I., Rodriguez, K. and Eastwell, D. [2018]. Seismic Detection of Source Rocks. GeoExpro, 6

Hodgson, N., Found, L. and Rodriguez, K. [2023]. “Cryptic Seismic Clues: Hunting for another Source Rock in the South Atlantic”. GeoExpro, 2

Jenkyns, H.C. [2010]. Geochemistry of oceanic anoxic events. In: Geochem. Geophys. Geosys., 11, Q03004.

Loseth, H., Wensaas, L., Gading, M., Duffaut, K. and Springer, M. [2011]. Can hydrocarbon source rocks be identified on seismic data. In: Geology, 39(12), 1167-1170.

Mello, M.R., Peres, W. and Mohirak, W.U. [2015]. Namibia: The Hunt for Oil and Gas Continues in the Land of Giants

Vohat, P., Sain, K. and Thakur, N.K. [2003]. Heat flow and geothermal gradient from a bottom simulating reflector: A case study. In: Current Science, 85(9), 1263-1265.

Figure 5 Legacy 2D line from pelotas reprocessed to PSDM in 2021. The section is 210 km long.

Jerv, a recent Palaeocene discovery at the UK-Norwegian

border. Is it so small?

Carl Fredrik Gyllenhammar1*, Ivar Meisingset 2, and Birger Dahl3 explain why an area of the UK-Norway border of the North Sea has more prospectivity than was previously thought.

Introduction

Long-term oil and gas production in the UK and Norway sectors of the North Sea has led to significant pressure drawdown in a number of plays. This can make new discoveries which otherwise would have been viable uneconomic. Norwegian gas/condensate discovery 15/12-25 (Jerv) is an example.

Jerv discovery well NOR 15/12-25 was spudded 18/2-2021 by Chrysoar Norge AS (now Harbour Energy) and drilled to a total depth of 2785 m TVDSS. The Ty Formation reservoir sands showed good quality with an average effective porosity of 19.2%, water saturation of 32% and net to gross of 80% with a gross thickness of 43 m. No wireline run was carried out and no fluid samples were acquired from the well (Chrysoar, 2021). After measuring low reservoir pressures, which confirmed communication with neighbouring UK field Fleming, the discovery was abandoned as uneconomic. The licence was relinquished in 2023.

Jerv is not properly appraised. We have revisited the discovery and found that the decision to abandon may have been hasty. Well NOR 15/12-25 did not find the contact, and may not have penetrated the whole clastic Paleocene section. The lower part of the structure is relatively flat, and there may be significant volumes below the gas/condensate down-to depth that the well proved. Only natural lift was considered as production mechanism; downhole compression is a breaking technology which may be a better alternative.

Structural setting

The Jerv gas/condensate discovery is situated on the northeastern flank of the Central North Sea basin at the Maureen Terrace boundary (Figure 1). It is a satellite to or a continuation of the UK Fleming field, and it could have the same contact. Both contain gas/condensate. Figure 2 shows a 3D perspective of the study area with field and discovery outlines draped on a Base Tertiary depth map, which is below but reasonably similar to top reservoir.

Stratigraphy

The reservoir section in Jerv is described as Ty Fm sandstones interbedded with Våle Fm shales, according to Norwegian stratigraphy standards (Figure 3).

In the UK sector this section is described as the Maureen Fm, and the nearby fields in the UK sector, which can be compared with Jerv, are described as having Maureen Fm reservoir. Figure 4 shows a schematic cross-section of the Lower Tertiary

1 Independent consultant, CaMa GeoScience | 2 Independent consultant, ModelGeo, Norway

3 Independent consultant, Pegis, Norway

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

DOI: 10.3997/1365-2397.fb2024042

Figure 1 Study area.

Figure 2 Structural setting of the Fleming-Jerv area.

Figure 3 Part of Lithostratigraphic Chart Norwegian North Sea, NPD 2014.

depositional systems in the UK sector (from Stratigraphic plays of the UKCS, Promote United Kingdom 2014, Department of Energy & Climate Change). ‘The Maureen Fm is lithologically heterogeneous, including mudstone, siltstone, sandstone, and reworked limestone’ (The BGS Lexicon of Named Rock Units).

Trap

Jerv is a stratigraphic trap formed by pinchouts of the Ty Formation sands into Våle shales and marls on the western flank of the

Varg high (Figure 2, Figure 4) and into reworked limestones towards the north (Figure 5, from Chrysaor 2021).

The closure towards the south is a structural spillpoint against the UK Fleming field (Figure 6). The geosection shows that the Fleming field gas-oil contact at 2802 m and oil-water contact at 2813 m depth fit the interpreted Jerv discovery (Chrysaor 2021).

Pressure measurements in well NOR 15/12-25 points established a gas gradient, indicative of a reservoir pressure of 58 to 59 bars at around 2760 m TVDSS, very near to the present-day

Figure 5 Ty formation thickness map highlighting the formation pinchout and the influence of reworked chalk on the Paleocene basin floor fan reservoir system. Regional BCU TWT map as background in greyscale. From Figure 4.2 in PL 973 Discovery Report, Well 15/12, Chrysaor September 2021.

Figure 6 North-South Geosection from 15/12-25 to UK well 16/29c-7, from Figure 4.4 in PL 973 Discovery Report, Well 15/12, Chrysaor September 2021.

Figure 4 Schematic cross-section of the Lower Tertiary depositional systems in the UK sector.

reservoir pressure of the depleted Fleming field. This verified reservoir communication between Jerv and Fleming (Chrysaor 2021).

The contact depth in Jerv is unknown. It may be the same as in Fleming, or shallower, or deeper. Whether Jerv is a satellite to Fleming, or whether it is part of the field with common contacts, is unknown. There is sufficient uncertainty in interpretation, depth conversion and the location of the stratigraphic pinch-out towards the east of the Ty Fm in the structural saddle area to give room for both.

Formation evaluation

We have carried out our own petrophysical interpretation of the well (Figure 7). The operator concluded that it had gas down-to at 2781.5m TVDss (2806.8m MD) (Chrysoar, 2021). We have attempted to detect the Free Water Level (FWL) using BVW analysis (Figure 9). This indicates a FWL at 2786 m TVDss, but as the BVW analysis from Fleming field appraisal well UK 16/29a-9 (Figure 8) is inconclusive, and predicts different FWL levels for different sand bodies (Figure 9), there may also be deeper sand

Figure 8 UK appraisal well 16(29a-9 in the Fleming Field. The hydrocarbon down to (HDT) at 9374 ft RKB is the same as reported by the operator, Phillips Petroleum UK in 1988.

Figure 7 Norwegian Exploration well NOR 15/12-25 (Jerv).

bodies in the Jerv area with deeper contacts. The BVW analysis is another down-to estimate, not a proof of contact.

The Fleming field is reported to have a gas-oil-contact (GOC) at 2802 m TVDss and an oil-water-contact (OWC) at 2813 m TVDss (Chrysoar, 2021), both of which are below TD in well NOR 15/12-25, and a residual oil zone down to 2829 m TVDss. Phillips, the operator of the Fleming appraisal well UK 16/29a-9 in 1988, had hydrocarbons down-to (HDT) 2832 m TVDss (Phillips 1988), which matches our CPI (Figure 8).

Both CPIs (Figure 7 and 8) have the GR in the first column with the volume of clay coloured from white (sand) to dark brown (100% clay). Following the resistivity column is the Salinity column. The green dashed line is the calculated apparent formation water resistivity (RwApp) (Gyllenhammar, 2020). In the Neu/Den/AC column the neutron (green line) and the density (red curve) show a separation that is coloured, green suggesting shale and yellow suggesting sand. The next important column is the Sw, where the water saturation is displayed from 1 to 0 and the hydrocarbon saturation from 0 to 1 coloured in red (Clavier et al., 1984). The next column shows the neutron-density calculated porosity, effective (Sw:PHIE) and total (Sw:PHIT) (Schlumberger, 1989). If available the core calculated (core:RAC_POROSITY) porosity is overlayed as black dots. The next column (last in fig 8) shows the calculated lithology. In well NOR 15/12-25 the mudlogging data was available in digital form. The mudgas ratio (Haworth et al., 1986 and Dolson, 2016) was calculated and displayed in the gas ratio column, as well as the total gas (black dotted curve) overlaid the hydrocarbon saturation in the Sw column. Following the computer-generated lithology is the lithology made by the mudloggers at the wellsite.

Contacts and pressures

BVW analysis of wells NOR 15/12-25 and UK 16/29a-9 is shown in figure 9. This alternative method to evaluate the free water level (FWL) is described by Cuddy et al (1993) in several publications. Bulk volume of formation water (BVW) is plotted against height above free water level (HAFWL), where HAFWL is equal to TVDss depth minus the deepest FWL depth in the study area, 2832 m TWDss was used in figure 9. FWL for each reservoir is then predicted solving the logarithmic equation Log(BVW) = loga + b * log (HAFWL).

Well UK 16/29a-9 has several sand bodies separated by shales (Figure 8) where different FWL depths are predicted, which means that they could be isolated reservoir zones with different contacts. This is not seen in well NOR 15/12, but it may occur elsewhere in the Jerv structure since the reservoir formation is the same as in the Fleming field.

Contacts in some other wells around the Jerv discovery are shown in Table 1. Well UK 16/29a-9 appears to be the only Fleming field appraisal well which has passed a potential hydrocarbon/ formation water contact. The other appraisal wells have base reservoir higher than the 2832 mTVDss.

The presence of a gas zone, a live oil zone and a residual oil zone in well UK 16/29a-9 is not clear from the CPI analysis, but it is supported by RFT pressure data (Figure 10). The pressure cross-plot shows three distinct gradients, for gas, oil and water. The gas and oil gradients intersect at the GOC at 2802 m TVDss, the oil and water gradients intersect at the OWC at 2813 m TVDss. The residual hydrocarbon (oil) leg between 2813 m TVDss and 2832 m TVDss (Figure 8) sits on the water gradient.

9 BVW analysis of wells NOR 15/12-25 and UK 16/29a-9, with BVW on the X-axis and HAFWL on the Y-axis.

Table 1 Hydrocarbon down-to depths in selected wells around the Jerv discovery, all depths are in metres TVDss.

Figure

Formation pressures in well NOR 15/12-25 (Figure 11) were very low, similar to the pressure in the Fleming field reservoir at the time of drilling (Chrysoar, 2021). This proved that there was pressure communication between Jerv and Fleming, and it seems that, for all practical purposes, Jerv has acted as a part of the Fleming field. The gas/ condensate that has been lost in Jerv, due to the pres-

sure draw-down, has most likely been produced through Fleming.

Figure 11 shows the TesTrak pressure measurements in well NOR 15/12-25 together with pressures from UK wells 16/29c-7, 16/29a-9, 16/29c-10 and two Fleming production wells; 22/5b-A5 and 22/5b-A9. UK wells 16/29c-7 and 16/29a-9 were drilled before production start in the area, and sit on the hydrostatic gradient. Well UK 16/29c-10 was also drilled before production start and shows some pressure draw-down. Probably due to production from the field located to the north and west of Flemimg. Well NOR 15/12-25 shows a dramatic pressure draw-down, equivalent to 225 bar at 2803 m TVDss. There are not enough pressure points in the well to determine if it only contains gas, or if there also is an oil leg.

Seismic interpretation

The operator used depth seismic for well planning, and observed a reasonable match between predicted and actual depth tops (Chrysaor 2021). No VSP or checkshots were acquired in the well. Figure 7 shows the operator’s depth seismic interpretation post drill (from Chrysaor 2021).

The seismic data in Figure 12 shows phase rotation at Top Shetland, which is represented with a double reflection (a strong blue over a strong red) instead of a single red reflection, which it should have had with this seismic polarity and colour scale. The insert in Figure 12 (from Harbour Energy 2023) shows that later time seismic from the operator has corrected this problem. The phase rotation makes the position of seismic Top Shetland uncertain on these seismic data. The regional Elephant 3D seismic from PSS-Geo (Figure 13) also does not have this problem.

Lacking VSP data from the well, the operator has relied on depth seismic for well tie. Only a small variation in the velocity model in the lower Paleocene is enough to either

Figure 11 Reservoir pressure plot. The plot is the general pressure plot with depth from 2700 to 290 0m. The hydrostatic pressure (thick blue line) is the pressure of a water column with a constant density of 1.04 g/cc.

Figure 10 RFT pressures from well UK 16/29a-9 showing gas, oil and water gradients.

make the well path cross Top Shetland, as the operator has done, or to stop it above. TD in the well is in the Våle Fm. It does not penetrate into the Shetland chalk as the insert in Figure 6 indicates. The well may have touched Top Shetland, but we have found no hard evidence of it. There could be more clastics, including Ty Fm sand, below TD and top chalk. Drilling the well a few metres deeper with a full suite of logs including VSP would have settled the question.

We have done our own seismic interpretation on a regional 3D seismic merge from PSS-Geo (Figure 13), using an alternative method to find well times. We get a very similar well tie at Balder Fm, Sele Fm and Lista Fm as in the operator’s depth seismic, but our lower Paleocene velocities are higher, and we get TD in the well some distance above Top Shetland. The difference between the two interpretations shows the remaining uncertainty at the well location.

The Top Ty Fm seismic interpretation was depth converted using a hiQbe velocity model from AGR where checkshots from surrounding wells in the Norway and UK sectors were included. The structure map at Top Ty Fm is shown in figure 14, with the line of section in figures 12 and 13 shown in black. The Fleming and Jerv outlines have been edited to match the depth map and to meet in the saddle where there is a possible structural spillpoint with stratigraphic pinch-out towards the east (Chrysaor 2021). The contact in Fleming is drawn at the OWC at 2813 m TVDss, in Jerv it is drawn at 2786 m TVDss.

Reservoir evaluation

As shown by the operator (Chrysaor 2021), the reservoir pressure in Jerv is not sufficient to lift enough gas for production to become economic, even if it only needed to be transported the short distance over to the Fleming Field. However, the operator has based this assessment on natural lift, and has not mentioned compression. A new technology which is now making its way in the oil and gas industry is downhole compression (Di Tullio et.al. 2009). We do not know if this is appropriate for Jerv, but if it is, then it could not only make Jerv viable, but also revitalise Fleming, which is on its last legs with shutdown currently estimated to come in 2027 (ref. Offshore Technology online).

The Fleming field contains gas/condensate with a live oil leg over a zone with residual oil. This is consistent with a hydrocarbon migration history where the field first held oil, and where the oil later was displaced by gas, as the source kitchen (to the southeast) became deeper and more mature. A gas column

Figure 14 Top Ty Fm depth map showing Fleming and Jerv outlines down to 2813 m TVDss and 2786 m TVDSS respectively, showing the line of section in figures 7 and 8.

Figure 12 Depth seismic example, from Figure 3.1 in PL 973 Discovery Report, Well 15/12, Chrysaor September 2021, with an insert from Figure 6 in the PL 973 & 973 B Status Report, License Surrender, Harbor Energy.

Figure 13 Alternative time seismic interpretation on the Elephant 3D seismic megamerge from PSS-Geo.

Figure 15 Fleming Field historical and projected production, ref. Offshore Technology online.

exerts higher pressure on the cap rock than an oil column. If the field does not have a strong enough cap rock to hold gas down to structural closure, then it may have leaked at the top, and a shallower hydrocarbon-water contact may have been established. This is an unproven hypothesis, but it would explain the residual oil zone, and it opens the door for Jerv having a deeper live oil contact than Fleming (if the cap rock in Jerv is stronger).

Summary

The reservoir pressure in the Jerv discovery is depleted to around the same pressure as in the adjacent Fleming Field, showing that the reservoirs are connected. Jerv was abandoned, since there was no realistic production scenario which could make it economically viable. The operator concluded that with natural lift there was no way to achieve sustained production for long enough to pay for a development. This left Jerv as an unappraised discovery, with significant uncertainties in reservoir thickness, extent and contact depth. New technology, such as downhole compression, may change this, and may reignite the interest in Jerv.

Acknowledgements

We are grateful for having the permission to use the log and seismic information from the NDR Digital database (UK) and from DISKOS (Norway).

We are also grateful for being permitted to use commercial data and software including the Elephant seismic megamerge from Pre Stack Solutions-Geo, the high quality regional hiQbe velocity model for depth conversion from AGR, petrophysical interpretations from CaMa GeoScience, pressures and other geological data from the extensive Pegis database, and the leading depth conversion software from ModelGeo.

References

Clavier, C., Coates, G. and Durmanoir, J. [1984]. Theoretical and Experimental Bases for the Dual-Water Model for Interpretation of Shaly Sands: Soc. Petroleum Eng. Journal , v. april, p. 153168.

Cuddy, S., Allinson, G. and Steele, R. [1993]. A simple, convincing model for calculating water saturation in southern North Sea gas fields: Transactions of the Society of Professional Well Log Analysts, 34th Annual Logging Symposium, Paper H , 17.

Chrysaor. [2021]. Discovery Report well 15/12-25 Jerv . Downloaded from DISKOS.

Di Tullio, M.T. Fornasari, S. Ravaglia, D. Bernatt, N. and Liley J.E.N. [2009]. Down Hole Gas Compression: Worlds’s First Installation of a New Artificial Lifting System for Gas Wells: Paper prepared for presentation at the 2009 SPE EUROPEC/ EAGE Annual Conference and Exhibition, Amsterdam The Netherlands 8-11 June 2009.

Dolson, J. [2016]. Understanding Oil and Gas Shows and Seals in the Search for Hydrocarbons . Springer Int. Publishing, 468

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

Harbour Energy. [2023]. Norwegian License Surrender report for license PL 973 & 973 B Status Report . Downloaded from NPD web site.

Haworth, J.H., Sellens, M. and Whittaker, A. [1986]. Interpretation of Hydrocarbon Shows Using Light (C1-C5) Hydrocarbon Gases from Mud-Log Data. AAPG Bull , 69, 1305-1410.

Phillips Petroleum UK LTD [1988]. Preliminary CPI well 16/29a-9, June 24, 1988.

Schlumberger [1989]. Log Interpretation Principle / Applications: Schlumberger Wireline and Testing, Houston, SMP-7017.

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