First Break January 2024 - Land Seismic by EAGE

VO L U M E 4 2 I I S S U E 1 I J A N U A R Y 2 0 2 4

SPECIAL TOPIC

Land Seismic EAGE NEWS President’s half-term report INDUSTRY NEWS Norway maps oil and gas resources TECHNICAL ARTICLE Machine learning for petrophysical modelling

FIRST BREAK® An EAGE Publication

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) • Pamela Tempone, Eni (Pamela.Tempone@eni.com) • Angelika-Maria Wulff, Consultant (gp.awulff@gmail.com) EAGE EDITOR EMERITUS Andrew McBarnet (andrew@andrewmcbarnet.com) MEDIA PRODUCTION Saskia Nota (firstbreakproduction@eage.org)

Ambient noise monitoring and HSE risk mitigation by the deployment of IoT technology on land seismic crews.

Editorial Contents 3

EAGE News

Personal Record Interview — Gang Han

Monthly Update

Crosstalk

Industry News

PRODUCTION ASSISTANT Ivana Geurts (firstbreakproduction@eage.org) ADVERTISING INQUIRIES corporaterelations@eage.org EAGE EUROPE OFFICE Kosterijland 48 3981 AJ Bunnik The Netherlands • +31 88 995 5055 • eage@eage.org • www.eage.org EAGE MIDDLE EAST OFFICE EAGE Middle East FZ-LLC Dubai Knowledge Village Block 13 Office F-25 PO Box 501711 Dubai, United Arab Emirates • +971 4 369 3897 • middle_east@eage.org • www.eage.org EAGE ASIA PACIFIC OFFICE UOA Centre Office Suite 19-15-3A No. 19, Jalan Pinang 50450 Kuala Lumpur Malaysia • +60 3 272 201 40 • asiapacific@eage.org • www.eage.org EAGE AMERICAS SAS Av. 19 #114-65 - Office 205 Bogotá, Colombia • +57 310 8610709 • +57 (601) 4232948 • americas@eage.org • www.eage.org EAGE MEMBERS CHANGE OF ADDRESS NOTIFICATION Send to: EAGE Membership Dept at EAGE Office (address above) FIRST BREAK ON THE WEB www.firstbreak.org ISSN 0263-5046 (print) / ISSN 1365-2397 (online)

Technical Articles 37 Virtual Shear Checkshot from a densely sampled DAS walkaway VSP in a desert environment Ali Aldawood, Amnah Samarin, Ali Shaiban and Andrey Bakulin. 45 Machine learning for petrophysical modelling: a case study of Groningen gas field, the Netherlands Xiao Wang

Special Topic: Land Seismic 53 Geothermal heat potential for district energy and industrial usage in Europe based on closed-loop well solutions Kim Gunn Maver, Ola Michael Vestavik and Camille Hanna 59

An integrated approach to Vibroseis sweep design Tim Dean

65 Ambient noise monitoring and HSE risk mitigation by the deployment of IoT technology on land seismic crews Andrew Clark, John Archer, Mikaël Garden and Jozsef Orosz 71 Revisiting the single sensor vs array debate in the light of new nodal system technology Amine Ourabah 79 Has the importance of ‘signal’ been forgotten in the signal-to-noise ratio of land seismic acquisition? Spencer L Rowse and Robert Heath 85

Understanding land seismic scattering noise through careful simulation Christof Stork

91 Using advanced fibre-optic point sensors at high temperatures to expand downhole deployment use cases Brett Bunn and Paul E. Murray 95

Digital sensors – The next steps C. Jason Criss

Calendar

cover: Sercel’s Nomad All-Terrain Vibrators on an Oman Crew in 2022.

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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 Edward Wiarda President

Laura Valentina Socco Vice-President

Pascal Breton Secretary-Treasurer

Caroline Le Turdu Membership and Cooperation Officer

Peter Rowbotham Publications Officer

Yohaney Gomez Galarza Chair Johannes Wendebourg Vice-Chair Lucy Slater Immediate Past Chair Erica Angerer Member 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 Aart-Jan van Wijngaarden Technical Programme Officer

Sustainable Energy Circle Carla Martín-Clavé Chair Giovanni Sosio Vice-Chair

SUBSCRIPTIONS First Break is published monthly. It is free to EAGE members. The membership fee of EAGE is € 80.00 a year including First Break, EarthDoc (EAGE’s geoscience database), Learning Geoscience (EAGE’s Education website) and online access to a scientific journal.

Maren Kleemeyer Education Officer

Aart-Jan van Wijngaarden Technical Programme Officer

Esther Bloem Chair Near Surface Geoscience Circle

Companies can subscribe to First Break via an institutional subscription. Every subscription includes a monthly hard copy and online access to the full First Break archive for the requested number of online users. Orders for current subscriptions and back issues should be sent to First Break B.V., Journal Subscriptions, Kosterijland 48, 3981 AJ Bunnik, The Netherlands. Tel: +31 (0)88 9955055, E-mail: subscriptions@eage.org, www.firstbreak.org. First Break is published by First Break B.V., The Netherlands. However, responsibility for the opinions given and the statements made rests with the authors. COPYRIGHT & PHOTOCOPYING © 2024 EAGE All rights reserved. First Break or any part thereof may not be reproduced, stored in a retrieval system, or transcribed in any form or by any means, electronically or mechanically, including photocopying and recording, without the prior written permission of the publisher.

Yohaney Gomez Galarza Chair Oil & Gas Geoscience Circle

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

Carla Martín-Clavé Chair Sustainable Energy Circle

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HIGHLIGHTS

Dedicated Sessions at 2024 Annual

ECMOR comes to Oslo

HPC event still pioneering the way

Meeting energy transition with a clear strategy EAGE president Edward Wiarda provides a half-term report on his period in office. The classicists amongst you will know that the month of January is named after the Roman god Janus, usually depicted as having two faces, one looking back, the other forward. In this spirit and allowing for the manageable risk of being called ‘two-faced’, I would like to reflect on 2023 now past as well review the possibilities ahead for 2024. I believe that last year’s adoption of our Circles nomenclature and birth of our new Sustainable Energy Circle defines a new and robust organisational framework. The three overlapping Circles ensure that the EAGE is ‘future-proof’, flexible, diversified and inclusive. We can confidently continue on our Energy Transition journey that puts sustainable development at the heart of our organisation. EAGE’s strategy going forward is clear and focused on: 1) Resolving the energy trilemma; 2) Facilitating and accelerating the Energy Transition towards a low-carbon future; and 3) Long-term sustainability providing a safe and just operating space for humanity. In other words, we need to help to produce more energy, emit less carbon, and become more sustainable. This can only be possible with a sustainable membership demography including a healthy influx of younger EAGE members representing

Edward Wiarda, EAGE president, at the Vienna Annual.

a new generation of geoscientists and engineers. Obviously, the EAGE Board is increasingly concerned about the steadily declining undergraduate enrollment into university geoscience programmes in many key countries, down 35-43% since 2014/2015. Starting in 2024, the EAGE is planning to roll out a suite of initiatives aimed at restoring the standing of geosciences, the energy sector and the oil and gas E&P industry. This starts by defining mission-driven goals for each EAGE circle. We envisage communication training as well as engagement and strategic sessions with policymakers at various key events. FIRST

Unfortunately, 2023 witnessed a string of natural disasters around the world that touched the hearts of geoscientists and engineers, notably the earthquakes in Turkey-Syria and Morocco in February and September respectively. There was a clear connection with the sub- and near-surface and engineering in many of these devastating cases. This highlights the need for our geoscientists and engineers to continue working together and across all borders in the fields of tectonics, seismology, structural geology, (induced) seismicity and earthquake-resistant construction. Similarly the devastating floods in Pakistan and Libya in 2023, and the droughts in the Middle East,

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EAGE NEWS

both underlined the urgent need for climate action. In as far as it can EAGE continues its efforts to address the root causes of climate change along with mitigation of its extreme impacts. It is why the work of the Near-Surface Geoscience Circle and relevant communities is so important with expertise on natural hazard analysis, identification, mapping and eventually mitigation.

Energy Circle encompasses CCS, geothermal energy, energy and hydrogen storage, offshore wind and ‘raw materials for the energy transition’ communities. At the same time we must not forget the value of our evolving oil and gas circle. It has the largest membership base and is very much focused on sustainable development of energy resources.

Edward Wiarda on a visit to the headquarters of Saudi Aramco and DGS (Dhahran Geoscience Society) last October.

It also follows that a key ambition in 2024 is to further engage with our members. We want to grow our three thriving EAGE Circles by stimulating and initiating the creation of underlying technical and special interest communities and their activities, both new and existing. This has already materialised within the newly created Sustainable

I am also happy to acknowledge our growing global network of active Student Chapters and Local Chapters, which I expect to expand further over the course of 2024 and beyond in numbers, geographic locations and activities. This widening global reach of the EAGE, with the support of our regional offices, means an increase in local-regional events.

Season’s Greetings and a Happy New Year! May it be filled with health and happiness.

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This ensures both enhanced engagement with our global member base as well as reducing the need to travel to many specialist events. That said, our flagship EAGE events will remain pivotal in facilitating the transfer of knowledge and sharing of experiences in the business and technologies where are members are represented. In my term as president so far I have truly enjoyed a very positive collaboration with my fellow Board Members and Board of Directors, and believe we have made some significant decisions enabling the EAGE to follow a clear strategy to meet the challenges of the energy transition era. I look forward to continuing this effective teamwork into 2024, together with our entire global staff whose tireless efforts over the years have never ceased to amaze me. Also, on behalf of all our members and the Board, I must extend my appreciation and gratitude to all those fantastic individuals and groups who commit their valuable time and seemingly bottomless energy on a voluntary basis to support EAGE’s multi-fold activities, especially our events, publications and educational programmes. I hope to meet many of you in person in 2024 at various events around the globe and of course at our 85th EAGE Annual Conference & Exhibition in Oslo on 10-13 June 2024. Until then, I wish you all a Happy New Year, or Gelukkig Nieuwjaar in Dutch!

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EAGE NEWS

Record number of workshops planned for Annual in Oslo After a record number of proposals, delegates attending the 85th EAGE Annual Conference and Exhibition can look forward to a comprehensive offering with a total of 18 workshops to choose from. The workshop programme of the EAGE Annual 2024 provides a unique opportunity for participants to share

field. In addition, the workshops emphasise community building within a narrow topic focus and feature a high level of interactivity and discussion. The workshops scheduled for Oslo reflect the geoscience and technology leadership of Norway and the continuing transformation of the Norwegian

Workshops at the EAGE Annual focus on the interactivity.

insights and in-depth knowledge in a focused environment. These one-day programmes focus on solving and discussing scientific topics amongst peers in a highly specialised discipline or topic

Continental Shelf (NCS) to a broad energy basin. Topics will range from CCS and energy storage, nuclear waste storage, geophysical acquisition, AI and machine learning, deep sea mining and

offshore renewables, to name a few. In addition, disciplines ranging from geology, geophysics, reservoir engineering, geotechnical, data science and geochemistry will be covered. Aligning with the conference theme, ‘Technology and talent for a secure energy future’, we will also have a non-technical workshop focused on nurturing geoscience talent. ‘We are delighted to offer the delegates a dynamic environment for sharing knowledge and exploring how geoscience can shape the energy transition,’ says Madjid Berraki, leading advisor geophysics, Equinor, and member of the 2024 Local Advisory Committee. Delegates can take advantage of the All Access Pass registration to benefit from access to the three days of workshop programming in addition to the extensive offering of field trips, courses and other activities. As the date approaches, make sure to mark your calendar and secure your spot at these engaging workshops. The future of geoscience and engineering awaits, and it’s all happening in Oslo at the EAGE Annual Conference. Visit eageannual.org/workshops for more details.

EAGE Online Education Calendar START AT ANY TIME

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

SELF PACED COURSE

6 CHAPTERS OF 1 HR

START AT ANY TIME

GEOSTATISTICAL RESERVOIR MODELING, BY D. GRANA

SELF PACED COURSE

8 CHAPTERS OF 1 HR

START AT ANY TIME

CARBONATE RESERVOIR CHARACTERIZATION, BY L. GALLUCIO

SELF PACED COURSE

8 CHAPTERS OF 1 HR

START AT ANY TIME

NEAR SURFACE MODELING FOR STATIC CORRECTIONS, BY R. BRIDLE

SELF PACED COURSE

9 CHAPTERS OF 1 HR

11 JAN 15 FEB

NAVIGATING CAREER CHALLENGES AND OPPORTUNITIES OF THE ENERGY TRANSITION, BY E. BLOEM, L. LEVATO & G. MICHAUD

EXTENSIVE ONLINE COURSE

24 HRS (INCL. 6 WEBINARS OF 2.5 HRS EACH)

INTERACTIVE ONLINE SHORT COURSE

4 HRS/DAY, 5 PARTS

15-16 JAN AN INTRODUCTION TO OFFSHORE WIND, BY J. GODTSCHALK

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

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EAGE NEWS

Dedicated Sessions at Annual

designed to meet wide range of interests

Our Annual Meeting this June in Oslo will once again gather a global audience of energy, resource and infrastructure professionals to explore the advancement of knowledge, products and services in the oil and gas and energy industries. You can anticipate a comprehensive Technical Programme featuring multiple sessions that cater to diverse interests, from discipline-specific expertise to the synergies between oil and gas, CCS, renewables and infrastructure geosciences. Embedded in the Technical Programme are 17 Dedicated Sessions that should resonate with our diverse EAGE Technical Communities, publications and expertise of our members. The Dedicated Sessions will cover a wide range of topics including petroleum systems, exploration, geology, modelling, critical minerals, rock mechanics, faults seal analysis, monitoring and data assimi-

lation, remote earth observation and energy transition. One Dedicated Session associated with the Decarbonization and Energy Transition group will present the changes EAGE is undertaking including discussion of the new special interest communities the Association is aiming to host in relation to the increasing interest in energy transition. Energy transition topics will be featured strongly throughout the 2024 Annual with sessions on geothermal, hydrogen, energy storage, CCS and the UN SDGs (sustain able development goals). In addition, there will be two Dedicated Sessions specifically designed to

showcase some of the best papers recently published in our journals. One session will review the science and technology of the rock-related subsurface disciplines in Petroleum Geoscience journal, while the other session will unveil the non-hydrocarbon energy geoscience and engineering research in the inaugural year of the Geoenergy journal. If you are interested in contributing content to one of the Dedicated Sessions, you are welcome to email abstracts@ eage.org for more details and availability. Additional information and latest updates on the Dedicated Sessions can be found on www.eageannual.org.

Last call for

abstract submissions!

The Call for Abstracts for the EAGE Annual 2024 is still open for submission until 15 January 2024, 23:59 CET. Take advantage of our excellent platform to expose your research to thousands of professionals from academia and industry, build valuable professioxnal connections and receive tonnes of constructive feedback. Hurry up and send in your abstracts at www.eageannual.org, to be considered for oral and poster presentations.

Arabian Plate’s hydrocarbon journey

Pre-Cambrian to Paleozoic Petroleum Systems of the Arabian Plate

through time now an EAGE book We are excited to announce the release of EAGE’s latest publication entitled Pre-Cambrian to Paleozoic Petroleum Systems of the Arabian Plate, available now on EarthDoc. Edited by Thomas B. van Hoof (Dutch Science Council), this compilation of abstracts in book form originates from the Seventh EAGE Arabian Plate Geology Workshop in Oman in 2018. It strives to enhance exploration efforts in the Precambrian-Paleozoic geology of the Arabian Plate. From the Silurian Qusaiba

hot shales in Saudi Arabia to the Permo-carboniferous glacigenic Al-Khlata formation in Oman, the book explores diverse hydrocarbon play concepts. Covering four billion years of the Earth’s history, the book reviews structural geology, sedimentology, (tectono-) stratigraphy, and unconventional targets. Visit earthdoc.org to acquire this addition to our bookshop. Active EAGE members can utilise MyEAGE credentials to order and benefit from a 15% member discount. FIRST

Edited by Thomas B. van Hoof

All EAGE book titles are available in Epub format, compatible with various e-readers.

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EAGE NEWS

EAGE membership can

enrich your professional journey in 2024

Engage with the EAGE Community and go a step further towards your personal and professional goals.

Where will your professional path lead you this year? Whether you are contemplating a transition to a different field, looking for a new job, or successfully moving forward with your studies, you can be sure that within EAGE you’ll find a wide community willing to assist you in writing the upcoming chapter of your personal story. Let us inspire you with Dr Evgeniia Martuganova’s journey. Currently a postdoc researcher at TU Delft, she decided to be part of our Association in 2012, while she was pursuing her Master’s degree: ‘One of the primary motivations for me to join was to keep abreast of the latest knowledge, current issues, and prospects in the field of geoscience. As an early career, being a

member of the EAGE would allow me to connect to senior professionals, an excellent chance for personal career advancement.’ Dr Martuganova has been actively engaged with the EAGE community since then: showcasing her research at our conferences, workshops and in scientific journals, taking advantage of our multiple online education programmes, and being part of the EAGE Local Chapter Netherlands. The feeling of belonging to a community of professionals passionate about their job, is what she highlights as one of the most rewarding aspects of her experience in the Association. ‘This feeling of belonging only grew with time. For example, during the first fibre optical workshop in Amsterdam

in March 2020, I was fascinated to meet many experts whose papers I was reading and studying for my PhD work at that time. Ultimately, this type of connection gives me the drive to seek excellence and be passionate about working in the geoscience field’, she says. Her commitment was recognised in 2022, when Dr Martuganova received the EAGE Loránd Eötvös Award for the best paper published in Geophysical Prospecting in 2021 on ‘Cable reverberations during wireline distributed acoustic sensing measurements: their nature and methods for elimination’. Written for her doctorate thesis, it was the first paper where she signed as a main author. She proudly recalls: ‘Receiving such an award as a young professional means a lot to me; it means that my hard work is recognised and my ideas are valuable for the geoscience professional community. This makes me feel more confident about my work.’ 2024 is a new year full of opportunities and challenges; a perfect occasion to hop on an enriching journey with EAGE. No doubt there are many more inspiring chapters to come in Dr Martuganova’s professional career in which EAGE will always be there to support. What about you? Make sure to renew your membership at eage.org/ membership to benefit from all EAGE has to offer.

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EAGE NEWS

Sustainability is key topic at IOR+ Symposium

CONFERENCE

REPORT

Celebrating its 22nd edition, the European IOR+ Symposium convened over 100 professionals across diverse fields in The Hague on 2-4 October and proved to be a pivotal gathering for our vibrant IOR/EOR community.

Busy occasion in The Hague.

This year’s conference centred around the imperative of extending the reach of enhanced oil recovery (EOR) while concurrently reducing the carbon footprint of hydrocarbon recovery. Additionally, the symposium explored (re)emerging applications where expertise in IOR/EOR played a vital role, encompassing carbon capture and storage (CCS), hydrogen storage, and geothermal energy. During the symposium, numerous pressing issues in the industry were addressed, including optimising resource utilisation while actively tackling the challenge of carbon emissions reduction. The comprehensive technical programme covered a wide range of topics, ranging from the future of carbon capture, utilisation, and storage (CCUS) with a focus on fundamental science and mechanisms, modelling challenges, sustainability concerns, and CO2 calculations. The event also shone a spotlight on practical applications in polymer technologies and shared valuable field experiences, offering attendees a holistic view 10

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of the advancements and innovations in the industry. The programme was enriched by keynote presentations from renowned experts. Each of them fostered discussions on key themes in our technical programme. Presentations by Dawoud Mahrouqi and Hanaa Al Sulaimani from PDO on ‘Chemical EOR in PDO: Charting progress and future outlook’ and by Almohannad A. Alhashboul from Saudi Aramco on ‘Carbon capture, utilization & sequestration (CCUS): R&D to field deployment’ provided in-depth perspectives on advancements and future trajectories in these pivotal areas. David Bruhn from TU Delft and Kristoffer Engenes from the Norwegian Petroleum Directorate shed light on the status, challenges, and critical developments in geothermal and CO2 storage projects. ‘After an initial learning phase, geothermal developments in the Netherlands are now accelerating to provide low-temperature heat for residential heating and cooling and industrial utilisation, especially the greenhouse operations. The sector profits a

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lot from advanced research support in the country and the experience of the oil and gas industry,’ David Bruhn said. Delegates had the unique opportunity to gain first-hand experiences through two exciting field trips. They explored geothermal developments in the Netherlands at the campus geothermal well at TU Delft and learned about sustainable underground energy applications at the Energy Cave in Rijswijk Centre for Sustainable Geo-energy. These excursions allowed attendees to witness innovation in action, complementing the theoretical knowledge shared during the sessions. The symposium’s social programme provided a relaxed atmosphere for delegates to meet and network. Overall, the symposium fostered a deeper understanding of sustainable practices in the field of CCUS, emphasising both the latest in IOR/EOR technologies and the emerging applications in the energy landscape. This success paves the way for future gatherings, reaffirming the industry’s commitment to progress, collaboration, and engagement.

EAGE NEWS

ECMOR 2024 in Oslo

is where mathematicians, engineers and geoscientists can expect applied research discussion Join us at the 20 th edition of the European Conference on the Mathematics of Geological Reservoirs (ECMOR) in Oslo, Norway on 2-5 September 2024, consisting of a three-day main event preceded by a one-day introductory workshop on ‘Enabling gigatonne disposal of carbon dioxide in the subsurface’. For over three decades, bi-annual ECMOR has been a key conference uniting mathematicians, engineers, and geoscientists to promote a multi-disciplinary approach to scientific discovery and the engineering of energy supply systems. It is renowned for featuring significant advances in this important area of applied research. Chaired by Stephan Matthai (University of Melbourne) and Arne Skorstad (Halliburton), representing academia and industry, respectively, ECMOR 2024 focuses on the enormous technical challenges that lie ahead, inviting long-standing and new participants to engage in discussions about how to address them. ‘We believe that mathematical modelling and simulation of the subsurface play a decisive role for finding the sustainable engineering solutions needed to achieve the United Nations Sustainable Development Goals, particularly ‘Affordable & Clean Energy’ (SDG 7) and ‘Climate Action’ (SDG 13),’ says Matthai, underscoring the conference’s alignment. At a time when data are produced at an ever-increasing rate, it is crucial that methods and decisions are based on a solid foundation of scientific understanding. ‘ECMOR continues to be an arena to promote such scientific progress’, Skorstad says, underlining the importance of targeting these goals with transparent scientific methods. Modelling and simulation are indispensable tools underpinning simulation-based engineering science. Hence, they are vital for the engineering of subsurface energy systems not only because they allow the forecasting and optimisation of the performance of engineering undertakings. Their ability to reveal the emergent behaviour of systems largely hidden in the subsurface makes it possible to mitigate unwanted side effects before engineering interventions are

made. Importantly, such insights cannot be obtained with data-driven approaches because the required data simply do not exist yet because the net-zero and hydrogen economies are still in their infancy. At the same time, the increasing complexity of such efforts can only be handled by including statistical analysis supported by AI, machine learning and algorithms. ECMOR’s technical programme covers a wide array of topics, such as: Physical Modelling including property-, pore scale-, multiphase flow- and geomechanical modelling across relevant time span scales and the

nity of subsurface stakeholders. The expectation is that openness and accessibility will stimulate peer review, raising the standard and rigour of geomodelling, simulation, field development planning, and site management. This increased transparency also reduces the risk that an increasingly competitive use of the subsurface poses. In this context, ECMOR’s goal is to break down communication barriers between different stakeholders such as subsurface storage managers, geothermal energy companies and so forth. Moving toward this goal will raise mutual awareness.

Delegates take the stage at previous meeting.

coupling of these processes; Computational Methods emphasising algorithm and method development, high-performance computing complemented by machine learning, and less-numeric methods for sustainability assessment; Uncertainty Quantification and Optimization focusing on geostatistics, risk analysis, and AI approaches to reservoir management; and Engineering of Open Simulation Software which is a new topic area of ever-increasing relevance as computer programming and computing become available to a larger community. Opening up the toolset and widening public access to site-specific models and simulation approaches that become progressively refined through community involvement, appears as essential to obtain the trust and support of the wider commuFIRST

ECMOR 2024 invites innovative contributions to a wide range of topics falling into the conference’s theme. It is designed to cater to both seasoned professionals and newcomers, creating an effective dialogue across discipline boundaries. This inclusive approach addresses the necessary growth of multi-pronged approaches in tackling arduous problems and the complex challenges associated with the engineering of a carbon neutral economy while keeping the environmental footprint of related subsurface measures to a minimum. The deadline for abstract submission is 1 February 2024. We encourage you to review the list of topics and start preparing your abstracts. For more detailed information and to begin your submission, please visit www.ecmor.org.

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EAGE NEWS

Innovation in fibre-optic sensing and reservoir monitoring on agenda for GeoTech 2024 conference The 3rd EAGE Geoscience Technologies and Applications Conference (GeoTech 2024) in The Hague, Netherlands on 8-10 April 2024 will combine two programmes – one on distributed fibre optic sensing and the other on practical reservoir monitoring – to provide a high value conference with the emphasis on energy transition issues and opportunities. We aim to provide participants with the opportunity to engage in two dedicated technical programmes, offering a platform for cross-disciplinary knowledge sharing and interactive exchanges. Additionally, the conference features a specialised marketplace for innovative companies in geoscience applications, creating an ideal environment for high-level networking and collaboration. The 4th EAGE Workshop on Distributed Fibre Optic Sensing will focus on this emerging technology for subsurface mapping offering high-resolution, continuous measurements of acoustic, strain, and temperature distributions. This workshop will cover various energy and industrial applications of these sensors, particularly advancements in geoscience and engineering, including 3C optical sensors. Challenges, business impacts,

and evolving best practices will be discussed. Workshop co-chair Mahmoud Farhadiroushan says, ‘the goal is to bring experts from academic and industrial organisations together and learn more about the latest advances in the development of the distributed fibre optic sensing technology and its wide range of applications such as reservoir, environmental and earth science monitoring.’ Submissions are welcomed from specialists and enthusiasts across different application areas, especially those offering case studies demonstrating clear business impacts or theoretical and modelling studies. An accompanying special course will introduce the foundational elements of fibre optic science and distributed sensing technology. The parallel EAGE 4th Workshop on Practical Reservoir Monitoring will be concentrating on reservoir surveillance techniques. Mark Thompson, senior advisor reservoir geophysics, Equinor, says: ‘The aim is to show how the use of modern reservoir surveillance practices can be applied to ensure safe injection and drainage. We’ll also discuss the benefits of multi-disciplinary data

Night time in The Hague.

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4th EAGE Workshop on

Distributed Fibre Optic Sensing

4th EAGE Workshop on

Practical Reservoir Monitoring integration, geophysical and engineering data, and increased digitalization that allow for improved work processes that enhance reservoir monitoring capabilities. Finally, we want to provide an open venue to investigate embryonic ideas and technologies, including future trends in hydrogen and carbon storage, while exploring global perspectives and the new business challenges and opportunities presented by potential coexistence with renewable energy.’ GeoTech 2024 is not merely about current practices but encourages forward-looking, embracing the global shift towards a low-carbon future. It underscores opportunities for geoscientists in areas beyond traditional hydrocarbon reservoirs, including geothermal, mining, engineering, and environmental geophysics. We invite professionals and researchers to contribute their insights and research to GeoTech 2024. The deadline for abstract submission is 22 January 2024. Ensure you register by 21 January to take advantage of the early bird fees. For more information, visit www.eagegeotech.org.

EAGE NEWS

WORKSHOP

REPORT

Geoscience still paving the way in high-performance computing

Last September the seventh edition workshop in Lugano showed once again that the geophysical community continues to be at the frontier of high-performance computing (HPC). Held in Lugano on the shores of the Ceresio lake, the workshop drew more than 50 representatives from industry and the academic world. For three days, the group discussed a wide range of topics in the field of HPC. The quest for performance remains inexhaustible, but sustainability of operations has become a key driver as well. As in the past, the answer is to constantly explore new technological solutions which have not been designed to meet the requirements of numerical algorithms. Not surprisingly, new opportunities are coming from the field of accelerators for machine learning applications (TotalEnergies). Exploring such opportunities implies learning new programming models, as well as addressing old well-known problems such as exploiting parallelism, dealing with limited memory, reducing the impact of communications and I/O. Communications and I/O are the bottlenecks that we must face both at level of numerical kernels and at the workflow level (Eni), and machine learning applications are not immune from them (Shell). Data compression is a possible workaround, many alternatives are available, and picking the one that offers the best trade-off between compression loss, compression rate, and speed of compression is not obvious (Aramco). The benefit of optimising the performance/cost ratio is clear: it enables the use of more complex equations in geophysics. Elastic (TTI) full waveform inversion is now a reality (Shell), but even more conventional and well-established algorithms also take advantage of such advancements. For instance, seismic data regularisation (Aramco), possibly at the price of some code refactoring to adapt, can benefit from accelerators. Performance comparison and benchmarking remain very important activities that are constantly carried out by our community (CGG, DevitoCodes), and should possibly be better standardised.

Scenes from successful HPC event in Lugano.

HPC is not only about maximising performance, but also about maximising the exploitation of the available computational capacity (AWS). Many applications are not monolithic consuming hundreds of nodehours for a single execution, but rather consist of the execution of workflows, where efficient orchestration of thousands of jobs is as crucial as the performance of each individual job. This scenario is typical, for example, of the use of predictive models and simulations for the design and operation of equipment and processes, which are increasingly recurring in the field of renewables. The latter calls for the availability of orchestration engines, with strong scalability, traceability of workflow execution, ability to manage asynchronous execution as well as fault tolerance. The workshop’s keynotes contributed to a lively event both for content and discussion they generated. Professor Robertsson from ETH showed a fascinating application of real-time computing to achieve physics-based noise cancellation, by making its wave- based laboratory experimentation anechoic through active noise cancellation driven by the Green’s theorem. The requirement for real-time computation is very strong to guarantee the numerical stability of the approach. Thus, FPGAs were employed to address calculation speed. Eric Boyer from Genci (France) showed how Europe is actively working on the deployment of the first European exascale system, with an ambitious approach that is not bonded to a single technology FIRST

and is including quantum accelerators. Professor Fichtner from ETH showed how to achieve a 10x speedup to make global seismology more of a reality. Quantum computing was also the subject of keynote speeches and presentations. Analogue versus gate-based quantum computers were discussed. The technology is clearly still in its infancy and probably the main challenge will be to find problems that can fully benefit from its potential. Finally, a dedicated session on HPC for energy transition was held and included three keynotes from Genci, Nrel and Nvidia. Trying to make this into a new ‘tradition’, for the second time the workshop included the visit to a datacentre. This year, participants had the opportunity to visit the CSCS (Centro Svizzero di SuperCalcolo, Swiss National Supercomputing Centre) datacentre in Lugano, which has the peculiarity of being cooled in a very sustainable way by using cool water taken directly from the lake. We were guided in the tour by the associate CSCS director Maria Grazia Giuffreda. With great competence and passion, he guided us through the datacentre currently hosting Piz Daint, a machine with a 21 PFlops Linpack performance benchmark which ranked third in the top 500 list in 2017. Piz Daint will soon be replaced by its successor called Alps. Our forthcoming 2024 workshop will be held in Saudi Arabia at KAUST where a tour of the supercomputing facility, with its new supercomputer, will be amongst the conference activities.

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EAGE NEWS

Join the discussion

on energy opportunities in the Caribbean The Caribbean, with its diverse landscape and strategic geopolitical position, is poised to become a significant player in the global energy landscape. That’s why the upcoming 1st EAGE Conference on Energy Opportunities in the Caribbean, scheduled for 5-7 November 2024 in Port of Spain, Trinidad & Tobago, promises to be a landmark event that will bring together industry leaders, experts, and stakeholders to discuss and chart the future of energy in the region. The conference organising committee includes representatives from leading companies such as CNOOC, PGS, S&P Global, Baker Hughes, BP, and others, reflecting the diversity and expertise necessary to address the complex challenges and exciting opportunities in the Caribbean’s energy sector. The Guyana-Suriname Basin has become a hotspot for exploration and production activities. Industry experts will share insights into the challenges and opportunities in this basin, providing a comprehensive overview of the region’s energy landscape. The conference will also shed light on the gas potential not only in the Guyana-Suriname Basin but also

Production increasing in the Caribbean.

in the area between Trinidad & Tobago and Venezuela. Examining current projects and future prospects, these sessions will outline the critical role of natural gas in the Caribbean’s energy transition. The Caribbean is also witnessing a surge in renewable energy projects. Experts will discuss the geothermal potential in the region, examining the technological advancements and regulatory frameworks necessary for its successful integration. Finally, with a focus on deepwater gas production in Trinidad & Tobago, the conference will provide a deep dive into the

challenges and innovations shaping this critical aspect of the region’s energy industry. The significance of critical infrastructure, including deepwater ports, shore bases, pipelines, platforms, and subsea infrastructure, will be underscored. Industry leaders will deliberate on the necessary investments and strategies to ensure the resilience and sustainability of energy operations in the Caribbean. This first EAGE conference in the region promises to be a milestone event, fostering collaboration and innovation that will shape the future of energy in the area.

Future of carbonate reservoirs discussion point for Kuwait workshop

Coming up on 23-25 April in Kuwait City is EAGE’s 1st Workshop on Advances in Carbonate Reservoirs: from Prospects to Development, and not to be missed by anyone involved in reservoir management. As we all know carbonate reservoirs play a vital role in the petroleum system and are one of the major contributors to glob-

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al hydrocarbon reserves. But they present complex challenges in order to maximise recovery from existing mature fields, yet ensuring production sustainability is critical in securing our energy sources for the future. The workshop addresses the latest technology to efficiently manage these complex reservoirs presenting an excellent opportunity to learn, engage, and connect with industry experts. It is a great space to explore various topics including reservoir modelling and simulation, production optimisation, and reservoir monitoring and management. Register now and contribute to the conversations to improve our understanding of our planet and its resources.

EAGE NEWS

LC Oslo explored AI geoscience frontier The EAGE communities in Norway are buzzing with activity in preparation for the coming Annual Conference in Oslo and exploring a multi-disciplinary range of interests in anticipation of vibrant discussions in June. Last November the Oslo Local Chapter called for an evening talk on ‘AI and exciting advancements in the world of geosciences’. The event took place in the geology building of the University of Oslo and was planned in collaboration with the OSEG (Oslo Society of Exploration Geophysicists). Kjetil Fagervik, head of products subsurface geoscience, SLB, shared perspectives on ‘Opportunities for AI in subsurface workflows’ and provided a general overview of

OUR JOURNALS

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the modern trends and technologies in the industry. Lukas Mosser, advanced data scientist, AkerBP, impressed the audience with both the depth of his findings and latest AI tools developments, and the colourful, mind-blowing pictures in his presentation ‘Generative AI and ChatGPT: What, how and why’. The group concluded a truly insightful and engaging technical session, with many questions and a rich discussion, fuelled by pizza. LC Oslo is looking forward to joining forces with the neighbouring Chapter based in Stavanger and the wider EAGE community in the country for future initiatives. Stay in touch via LinkedIn or by updating your EAGE affiliations!

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 1) will be published within January, featuring 17 articles. This is the Special Issue on ‘Machine Learning Applications in Geophysical Exploration and Monitoring’. Editor’s Choice articles: • Deep learning multiphysics network for imaging CO2 saturation and estimating uncertainty in geological carbon storage – E. Um et al. • A comparison of deep and shallow models for the detection of induced seismicity – D. Gorse & A. Goel

CHECK OUT

THE LATEST GP Presentations in progress at LC Oslo session.

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EAGE NEWS

Bangladesh students research waste disposal monitoring on tourist beach

STUDENT CHAPTER

EAGE Student Chapter University of Barishal takes to the beach.

Kuakata Seabeach, Barishal on the southwestern coast of Bangladesh with its spectacular sunrise and sunsets has unique features which could make it a tourist hub. Unfortunately its fragile ecosystem, coastal erosion, and contamination of ground and surface water pose significant environmental issues. Rising to the challenge the EAGE Student Chapter at the University of Barishal, with support from the EAGE Student Fund, decided to embark on a project to review proper waste disposal monitoring to make the area more inviting to visitors. The one day environmental fieldwork project in October involved 30 students, including student chapter executives, 10 members selected

based on their research proposals, guided and supervised by assistant professor Md Abdullah Salman and associate professor Dr Dhiman Kumer Roy from the Department of Geology and Mining at the University of Barishal. Kuakata Sea Beach, popularly known as the Daughter of the Sea, is 18 km long and 3 km wide. Three primary sources of waste were identified – localised waste, tourist-related debris, and contributions from various agencies. Highlighting the urgent need for waste management, the team observed several categories of waste, ranging from plastic items and cigarette butts to metal cans, glass bottles, abandoned trees, fishing gear, to pharmaceutical waste.

The limited availability of disposal bins exacerbated the issue, making waste monitoring more susceptible to contaminating seawater. The sediment deposition revealed Quaternary deposition in the Kuakata region. The fieldwork provided valuable hands-on experience in addressing environmental issues, developing problem-solving methods, implementing beach pollution prevention, and managing waste. Sedimentological analysis for tidal influence was conducted using a boring method with a hand auger at six stations per 30 to 50 cm depth variance. The team also utilised a measuring tape to calculate seawater fluctuations during high and low tides and determined the slope angle of Kuakata Sea Beach.

EAGE Student Calendar 24 JAN

FIRST SUBMISSION LAUIRE DAKE CHALLENGE

ONLINE

30 JAN

EAGE STUDENT CHAPTERS RENEWAL

ONLINE

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

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EAGE NEWS

Minus CO2 Challenge winners point the way to sustainable future In a global showcase of ingenuity and commitment to environmental stewardship, the Minus CO2 Challenge 2023 brought together 22 teams from universities around the world to revolutionise the landscape of carbon reduction initiatives. It was a memorable contest. Securing the top spot was the Faculty of Oil and Chemistry at the University M’hamed Bougara Boumerdes in Algeria, a testament to their groundbreaking approach towards sustainable energy solutions. Second place was claimed by IFP School in France, with Technische Universität Clausthal (TU Clausthal) in Germany taking third. Each of these teams showcased exceptional academic prowess and a profound dedication to addressing the pressing challenges of climate change. At the heart of the success of the self-styled Algerian Decarbo-Nomads team – comprising Merouane Sbaihi, Imad Smaini, Ahmed Guembour, Ibrahim Elkhalil Hadjadj, and Wassim Alalouche

Bill Richards, chair, EAGE Students Affairs Committee.

– was a visionary project combining wind and solar energy generation in the North Shore Area and Amherst, respectively. Harnessing the unique environmental attributes of these regions, the integration of 200 MW wind capacity and 100 MW solar capacity promises a robust and sustainable power supply. What distinguished their project was the intricacy of its combined storage system. This system marries Adiabatic Compressed Air Energy Storage (A-CAES) for short-term energy needs and hydrogen storage for seasonal demands. The A-CAES component, designed to address daily requirements, boasts a storage volume of 198,425 m³, supporting a maximum of 1556 MWh. For seasonal demands, especially during winter, the team anticipates a cumulative energy shortfall of 39,501 MWh over five months. To meet this, a hydrogen storage volume of 598,956 m³ will be engineered. Annually, the project will contribute with 760 GWh of electricity, translating into $194 million in revenue. Beyond the financials, the initiative is a beacon of environmental stewardship. By harnessing renewable energy sources and implementing efficient storage mechanisms, the project pledges to curtail annual CO2 emissions by approximately 273,645 metric tons for a 300 MW plant when compared to conventional fossil fuel-based electricity generation. The team’s journey transcends mere participation: it is a testament to the power of collaboration, innovation, and

Winner team Minus CO2 Challenge 2023 Faculty of Oil and Chemistry, University M’hamed Bougara Boumerdes, Algeria.

Second Place Minus CO2 Challenge 2023 IFP School, France.

a shared commitment to ushering in a sustainable and eco-conscious future. The EAGE Student Fund played a pivotal role in supporting the winning teams, providing travel grants for their participation in the competition, as well as covering their registration fees for the GET 2023 Conference where they received their rewards and had the opportunity to present their projects. As we celebrate the triumphs of these visionary teams, the Minus CO2 Challenge 2023 continues its quest for innovative solutions to combat climate change.

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

D O N AT E T O DAY ! FIRST

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EAGE NEWS

We would like to thank our sponsors for their generous support to EAGE in 2023!

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We thank all our valued advertisers for their loyal support in 2023!

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EAGE NEWS

We would like to thank our exhibitors for their generous support to EAGE in 2023! A

Advanced Geosciences Europe S.L. • AgileDD • Alcatel Submarine Networks • Allton • ALSEAMAR • Ambrogeo Instruments •

Ampseis • Applied Acoustic Engineering Ltd • Arianelogix • Aspentech • Atlas Fluid Controls • Avalon Sciences Ltd

Baker

Hughes • Beicip-Franlab • Bentley Systems International Ltd • BGP Inc. • BGR Bundesanstalt für Geowissenschaften und Rohstoffe • BLUWARE, Inc.

Cegal AS • CGG Services SAS • CoCoLink Corp • Cognite AS • Colchis Petro Consulting

(Beijing) Ltd. • CVA Europe Holding

Delft Inversion • Dell Computer S.A. • dGB Earth Sciences • DownUnder GeoSolutions

(London)Pty Ltd • Dynamic Graphics Ltd

Earth Science Analytics • Earth Signal Processing Ltd. • EIF Geosolutions •

EIWT • Eliis SAS • Elsevier B.V. • EMGS ASA • Engenius Software • EOST Strasbourg • EPI Ltd Fraunhofer IWES

fibrisTerre Systems GmbH •

GB Geotechnics Limited • GEM Systems Advanced Magnometers • Geo Ex Machina • GEO ExPro

GeoPublishing Ltd • GEO Resources Consultancy International • GEODEVICE • Geofive Co.,Ltd • Geofizyka Torun S.A. • Geolink Service • GeoLogica Ltd • Geomage • Geomatrix Earth Science Ltd • Geometrics Inc • Geomex Technologies LLC • Geomind AS • Geopartner Geofizyka sp. z o.o. • Geophysical Insights • Geophysical Technology Inc • GeoScienceWorld • GeoSoftware • Geospace Technologies Corp. • Geotec SpA • Geoteric • GeoTomo LLC • Geovista Ltd • Getech • GK Processing • Grepton Informatikai Zrt. • Guideline Geo

Halliburton Landmark • Hefei Guowei Electronics Company

Limited • Heriot-Watt University • HGS Products B.V. • HOT Engineering GmbH • HRH Geology

I-GIS A/S • ICS

Business International SRL • Ikon Science Ltd • InApril AS • INT Inc. • International Seismic Co (iSeis) • IRIS Instruments K

Kadme AS • Katalyst Data Management • KIGAM • King Abdullah University of Science and Technology

Geophysics • Leobersdorfer Maschinenfabrik GmbH • Lim Logging • LIM SAS • Loupe Geophysics Pty Ltd Enterprises Inc. • McPhar International Pvt. Ltd. • MIND Technology, Inc Nissan Chemical Corporation OYO Corporation

League

Marac

Nimbuc Geoscience • NIS A.D. NOVI SAD •

OMV Exploration & Production GmbH • OPENGOSIM Ltd • OvationData Ltd. •

PanTerra Geoconsultants BV • Petroleum Experts Limited • Petroskills • PetroStrat Limited • PGS

Exploration (UK) Ltd. • Prospectiuni SA • PXgeo

Qeye

Radar Systems Inc. • RadExPro Seismic Software LLC •

Resoptima AS • Rezlytix Technologies Pvt. Ltd • Robertson Geo • Rock Flow Dynamics • RockWave Ltd • ROGII Inc • RoQC Data Management • RPS Energy • RSK Environment Limited

S&P Global Commodity Insights. • SAExploration • Saudi

Aramco • Saudi Geophysical Consulting Office • Schlumberger Technology Corp • Seagate Technology • Searcher Seismic • Seequent • Seismeq AS • Seismic Image Processing Ltd • SENSYS - Sensorik & Systemtechnologie GmbH • Sercel • Sharp Reflections AS • Sharp Reflections GmbH • Shearwater Geoservices Limited • Silixa Ltd • Sinopec Geophysical Corporation • Sisprobe • SkyTEM Surveys ApS • SmartSolo Inc. • Society of Petroleum Engineers (SPE) • Sound Oceanics LLC • Sound QI Solutions Ltd. • SPH Engineering • Spotlight • Stryde Limited • StudioX • Subsurface AI Inc. • Suzhou Geophysical Deep Sensing Technology Co., Ltd • Sword IT Solutions Ltd • SYRLINKS

TDI-Brooks International Inc. •

Tech Limit • TechnoImaging • TEMcompany ApS • TERRASYS Geophysics GmbH & Co. KG • TGS • The EasyCopy Company • The Open Group • Thermo Fisher Scientific • TOTAL Energies S.E. • Troika International Ltd Limited • Visage Technology (OPC) Pvt Ltd • VSProwess Ltd Technologies, LLC • Wintershall DEA AG

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UEST • Ulmatec

Verif-i

Weihai Sunfull Geophysical Exploration Equipment • Wildcat

Xcalibur Multiphysics Group

JANUARY

Zhaofeng Sensor Equipment Co Ltd

PERSONAL RECORD INTERVIEW

Gang Han

Personal Record Interview

Passage from China to geomechanics worldwide As a young petroleum engineer Gang Han left China for postgrad study in Canada. He is now senior petroleum engineering consultant at Aramco Americas in Houston after periods working with CNPC, Schlumberger, Terralog and Hess on oilfields worldwide.. A champion of geomechanics in all energy fields, he has worked on numerous research projects, published extensively and is current chair of the American Rock Mechanics Association (ARMA), testimony to his belief in the role of professional societies.

Starting point in China I was born in the Shengli oil field area where both my parents worked. Surrounded by field engineers and ‘Xmas tree’ wellheads, entertained by asphaltene-transformed ‘play doh’, the oil business was imprinted on my childhood. So it was natural for me to become a petroleum engineer after graduating from the China University of Petroleum (East China).

horizons and landed me with the first job as a developer for SLB, still the largest reservoir simulation software company based in Oxford. Knowledge acquired from the Mars Very Deep Drilling Project with the NASA Jet Propulsion Laboratory would later help me tackle the challenges of working at 30,000 ft water depths in the Gulf of Mexico at the global drilling department of Amerada Hess in Houston.

Arriving in Canada Life is never short of surprises. When the World Petroleum Congress was held in Beijing in 1990s, I volunteered as an English translator. After one technical presentation, the professor I was working with (Prof Maurice Dusseault) came and shook my hand: ‘Great job, young man. Would you like to come and study with me in Canada?’ That’s how I came to obtain my PhD in chemical engineering at University of Waterloo in Ontario, Canada, and my wife and family have all become proud Canadians. Our first child David was born in Canada.

Changing work focus Geomechanics starts with ‘geo’ and ends with ‘engineering’ and hence is genuinely multi-disciplinary. I have had the fortune to work on many inter-disciplinary applications involving geology, geophysics, drilling, completion, production, and reservoir engineering. Over the past decade, the success of shale revolution has shone the spotlight on geomechanics, especially hydraulic fracturing. The best practices and lessons learnt from unconventional fields are now being put into practice and benefiting other industries such as geothermal and mineral mining. It means the future of geomechanics could not be brighter.

A career of learning I have experienced many diverse environments, cultures, and people. It has taught me to be humble and appreciate everyone’s uniqueness and perspectives. Skills I acquired outside the petroleum curriculum have been a great benefit. The additional computer and math classes in graduate school expanded my

Great supporter of industry groups For me, nothing is more fulfilling than finding like-minded people striving for a shared cause like promoting geomechanics. The American Rock Mechanics FIRST

Association (ARMA) is unique in that it is multi-disciplinary involving as mining, petroleum, civil, geothermal, underground storage and utilisation. As the president in 2021-2023, I have worked with colleagues to transform ARMA into a more technological, innovative, diverse, and transparent society contributing to net-zero. One example is the phenomenal growth of ARMA student chapters, from four US schools to 27 universities in North and South America, Middle East, East Asia, South Asia, and Australia. Collaborating with other societies including EAGE, I am also lucky enough to work with world-class leaders and professionals to develop the International Geomechanics Symposium (IGS) into a global platform for geomechanics technologies and communities. How easy was transition from China? Not sure if I could ever get away from my accent, but I actually treat the multi-lingual, multi-cultural environment I have experienced as a gift. professionally, socially, and personally. You love to run Running helps me relax, recover, and recharge. It brings a healthy body, a strong mind, and many good friends. Marathon runners say the real race starts at mile 20 (of 26). It is an apt metaphor for many aspects of life.

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Make sure you’re in the know

EAGE MONTHLY UPDATE Get set for a thrilling journey with EAGE in 2024! We’ve curated some key highlights to give you a taste of the excitement awaiting you this year. Keep an eye out for more updates as we unfold our plans.

E U R O PE Fourth EAGE Digitalization Conference & Exhibition

Paris, France

8-10 Apr

Third EAGE Conference on Geoscience Technologies and Applications (GeoTech)

The Hague, Netherlands

10-13 Jun

85th EAGE Annual Conference & Exhibition

Oslo, Norway

2-5 Sep

20th European Conference on the Mathematics of Geological Reservoirs (ECMOR)

Oslo, Norway

8-12 Sep

Near Surface Geoscience Conference & Exhibition 2024 (NSG)

Helsinki, Finland

4-7 Nov

Fifth EAGE Global Energy Transition Conference & Exhibition (GET)

Rotterdam, Netherlands

AME R ICAS

25-27 Mar

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First EAGE Workshop on the Role of Artificial Intelligence in Full Waveform Inversion

Cartagena, Colombia

17-19 Sep

Fourth EAGE Conference on Pre-Salt Reservoir

Rio de Janeiro, Brazil

3-4 Oct

Third EAGE Workshop on EOR

Buenos Aires, Argentina

24-25 Oct

Third EAGE Workshop on Advanced Seismic Solutions in the Gulf of Mexico

Mexico City, Mexico

5-7 Nov

First EAGE Conference on Energy Opportunities in the Caribbean

Port of Spain, Trinidad & Tobago

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DON’T MISS OUT THE OPPORTUNITY

TO PRESENT YOUR RESEARCH DEADLINE: 15 JANUARY 2024

& AFRICA

MIDDLE EAST

ASIA PACIFIC 30-31 Jan

EAGE/AAPG Workshop on New Discoveries in Mature Basins

Kuala Lumpur, Malaysia

13-15 May

Sixth Asia Pacific Meeting on Near Surface Geoscience and Engineering (NSGE)

Tsukuba, Japan

12-13 Aug

Third EAGE Conference on Unlocking Carbon Capture and Storage Potential

Perth, Australia

23-24 Sep

Asia Petroleum Geoscience Conference & Exhibition (APGCE 2024)

Kuala Lumpur, Malaysia

15-16 Oct

EAGE Conference on Unleashing Energy Excellence: Digital Twins and Predictive Analytics

Kuala Lumpur, Malaysia

26-28 Feb

First EAGE Data Processing Workshop

Cairo, Egypt

4-6 Mar

EAGE Sub-Saharan Africa Energy Forum

Windhoek, Namibia

23-25 Apr

First EAGE Advances in Carbonate Reservoirs

Kuwait City, Kuwait

6-8 Oct

Fifth EAGE Workshop on Naturally Fractured Rocks (NFR)

Muscat, Oman

21-24 Oct

GEO 4.0: Digitalization in Geoscience Symposium

Al Khobar, Saudi Arabia

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CROSSTALK BY AN D R E W M c BAR N E T

•

Reflections on a decade of commentary This month marks 10 years since the Crosstalk column began in an opportunity to revive interest in onshore operations, a number the January 2014 issue of First Break, on the initial suggestion of of companies were racing to find the right solution that would our CEO Marcel van Loon, with a title dreamt up by the late and persuade oil companies to adopt the new technology. Would it be much missed Neil Goulty, EAGE publications officer at the time. blind shooting or wireless was the question. With the disclaimer that EAGE was not responsible for the views Ten years on, the decimation of seismic fleets reflects the expressed, your correspondent has had the privilege of being able view often expressed in this column. As a business proposition to choose a monthly topic and run with it for all these years, no marine seismic has always struggled to be consistently viable. questions asked, so to speak. Historically, the first consolidations began in the mid-1980s, and By December last year total Crosstalk output amounted to an have continued ever since, interspersed with a few heady years estimated 195,000 words of one person’s opinion, a salutary statisconvincing contractors that the downturns could be survived. tic. Unsurprisingly, supplying a decade of uninterrupted monthly Cyclical oil company demand, over-supply of vessels, overhead of commentary on subjects of possible interest to vessel ownership, and costly search for illusory the geoscience and engineering community has ‘A frame of reference technology differentiation have always plagued had it challenges. the industry. Today Shearwater GeoServices for events over But there’s no point in burdening readers and TGS (once it’s takeover of PGS is comwith the woes of writers, e.g., struggling to plete) are effectively the only global providers the period.’ come up with new ideas, trusting your judgstill standing. The jury is still out as to whether ment, deadline pressures, etc. Describing the writer’s lot, prolific some kind of economic equilibrium has been reached; similarly author J.K. Rowling has noted: ‘The wonderful thing about writing the profitable application of seabed seismic nodal technology is by is that there is always a blank page waiting. The terrifying thing no means a slam dunk. One recent surprising trend is the apparent about writing is that there is always a blank page waiting.’ uncertain future of the once successful marine seismic multi-client Looking back through the columns hopefully provides a frame survey model. of reference for events over the period, although obviously subject On review it seems that onshore seismic operations have not to all the unreliability of one person’s perspective and preoccupabeen accorded a great deal of space. This is most likely because tions. There do seem to be a number of recurring themes worth survey demand outside the Middle East has been pretty dismal and sharing. But context first. hence slowed the advance of nodal technology, now clearly in the The seismic business in 2014 was in a very different place ascendant. Otherwise, the business has experienced many of the compared with now. The carnage that has reduced the active same ups and downs as marine, mainly downs. global towed streamer fleet from more than 60 vessels to around Often pointed out in this column is that a wide spectrum of 15 was not yet a threat. The perennial over-capacity issue was geoscience-related business, including data processing, is driven rearing its ugly head with the expectation of reduced oil company by oil company budgets which are subject to extraordinary unpreexploration spending after some good years. It was ominous for dictability. This has always been a major complication for service the main players like Schlumberger, PGS and CGG along with companies because uncertainty means risk. Some idea of future newcomer Dolphin Geophysical, all of whom had been investing spending is required. Yet trying to forecast when, how much and in newbuilds. On land, the less buoyant seismic marketplace was where oil companies are going to spend their dollars is notoriously on the threshold of the nodal acquisition revolution. Identifying difficult.

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CROSSTALK

energy and of course carbon capture and storage (CCS) as a climate You used to be able to go along with the narrative that change mitigation measure. The caveat to serious implementation oil companies conformed to a pattern of exploration spending of virtually all the possibilities at the necessary rate to lower CO2 followed by a period of new field development and then the next emissions is the lack of investment. Oil/energy companies have phase of exploration to fill depleting reserves. That scenario is out made clear there are limits to their spending on alternative sources the window with companies today broadly focused on maximising of energy. The clear conclusion is that only concerted government recovery from existing reserves and focusing on ‘advantaged oil’, measures/direction can seriously accelerate energy transition. That thereby dramatically reducing the scale and timing of seismic in turn would require overcoming public suspicion of government survey requirements. intervention not to mention reluctance in prosperous countries to It is also the case that the data reprocessing of the extensive undergo potential lifestyle changes in the cause of reducing global available seismic libraries built up over time has impacted the warming. If COP28 proceedings are anything to go by, any internaincentive to carry out seismic operations in the field. Casting a tional agreement to tackle climate change remains problematic with shadow over all fresh initiatives to increase global oil supplies is a deep divide between rich and poor nations. the widespread public sentiment anxious about climate change Crosstalk has often pointed out that public understanding of for which the industry has become the number one scapegoat. Its energy issues is remarkably limited, hence the vilification of the impact on oil companies is immeasurable, nonetheless a major oil industry is often based either on ignorance, misunderstanding factor to be taken into account in any calculations about future or blatant hypocrisy, i.e., critics enjoy the lifestyle their oil business. consumption affords. The geoscience community is never able to Of course, oil companies do not operate in a vacuum. Their explain that its everyday work includes a mission to improve our production is dictated by the global oil market, and that is another global environment. That message is easily lost in the era of fake whole aggravation. This column has always taken a sceptical view news, facilitated by social media, providing a platform for endless of how much value can be placed on energy forecasts in general, unsubstantiated information and disregard for and oil demand and pricing in particular. There ‘Not confined purely verifiable scientific evidence. has been no telling when Saudi Arabia unilatIt has been hard not to speculate whether a erally, or in concert with Russia, or united with to the heavy stuff.’ new generation of students can be recruited. The other OPEC+ member states will turn the oil news is not all bad. It is said that the decline in geoscience courses taps on or off hence determining the price of doing oil business. in Europe and North America is being partially balanced by student Analysts can do their best but they cannot take into account the real numbers in China and India. Also, there is a significant change politik often involved in these major decisions, such as flooding the underway in the qualifications sought for entrance into energy market to spite the US shale business. And obviously there was no companies, notably more digital awareness and multi-disciplinary way they could have foreseen the Covid-19 pandemic followed by emphasis, already being reflected in the traditional science-oriented Russia’s invasion of Ukraine, events which have had a huge impact universities. Meantime climate change and environmental studies on global energy supply and demand. are invigorating the interest in near surface geoscience. Rather the same applies to progress on energy transition, The Crosstalk column has not confined itself purely to the a topic to which Crosstalk has often turned with a degree of heavy stuff. A column on geoscience and music a few years ago scepticism because we just don’t know. A case in point, the with geologists in mind found that the use of the word ‘rock” in the International Energy Agency (IEA) in 2021 published Net Zero by song title guaranteed a good result in the Eurovision Song Contest 2050: A Roadmap for the Global Energy Sector detailing how each registering two wins and a second. Remarkably, a Turkish pop diva sector energy transition options could develop to meet the Net Zero was entered into the 1980 competition with a song called Petroleum. target. However, in the short time since then, IEA says much has Poetry was the topic one month revealing the existence of changed citing ‘mostly discouraging developments’. It reports ‘The the somewhat metaphysical study of ‘geopoetics’ and an unusual global economy has rebounded from the Covid-19 pandemic, and teaching method in which students have been invited to pen a the first global energy crisis has seen world energy prices touching short poem to summarise the findings of their scientific papers. Oil record levels in many markets, bringing energy security concerns industry-based board games also got a mention, concluding that to the fore.’ the ultimate cut-throat game should be called Turmoil, better than Understandably the best IEA can do in its latest update is to existing titles such as Gusher King Oil, Wildcatter, etc. offer ‘a comprehensive account of how policymakers and others Contemplating further Crosstalk columns, pace ChatGPT, the could respond coherently to the challenges of climate change, French Nobel Literature prize winning author André Gide had energy affordability and energy security.’ The speculative ‘could’ some comforting words, namely ‘Everything that needs to be said is of course the giveaway word here. has already been said. But, since no one was listening, everything Crosstalk has over time reviewed most of the various existing or must be said again.’ emerging energy transition options including some form of nuclear

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

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Norway considers Barents Sea gas option

PGS releases Norwegian Sea data

CGG shoots 2D survey offshore Malaysia

Norway maps substantial oil and gas resources from tight reservoirs The Norwegian Offshore Directorate (previously Norwegian Petroleum Directorate) has reported vast proven gas resources on the Norwegian shelf which are currently without development plans. Much of this gas is located in tight reservoirs, which cannot normally be produced using conventional wells but the NOD said are increasingly easier to produce because of fast-developing technology.

part of the North Sea is 750 million Sm³ of oil and 90 billion Sm³ of gas. Most of this is located in chalk reservoirs in the Ekofisk, Eldfisk and Valhall area. Producible oil in basement rock has also been proven on the Utsira High. Basement rock consists of hard and tight rocks. However, the basement rock in this area is so fractured and porous that oil has migrated into it.

Ekofisk oil field on the Norwegian Continental Shelf.

‘Despite the significant uncertainty associated with how much gas we’re talking about, the cost level and future gas prices, our calculations show that the values involved are substantial,’ said Arne Jacobsen, assistant director of technology, analyses and coexistence. The estimate for mapped volumes in place in tight reservoirs in the southern

In the northern part of the North Sea, the mapped volume in place in tight reservoirs is estimated at 360 million Sm³ of oil and 80 billion Sm³ of gas. In this area, a considerable percentage of the volumes are located in sandstone reservoirs. However, there are also substantial volumes on Oseberg and Gullfaks in the overlying Shetland Chalk and partly in the Lista Formation. FIRST

Test production of oil has been carried out in the Shetland Chalk on Oseberg. Licensees are considering testing the potential of different well stimulation methods. On Gullfaks, production is currently under way from the tight Shetland Chalk. Here they are using water injection and horizontal wells to improve recovery. Mapped volumes in place in tight reservoirs in the Norwegian Sea are estimated at 130 million Sm³ of oil and 420 billion Sm³ of gas. These volumes are located exclusively in sandstone reservoirs. A large percentage is located in the Tilje and Garn formations, which are deep and have highly variable reservoir properties. The Lavrans, Linnorm, Noatun and Njord Nordflanken 2 and 3 discoveries all have tight reservoir zones where the licensees are still considering the possibility of development using different technologies to improve profitability. Slim-hole technology has been used in the tight zones in the Garn Formation on Smørbukk Sør. This technology has also been used in several other fields, such as Edvard Grieg, Valhall and Ivar Aasen. Mapped volumes in place in tight reservoirs in the Barents Sea are estimated at approx. 5 million Sm³ of oil and 270 billion Sm³ of gas. ‘Since the Barents Sea is more of a frontier area than the North Sea and the Norwegian Sea, the resource base is more uncertain,’ said the NPD. The tight

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reservoirs in the Barents Sea are sandstone reservoirs from the Triassic. About 65% of the overall gas resources on the Norwegian shelf have not yet been produced, said the NOD. Some of the remaining gas resources face a variety of challenges in the subsurface, such as tight reservoirs, high pressure and temperature, challenging gas quality and/or low pressure. Kjersti Dahle, the NOD’s director for technology, analyses and coexistence, said: ‘There are considerable gas resources in discoveries and fields in operation. It

makes sense to think that higher gas prices can drive necessary technology development, coordination and new infrastructure in order to realise this gas, as long as there is the will and ability to do this.’ Addressing the viability of tight reservoir production, the Norwegian Offshore Directorate (NOD) said, ‘So far, various forms of fracturing and multi-branch wells remain the most relevant methods for recovering resources in tight reservoirs. ‘Slim-hole technology is also relevant is several places, where a large number

of slim boreholes in the same well will increase the wells’ contact surface with the reservoir (reservoir exposure) and make it easier for hydrocarbons to flow into the wells. ‘These methods and technologies have all been previously tested and applied on the Norwegian shelf, but are mainly used to extract additional oil. Elsewhere in the world, such as in the Gulf of Mexico, the UK shelf and on certain onshore fields, the technologies have been used to produce gas.’

TGS and PGS shareholders approve merger TGS’ and PGS’ shareholders have approved the proposed merger between the two companies at separate extraordinary general meetings. The decision to approve the merger will now be filed with the Norwegian Register of Business Enterprises. Completion of the merger remains conditional upon customary closing conditions, compliance with applicable covenants and expiry of statutory waiting periods.

Rune Olav Pedersen, CEO, PGS.

‘All proposals on the agenda were approved with requisite majorities, including the merger plan dated 25 October 2023 and the corresponding share capital increase in the company,’ said TGS. PGS CEO Rune Olav Pedersen said: ‘The combined company will be uniquely positioned to unlock substantial value for our shareholders, customers and employees.’

Norway considers Barents Sea gas transport options The Norwegian Offshore Directorate (formerly known as Norwegian Petroleum Directorate) has said that it is considering a pipeline to connect the Barents Sea to the well-developed pipeline system that runs from the Norwegian Sea to the south and west. ‘This option would make the Norwegian shelf a single petroleum province, tied together with solid and highly-developed infrastructure.’ Another option is to expand capacity at the LNG plant on Melkøya, outside Hammerfest in Finnmark county. The LNG plant is the sole alternative for delivering gas from the Barents Sea and gas exports in the form of liquified gas are dispatched to markets using

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specialised ships. The challenge is that gas from the Snøhvit field alone will continue to occupy all capacity at the LNG plant until 2040. Without new gas transport capacity, projections indicate that the plant will be fully utilised up to 2050, based on

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already proven resources in fields and discoveries. A third option is to use gas from the Barents Sea to produce ammonia, which is then exported by ship, said the Norwegian Offshore Directorate (NOD).

INDUSTRY NEWS

Fugro shoots geophysical survey for Danish offshore wind farm

Fugro has launched a geophysical survey for client RWE off the Danish west coast. Up to three survey vessels will be deployed to carry out a detailed pre-construction survey including a search for unexploded ordnance (UXO) 34 km off the coast of Thorsminde. The data acquired will define the cable routes and exact turbine locations for RWE’s Thor offshore wind farm. Fugro has already conducted a comprehensive geotechnical site investigation for Thor in 2022. Günther Fenle, project director Thor offshore windfarm, RWE Offshore Wind, said: ‘We are looking forward to using the data collected by Fugro to finalise the layout of the wind farm and to determine the routes for the inter-array and export cables.’

Land Seismic Noise Specialists

Marc Kebbel, Fugro’s service line director of hydrography and cable route surveys said: ‘We are using a wide range of survey techniques, comprising offshore and nearshore standard geophysical and UXO surveys techniques, a seismic land refraction survey, and Fugro’s rapid airborne multi-beam mapping system (RAMMS) for comprehensive mapping of the shallow area and beach in the transition zone. ‘The metocean challenges posed by Thor’s exposed offshore location, such as high waves and strong wind in autumn and winter, are adding to the complexity. With a planned capacity of 1000 megawatts (MW) Thor will be Denmark’s largest offshore windfarm to date. Once fully operational, no later than 2027, Thor will be capable of producing enough green electricity to supply the equivalent of more than one million Danish households. RWE is already involved in the Danish Rødsand 2 offshore windfarm, which is located south of the Danish island Lolland, 10 km southeast of Rødbyhavn. The windfarm has an installed capacity of 207 MW (RWE share: 20%) and has been in operation since 2010.

Our Full-Wave Correction (FWCTM) Technology Can Address Surface Scattering and Improve Your Challenging Seismic Data

Ikon donates RokDoc software to US university Ikon Science has donated RokDoc software to Kansas State University. The software, which has an industry value of $4.6 million annually, supports applied geophysics teaching and research in the university’s geology department in the College of Arts and Sciences. Kansas State University uses RokDoc as part of its curriculum to train geoscience students to properly understand rock physics, reservoir characterisation, seismic inversion, geopressure and geomechanics to inform subsurface evaluations. Using the software students can model, predict and integrate multidiscipliFIRST

nary workflows for quantitative interpretation, pore pressure and geomechanics, said Ikon. ‘The U.S. Bureau of Labor Statistics predicts a 5% growth in geoscience jobs between 2019 and 2029, which is higher than average for all occupations,’ said Abdelmoneam Raef, associate professor of exploration and development seismology in Kansas State University’s geology department. ‘The RokDoc suite is a valuable resource for training our students in programs that focus on water and energy resources, which are high priorities at K-State.’

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ENERGY TRANSITION BRIEFS Wood Mackenzie has launched Lens Carbon, a colution that that enables users to screen analyse and value carbon management projects on a global scale. Lens Carbon explores carbon capture utilisation and storage (CCUS), direct air capture (DAC) and carbon offset projects through proprietary data, analysis and benchmarking. The US Department of Energy (DOE) has announced 66 hydro facilities will receive more than $38 million in incentive payments for electricity generated and sold. Eni has reached an agreement in principle with the UK Government on terms and conditions for the economic, regulatory and governance model for the transportation and storage of carbon dioxide at the HyNet North West industrial CCS cluster, providing carbon transportation and storage for companies in the North West of England and North Wales. The US Bureau of Ocean Energy Management (BOEM) has identified a Draft Wind Energy Area (WEA) in the Gulf of Maine, opening a 30-day public review and comment period.The Draft WEA covers approximately 3,519,067 acres offshore Maine, Massachusetts and New Hampshire. Porthos has taken a final investment decision to develop a €1.3 billion CO2 transport and storage system in the Netherlands. In 2024 construction will begin in Rotterdam, with the Porthos system expected to be operational by 2026. Porthos is a joint venture of EBN, Gasunie, and the Port of Rotterdam Authority. Companies in the port of Rotterdam, including Air Liquide, Air Products, ExxonMobil, and Shell will invest in their own capture installations to supply CO2 to Porthos. Porthos will transport the CO2 through the port of Rotterdam to depleted gas fields in the North Sea, approximately 20 km off the coast, where it will be permanently stored at a depth of 3 to 4 km under the seabed. Porthos plans to store about 2.5 Mton per year for 15 years. TotalEnergies and its partners, Corio (27.7%) and Rise (16.3%), have announced that New York State has selected their Attentive Energy One project for a 25-year contract to supply 1.4 GW of renewable electricity off the coast of New York and New Jersey.

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CGG sells ARGAS to end its data acquisition services CGG has agreed to sell its entire 49% stake in Arabian Geophysical and Surveying Company (ARGAS). Sophie Zurquiyah, CEO CGG, said ‘The sale of our stake in ARGAS marks a final step in the strategic plan that we launched back in 2018 to become an asset-light company, by exiting the data acquisition services business and strengthening the focus on our differentiated high-end technology businesses. We look forward to continuing to provide the Kingdom of Saudi Arabia and TAQA with our high-end subsurface imaging and seismic acquisition systems, playing our part in the successful development of energy and low-carbon resources in the Middle East region.’

TAQA is acquiring the outstanding 49% in Arabian Geophysical and Surveying Company (ARGAS) from CGG. Picture shows; TAQA. Supplied by Saudi Arabia’s TAQA.

PGS releases Norwegian Sea data PGS has made data available from its multi-azimuth GeoStreamer X surveys in the Norwegian Sea. The initial GeoStreamer X Norwegian Sea covered 6700 km2 on the Halten/Donna Terrace. An additional 6150 km2 was added in 2023, and a further 7340 km2 acquisition is planned in 2024. A first look at the final full stack data is now possible, in advance of the release of the full volume which will be available by the end of this year, said PGS. ‘In the Norwegian Sea, GeoStreamer X gives a significant advancement in data quality, with more accurate subsurface images,’ said PGS. ‘This first full stack seismic data shows significant improvements that can be observed both at shallow depths and in deep settings, revealing structure and stratigraphy in unprecedented detail, fault imaging enhancement, geological interpretation refinement and signal/ noise ratio augmentation. Kjetil Roverud, PGS sales manager Norway added: ‘We have a realistic 2024

first impression of the final full multi-azimuth stack results from the 2022 program, which we expect to deliver to clients after Christmas.’ Meanwhile, PGS has won a 3D exploration contract in Asia Pacific.

Ramform Sovereign headed for Asia Pacific.

The 50-day survey will secure work for the vessel Ramform Sovereign into the first quarter of 2024. ‘Most of our activities in Asia Pacific in 2023 have been well pre-funded multi-client projects. Now we are experiencing increasing contract tendering activity and see potential for more proprietary work in the region,’ said Rune Olav Pedersen, PGS president and CEO.

INDUSTRY NEWS

UK sets out role of seismic data for energy transition projects The UK North Sea Transition Authority has set out the key role that seismic imaging will play in its rapidly expanding programme of carbon capture, storage and utilisation as well as wind energy projects. The UKCS Energy Transition Environment Report examines the vital and growing role that seismic and geological tools can play in studying the seabed and assessing potential uses of different areas of the North Sea. The report looks in detail at the technological solutions for exploring sites, understanding their characteristics, and undertaking necessary monitoring. ‘Whilst some techniques, such as the use of streamer seismic, may currently be most cost-effective, they have downsides due to their larger footprint and difficult access into developed areas,’ says the report. ‘The focus will increasingly be on techniques

which can minimise operational footprints (e.g. ocean bottom seismic), enhancing resolution where it is needed most, make the best use of early baseline data, take full advantage of improvements in processing, and exploit passive signals thus obviating the need for extensive operations.’ Twenty one carbon storage licences have recently been awarded and the NSTA estimates that up to 100 carbon storage licences will be needed in the near future to meet sequestration targets, and the continuing development of offshore wind. Jo Bagguley, NSTA head of pre-Licensing and storage, said: ‘There is potential for up to £200 billion of private sector investment in the UKCS by 2030, and that will drive UK energy security and the path to net zero. ‘It will also lead to challenges, including how to accommodate the many pro-

jects which require space in the offshore environment. Technology can play a very important part in helping that, alongside the need for collaboration through dialogue and information sharing.’ Professor John Underhill, Aberdeen University’s director for energy transition, said: 'For sequestration to be successful, it is imperative to select and monitor the best stores to ensure that they are safe and do not leak. 'Crucially, the NSTA report documents the significant challenges resulting from the competition for offshore areas, particularly where fixed and floating wind farms impede seismic data acquisition. ‘The report is a timely reminder of the urgent need for marine spatial planning to maximise the use of offshore areas, if the country is going to meet its net zero targets.’

Oil majors results round-up CNOOC has reported third quarter net profit of $13.4 billion. Capital expenditures for the first nine months were $12.3 billion. Capital expenditure for 2023 is expected to be $16.5-18 billion. Costs have been cut by 6.3% to $28.37 per BOE. For the first three quarters, the company has made eight discoveries and produced 500 million BOE, an increase 8.3% year on year, a record high. In the third quarter, the company discovered Huizhou 26-6 North, which was confirmed to be a medium-sized commercial discovery. ExxonMobil has announced third-quarter 2023 earnings of $9.1 billion. Cash flow from operations was $16 billion, up $6.6 billion versus the second quarter. Capital and exploration expenditures were $6 billion in the third quarter, bringing year-to-date 2023 expenditures to $18.6 billion. Full-year capital and exploration expenditures are expected to be at the top end of $23 billion to $25 billion.

Equinor has reported adjusted third quarter earnings of $8.02 billion and $2.73 billion after tax in the third quarter of 2023. Net operating income was $7.45 billion, and net income was $2.5 billion. Shell has reported third quarter earnings of $6.2 billion, up from $5 billion in Q2. Capital spending is expected to be $23-25 million for the full year. The company is reported to be preparing to cut at least 15% of the workforce at its low-carbon solutions division and scale back its hydrogen business as part of CEO Wael Sawan’s drive to boost profits. bp’s third-quarter profits fell by 60 per cent to $3.3 billion after oil and gas prices receded from last year’s highs. Operating cash flow was $8.7bn; net debt was reduced to $22.3bn. Capital expenditure in the third quarter was $3.6 billion. Bp now expects capital expenditure, including capital expenditure to be around $16 billion in 2023.

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ConocoPhillips has reported third-quarter 2023 earnings of $2.8 billion, compared with third-quarter 2022 earnings of $4.5 billion. SLB has reported Q3 revenues of $8.31 billion up 3% sequentially and 11% year on year. Net income was $1.12 billion, up 9% sequentially and 24% year on year. Chevron has announced third quarter earnings of $6.5 billion, down from $11.2 billion in the third quarter of 2022. The company reported expected organic capital expenditure range of $15.5 billion to $16.5 billion for 2024. Upstream spending in 2024 is expected to be about $14 billion with two-thirds allocated to the US, including $6.5 billion to develop Chevron’s US shale and tight portfolio, of which around $5 billion is planned for Permian Basin development. About 25% of US upstream capex is planned for projects in the Gulf of Mexico, including the Anchor project, which is expected to achieve first oil in 2024. Some $2 billion has been allocated to ‘lower carbon capex’.

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Drilling contract awards will continue to lengthen, says Westwood As offshore drilling rig utilisation increases and availability continues to tighten, Westwood has recorded a marked lengthening of new contract award durations. New rig deal durations peaked in 2013 for jackups and in 2014 for floating rigs (semisubmersibles and drillships). Analysis shows that the length of such deals dwindled during the prolonged downturn, reaching a trough in 2018 for floaters and 2019 for jack-ups, but has picked up steam again since the global rig market recovery got under way in 2021. On average, awarded jack-up contract durations have increased 36% compared with 2021, while drillships have increased 41% and semisubs 117%. Drillships have an average global duration of 569 days in 2023 year-to-date, driven by South America (698 days), Mexico (1080 days), the Mediterranean (500 days), India (451 days) and West Africa (517 days). Meanwhile semisubs are currently sitting at a global average contract duration of 384 days, and those areas driving demand are South America (414 days), Mexico (953 days), the North Sea (369 days), the Far East (627 days) and Australia (309 days).

Jack-up demand is coming mostly from areas where there is strong national oil company presence. The average global contract duration so far this year is 661 days with demand driven by the Persian Gulf (1165 days), followed by India (840 days), the Far East (528 days) and Mexico (457 days). Since 2022, awards with the longest contract duration have been for jack-ups in the Middle East. Notably ADNOC Offshore awarded six deals last year, all for 15 years apiece. The same operator has since awarded further long-term jack-up deals, five of which were fixed in June this year for 10 years apiece. Floating rig (semisub and drillship) deals have so far been fixed at up to five years in duration. ‘Westwood believes that further lengthening in average rig deals will be seen over the coming year. Interestingly, there are already 10-year tenders out in the market for a pair of drill ships required for campaigns beginning in early 2025, which is unsurprising considering marketed utilisation of sixth to eighth generation assets is already at 97%,’ said the report.

‘We also expect to see further longterm deals secured for semisubs, especially within the sixth-generation harsh environment segment, where marketed utilisation is now at 100% and there is very limited availability until the second half of 2024,’ Westwood added. In terms of jack-ups, where global utilisation is now sitting at 92% and 95% for high-specification assets, Westwood anticipates further long-term contracting activity to continue. Compared with the 10-year average contract lead time in 2023 is performing almost 9% higher, but has year-to-date made no improvement on the 2022 figure, with both recording an average lead time of 237 days. However, this number is still the longest recorded since the downturn hit in 2014 (248-day lead time average), said Westwood. ‘Westwood predicts that as contract duration and utilisation continue to increase, coupled with decreasing availability and day rates heading further north, lead times will lengthen as operators become more concerned with securing the right assets for their upcoming campaigns.’

CGG and Petronas start 2D project offshore Malaysia

Map showing the location of the 2D multi-client seismic program offshore Malaysia.

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CGG and Petronas have started the Selat Melaka 2D multi-client seismic programme over the Langkasuka Basin offshore Malaysia. Located in the Malacca Strait, the project has received industry funding and will deliver early products in December 2023 and final results in August 2024. Experts at CGG’s Kuala Lumpur subsurface imaging centre will apply its latest proprietary full-waveform inversion (FWI) and Q-tomography imaging technologies with a focus on the prospective pre-tertiary target.

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Mohamed Firouz Asnan, senior vice-president, Malaysia Petroleum Management (MPM), Petronas, said: ‘Petronas continues to invest in data enrichment for Malaysian basins, like the emerging Langkasuka Basin. Initiatives such as this multi-client seismic survey are expected to attract exploration interests to support the country’s production growth strategy.’ Dechun Lin, EVP, Earth Data, CGG, said that the project in an area lacking data coverage would help to reduce uncertainties ahead of Malaysia’s 2024 Bid Round.

INDUSTRY NEWS

TDI-Brookes completes shallow hazard surveys off Trindad and Tobago

Research vessel RV Proteus.

TDI-Brooks has completed multiple shallow hazard surveys off the East Coast of Trinidad for Perenco T&T Limited. Its research vessel RV Proteus operated geophysical survey equipment including 2DHR seismic, side-scan sonar, magnetometer, sub-bottom profiler and a multi-beam echosounder. The primary objective for these projects is to identify potential hazards and factors of operational significance relative to the placement of drilling

rigs. This involves exploring and defining shallow gas accumulations up to depths of approximately 600 m below the mud line or 2.0 seconds two-way time through the acquisition and interpretation of high-resolution 2D seismic data. The focus also extends to the identification of seafloor obstructions, investigation of the proposed area’s seabed for potential man-made and geological hazards, and the determination of water depth and seafloor conditions.

PGS reprocesses Lower Congo Basin data PGS has started depth reprocessing of the ANG Block 16 MC3D GeoStreamer dataset in the Lower Congo Basin, focusing on deeper exploration targets. PGS’ and partner ANPG’s reprocessing of a ten-year-old GeoStreamer MC3D survey at the 3684 km2 ANG Block will apply depth imaging techniques akin to those used recently on the neighbouring Block 1/14 GeoStreamer MC3D survey. PGS said the technique has already demonstrated an improved picture of the deeper post-salt sections in the area. ‘The presence of nearby hydrocarbon accumulations in older reservoirs, coupled with the evidence of oil charge to Upper Miocene units, provides great encouragement that the reprocessed ANG Block 16 dataset can lead to further exploration success,’ said the company. Numerous significant discoveries have been made in the deepwater Lower Congo Basin in recent years and brought on stream at rapid pace, said PGS. Successful recent exploration in the Lower Miocene and Oligocene post-salt plays can be correlated to the evidence of overlooked hydrocarbon shows in the overlying younger stratigraphy. Several cases exist in neighbouring blocks where deeper success lies beneath

Significant potential remains in an underexplored offshore area surrounded by oil and gas discoveries.

the presence of shows or discoveries in Upper Miocene reservoirs that were declared non-commercial at the time, PGS added. Block 16 has largely been overlooked for exploration potential since the early-2010s, with the most recent exploration well drilled in 2013. The Bengo (1994) and Longa (1995) Upper FIRST

Miocene discoveries in the north of Block 16 were, until recently, the only publicly known oil and gas finds imaged by the ANG Block 16 dataset. The recent re-evaluation of wells in the Lower Congo Basin has revealed that oil was also recovered from Upper Miocene reservoirs in the south of the survey area. Data will be ready in Q3 2024.

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BRIEFS PXGEO has won a contract with Petrobras for a 4D Monitor Ocean Bottom Node (OBN) survey in the Santos Basin, Brazil. The survey is to be acquired in water depths up to 2200 m with a duration of approximately 7 months. Shearwater has signed a technology agreement with Petrobras to ‘reshape seismic exploration and field developments in Brazil’. The companies will collaborate on optimising application of Shearwater’s BASS marine vibrator. ‘This project aims to accelerate the exploration and development of the Brazilian fields, leveraging increased operational efficiency, innovative geophysical method and better control of seismic frequencies,’ said Petrobras. As a result of the order issued by the United States Court of Appeals, the US Bureau of Ocean Energy Management (BOEM) scheduled Lease Sale 261 for 20 December, 2023. The Gulf of Mexico oil and gas lease sale was originally scheduled for 27 September 27, 2023, and later scheduled for 8 November, 2023, in response to judicial orders. BOEM will include lease blocks previously excluded due to concerns regarding potential impacts to the Rice’s whale population in the Gulf of Mexico. Petronas has recorded 19 exploration discoveries and two exploration-appraisal successes, contributing more than 1 billion barrels of oil equivalent (bboe) of new resources for Malaysia in 2023. This was the result of drilling 25 wells, the highest number of exploration wells drilled in a single year since 2015. More than half of the discoveries were made in the Sarawak Basin, primarily in two clusters within the Balingian and West Luconia geological provinces. The UK North Sea Transition Authority has reported that the UK has approved seven new oil and gas projects in its waters in 2023, which are expected to generate around $4 billion of investment and produce some 370 million barrels of oil and gas.

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CGG launches HPC and AI solutions CGG has launched its Outcome-as-a-Service (OaaS) offering, designed to deliver customised, capability-focused HPC and AI solutions for scientific and engineering domains including generative AI and life sciences. ‘OaaS offers a guaranteed cost-effective approach for users wanting to transition their HPC and AI workloads to a production-based model aligned with their business objectives,’ said CGG, which added that is the ‘first market player’ to introduce an OaaS offering. ‘The combination of the latest compute technology, including AMD EPYC Genoa CPUs, Intel Xeon Sapphire Rapids CPUs and Nvidia H100 GPUs, together

with the novel OaaS commercial model, will deliver an industrialised HPC solution that is ideal for AI, as well as workload-intensive simulation and modelling in areas such as molecular dynamics.’

Norway makes first offshore wind data sets available The Norwegian Offshore Directorate (formerly the Norwegian Petroleum Directorate) has prepared the first data sets for offshore wind on the Norwegian shelf. Data from the subsurface surveys in the first phase of Sørlige Nordsjø II (Southern North Sea II) are now ready for download from Diskos. This includes surveys NPD22100 and NPD23100. Each survey contains: 2D Ultra-High-Resolution (UHR) multi-channel seismic data; Bottom penetrating sonar data; Multi-beam echo sounder (bathymetry) data; Back-scatter data; MBES water column data; Magnetometer data and Side-Seeking Sonar (SSS) data. The first phase of the survey in Sørlige Nordsjø II (eastern part) was started in the autumn of 2022 and completed in 2023. The survey on Utsira Nord started in the summer of 2023. To date, the northern area has been completed, while the southern area is nearing completion. Work recently began on the central area. The Utsira Nord survey will be completed in the spring of 2024. Magnetometer data and MBES water column data will only be made available after a licence is awarded, said the NOD. JANUARY

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Players will also have access to the complete version of the interpretation report. The first areas were opened for renewable offshore energy production on the Norwegian shelf in 2020. In 2023 Norway announced project areas for offshore wind at Utsira Nord and Sørlige Nordsjø II. The authorities plan to award acreage during the first quarter of 2024. Norway’s ambition is to award acreage for 30,000 megawatt (MW) of energy generation by 2040. The NOD said that players who want to access the collected data, NPD22100 (NPDid 10679) and NPD23100 (NPDid 10620) can access the Diskos Public Portal.

INDUSTRY NEWS

Fugro completes geophysical survey offshore Namiba Fugro has won a contract with the Portugeuse energy company Galp to conduct an environmental and geophysical survey offshore Namibia. Geophysical vessel Fugro Venturer collected sediment samples for environmental and chemical analysis before an autonomous underwater vehicle (AUV) captured seabed video footage at depths

of 2000 m. Additionally, Fugro acquired in situ full ocean depth water profiles and water samples to measure the current biodiversity. The geo-data will support the identification of potentially sensitive habitats, advance knowledge of remote seamounts, and contribute to informed project planning and resource management.

The geophysical survey will also provide insights into the underwater landscape, ensuring the safe movement and operation of offshore assets within the designated area. ‘Known for its remote location, challenging conditions and ultra-deep water, this site is key to future energy operations in the region,’ said Fugro.

KPMG calls for green energy investment revolution in Africa KPMG has highlighted ‘significant untapped green investment opportunities’ in Africa at the COP 28 conference in Abu Dhabi last month. The Climate Policy Iniative reports that Africa needs $277 billion annually until 2030 to meet Paris Agreement targets but there is currently annual public and private investment of $29.5 billion from domestic and international sources. KPMG’s report Climate Investing in Africa details $250 million of investment opportunioties in renewable energy resources such as wind, solar and low-carbon hydrogen. ‘The untapped promise of wind is particularly marked, with recent research showing that 27 countries in Africa have sufficient wind potential on their own to satisfy the entire continental electricity demand, despite the fact that Africa only uses 0.01% of its wind potential,’ said KMPG. Pieter Scholtz, KPMG’s ESG Africa Partner Lead, said: ‘It is unlikely that global climate change mitigation efforts can be successful without taking Africa into consideration. The continent offers some of the planet’s biggest and most profitable options for investments in the global energy transition. Superior returns can be realised by smart investors who are willing to act as early movers on the continent.’ Despite its abundant renewable energy resources and vast non-arable land, Africa currently receives only 3% of global renewable energy investment while the

continent is home to 20% of the world’s population. ‘While the region is not without its investment hurdles, for a significant number of countries, the perceived risks are greater than the actual risks,’ said KPGM. The report tackles often-cited issues such as political instability, regulatory concerns and limited network infrastructure, showing that these are undeniable yet nuanced and are not insurmountable challenges. The report shows that if Africa were to exploit all of its wind resources for renewable energy generation, it could bridge the current energy provision gap on the continent. The International Finance Corporation estimates that Africa’s wind potential is so substantial that it could meet electricity demand 250 times over. Underinvestment has resulted in inadequate infrastructure and high costs in the solar sector. Africa’s current solar potential is estimated to be over 1000x the current solar power electricity generation capacity, yet it has only been systematically deployed in a handful of countries. ‘This is indicative of the significant investment opportunity that exists – bolstered by the continent’s solar irradiation quality, yield and abundance,’ said KPMG. Despite the fact that Africa has some of the greatest potential worldwide for producing hydrogen and ammonia from renewables at relatively low cost, the current use of low-carbon hydrogen on the continent today is minimal, said KPMG. ‘Africa’s possession of copious renewable energy FIRST

KaXu Solar One provides clean energy to 80,000 South African households a year. Image courtesy of Abengoa.

resources and vast arable land positions the continent uniquely well to produce green hydrogen and catalyse the broader process of industrialisation on the continent.’ Dr Benedikt Herles, EMA Head of ESG insights and innovation, head of country practice Africa, said: ‘Despite the region’s capacity to play an essential role in the global climate response, Africa continues to be stifled by underinvestment and a range of misconceptions around its attractiveness as a location to direct green financing. Africa is home to some of the planet’s largest and most profitable options for investments in the global energy transition, making it a uniquely appealing green investment destination. ‘Climate investors are looking ahead to new and emerging markets to deploy their funds. It is vital that there is a nuanced and sophisticated understanding of Africa’s potential, and that private investors appreciate the unique advantages and characteristics of the region with respect to not just climate investing, but the broader contribution to the global energy transition from an environmental and social impact perspective.’

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INDUSTRY NEWS

Fugro wins survey for wind contract off South Korea Fugro has won a contract from KREDO Offshore for a metocean and wind resource measurement campaign on the west coast of South Korea, offshore Yeonggwang County. Fugro will provide a turnkey solution encompassing technology deployment, provisioning, operations,

maintenance and comprehensive data reporting. The project site is in the initial investigation stage to assess its suitability for investment. A total of four Seawatch Lidar buoys have been strategically deployed within the study area. These buoys measure a comprehensive range

of metocean parameters which include wind, waves, current and meteorological conditions. The data collection will take place over the next 12 months, with real-time data provision for decision makers and consultants with data in advance of final reporting from Fugro.

Oil and gas round-up Beach Energy has made a gas discovery in the Perth Basin, offshore western Australia. Tarantula Deep 1 reached total depth of 4121 m and intersected a 63-m gross section of high quality Kingia Sandstone reservoir comparable to the offset well Beharra Springs Deep 1. Tarantula Deep 1 intersected a gas water contact within the Kingia reservoir, with net gas pay of 10 m above the contact confirmed by gas sampling. The Norwegian Offshore Directorate has granted Aker BP and Equinor a drilling permit for wells 30/12-3 S, 30/12-3 A and 30/12-3 B in production licence PL 272 B in the North Sea. OKEA has confirmed a find of 0.2 and 0.5 million Sm3 of recoverable oil after drilling well 31/4-A 13 E at the Brage field in the northern part of the North Sea. Equinor has made a commercially viable gas discovery by the Gina Krog field in the North Sea. The discovery is small, but gas production can start as early as 2023. Recoverable volumes are estimated to be between 5 and 16 million barrels of oil equivalent. Equinor is the operator with KUFPEC and PGNiG as partners. ExxonMobil’s Lancetfish-2 appraisal well in the Stabroek Block has resulted in a significant discovery offshore Guyana. This marks the fourth offshore discovery in Guyana for the year 2023 and brings the total number of discoveries from 2015 to date to a total of 46. The Lancetfish-2 discovery in

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the Liza Petroleum Production Licence area has unveiled an estimated 20 m of hydrocarbon-bearing reservoir, along with approximately 81 m of additional hydrocarbon-bearing sandstone. ExxonMobil affiliate Esso Exploration and Production Guyana is operator and holds a 45% interest. Hess Guyana Exploration holds 30% interest and CNOOC Petroleum Guyana holds 25% interest. Petronas has made an oil discovery at the Roystonea-1 exploration well in Suriname’s Block 52. The well, located about 185 km offshore in water depth of 904 m, was drilled to a total depth of 5315 m. It also encountered several oil-bearing Campanian sandstone reservoir packages. Block 52 covers an area of 4749 km2 in the prospective Suriname-Guyana basin. Petronas (50%) is the operator of Block 52 with ExxonMobil (50%). Var Energi has won a drilling permit for wells 25/7-12 S and 25/7-12 A in production licence PL 917 in the Norwegian North Sea. Licensees are: Var Energi 40%; Aker BP 40%; and Equinor 20%. Equinor has completed the drilling of wildcat well 6307/1-2, 36 km south of the Njord field in the Norwegian Sea. This is the first well in production licence 1058, issued in the Awards in Pre-defined Areas in 2019. Water depth is 312 m. The objective of the well was to prove petroleum in Triassic reservoir rocks (Red Layer), as well as to evaluate cap rock, reservoir and fluid proper-

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ties. The well encountered sandstones, conglomerates and intermittent silt and clay stone with reservoir quality in the exploration target consistently in the range of poor to none. Extensive data acquisition and sampling were carried out. The well was drilled to a vertical depth of 2283 m below sea level, and was terminated in sandstones in the presumed Red Layer in the Middle Triassic. Equinor has discovered oil and gas in exploration well 30/6-C-2 A (Lambda), about 4 km west of the Oseberg field in the North Sea. Equinor is the operator of production licence 053; other licensees are Petoro, Total and Conoco Phillips. The size of the discovery in the Eiriksson Formation is estimated between 0.2 and 0.4 million standard cubic metres of recoverable oil equivalent and in the Cook Formation to between 0.2 and 1 million standard cubic metres of recoverable oil equivalent. The primary exploration target for the well was to prove petroleum in Upper Triassic to Middle Jurassic reservoir rocks in the Statfjord Group. The secondary exploration target for the well was to prove petroleum in Lower Jurassic reservoir rocks in the Cook Formation. Well 30/6-C-2 A encountered about 23 m of oil and gas-filled sandstone with good reservoir quality in the Eiriksson Formation in the Statfjord Group. In the Cook Formation, the well encountered about 15 m of oil and gas-filled sandstone with moderate to good reservoir quality.

TECHNICAL ARTICLE

Virtual Shear Checkshot from a densely sampled DAS walkaway VSP in a desert environment Ali Aldawood1*, Amnah Samarin1, Ali Shaiban1 and Andrey Bakulin.

Summary Distributed Acoustic Sensing (DAS) provides a cost-effective method for recording borehole seismic surveys. DAS can measure only a single component of strain or strain rate, making it unsuitable for 3-component processing necessary to separate mode-converted waves, unlike conventional 3C geophone Vertical Seismic Profile (VSP) data. However, in moderately deviated wells equipped with optical fibres, DAS can accurately capture high-fidelity modeconverted events even at significant source offsets from the well. Recently, DAS VSP data was acquired in a desert environment, revealing mode-converted energy across the deviated part of the well from shots spanning an offset range between 1.5 km to 2.7 km. The virtual source method, also known as seismic interferometry, was applied to this mode-converted energy to create virtual shear sources igniting mainly shear-wave energy inside the borehole. The method was basically utilised to transform the walkaway DAS VSP data into single-well profiling or virtual checkshot, enabling precise measurements of shear-wave seismic velocities. The obtained velocity profiles from the virtual downhole shear sources closely match the velocities acquired from the dipole sonic log and geophone VSP data in an adjacent well. These results underscore the effectiveness of seismic interferometry in obtaining accurate shear-wave velocity profiles, even from single-component DAS measurements.

Introduction Distributed Acoustic Sensing (DAS) has proven to be a relatively inexpensive tool to record seismic signals (Zhan, 2020). It has been widely used in borehole seismic acquisition since it provides a dense array of recording points along the fibre at a relatively low cost (Mateeva et al., 2014). DAS vertical-seismic-profiling (VSP) are increasingly acquired and demonstrated as a replacement for conventional geophone surveys (Yu et al., 2020), particularly for 4D seismic and reservoir monitoring (Mateeva et al., 2013, 2014; Isaenkov et al., 2022). DAS uses fibre-optic cables as a sensing array to record seismic data instead of the three-component geophones used in VSP acquisition surveys (Yu et al., 2018) by measuring the axial strain or strain rate along the fibre (Bakku, 2015). Cables are often installed inside wellbores, resulting in a large downhole seismic array for VSP imaging and monitoring (Yu et al., 2019). Downhole wireline geophones typically have a fixed spacing of around 15 m, and the array’s length is limited to a few hundred metres, which are often moved multiple times to cover the desired depth range (Titov et al., 2022). Enhancing the density of VSP data poses a significant challenge with traditional geophone receivers, necessitating innovative acquisition methods such as DAS. The DAS receiver acts as a natural array, providing an average over the gauge length while enabling dense receiver sampling (Bakulin et al., 2020). Optical fibres enable complete well coverage in a single sweep, offering high receiver densities at a more affordable cost (Yu et al., 2019). Fibre-optic cables are

Saudi Aramco

Corresponding author, E-mail: ali.dawood.18@aramco.com

now commonly deployed in wellbores for real-time pressure and temperature monitoring during production (Fitzel et al., 2015). These pre-installed cables can capture borehole seismic data without wellbore intervention, with the assistance of a seismic vibrator and an interrogation box for recording optical signals. Different VSP acquisition geometries and cable conveyance methods, including on-tubing, behind the casing, and wireline, have been effectively utilised in successful DAS VSP field tests for subsurface imaging and monitoring (Hartog et al., 2014, Mateeva et al., 2014, Parker et al., 2014). Eliminating the need to move the tool string due to DAS covering the entire well enabled the acquisition of a multi-well 3D VSP survey (Mateeva et al., 2014). Aldawood et al. (2023) presented initial findings from their simultaneous dual-well DAS walkaway VSP acquisition. Their study showcased the potential of pre-installed DAS on production tubing, revealing high-resolution subsurface models and delivering high-quality imaging between two deep wells. This study shows an advanced analysis of this dataset focusing on harvesting valuable subsurface information using mode-converted waves. In one well, we found clear mode-converted (PS) waves in the recorded data. We utilised the virtual source method (VSM) or seismic interferometry, leveraging these signals. This method enabled the creation of virtual shear sources in the downhole environment (Bakulin and Calvert, 2005, 2006; Schuster, 2009). The interferometric transformation enabled us to redatum

DOI: 10.3997/1365-2397.fb2024001

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Figure 1 Dual-well acquisition set-up and data: (a) the acquisition geometry featuring the deviated well A and nearly vertical well B connected to the interrogator through a jumper cable (black); (b) a representative receiver gather at a depth of 2 km, highlighting distinct mode-converted arrivals indicated by green oval.

Figure 2 Three typical shot gathers from different offsets from the well showing the direct arrival event (A), the mode-converted PS arrivals (B), and the slow tube-waves (C).

surface shots to virtual sources inside the borehole using recorded data as natural wavefield extrapolation (Bakulin et al., 2007; Schuster, 2009). Thus, physically recorded data as walkaway VSP is transformed into a virtual single-well profiling (SWP) dataset. Bakulin et al. (2007) and Aldawood et al. (2019) showcased the reliability of S-wave velocity profiles derived from redatumed sources using 3C geophone walkaway VSP datasets. This study extends this method to single-component DAS walkaway VSP data. We aim to obtain an accurate shearwave velocity profile similar to sonic log results, utilising the cost-effective DAS technology. DAS walkaway VSP data The survey utilised two pre-installed optical fibres in adjacent deep wells, spaced approximately 1.5 km apart, within a desert environment. In Figure 1a, the acquisition geometry is illustrated, with yellow dots representing receivers inside the boreholes (639 in well A and 630 in well B), and red dots indicating 292 surface shot locations spaced about 12.5 m apart. Both wells have a depth of approximately 4 km, and for this experiment, a gauge length (GL) of 24 m was set, with receiver spacing at 6.4 m. The GL refers to the length of the optical fibre over which the recorded signal is optically averaged (Dean et al., 2017). Both fibres are linked to the same interrogator, enabling simultaneous data recording from each shot point. In well B, the fibre is connected to the box through a jumper cable (black), as depicted in Figure 1a. 38

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Figure 1b displays common-receiver gather from a depth of approximately 2 km at well A, highlighting evident mode-converted (PS) arrivals indicated by green oval. These PS arrivals are discernible within an offset range extending from around 1.5 km to 2.75 km towards well B. Shots within this range are employed in the interferometric redatuming process. Additionally, the elevation curve of the shots is depicted in Figure 1b, illustrating varying topography that contributes to significant statics in the first-arrival waveforms. Figure 2 displays three representative shot gathers captured at well A with offsets of 1 km, 2 km, and 2.5 km towards well B. Event A represents the P-wave initial arrival, while event B signifies the mode-converted arrival, and event C denotes the slow tube wave. Notably, event B exhibits a distinct slope and slower velocity in contrast to event A, the P-wave first arrival. This is evidence of capturing the mode-converted shear waves at these larger offsets from well A. We applied a processing workflow to the DAS VSP dataset recorded at well A tailored to enhance downgoing mode-converted PS energy. These gathers are subsequently used for the interferometric transformation. Figure 3a shows the processing workflow for shear-wave profiling using the virtual source method. It starts with the first-break (FB) picking of the downgoing P-wave first arrivals followed by FB flattening and median filtering of the downgoing P-wave energy. The resultant wavefield consists of upgoing energy and downgoing mode-converted waves. Dip-median filtering is applied to amplify the upgoing P-wave reflections, crucial for imaging as demonstrated in Aldawood et al. (2023). Meanwhile,

TECHNICAL ARTICLE

the remaining wavefield, rich in downgoing mode-converted PS energy, is harnessed in the interferometric redatuming process. It’s essential to highlight that the wavefield separation operations are confined to median and dip median filters due to the nature of the recorded DAS signals, which strictly represent single-component strain measurements along the optical fibre (Sayed and Stewart, 2020). Figure 3b shows the effect of the processing sequence on three representative shot DAS VSP gathers at varying offsets from the well. These processed DAS VSP shot gathers were inputted into the interferometric redatuming engine, resulting in the creation of the targeted shear-wave downhole virtual gathers. Interferometric redatuming with virtual shear source Seismic interferometric redatuming aims to convert the traditionally acquired walkaway VSP dataset into a virtual dataset with an altered acquisition set-up called single-well profiling (SWP). This transformed geometry (VSP → SWP transformation) situates both sources and receivers inside the borehole, achieved by moving surface sources to downhole receiver positions (Bakulin and Calvert, 2006; Schuster, 2009). The VSP-to-SWP interferometric redatuming is performed by applying the reciprocity equation of the correlation type (Wapenaar and Fokkema, 2006; Schuster, 2009) which in the frequency domain is written as follows: (1)

where G(r2|r1) represents a virtual SWP trace recorded at a deeper receiver station r2 due to a virtual downhole shear source at a shallower receiver station r1. G(r2|s) is the recorded DAS VSP seismic trace containing the extracted mode-converted PS arrivals recorded at r2 due to a surface source at s. G(r1|s)* is the complex conjugate of the recorded DAS VSP trace recorded at a receiver station r1 due to a source at s. Note that the multiplication with the complex conjugate in the frequency domain is equivalent to the cross-correlation with the same trace in the time domain. A schematic ray diagram in Figure 4a illustrates the geometrical interpretation of the cross-correlation between a mode-converted PS arrival recorded at r2 due to a source at s and another mode-converted PS arrival recorded at r2 due to a source at s. This operation results in a single-well profiling trace, representing a virtual shear-wave source ignited at a shallow receiver r1 and recorded at a deeper receiver r2. The travel time linked to the shared ray path is subtracted, and the arrival time of the virtual event corresponds to a direct shear energy propagating from r1 to r2. The virtual trace is obtained through a data-driven cross-correlation process between recorded traces, without relying on the subsurface velocity model. Importantly, redatuming the surface seismic eliminates the source-side statics (as shown in Figure 1b), providing a significant advantage (Schuster, 2009). Bakulin et al. (2007) demonstrated that the use of a deviated well enhances the effectiveness of the Virtual Source Method

Figure 3 DAS data pre-processing and result: (a) The processing workflow used to extract downgoing mode-converted waves; and (b) three representative shot gathers at varying offsets showing enhanced PS arrivals after pre-processing.

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Figure 4 Interferometric redatuming illustrated: (a) a schematic Figure demonstrating crosscorrelation redatuming of surface shots into a virtual downhole shot emitting shear-waves; and (b) a schematic Figure showing the advantage of including the recorded multiples in the interferometric transformation.

because it allows the downhole virtual source to effectively combine all mode-converted waves at non-vertical angles, as illustrated in Figure 4a. Consequently, stacking all shots within the offset range exhibiting mode-converted waves (1.5 km to 2.7 km offset in our study) results in precise shear-wave arrivals in the deviated well. These shots, as identified through stationary phase analysis, provide substantial physical contributions to the data (Korneev and Bakulin, 2006; Poliannikov and Willis, 2011). In well A, a comparable maximum deviation of approximately 26° from the vertical aligns with the field and synthetic examples presented by Bakulin et al. (2007). Their study utilised the horizontal component of the wavefield, primarily consisting of PS arrivals, for the interferometric transformation. In our DAS case, advanced processing of the single-component wavefield was necessary to separate the mode-converted arrivals. To enhance the reconstruction of virtual SWP shear-wave arrivals, we incorporated all mode-converted arrivals in the interferometric transformation. This strategic approach enables the constructive contribution of multiples of different orders to the desired downhole arrival, as depicted schematically in Figure 4b.

Results and discussion A total of 233 downhole shear-source virtual gathers, ranging in depth from approximately 2000 m to nearly 3600 m in true vertical depth (TVD), were reconstructed using the interferometric transformation outlined in equation (1). This process redatumed and concentrated 140 surface shots, crucial for constructive interferometric stacking, at the downhole receiver positions illustrated in Figure 5a along the well trajectory. Figure 5b displays three illustrative virtual shear-wave shots corresponding to various virtual-source depths, ranging from shallow to deep within the reconstructed depth range. The picked arrivals on these virtual shots exhibit distinct event moveouts. In Figure 5b, four delineated zones highlight notable velocity changes, represented by varying slopes of the events. It’s evident that there’s a subtle overlap in the FB picks of the shear-wave direct arrival on the virtual shots across different zones. Zones 1 and 3 demonstrate slower shear-wave velocities, whereas Zones 2 and 4 display comparatively faster ones. More than 16,000 shear-wave first-break (FB) picks were employed to reconstruct a partial profile spanning from a true vertical depth (TVD) of approximately 2000 m to 4000 m.

Figure 5 The virtual shear source reconstruction: (a) the virtual source locations with accurate reconstruction of the shear-source wavefield; and (b) three sample virtual shot gathers from shallow, intermediate, and deep locations within the reconstructed range. Distinct zones were delineated, each exhibiting unique slopes. The green dots highlight first-arrival picks of shear-wave energy.

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Figure 6 Shear-Wave Profiling: (a) More than 16,000 first-break picks were meticulously chosen for each virtual shot gather, covering a specific segment of the receiver depth range. All these picks contributed to constructing profiles in (b); (b) a total of 233 shear-wave velocity profiles across a depth range of approximately 2 km. Distinct boundaries outlining four different velocity zones are clearly discernible, as indicated by the red lines.

Figure 6a and 6b present all the picks after a 13-sample point linear-fit smoothing, and their corresponding 233 profiles, respectively. Notably, the four distinct zones are clearly delineated in Figure 6b. We used all the reconstructed profiles to deduce the mean shear-wave velocity profile (in blue) with its standard deviation (in red) and presented the results in Figure 7. The black arrows mark the boundaries separating the different zones with lithology. The description of the cutting samples confirms these boundaries. The initial demarcation between Zone 1 and Zone 2 signifies the transition from clastic rocks featuring shale, siltstone, and sandstone interbeds to dolomitic lime mudstone. The subsequent boundary, distinguishing Zone 2 from Zone 3, indicates the presence of a distinct shale layer underlying the dolomitic lime mudstone. The third interface marks an unconformity between the shale in Zone 2 and a formation consisting of interbedded anhydrite, shale, and dolomitic lime mudstone. Therefore, the lithology change provides a strong validation of the virtually constructed shear-velocity profile. To confirm the accuracy of the obtained shear-wave velocity profile, we superimposed the reconstructed profile in Figure 7 with a shear sonic-log profile from the nearby well B. The dashed black curve represents the shear sonic log, which aligns closely with the profile obtained using the virtual source method. Previously, zero-offset VSP (ZVSP) dataset was collected in well B, and Alford rotation (Alford, 1986) was employed on the ZVSP datasets to extract both radial and transverse components. Shear-wave arrivals were identified to reconstruct shear-wave velocity profiles on the radial component, spanning the interface between Zone 3 and Zone 4, where a pure shale layer overlays a carbonate formation. Figure 8a displays the selected radial component geophone ZVSP gather, while Figure 8b showcases a single virtual DAS gather across the same depth range along the interface. The shear-wave velocity profile obtained from the radial component geophone picks is illustrated in Figure 9 in yellow. It shows a remarkable agreement with the mean profile derived from the virtual gathers across the interface, indicated by the red

arrow. The dashed black curve represents the shear-wave sonic from the neighbouring well, providing additional validation for the accuracy of the constructed profile using seismic interferometry. The discrepancy between the log and the seismic profiles, especially below the interface can be related to the fractures within this depth interval. It is a highly fractured zone that often shows strong shear-wave splitting effect; thus, it can yield different measurements for sonic and seismic depending on the azimuth of the tools and shot locations.

Figure 7 the average shear-wave profile depicted in blue, derived from all 233 profiles shown in Figure 6b. The corresponding standard deviation is represented in red. The black dashed curve represents the shear sonic log from the adjacent well B.

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Figure 8 Shear-wave picking on: (a) the radial component of the ZVSP data spanning a depth range of 200 m across the boundary between Zone 3 and Zone 4; and (b) the virtual DAS downhole shear-source gather over the corresponding depth range. Note that the time in the radial component geophone data is the absolute time from the surface to downhole whereas the virtual DAS gathers shows the same time interval using the relative times after interferometric redatuming.

recorded data exhibited reliable mode-converted waves from specific shots at offsets ranging from 1.5 to 2.7 km, particularly at deeper receiver stations within the deviated section of the well. These selected shots, producing consistent stationary contributions, were utilised in a correlation-type interferometric redatuming operation. The resulting virtual downhole shot gathers, containing direct shear-wave energy, enabled the reconstruction of a robust shear-wave velocity profile from depths of approximately 2 to 4 km. The average velocity profile, derived from all the gathers, was calculated alongside the standard deviation, showcasing the reliability of the reconstruction. Remarkably, the shear sonic log from a nearby well closely matched the reconstructed profile obtained through interferometry. This alignment revealed four distinct lithological zones, a finding corroborated by drill cutting samples. To further validate the profile’s robustness, we compared the reconstructed profile from picks on the radial component geophone with the mean profile derived from the DAS virtual shear gathers across a specific interface. The consistency between these profiles emphasised the reliability and accuracy of our methodology. In summary, our study demonstrates the efficacy of the virtual source method in reconstructing shear-wave sources from DAS VSP data, offering valuable insights into subsurface structures and confirming the method’s applicability for geological investigations in challenging desert environments. Figure 9 Comparison of shear-wave velocity estimates across the same interval in Figure 8. The yellow line represents data from the radial component of the ZVSP data (Figure 8a), while blue dots depict virtual shear checkshots from DAS data (Figure 8b). The shear log from the neighbouring well B is shown as a dashed black curve. Notice the strong agreement between geophone and DAS profiles, as well as alignment with the sonic log, indicating the accuracy and reliability of the obtained shear-wave velocity data.

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Conclusions In this study, we successfully applied the virtual source method to reconstruct downhole shear-wave sources using a recently acquired walkaway DAS VSP dataset in a desert environment. The 42

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optical profiling on wireline logging cable. Geophysical Prospecting,

Y.J. [2019]. 3D-VSP survey using a DAS system and downhole

62(4), pp.693-701.

geophone array in Southwest China. 81st EAGE Conference and

Isaenkov, R., Tertyshnikov, K., Yurikov, A., Shashkin, P. and Pevzner, R. [2022]. Effect of Source Mispositioning on the Repeatability of 4D Vertical Seismic Profiling Acquired with Distributed Acoustic Sensors. Sensors, 22(24), p.9742.

Exhibition 2019, (Vol. 2019, No. 1, pp. 1-5), European Association of Geoscientists & Engineers. Yu, G., Xiong, J.L., Wu, J.J., Chen, Y.Z. and Zhao, Y.S. [2020]. Enhanced surface seismic data processing using simultaneous acquired DAS-

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sensitive seismic antennas. Seismological Research Letters, 91(1), pp.1-15.

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Machine learning for petrophysical modelling: a case study of Groningen gas field, the Netherlands Xiao Wang1*

Abstract Petrophysical modelling is important in reservoir characterisation. Classic geostatistical approaches have been widely used to generate 3D petrophysical properties. However, many manual interactions are required in classic approaches because they are based on the simple stationarity assumption. Various machine-learning (ML) algorithms have been developed to reduce the cycles of petrophysical modelling. In this paper, we apply a ML petrophysical modelling algorithm combining random forests and Kriging to the Groningen gas field. Four scenarios are evaluated: (1) using different quality of well data as input, (2) using different geometrical variables as secondary variables, (3) using different seismic attributes as secondary variables, (4) upscaled gamma and density properties with a nonlinear relationship. The conclusions are (1) bad-quality well data can seriously impact the results, (2) inclusion of more geometrical variables can dramatically improve the results, (3) the impact of seismic attributes on the results heavily depends on the correlation between seismic attributes and input wells, (4) generated gamma and density properties can automatically reproduce the nonlinear relationship in wells. This case study is helpful both for better use of this algorithm in future studies and for providing a reference for evaluating other ML petrophysical modelling algorithms based on the Groningen dataset.

Introduction The estimation and simulation of 3D petrophysical properties (e.g., porosity, permeability, density, etc.) in the subsurface are very important in reservoir characterisation. The generated properties are the main inputs of volume calcuation and reservoir simulation. Classic geostatistical approaches have been successfully used to generate 3D petrophysical properties for decades. As stated by Ismagilov et al. (2019), most classic geostatistical approaches (such as Sequential Gaussian simulation) are based on the stationarity assumption, which is often not borne out by field data. A common solution is removing trends within a petrophysical property to transform data to a more stationary shape. This requires many manual interactions to build and update the petrophysical models. Recently, there has been a great interest in utilising machine learning (ML) methodology to do petrophysical modelling (e.g., Vallabhaneni et al., 2019; Daly, 2020; Yasin et al., 2021). For example, Vallabhaneni et al. (2019) propose an ML-based approach that integrates 3D spatial availability of seismic data with petrophysical properties. Yasin et al. (2021) present a strategy of joint inversion that combines support vector machine and particle swarm optimisation algorithms to predict the distribution of porosity using well logs and seismic data. However, to the best of our knowledge, there have been few activities in combining geostatistics and ML to do petrophysical modelling. Daly (2020) presents an embedded model estimator

SLB

Corresponding author, E-mail: XWang53@slb.com

that combines Kriging with quantile random forests for petrophysical modelling. Based on the definition of Lafferty et al. (2001), the embedded model estimator developed by Daly (2020) belongs to the class of conditional random fields (CRF). The form of CRF used in this algorithm embeds existing spatial models using a Markovian hypothesis (Durrett, 2019). In this algorithm (Daly et al., 2021), the target variable is a petrophysical property (e.g., porosity, permeability, density, etc.). The secondary variables normally are seismic attributes, coordinates of the cells in the 3D grid. The embedded variables are two simple Kriging models, which are a long-range and a short-range model. The contribution of these embedded variables and secondary variables can be automatically determined. To do the 3D petrophysical modelling, this embedded model estimator works in two steps (Daly, 2022). In the first step, known as estimation, the statistical distributions of the target variable at each location in the reservoir are estimated. Different properties can be generated from these statistical distributions, such as different quantiles of the petrophysical properties. For example, the P50 of the estimated petrophysical property is calculated by extracting the P50 of the statistical distributions at each location. In the second step known as simulation, realisations of the petrophysical properties which are suitable for flow simulation are created by stochastic sampling from the statistical distributions. Compared with classic geostatistical approaches, this algorithm can explicitly handle trend-like variables in the estimation process, and the data transformation

DOI: 10.3997/1365-2397.fb2024002

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is not required. Meanwhile, multiple secondary variables can be used, and the predictor may ‘reweight’ the local importance of secondary variables to adapt to local heterogeneity (Daly, 2020). In this study, we apply this embedded model estimator to do the petrophysical modelling over the Groningen gas field. By using different kinds of input data and comparing the results, we aim to further evaluate this algorithm. Meanwhile, because the geological model of the Groningen gas field is a well-known open dataset, the workflow of this study is informative for evaluating other ML petrophysical modelling algorithms on the Groningen dataset. Thus, this case study can help to advance research in ML petrophysical modelling. The Groningen gas field and open dataset The Groningen gas field is located in the northeast of the Netherlands, which is within the southern Permian basin (Dempsey and Suckale, 2017). It is the largest onshore gas field in northwest Europe and one of the largest gas fields in the world. It was discovered in 1959, and production started in 1963. In the Groningen gas field, the gas is produced from the Permian Rotliegend group, which is composed of sandstone interbedded with silt and shale. The depositional environment of the reservoir is alluvial fan and

Figure 1 The top of Permian Rotliegend group in depth.

desert lake (Glennie, 1972). The porosity range in the reservoir is from 15% to 20%, and the permeability ranges from 0.1 to 3000 mD (van Thienen-Visser and Breunese, 2015). Based on the study from van Wijhe et al. (1980), the Carboniferous coals and organic-rich shales are the source rocks in the Groningen gas field. The Permian Rotliegend group is capped by the Permian Zechstein group, which comprises evaporite and anhydrite layers (Bourne et al, 2014). There are numerous normal faults orienting northwest-southeast in the centre of the Groningen field, and there is also a crossing set of faults orienting northeast-southwest (Figure 1). To achieve the optimal economic return, the field is developed by clusters with several wells in each cluster. The open dataset of the Groningen gas field is released by Nederlandse Aardolie Maatschappij (NAM) and Utrecht University (NAM, 2020), and it provides a good basis for evaluating various technologies. It consists of a prestack-depth-migrated 3D seismic cube, which has 1961 inlines and 2181 crosslines. The lateral bin size of the 3D seismic cube is 25×25 m, and its vertical sample rate is 8 m. The open dataset contains 27 well markers, which include the Permian Rotliegend group and the overlying stratigraphic formations. There are 1102 wells in the open dataset, and they belong to more than 30 clusters. The common logs are gamma ray log (in 455 wells), caliper log (in 388 wells), density log (in 412 wells), and sonic log (in 190 wells) (Degterev et al, 2023). A static model of the Rotliegend reservoir formation is also provided by NAM and Utrecht University, and there are 665 faults and 14 horizons. The average cell size of this existing static model is 100×100 m. Because it is easily accessible and contains a large amount of well and seismic data, the open dataset of the Groningen field has been widely used in different studies (e.g., Perez, 2023; Degterev et al, 2023). But, to the best of our knowledge, there are a lack of studies that check the consistency between raw data and the existing static model of this open dataset. After carefully checking this open dataset, we find there is a difference in depth between well markers and the corresponding horizons in the existing static model. This depth difference changes across the field, and it is caused by different reasons. Regarding the top of Rotliegend group (RO_T), the minimum depth difference between the well marker and the horizon in the static model is about –31 m, and the maximum depth difference is about 45 m. As shown in Figure 2A,

Figure 2 (A) Depth difference of RO_T between well marker and horizon in the static model, and the selected area for the subsequent studies (inside of the blue polygon). (B) (C) Comparison between well marker (solid line) and horizon (dashed line) in the static model for RO_T at well SSM-2A and well EKR-1.

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Zone

Top horizon

Bottom horizon

Average thickness (m)

TBS3

RO_T

TBZ3_T

12.8

TBS2

TBZ3_T

TBZ2_T

14.7

TBS1

TBZ2_T

USS_3.1_T

29.7

USS.3res

USS_3.1_T

USS_2.2_T

35.1

Table 1 Zones and horizons in the selected area

the depth difference of RO_T is relatively small in the northeast of the static model. However, the depth difference in the remaining area is too large to be ignored. For example, even for the well marker in well SSM-2A used to construct the static model, there is a 5 m depth difference for RO_T (Figure 2B). Meanwhile, the depth difference of RO_T at well EKR-1 is 15 m because its well marker is not utilised to generate the static model (Figure 2C). As mentioned above, the well markers and horizons in the static model do not match each other very well. This mismatch can seriously affect the petrophysical modelling results because the upscaled well log properties cannot fully reflect the subsurface geology. To eliminate the negative effect on petrophysical modelling caused by this mismatch, we choose a small part of the existing static model for the subsequent studies. In the horizontal direction, the static model we use later is inside of the blue polygon, and there are 16 well clusters in this area (Figure 2A). The lateral extent of this selected area is 315 km2. The depth difference between the well marker and horizon in this area is from -2 m to 3.5 m, which is relatively small and has little negative impact on the subsequent studies. As shown in Table 1, in the vertical direction, the top horizon of the selected area is RO_T and the bottom horizon is USS_2.2_T. There are four zones in this area, and the average thickness of the selected area is 92.3 m.

Figure 3 (A) Caliper and density log of well PAU-4. (B) Caliper and density log of well BIR-11. The first track is caliper log and the second track is density log.

studies. Therefore, the upscaled well log properties reflect the subsurface geology as much as possible. Because density property normally is affected by the lithology, four seismic attributes (Envelope, First derivative, Instantaneous frequency and Relative acoustic impedance) which can reflect the general stratigraphic information are used as the secondary variables to further constrain the 3D density modelling. To better evaluate this algorithm, we consider four different scenarios as described below. 1) Use different quality of well data as input:

Applications The embedded model estimator developed by Daly (2020) is used to generate the 3D petrophysical properties in the selected area of the existing static model. As discussed before, because the density log is available for most of the wells, density is used as the target variable. Meanwhile, only the wells whose well markers are used to construct the static model are considered in the subsequent

It is commonly assumed that density log can be significantly impacted by the bad wellbore condition (Bhattacharya, 2021). A careful check of the caliper log shows that some wells have very bad wellbore condition. As shown in Figure3A, the caliper log of well PAU-4 is abnormal in the interval from horizon RO_T to horizon USS_3.1_T, and this can lead to a questionable density log. In contrast, the wellbore condition of well BIR-11 is good,

Figure 4 (A) Locations of blind well OVS-7 and input wells with good wellbore condition. (B) Locations of blind well OVS-7 and input wells with good and bad wellbore condition. The blue polygon is the boundary of the modelling area.

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Figure 5 Petrophysical modelling results at the blind well OVS-7. The first track is the caliper log. The second and third tracks show the estimated P50 property and upscaled density property. The fourth track shows the estimated uncertainty range based on different quality of well data.

Figure 6 (A) Cross-plot between the K index of cells and upscaled density property. (B) Cross-plot between the Z index of cells and upscaled density property.

and the measured density log may reflect the subsurface condition (Figure 3B). To check whether the petrophysical modelling results of this embedded model estimator are significantly affected by the quality of well data, we use two different sets of wells and the forementioned seismic attributes to create two density models. Well OVS-7 is used as the blind well to compare the petrophysical modelling results. As shown in Figure 4A, nine wells with good wellbore condition are used to generate the first density model. For the second density model, three wells (well PAU-4, well AMR-8, well ZND-8B) have relatively bad wellbore condition, and the wellbore condition of the remaining six wells is good (Figure 4B). In Figure 4A and Figure 4B, the blind well is highlighted by the red circle, and the wells with relatively bad wellbore condition are highlighted by the black circles. As shown in Figure 5, when we use wells with good wellbore condition in this embedded model estimator, the P50 of estimated density property (blue curve) is similar to the upscaled density property (red curve) at the blind well location. However, when we use the wells with good and bad wellbore condition as input, the estimated P50 property is different from the upscaled density property, especially in the interval from horizon USS_3.1_T to horizon USS_2.2_T. Compared with the estimated uncertainty 48

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range based on wells with good and bad wellbore condition, the one based on wells with good wellbore condition is much smaller in the interval from horizon RO_T to horizon USS_3.1_T. In the interval from horizon USS_3.1_T to horizon USS_2.2_T, the estimated uncertainty range based on wells with good and bad wellbore condition is slightly better than the one based on wells with good wellbore condition. However, the estimated P50 property based on the wells with good and bad wellbore condition is worse than the one based on the wells with good wellbore condition. So, by considering both estimated P50 property and uncertainty range, the petrophysical modelling results are better when the wells with good wellbore condition are used as the input. The quality of well data plays an important role in this algorithm. 2) Use different geometrical variables as secondary variables:

Classic geostatistical approaches (such as Sequential Gaussian simulation) are normally based on assumption of stationarity. In practical terms, stationarity means that the overall mean of a petrophysical property is constant and differences from this mean are considered as local fluctuations. Because of this, by using classic geostatistical approaches, any inherent 1D, 2D

TECHNICAL ARTICLE

or 3D trend of a petrophysical property should be manually removed, and it involves a lot of preparatory steps prior to results generation in classic geostatistical approaches (Xiao and Leigh, 2022). For the selected area of this study, the upscaled density property has a nonlinear relationship with the K index of cells in the 3D grid (Figure 6A). However, there is no trend in the cross-plot between the Z index of cells and upscaled density property (Figure 6B). It means that the inherent 1D trend of upscaled density property can be better identified based on the K index of cells. Besides the well and seismic data, this embedded model estimator can use the geometrical variables (X, Y, Z, I, J, K index of the cells in the 3D grid) as secondary variables. To check the impact of different geometrical variables on property modelling results, we create two different density models based on this algorithm. The wells with good wellbore condition (Figure 4 (A)) and forementioned seismic attributes are used as the inputs. Both of the models use X, Y, Z, I and J index of the cells in the 3D grid as secondary variables. The only difference between these two models is whether the K index of cells in the 3D grid is used as the secondary variable. As shown in Figure 7, when the K index of cells in the 3D grid is used as the secondary variable of this algorithm, the P50 of estimated density property (blue curve) is close to the upscaled density property (red curve) at the blind well location. Compared with the results that do not include K index of cells as input, the uncertainty range of estimated property is smaller, especially in the interval from horizon USS_3.1_T to horizon USS_2.2_T. This means that the property modelling result is improved when more geometrical variables (such as K) are used as secondary variables. In this study, the property modelling results in the vertical direction are better by using the K index of cells. Meanwhile, because these geometrical variables (X, Y, Z, I, J, K index of cells in the 3D grid) can be automatically included in this algorithm, the working efficiency and accuracy is better than the classic geostatistical approaches.

3) Use different seismic attributes as secondary variables:

One advantage of this algorithm is that it can use many secondary variables to do the petrophysical modelling (Daly, 2020). In the previous studies, four seismic attributes (Envelope, First derivative, Instantaneous frequency and Relative acoustic impedance) were used to constrain the density modelling. Now, different sets of seismic attributes are used as the inputs to create two density models. In the first density model, all four seismic attributes are used as the secondary variables. In the second density model, the First derivative seismic attribute is removed from the input. Besides this difference, these two porosity models are generated based on the same input wells (Figure 4 (A)). As shown in Figure 8 and Table 2, even the First derivative seismic attribute strongly correlates with upscaled density property at well OVS-7; no matter whether the First derivative is used as the input, the P50 and uncertainty range of estimated density property at the blind well location are almost the same. This is because the correlation coefficients between First derivative and upscaled density property at the input wells are relatively small (Table 2). Even this dataset has a relatively large number of wells, it is still hard to derive a proper relationship between the target variable and secondary variables. This is because the wells are clustered and the lateral cell size of this geologic model is not small (100×100 m). As a result different wells from the same cluster may locate in the same cell of the 3D grid. So, even if

Figure 8 Petrophysical modelling results at the blind well OVS-7. The first and second tracks show the estimated P50 property and upscaled density property. The third track shows the estimated uncertainty range that includes First derivative as input or not.

Figure 7 Petrophysical modelling results at the blind well OVS-7. The first and second tracks show the estimated P50 property and upscaled density property. The third track shows the estimated uncertainty range that includes K index of cells as input or not.

Zone

At Input wells

At blind well

TBS3

-0.14

0.6

TBS2

-0.14

0.79

TBS1

0.2

–0.64

USS.3res

0.07

–0.09

Table 2 Correlation coefficients between upscaled density property and First derivative per zone.

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Figure 9 (A) Cross-plot between the upscaled gamma and density properties. (B) Cross-plot between the estimated P50 of gamma and estimated P50 of density properties generated from the embedded model estimator.

many secondary variables can be used in this algorithm, it is still better to have more wells evenly distributed to better capture the relationship between secondary variables and target variable. 4) Upscaled gamma and density properties have a nonlinear relationship:

to have more well data as the input. Our research provides a good reference to utilise this ML algorithm in the future. Meanwhile, our study (such as the data quality check) is also very useful for evaluating other ML petrophysical modelling algorithms based on the Groningen dataset.

In this dataset, upscaled gamma and density properties have a nonlinear relationship (Figure 9A). If we need to reproduce this relationship by using classic geostatistical approaches (such as Sequential Gaussian simulation), we need to manually define the bivariate distribution, which is time consuming and error prone. By using the P50 of estimated density property as one of secondary variables, we use this embedded model estimator to do the 3D gamma modelling. As shown in Figure 9B, the relationship between the P50 of estimated gamma and P50 of estimated density properties is similar to what we have in wells. So, this embedded model estimator works for both the linear relationship and the nonlinear relationship. More importantly, this complex relationship is automatically reproduced by using the embedded model estimator, and no additional operations are required. Compared with the classic geostatistical approaches, the working efficiency is improved without the loss of working accuracy.

Acknowledgements

Conclusions Based on the open dataset of the Groningen gas field, a ML petrophysical modelling algorithm has been successfully used to create the 3D density and gamma properties. Before utilising this embedded model estimator, we carefully check the data quality of this open dataset, and some problems are found, such as the mismatch between the well marker and horizon in the existing static model and bad wellbore conditions. By using different input data and comparing the petrophysical modelling results based on blind well, we find that the quality of the well data can heavily impact the property modelling results. We also find that this ML algorithm has two advantages. First, the inclusion of geometrical variables can generate better 3D petrophysical properties. Second, the nonlinear relationship between different properties can be easily reproduced. Meanwhile, even this algorithm can use many seismic attributes and geometrical variables, it is still better

Daly, C. [2020]. Tight integration of decision forests into geostatistical

The author would like to thank SLB for the opportunity to present this workflow and results. The author would like to thank Nederlandse Aardolie Maatschappij (NAM) and Utrecht University for providing the Groningen dataset to the public under the Creative Commons Attribution 4.0 International Public Licence.

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LAND SEISMIC Land seismic solutions are improving to facilitate ever more channels, more hard-wearing and smaller nodes along with more cableless systems to ensure more effective acquisition in all terrains, in challenging weather and with little downtime. Kim Gunn Maver et al explain why closed-loop geothermal well solutions avoid many of the doublet well solution geological requirements and enable an expansion of areas where geothermal heat can be used for district energy and in industrial processes. Tim Dean describes a more holistic approach to Vibroseis sweep design, which accounts for noise characteristics, attenuation, the acquisition method being employed, the characteristics of the vibrator, and the survey geometry. Andrew Clark et al describe how in recent onshore nodal seismic surveys IoT technology has been used to provide cable-free Ambient Noise Monitoring to enable better decision-making and risk mitigation. Amine Ourabah explores how the shift from geophone arrays to single-sensor nodes impacts seismic acquisition. Spencer L Rowse et al discuss how the signal strength of a source affects the SNR, fold, and productivity. Christof Stork explores the characteristics of scattering noise through careful seismic elastic modelling using the finite difference approach. Brett Bunn et al present a new fibre-optic sensing system, which consists of a highly configurable suite of 3-component optical point receiver accelerometers for true vector wavefield recording at high temperatures and pressures. C. Jason Criss demonstrates how the merging of the MEMS sensor with standard land seismic nodes combines the benefits of both technologies to form a unified solution for seismic acquisition.

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SPECIAL TOPIC: LAND SEISMIC

Geothermal heat potential for district energy and industrial usage in Europe based on closed-loop well solutions Kim Gunn Maver1*, Ola Michael Vestavik1 and Camille Hanna1 explain why closed-loop geothermal well solutions avoid many of the doublet well solution geological requirements and enable a significant expansion of areas where geothermal heat can be used for district energy and in industrial processes. Introduction The deep geothermal heat potential for district heating and to a lesser extent district cooling and industrial usage in Europe has been reviewed in many articles and reports. A common premise in these publications is that the heat extraction is based on a conventional doublet geothermal well solution, requiring a geothermal reservoir with certain parameters. The doublet well solution uses one well to produce formation water and another well to inject cooled formation water some distance apart, typically at a vertical depth of 2-4 km. The solution is dependent on the geothermal reservoir’s thickness and parameters such as porosity, permeability, and geochemistry to ensure hydrologic connectivity between the wells to maintain heated water production. These geological reservoir requirements limit the usage of the solution for geothermal heat production. New geothermal closed-loop well solutions have been introduced to mitigate the issues with the doublet solution. Stellae Energy has developed a single well closed-loop system for repurposed abandoned oil and gas wells with the fluid circulated down the well annulus, getting heated from the surrounding rock through conduction and convection, and then produced back to the surface through the production tubing (Stellae Energy, 2023). Eavor announced in 2022 the start of a closed-loop geothermal system in Geretsried, Germany. The system is similar to how an underground heat exchanger works. Initially two wells are drilled vertically and are then directed horizontally with several parallel branches being created. The boreholes from the two wells are connected at depth with a connection point the size of an A4 sheet of paper. This makes it possible to independently circulate a fluid in the rock and no geothermal water is required (Eavor, 2022). Green Therma has recently introduced a new geothermal horizontal closed loop well solution that is based on a single well or a group of single wells depending on the energy requirement (Maver et al., 2023). Each well is completed with a patent pending dual vacuum pipe technology. The fluid is heated when flowing along the geological formation in the horizontal section

Green Therma

Corresponding author, E-mail: kgm@greentherma.com

of the well and returned back to the surface with minimal heat loss inside the inner dual vacuum pipe, which works similarly to a thermo flask. Closed-loop geothermal well solutions avoid many of the doublet well solution geological requirements and enable a significant expansion of the areas where geothermal heat can be used for district energy and in industrial processes. In addition, the closed loop geothermal well solution mitigate a number of operational issues with the doublet solution like the produced water can cause corrosion, scaling, clogging, include toxic waste and result in significant maintenance issues of surface installations, in the injection well and in the reservoir around the injection wellbore. Furthermore, unlike closed-loop solutions, hydraulic fracking may be required to improve injectivity and formation connectivity with the risk of compromising groundwater aquifers, having a detrimental impact on the reservoir formation and potentially inducing seismicity with associated unwanted surface effects. Mapping of suitable geothermal exploration areas Currently the mapped areas in Europe applicable for using geothermal energy are for district heating and are mainly based on implementing the conventional doublet well solution. Figure 1 presents a map published on the Geothermal District Heating (GeoDH) website, geodh.org. The map shows the potential for geothermal district heating based on temperatures from 60 degrees celsius, adequate reservoir permeability and the presence of formation water. The Paris and Munich basins are the two main regions today in terms of number of geothermal district heating systems in operation as well as in Hungary (GeoDH, 2015). Areas with the best geothermal energy potential are those with sedimentary reservoirs in the extensive European Lowlands like Denmark, Germany, Poland as well as the Pannonian Basin in Central and Eastern Europe (GeoDH, 2015). Even though there seems to be extensive opportunities to implement the doublet well solution in Europe, the geothermal

DOI: 10.3997/1365-2397.fb2024003

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reservoir requirements limit the application and executed projects are not always successful. Rystad Energy recently reviewed the geothermal drilling success and found it is variable and very dependent on the specific location of the well and the industry’s maturity in the relevant country. Success rates in Germany and Hungary often exceed 90%, but similar rates in the Netherlands are as low as 70% (Rystad, 2022). These issues and limitations can explain why there are only around 240 district heating systems in Europe (GeoDH, 2015) supplied by geothermal energy out of recently mapped 10,000 district heating systems in Europe (Rystad, 2023). The market for district cooling is currently smaller than for district heating even though the demand for cooling is far higher than for heating on a global scale. The district cooling market is already growing rapidly and is expected to keep growing in the future – both in temperate countries and even faster in warmer countries, where the strongest growth in population, building mass, income levels and thereby cooling demand is expected (DI Energy, 2022). District cooling works according to the same principles as district heating. It provides better energy efficiency than existing cooling solutions, frees up much-needed space in urban areas and provides easier operation of cooling systems for users (DI Energy, 2022). In Europe smaller-scale district cooling networks exist mostly in larger cities. Even in colder parts of Europe, there has been a substantial development in district cooling, primarily for hotels and office buildings over the past decade (DBDH, 2023). District cooling relies on waste heat from power plants, industrial processes, renewable energy sources like solar thermal, and biomass as well as natural cooling sources such as seawater, lake water, or river water. Currently there seems to be no use of geothermal energy for district cooling. In the Gulf region (GCC), investments in district cooling are increasing annually, leading to widespread adoption in the UAE and Saudi Arabia (DBDH, 2023). Recently ADNOC and the National Central Cooling Company PJSC (Tabreed), have announced the first project in the Gulf region to harness energy from two geothermal wells at Masdar City in Abu Dhabi. The wells produced hot water at temperatures exceeding 90 degrees celsius. The hot water generated from the wells will pass through an absorption cooling system to produce chilled water, which will then be supplied to Tabreed’s district cooling network at Masdar City, accounting for 10% of its cooling needs (ADNOC, 2023). Literature shows that the single-effect absorption chillers designed for 80-120 degrees Celsius typically have a coefficient of performance (COP) of 0.65-0.75 to produce 6-7 degrees celsius chilled water, which, however, varies with the heat source and the cooling water temperature (Al-Tahaineh et al., 2013). This current temperature range aligns with the temperature requirements for 3rd generation district heating. There is also a range of other usages of heat, and depending on the geothermal temperature, it can be for recreational usage, in the agro-industry sector and industrial process usages (World Bank, 2022). However, in Europe the industrial usages of geothermal energy are still very limited (Popovska-Vasilevska, 2009). 54

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Figure 1 Green areas possibly suitable for the doublet geothermal well solution with more than 60 degrees celsius at a depth less than 3000 m from GeoDH interactive map (Information extracted from GeoDH, 2015).

European geothermal potential Closed loop well solutions are judged to be primarily suitable for district energy (heating and cooling) and industrial usages. Due to the subsurface temperatures considered of up to around 130 degrees celsius, electricity generation is not considered. Most district heating systems are categorised as 3rd generation requiring an input temperature of approximately 90 degrees celsius. However, to improve the cost efficiency a transition has started to 4th generation district heating systems requiring an input temperature of 50-70 degrees celsius. Currently, district cooling solutions would require the same input temperature range as 3rd generation district heating systems. For industrial usage the whole geothermal temperature range can be utilised for greenhouse heating, the lower temperature range as an example for pasteurisation, milk evaporation and concrete curing and the higher temperature range as an example for cement drying and sterilisation (World Bank, 2022). To efficiently achieve the input temperatures from a geothermal well, the original heat source rock temperature should be significantly higher than the input temperature, preferably several tens of degrees celsius. Figure 2 presents the average geothermal gradients by country in Europe, which exhibit, significant regional variations. This

Figure 2 The average thermal gradient per km by country on the Europe continent (Information extracted from ThermoGlobe, 2023).

SPECIAL TOPIC: LAND SEISMIC

needs to be considered, when a geothermal well is planned, to achieve the required temperatures. As an example, for Germany the mean, 25%, 50% and 75% temperature gradient per km are 42, 23, 30, and 67 degrees celsius (ThermoGlobe, 2023). In Denmark there is approximately 30 degrees celsius difference between the hottest and coldest rock at 3000 m (Fuchs et al., 2020), which with the average geothermal gradient equals 1 km of depth. Figure 3A is a temperature map at 3500 m depth, which can be used for an assessment of the geothermal energy resource. 3rd generation district heating, district cooling and some industrial usage could be supplied by geothermal energy at 100-150 degrees celsius in significant parts of Central and Southern Europe, Turkey and Caucasus region. At 4500 m an even better coverage is possible with additional potential on the British Isles, Denmark and limited areas elsewhere (Chamorro et al., 2013). For 4th generation district heating and some industrial usages, most of Europe has as a minimum 50-100 degrees celsius except for some areas in Eastern Europe, Finland and Russia at 3500 m (Figure 3). Most of Europe has a potential at 4500 m depth (Chamorro et al., 2013).

The thermal conductivity of the rock impacts the amount of energy that can be produced over time from a geothermal well at a certain subsurface temperature. Table 1 presents an example of thermal conductivities for various rock types. Thermal conductivity varies with the composition of the rock and is controlled primarily by the relative effectiveness of heat transport through grain-to-grain paths of the rock. The presence of pores in the rock will therefore limit the heat transport. A rock type can also have a large range of heat conductivities, depending on the grain size, grain composition, material between the grains, pore fluid composition, pore size and porosity (Robertson, 1988). Rock type

Thermal conductivity

Rock type

Thermal conductivity

Typical rocks

1- 3

Limestone

2-3

Gneiss

1-5

Sandstone

0.5-3

Granite

1-4

Shale

0.3-1

Basalt

0.5-2

Halite (salt)

4-7

Table 1 Example of thermal conductivity (W/mK) for various rock types.

Figure 3 A – Calculated temperature at 3500 m depth in Europe (Modified and simplified from Chamorro et al., 2013). B – Outline of areas with salt structures (Modified and simplified from Caglayan et al., 2020). C – Temperature distribution at 3500 m depth and the potential geothermal heat usage. Limited opportunities for using geothermal heat in areas with less than 50 degrees celsius. In areas with 50-100 degrees celsius there are opportunities for 4th generation district heating (4th DH) and some industrial usage (IU). In areas with more than 100 degrees celsius there are opportunities for 3rd, 4th generation district heating (3rd/4th DH), district cooling (DC) and industrial usage (IU) potential based on Figure 3A. D – Sediment thickness above the expected crystalline crust based on Figure 4.

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Assessing the actual thermal conductivity of the subsurface requires mapping of the individual layers of the stratigraphic column and if possible, using sample measurements from nearby analog wells. Sedimentary rocks in general have a thermal conductivity of 2-3 W/(mK) as measured for geological units derived from logs from 24 well in the Danish-German border region, with a few exceptions like a higher value for Zechstein and a lower value for Lower Jurassic (Fuchs and Balling 2016). The high thermal conductivity of Zechstein is due to rock salt but also partly anhydrite and dolomite. A rock salt sample has high thermal conductivity of >6 W/(mK) at 20 degrees celsius changing to slightly less than 5 W/(mK) at 160 degrees celsius and to as low as 4 W/(mK) at 160 degrees when mixed with clay and Sylvite (Raymond et al., 2022). This high thermal conductivity makes rock salt very attractive for producing geothermal energy, which will improve as the rock salt is cooled as part of production. Optimising the stratigraphic level of the well is important for achieving a thermal conductivity that can ensure an adequate energy output over time. Geological settings to explore for geothermal heat To explore for and harness the heat in the reassessed geothermal areas the following three general geological settings have been identified based on drilling and completion requirements as well as how suitable they are for producing geothermal energy: sedimentary rocks, igneous rocks and rock salt. Sedimentary rocks

Figure 4 presents the European distribution of sedimentary rocks and with thicknesses of at least 2-3,000 m will have the same drilling requirements as for oil, gas, and for water wells. The well should target the best part of the sedimentary geological section in relation to the required temperature and thermal conductivity. Igneous rocks

Igneous basement rocks cover Sweden, Norway, Finland, most of the Baltic countries in Belarus and Russia and there are areas in Northern Scotland, Western France, Alps, Turkey and Greece as well with less than 1000 m sediments to no sediments (Figure 4). The rock temperature in these areas both at 3500 m and deeper are in general slightly lower than for the rest of Europe (Figure 3A). Igneous rocks are more difficult and more expensive to drill than sedimentary rocks. Deep geothermal wells at 9 sites in the Rhine Graben and Bohemian Basin in Austria have been drilled in mainly crystalline granite or hard sandstone. A higher Rate Of Penetration (ROP) values is found between 2000 and 3500 m depth of 3 to 6 m/h than at greater depths of 2 to 5 m/hour (Baujard et al., 2017). Rock salt

Rock salt can be easy to drill but more difficult to complete. Typical ROP of 15 to 40 m/hour means that a 1000 m section can be drilled in two or three days with a PDC bit (Dusseault et al., 56

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Figure 4 Thickness of the sedimentary cover based on the depth to the crystalline basement from a seismic definition of the top of the crystalline crust, which is not unique and is based seismic velocities unless the depth to the basement is reported in original publications (Artemieva and Thybo, 2012).

2015). This is 2-3 times faster than drilling in sedimentary rocks and even faster than drilling in igneous rocks. The risk of drilling horizontally increases significantly at the top of a salt structure and at depth. The weathering zone at the top of a salt structure can contain anhydrite, karst cavities, and cracks resulting in fluid loss zones. Rock salt creeping behaviour results in issues of stuck pipe during drilling operations, casings deformation and collapse that have led to well suspension and abandonment. However, these drilling and completion challenges in salt deposits can be mitigated with an appropriate well plan adjusted to the area and geological setting (Dusseault et al., 2015). The thermal conductivity of rock salt is significantly higher than that of typical sediments, see Table 1. Salt structures often display large vertical relief and thereby provide paths for the conduction of heat from depth to the surface (Petersen and Lerche, 1995). The large vertical relief and the high thermal conductivity makes rock salt an excellent target for producing geothermal energy and completing a horizontal heat extraction section of a well within the rock salt increasing the longevity and/or effect of the system significantly. Figure 3B presents a map of salt structures in Europe. The technical potential of salt caverns for gas and hydrogen storage in Europe have been assessed and looks promising (Caglayan et al., 2020; Gillhaus, 2007). These salt structures could also be used for installing closed loop geothermal well solutions. Especially in parts of Germany, Poland, Denmark, Belarus, Romania and Ukraine significant salt structures are present and in other parts of Europe there are rock salt deposits of variable thickness and geographical extent. At some locations the depth to the salt deposits may not be adequate for a sufficient geothermal temperature or the salt deposits are thin. Drilling geothermal wells The commercial use of geothermal energy is strongly dependent on the drilling costs, which are related to the depth, well type, geological setting and completion requirements. Drilling technologies are usually developed in the oil and gas industry and then transferred and adapted for the benefit of the geothermal industry and, as a result, geothermal drilling technology is following behind oil and gas technology developments

SPECIAL TOPIC: LAND SEISMIC

(Cultrera, 2016). The geothermal drilling costs also follow the general oil and gas industry trend, which can be illustrated by the geothermal rig rate’s total dependence and correlation to oil prices in the period 2000-2012. This situation is likely to persist as long as the geothermal drilling sector does not build up a strong market share of its own (Dumas et al, 2013). Furthermore, in some countries in Europe, the number of drilling companies is not high enough to allow full competition driving up costs (Garabetian, 2020). The USA onshore oil and natural gas industry has shown that by continuously developing best practice and improving well designs, it was possible to drive the major production increase in oil and gas production since 2010. This evolution was possible due to new technology and developments for deep horizontal drilling and completion leading to reduced drilling and completion times, lower total well costs, and increased well performance in the period 2006 to 2015 (EIA, 2016). By planning campaigns of hundreds or even thousands of wells at a time with a high degree of repeatability the operators adopted a manufacturing mentality to field development, which had a significant impact on efficiency and cost. There are examples of rig moves, where the operators have been able to reduce rig move times by 40%. For an unconventional oil and gas well campaign the first three wells took 73 days to drill, the next three wells were 20% faster and a further three wells were 37% faster than the first wells. This learning curve has also been observed for larger European geothermal projects (Latimer and Meier, 2017). With a further emphasis on and expansion of a dedicated geothermal well industry, using a manufacturing mentality when drilling and developing larger projects to take advantage of a local learning curve, the drilling and completion costs are expected to be reduced significantly in the future making it possible to increase the use of geothermal energy as it will be economical to drill deeper and further horizontally for improved energy output.

The most attractive areas and easiest to drill are where there are sufficient sedimentary deposits of at least 3 km. These areas include a number of salt structures, which may be particularly attractive, due to a higher temperature and especially a high thermal conductivity (See Figure 3B). The rest of Europe still has a significant potential for district energy and industrial usage, but the lower geothermal gradient and the presence of some igneous rocks within the first 1-3 km will make the economics of a project more challenging. Less than 1 km to no sediment will make it even more economically challenging to complete a geothermal project at current market conditions. A very attractive area for drilling wells for all geothermal energy applications is Netherlands, Germany, Denmark and Poland with a large sediment thickness and the presence of salt structures (Figure 3B). There are areas where the potential for geothermal heat production is limited due the large well depth required to achieve a sufficient temperature and power output. But with a growing geothermal well business, where there is a focus on bringing down cost through technology development and improved operations, a further market expansion is possible with geothermal energy supplying a significant part of Europe’s future heating, cooling, and industrial energy usage requirements. Even for the most mature application of geothermal energy the decarbonisation potential of district heating is largely untapped (IEA 2022). With closed-loop solutions it would be possible to significantly impact the decarbonisation of district heating moving towards ‘zero’ CO2 emissions and with a nearly unlimited resource of heat from the earth’s interior that is both reliable and cost effective.

New geothermal opportunities Figure 3C presents a map of Europe for assessing the potential to harness heat at 3500 m depth. In large parts of Europe with a subsurface temperature of more than 100 degrees celsius 3rd generation district heating and district cooling solutions and some industrial usage is possible. Besides northern Norway, Finland, Estonia, Belarus, the northern part of Ukraine and an area in the far western part of Russia, there is also the potential for 4th generation district heating and some other industrial usages at 3500 m depth. In cases where the heat is harnessed at 4500 m depth, the area for 3rd generation district heating and cooling increases as well as the area for 4th generation district heating and all industrial usages. Only a small area in northern Norway and Finland is not suitable for harnessing geothermal heat at reasonable depths. Figure 3D presents a map of Europe, assessing the most promising regions for application of the closed loop solutions. Most of Europe will be suitable for closed-loop geothermal well solutions with adequate geological considerations when preparing the drilling plan and well completion. However, the geological setting impacts the well operation and the economics.

Al-Tahaineh, H., Frihat, M. and Al-Rashdan, M. [2013]. Exergy Anal-

References ADNOC [2023]. ADNOC and Tabreed Advance the First Project in the Region to Harness Geothermal Energy. Press Release, 14 August. https://www.adnoc.ae/en/News-and-Media/Press-Releases ysis of a Single-Effect Water-Lithium Bromide Absorption Chiller Powered by Waste Energy Source for Different Cooling Capacities. Energy and Power 2013, 3(6), 106-118. http://dx.doi.org/10.5923/j. ep.20130306.02 Artemieva, I.M. and Thybo, H. [2012]. EUNAseis: A seismic model for Moho and crustal structure in Europe, Greenland, and the North Atlantic region. Tectonophysics 609, p 97-153. Baujard, C., Hehn, R., Genter, A., Teza, D., Bau, J., Guinot, F., Martin A. and Steinlechner, S. [2017]. Rate of penetration of geothermal wells: a key challenge in hard rocks. Proceedings, 42nd Workshop on Geothermal Reservoir Engineering Stanford University, Stanford, California, February 13-15, SGP-TR-212 1. Caglayan, D.G., Weber, N., Heinrichs, H.U., Linßen, J., Robinius, M., Kukla, P. A., and Stolten, D. [2020]. Technical potential of salt caverns for hydrogen storage in Europe. International Journal of Hydrogen Energy, 45( 11), 28 February, p 6793-6805. Chamorro, C.R., García-Cuesta, J.L., Mondéjar, M.E. and Pérez-Madrazo, A. [2013]. Enhanced geothermal systems in Europe: An estimation and comparison of the technical and sustainable potentials. Energy 65, p 250-263. http://dx.doi.org/10.1016/j.energy.2013.11.078 FIRST

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Cultrera, M. [2016]. Design of deep geothermal wells. Italian Journal of

IEA [2022]. District Heating. https://www.iea.org/reports/district-heating.

Groundwater http://dx.doi.org/10.7343/as-2016-248

Latimer, T. and Meier, P. [2017]. Use of the Experience Curve to

DBDH [2023]. District cooling. Danish Board of District Heating (DBDH)

Understand Economics for At-Scale EGS Projects. Proceedings, 42nd Workshop on Geothermal Reservoir Engineering Stanford

https://dbdh.dk/all-about-district-heating/cooling/ DI Energy [2020]. The future of district energy. The Danish Energy

University, Stanford, California, February 13-15, SGP-TR-212.

Industries Federation (DI Energy).

Maver, K.G., Vestavik, O.M., Rasmussen, J.P. and Larsen, C.-E. [2023]. Closed loop single well geothermal solution. First Break, 41(9),

Dumas, P., Antics, M. and Ungemach, P. [2013]. Report on Geothermal Drilling. GeoElec, Deliverable no. 3.3, March.

p 83-86.

Dusseault, M.B., Maury, V., Sanfilippo, F. and Santarelli, F. J. [2015].

Petersen, K. and Lerche, I. [1995]. Quantification of thermal anomalies in sediments around salt structures. Geothermics, 24(02), p 253-268

Drilling through salt: Constitutive behaviour and drilling strategies. ResearchGate, 12 pp.

Robertson, E.C. [1988]. Thermal Properties of Rocks, Open-File Report

Eavor [2022]. Groundbreaking ceremony for the drilling site of the Eav-

88-441, US Dept. of the interior Geological Survey.

or-Loop™ project in Geretsried. News, October https://eavor-gerets-

Popovska-Vasilevska, S. [2009]. Geothermal energy direct application in industry in Europe. International Geothermal Days. Slovakia.

ried.de/en/bauantrag-fuer-eavor-loop-in-geretsried-genehmigt/ EIA [2016]. Trends in U.S. Oil and Natural Gas Upstream Costs. US

Conference and summer school.

Energy Information Administration, Report, March.

Raymond, J., Langevin, H., Comeau, F.-A. and Malo, M. [2022]. Temper-

Garabetian, T. [2020]. Report on Competitiveness of the geothermal

ature dependence of rock salt thermal conductivity: Implications for

industry. ETIP-DG.

geothermal exploration. Renewable Energy 184, p 26-36.

Fuchs, S. and Balling, N. [2016]. Improving the temperature predictions

Rystad Energy [2022]. Full steam ahead: Europe to spend $7.4 billion on

of subsurface thermal models by using high- quality input data. Part

geothermal heating, capacity to reach 6.2 GWt by 2030. News, Press

2: A case study from the Danish-German border region. Geothermics

release, 27 September.

64, p 1-14.

Rystad Energy [2023]. Geothermal Market Outlook. The geothermal mar-

Fuchs, S., Balling, N. and Mathiesen, A. [2020]. Deep basin temperature

ket is heating up: full steam ahead. Energy Transition Report, 17 p.

and heat-flow field in Denmark – New insights from borehole

Stellae Energy [2023]. Single Well Closed System. https://stellaeenergy.

analysis and 3D geothermal modelling. Geothermics 83, 101722.

com/geothermal-energy/geothermal-solutions. Thermoglobe [2023]. A repository for data and models related to thermal

GeoDH [2015]. Geothermal District Heating website. http://geodh.eu/ Gillhaus, A. [2007]. Natural Gas Storage in Salt Caverns–- Present

studies of the Earth http://heatflow.org/

Status, Developments and Future Trends in Europe. Solution

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Mining Research Institute, Spring 2007 Conference 29 April- 2 May, Basel.

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An integrated approach to Vibroseis sweep design Tim Dean1* describes a more holistic approach to Vibroseis sweep design, which accounts for noise characteristics, attenuation, the acquisition method being employed, the characteristics of the vibrator, and the survey geometry. Introduction Vibroseis is the predominant source for land seismic acquisition, being employed wherever access allows. A key part of the start-up of any vibroseis survey is determining the sweep parameters, with either much effort being made to determine the ‘optimum’ values, or the values employed being simply those that have been found to be adequate in the past. Although the sweep is often thought of in terms of simple parameters such as bandwidth, length and tapers, we also need to think about the interaction between the sweep parameters and the desired SNR – including the noise characteristics, attenuation, the acquisition method being employed, the characteristics of the vibrator, and the survey geometry. In this paper I describe a more holistic approach to sweep design, which accounts for these variables and, in particular, their interaction with productivity. For those unfamiliar with vibroseis I highly recommend the book simply called Vibroseis by Nigel Anstey (Anstey 1991) which is well worth a read, and includes a more detailed summary of some of the principals included here. The Vibroseis wavelet The basic model of seismic reflection data, the convolutional model, states that a recorded seismic trace is simply the convolution of the reflectivity series with the source wavelet, plus noise. In essence, each spike in the reflectivity series is replaced by a scaled, shifted, copy of the source wavelet. The ideal source wavelet is a spike (or Dirac Delta function) which has an essentially infinite bandwidth. For vibroseis the theoretical (and assumed) source wavelet is simply the autocorrelation of the sweep. This is the point at which reality (unfortunately) comes into play, with a vibroseis unit being limited in the frequencies it can produce, and the earth limiting the frequencies that we can transmit through it. The resolution of seismic data, i.e., our ability to differentiate between adjacent layers, is directly related to the wavelet shape, in particular the width of the central lobe, and the position and amplitude of any sidelobes. As seen in Figure 1a, the width of the central lobe is directly related to the mid-frequency of the sweep and the height of the sidelobes is proportional to the bandwidth of the sweep. Figure 1b shows three sweeps with the same bandwidth when measured in octaves (a doubling of frequency), the shape of the wavelet does not change but the width of wavelet is compressed as the frequency increases. Thus, the ideal sweep is

Anglo American

Corresponding author, E-mail: tim.dean@angloamerican.com

one with a broad bandwidth and high central-frequency, i.e., one which approximates the bandwidth of the Dirac Delta function as closely as possible. Even if we could transmit a wide bandwidth sweep, say 5 to 200 Hz, the earth does not transmit all frequencies equally. This is a result of attenuation, which is typically defined in terms of the rock quality factor Q. When Q is frequency-dependent (which it is within the typical seismic bandwidth) then the attenuation is per cycle, which is why it has an increased effect at high frequencies. To correct for the effects of attenuation we need to boost the sweep by 27 / Q [dB] (Anstey 1991). The simplest way to do so is by using a dB/Hz sweep. Q values typically range from 50 to 300 (Sheriff 2002); at the lowest value we will require a 0.54 dB/Hz sweep to overcome attenuation. For a 10 to 100 Hz sweep this means we will require 48.6 dB more at 100 Hz than 10 Hz. Such a sweep, commonly referred to as a ‘high-dwell sweep’, is shown in Figure 2, at the end of the sweep (100 Hz) the sweep rate (1.25 s/Hz) is 270 times higher than at 10 Hz (0.005 s/ Hz) and we reach the mid-frequency of the sweep (50 Hz) after just 0.82 s (4% of the total sweep length). Sweeps with such a high-frequency emphasis are clearly not feasible as they require the sacrifice of too much low-frequency energy, but it may be worthwhile increasing the high-frequency content of a sweep to overcome attenuation to a lesser degree.

Figure 1 (a) Autocorrelation of three sweeps with different central frequencies. (b) Autocorrelation of three sweeps with the same octave bandwidth but different central frequencies.

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Figure 2 An example 0.54 dB/Hz sweep from 10 to 100 Hz over 20 s.

theoretically, data acquired with the non-linear sweep could simply be filtered to appear as if it had been acquired using a linear sweep, or any other wavelet that we choose. Such an approach assumes noise-free conditions, but what happens if we add noise? Figure 4 shows the power spectral densities (PSD) of a linear sweep, a 0.27 dB/Hz sweep, and some random noise. As expected, the non-linear sweep has increased high-frequency content at the expense of low-frequency content. Note that the noise is stronger than the signal, as the results shown are for the uncorrelated traces whereas correlation boosts the signal level considerably. Figure 5a and b show the correlated results between the two sweeps (the pilot signals) and the two sweeps plus the random noise. Figure 5c is the dB/Hz sweep after it has been shaped using the filter designed using the autocorrelations (as shown in Figure 3). Clearly the shaped wavelet is now considerably noisier than its linear counterpart unlike the noise-free result (Figure 3). Given the success of wavelet shaping for the noise-free data why is this now not the case with noise added? It is all to do with the signal-to-noise ratio (SNR) of the data: Figure 6a and b show the PSD of the signal and noise components of the data (after correlation) whilst Figure 6c shows their difference. As the sweep length is constant, the dB/Hz sweep ‘trades’ SNR at high frequencies for that at low frequencies. This causes the signal level to drop below the noise level at frequencies below ~40 Hz. The linear sweep, however, has a consistent SNR across the full

Figure 3 Autocorrelations of (a) 10-100 Hz 0.27 dB/Hz sweep and (b) 10-100 Hz linear sweep. (c) is the non-linear sweep wavelet after being shaped to the linear wavelet using a Wiener filtering approach.

Signal-to-noise The signal component of the data is only part of the issue, and we also need to consider noise, and in particular its spectral content. In the past, the power spectrum of a sweep was a result of the sweep design process with its properties typically being defined by the frequency function, commonly the standard linear sweep where the frequency changes linearly over the course of the sweep. Recently, however, sweep design has tended to use the power spectrum of the sweep as the input rather than the output (Bagaini et al. 2008, Dean et al. 2016), even if the desired power spectrum is just that of a linear sweep. Putting sweep design aside momentarily; as mentioned previously, our ideal source wavelet has a narrow central lobe along with minimal sidelobes. Sweeps are often, therefore, compared by looking at their autocorrelations. But does the shape of the autocorrelation really matter? We can simply shape the wavelet to produce the wavelet that we want. For example, Figure 3a is the autocorrelation of a 0.27 dB/Hz (Q = 100) sweep, which clearly has a significant amount of ringing (sidelobe energy) in it due to the increased high frequency content. Figure 3b is the autocorrelation of a linear sweep with the same bandwidth which is likely to have a superior resolution due to the lower level of ringing. Figure 3c is the non-linear sweep autocorrelation after being shaped to the linear sweep autocorrelation using a standard Weiner filtering approach, although there are slight differences between the two wavelets the shaping has been successful. So, 60

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Figure 4 Power spectral density of random noise and two 10 to 100 Hz sweeps, one linear and the other with a 0.27 dB/Hz boost.

Figure 5 Cross-correlation of (a) 10-100 Hz 0.27 dB/Hz sweep and (b) 10-100 Hz linear sweep with the same sweep function but with random noise added as per Figure 4. (c) is the non-linear sweep wavelet after being shaped to the linear wavelet using the same filter as shown in Figure 3.

SPECIAL TOPIC: LAND SEISMIC

sweep? This brings us to our next topic, the interaction between sweep design and other vibroseis acquisition parameters. Interaction with acquisition parameters As mentioned in the previous section, there are different ways in which we can improve the SNR of vibroseis data other than by changing the sweep parameters. These are summarised in the following equation (Landrum 1967) (1)

bandwidth as both its PSD and the noise PSD are constant. The key finding here is that we cannot rely on spectral shaping to overcome underlying SNR issues in the data. Although the relationship between the sweep and noise spectra is important, as previously discussed, we also need to consider attenuation. To illustrate this, Figure 7a is the spectrum of the same linear 10-100 Hz sweep used previously. Figure 7b is the attenuation for a Q value of 100 (0.27 dB/Hz). These are combined in the blue line in Figure 7c. Figure 7c also shows the noise level, which in this case is constant across the sweep bandwidth; the two lines intersecting at around 50 Hz. At this point we have decisions to make, a) do we simply give up on frequencies above this limit and shorten the sweep thus improving productivity or b) do we attempt to overcome the limits imposed by attenuation and noise by increasing the sweep energy above this limit, by for example, increasing the number of vibrators, increasing the sweep length or using a non-linear

where N is the number of vibrators in each fleet, F is the fundamental ground force (the output force of the vibrator), S is the number of sweeps, and L is sweep length. What is immediately obvious from equation 1 is that increasing the sweep length and/ or the number of sweeps is a relatively inefficient way to improve SNR compared to increasing the force and/or the number of vibrators. If there is a need to improve SNR then increasing the number of vibrators is intuitively the most effective approach (it is not generally feasible to increase the output force of the vibrator significantly other than by replacing them with larger units), particularly when doing so can also improve productivity (Dean et al. 2010). For example, going from 1 to 2 vibrators/fleet has the same effect as quadrupling the sweep length. Equation 1 has been shown to hold (Dean and Tulett 2014, Kristiansen et al. 2010) although allowance needs to be made for the feedback between multiple vibrators in a fleet reducing their combined energy (Dean et al. 2016). Despite this, I have found that small differences to the signal component of the SNR from the sweep length are insignificant when compared to variations in the noise component. Figure 8a shows the average trace SNR for each of the 54,300 records calculated as the ratio between a time-window centred on, and a time-window above, the first break. When compared to the distribution of sweep lengths (Figure 8b) the difference in sweep length had no recognisable effect on the resulting SNR, which is understandable given that the difference in SNR from equation 1 is just 0.4 dB.

Figure 7 (a) PSD of a linear 10 to 100 Hz sweep. (b) Attenuation corresponding to a Q value of 100. (c) The sweep PSD after the application of the attenuation function (blue) and the PSD of the noise (red).

Figure 8 (a) Scatter plot of shot-record SNR values. (b) Scatter plot of the sweep lengths (11, 11.33, 11.66, and 12 s).

Figure 6 (a) PSD of the dB/Hz sweep signal and noise components, (b) PSD of the linear sweep signal and noise components, (c) difference between the signal and noise components for the dB/Hz sweep (red) and linear sweep (green).

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As well as these overarching parameters the performance of individual vibrator models (and even individual vibrators) is also important. At low frequencies the output of the vibrator is predominantly controlled by the maximum mass stroke (the distance the reaction mass can move up and down) and the flow rating of the hydraulic pumps. At high frequencies it is controlled by the baseplate, the pilot valve and the supply pressure (Sallas 2010), but the ground conditions also have a significant affect (Dean, Quigley, MacDonald and Readman 2016). From Table 1 there are clearly two classes of vibrators, ‘heavy’ vibrators with a peak force of 250 kN or higher and ‘light’ vibrators with a peak force of less than 120 kN. The former tend to have better low-frequency performance, whilst being limited to frequencies of less than ~120 Hz, and the latter tend to do better at high frequencies (up to 250 Hz). It should be noted that just because their performance may not be as good, light vibrators are still capable of outputting low frequencies and have mass stroke values in some cases, comparable to heavy vibrators, but heavy vibrators tend to be incapable of outputting high frequencies even at much reduced drive levels. We can generally overcome the high or low frequency performance limitations of vibrators by reducing the drive, but this comes at the cost of having to spend considerably longer sweeping at those frequencies. Specifically, the relationship is given by (Dean, Quigley, MacDonald and Readman 2016)

Figure 9 (a) Theoretical amplitude-frequency performance of two different vibrators taking only the mass-displacement limit into account. (b) the resulting frequency-time plots of the sweeps required to achieve the same PSD for the two vibrators.

(2) where Δt is the increase in time and D is the reduced drive level (in %). Thus a 30% decrease in drive-level requires spending twice as long sweeping, a 50% drop requires four times longer, and a 75% drop requires 16 times longer. This now gives us an additional consideration. Even though we may desire that portion of bandwidth, and we can design a sweep such that the vibrator can generate it, we need to consider the cost of that bandwidth and if it is worthwhile. The approach to use the PSD of the SNR as the input to our sweep design process opens up further possible positive effects on productivity resulting from the employment of different vibrator models. For example, Figure 9 shows two 1 to 100 Hz Model

Peak force (kN)

Reaction Mass (kg)

Stroke (cm)

Envirovibe

66.0

794.0

7.0

Nomad 15

77.2

1000.0

7.0

UV2

115.3

1828.0

10.1

AHV-IV 364

275.0

4998.0

9.8

Nomad 65

278.0

4700.0

10.2

AHV-V

356.0

6109.5

17.8

AHV-IV 380

356.0

5910.0

10.2

Nomad 90

400.3

7000.0

10.2

Table 1 A summary of some of the key parameters of commonly used vibrators ranked by their peak force.

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Figure 10 Bar graph showing the cost of different frequency ranges for sweeps with the same PSD shown in Figure 9.

sweeps with a 3 dB down point in the PSD at 1.8 Hz designed for both the AHV-IV 380 and the AHV-V taking only the limitation of the mass displacement into account. The later has a heavier reaction mass and much larger stroke (Table 1) which gives it a considerably lower maximum displacement frequency (the frequency at which full drive can be reached) of 4.07 Hz vs. 5.47 Hz for the AHV-IV (Figure 9a). Given the dramatic increase in time required to counteract their difference in drive (equation 2) this results in the AHV-IV sweep having to spend far longer at low frequencies (Figure 9b) resulting in the sweep being 40% longer. This can also be seen by comparing the ‘cost’ of the frequencies within defined bandwidths. Figure 10 shows the result for the two sweeps shown in Figure 9. The cost of the energy between 1 and 1.5 Hz is 2.5 times that for the AHV-IV when compared to the AHV-V. For the AHV-IV the cost of 1-1.5 Hz is four times that of 1.5-2 Hz. Such cost charts are particularly useful for comparing the performance of different vibrators, if a choice is available, and for comparing the costs of different sections of the sweep bandwidth if a compromise is required between low and high frequency content.

SPECIAL TOPIC: LAND SEISMIC

Influence on productivity I have already discussed how the sweep design needs to incorporate other acquisition parameters, such as the number of vibrators in the fleet, but we also need to assess its impact on productivity and our ability to acquire a dense source grid. Given the choice, it is generally accepted (Meunier 2011, Monk 2020) that it is more important to increase trace density rather than have longer/ additional sweeps or high-powered sources (within reason of course, no amount of stacking with a sledgehammer as the source will enable you to image the Moho). Acquiring numerous source points, however, is generally prohibitively expensive using conventional acquisition methods (hence the historical tendency to use fleets of vibrators rather than single units to reduce the sweep length). This can be overcome, however, through the use of high productivity acquisition techniques. Such techniques rely on overlapping sweeps with the interference being reduced by limiting how close they can be in time (Rozemond 1996), distance (Bouska 2010) or a combination of the two (Dean 2016, Quigley et al. 2013), by using specially designed sweeps (Dean 2014), or simply accepting the interference and removing it in processing (Abma et al. 2015). Whichever method is used, it is generally desirable to minimise interference between shots as much as possible. For methods where time separation is used to minimise interference (e.g., slip-sweep) then the principal consideration is the level of harmonic noise emitted by the vibrator which after correlation extends into negative time (Figure 11). Interestingly, the addition of a low-frequency section of the sweep does not actually increase the extent to which the harmonic noise extends into negative time (although it does increase its amplitude). This can be seen by comparing Figure 12, which starts at 1 Hz and is thus 4.5 s longer than the otherwise identical sweep shown in Figure 11. Note how the sweep rate of the low-frequency section that I have added is low enough that it does not cause the harmonics to extend further into negative time. This

Figure 11 (a) uncorrelated and (b) correlated 6-80 Hz sweeps with the 2nd and 3rd harmonics added.

Figure 12 (a) uncorrelated and (b) correlated 1-80 Hz sweeps with the 2nd and 3rd harmonics added.

means that the only impact on adding a low-frequency component to a sweep is limited to the sweep length and not the slip-time (the time between consecutive sweeps). Practical application Considering the points raised above, a design flow-chart of the recommended approach to sweep design is presented in Figure 13, it consists of the following steps: 1. Establish the desired SNR for the target(s) of the survey. 2. Determine the likely attenuation. If attenuation is not known then it can be determined practically by outputting a series of linear sweeps, to the maximum possible frequency that the vibrator is capable of, and then examining them for signal energy within different bandwidths using frequency panels. Synthetic seismograms and VSPs (where available) are routinely used in interpretation, but, if available, they should also be used when designing the sweep. 3. Determine the noise characteristics. This can be achieved using recordings of the background noise within the area (note that the noise characteristics may vary across a survey area as shown in Figure 8). If possible, the ability of processing to remove noise should also be included at this stage. 4. Determine the required vibrator parameters – e.g., peak force, the force-frequency relationship (e.g. Figure 9a) and, the fleet size. 5. Establish how the geometry will affect the data – this can be as simple as determining the likely fold at the target level and assuming the improvement in SNR will be . 6. Determine the preferred acquisition method (flip-flop, slipsweep, etc.). 7. Combine the inputs from steps 1 to 5 to establish the required sweep parameters. Note that some of the inputs in 1-5 may vary spatially, for example the noise levels or the target depth, and this may result in spatially variant sweep parameters. FIRST

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8. Establish costs by combining 6 and 7; this is not just the overall cost of the survey but also the cost of each segment of the bandwidth. If overall survey cost is beyond available budget, then reassess options, for example any combination of: 1. Reduction of SNR required. 2. Reduction of bandwidth required, e.g., high frequencies are likely to be more expensive due to higher attenuation so do we drop the top 10 Hz of the sweep? 3. Going from a single noise level across the survey to a reduced noise level in some areas, allowing the sweep to be shorter in that area. 4. Use small fleets rather than individual vibrators. 5. Increase the receiver to source ratio so that fewer VPs are required but the trace density is maintained. 6. Vary the geometry of the survey, e.g., increase the line spacing if the target gets deeper. 7. Accept a higher interference level by changing the acquisition method, e.g., be reducing the slip-time and increasing the level of cross-harmonic noise. Consider the use of pseudorandom sweeps (Dean 2014, Dean et al. 2017).

4. We can design a sweep to overcome attenuation, but doing so has a cost. 5. The sweep design should not be considered as a separate process from the remainder of the survey design process (Figure 13). 6. The sweep parameters are an output of the design process not an input. Acknowledgements I would like to thank all my colleagues over the years who have helped me to develop the approach described here and Denis Sweeney and Nick Josephs in particular for reviewing this paper. References Abma, R., Howe, D., Foster, M., Ahmed, I., Tanis, M., Zhang, Q., Arogunmati, A. and Alexander, G. [2015]. Independent simultaneous source acquisition and processing. Geophysics, 80(6), WD37-WD44. Anstey, N. A. [1991]. Vibroseis. Prentice Hall. Bagaini, C., Dean, T., Quigley, J. and Tite, G.-A. [2008]. Systems and methods for enhancing low-frequency content in vibroseis acquisition. US. Bouska, J. [2010]. Distance separated simultaneous sweeping, for fast, clean, vibroseis acquisition. Geophysical Prospecting, 58(1), 123-153.

Discussion and conclusion 1. When acquiring vibroseis data we should always be looking to maximise the recorded useful bandwidth. We should avoid making ‘processing decisions’ such as trying to optimise the autocorrelation shapes during acquisition, as afterwards the decision may be irreversible (see point 2). 2. The shape of the autocorrelation is not overly important, as we can deconvolve to our preferred wavelet if the SNR is sufficient (see point 1). 3. The easiest way to achieve the required bandwidth of a sweep is by increasing the low frequency content (e.g., it is easier to go from 8 to 4 Hz than 100 to 200 Hz). Low frequency data is also very important for inversion.

Dean, T. [2014]. The use of pseudorandom sweeps for vibroseis surveys. Geophysical Prospecting, 62(1), 50-74. Dean, T. [2016]. High producitivty vibroseis techniques: a review. ASEG Preview 184, 36-40. Dean, T., Kristiansen, P. and Vermeer, P. L. [2010]. High productivity without compromise - The relationship between productivity, quality and vibroseis group size. 72nd EAGE Conference & Exhibition. Dean, T., Quigley, J., MacDonald, S. and Readman, C. [2016]. The design of optimized broadband vibroseis sweeps. The Leading Edge, 35(8), 684-688. Dean, T. and Tulett, J. [2014]. The relationship between the signal-to-noise ratio of downhole data and vibroseis source parameters. 76th EAGE Conference & Exhibition. Dean, T., Tulett, J. and Lane, D. [2016], The effects of inter-vibrator interference on vibrator performance. Geophysical Prospecting 64(6), 1516-1523. Dean, T., Tulett, J. and Lane, D. [2017], The use of pseudorandom sweeps for vibroseis acquisition. First Break, 35, 107-112. Kristiansen, P., Quigley, J., Holmes, D. and Dean, T. [2010]. What if I...? - The Use of Vibroseis ‘Energy Tests’as an Aid in Parameter Choice. 72nd EAGE Conference & Exhibition, Barcelona, Spain. Landrum, R.A. [1967]. Extraction of signals from random noise by crosscorrelation. 37th SEG Annual Meeting. Meunier, J. [2011]. Seimic acquisition from yesterday to tomorrow. SEG. Monk, D. J. [2020]. Survey Design and Seismic Acquisition for Land, Marine, and In-between in Light of New Technology and Techniques. Quigley, J., Holmes, D. and O’Connell, K. [2013]. Putting It All Together – Broadband, High-density, Point-receiver Seismic in Practice. 75th EAGE Conference & Exhibition. Rozemond, H.J. [1996]. Slip-sweep acquisition. SEG Technical Program Expanded Abstracts 1996, 64-67. Sallas, J.J. [2010]. How do hydraulic vibrators work? A look inside the black box. Geophysical Prospectin,g 58(1), 3-18.

Figure 13 Flow-chart showing a holistic sweep design process. *Includes fleet size.

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Sheriff, R.E. [2002]. Encyclopedia dictionary of applied geophysics. SEG.

SPECIAL TOPIC: LAND SEISMIC

Ambient noise monitoring and HSE risk mitigation by the deployment of IoT technology on land seismic crews Andrew Clark1*, John Archer1, Mikaël Garden2 and Jozsef Orosz3 describe how in recent onshore nodal seismic surveys IoT technology has been used to provide cable-free Ambient Noise Monitoring to enable informed decision-making and mitigation of risk. Summary The authors describe how in recent onshore nodal seismic data acquisition surveys IoT technology has been used to efficiently provide both cable-free Ambient Noise Monitoring widely sampled across the recording spread, to enable informed decision making regarding noise levels affecting recording operations, and the mitigation of safety risk to remote workers, especially in hazardous terrain, by providing real time status monitoring and an emergency SOS capability where traditional communications are limited or impaired.

ly reduce the amount of data to be transmitted over a network. A simple example would be a fire detector which monitors temperature constantly but only sends an alert signal when the temperature exceeds a certain threshold value. LPWAN networks were established on three seismic projects in the last year in Canada and Romania. Two types of Edge devices were also deployed to utilise the LPWAN – Ambient Noise Monitors (ANMs) distributed across the active recording spreads, and the second, individual emergency pagers with GPS location capability, were issued to field workers.

Introduction Recent developments in the Internet of Things (IoT) technology enabling the exchange of data between devices and systems over the internet or other communications networks provide solutions to long-standing concerns and objectives in the oil and gas industry. In this paper we discuss their application to address two such concerns specific to seismic data acquisition. The first, the real time monitoring of ambient noise levels during seismic data acquisition using nodal seismic data acquisition systems, and the second the mitigation of risk to workers operating in remote areas often in difficult terrain with poor communications. For those readers unfamiliar with IoT developments it will be helpful to explain two terms used in the following paper. The first is LPWAN which stands for Low Power Wide Area Network. LPWANs are built using wireless protocols specifically designed to allow long-range communications between battery-powered remote sensors. Examples of LPWAN technologies include LoRa, Sigfox, NB-IoT, and LTE-M. Different LPWAN technologies have varying features, making them suitable for specific IoT applications depending on factors like required coverage area, data rate, and battery life. An example of the use of LPWANs is the communication with smart meters used by utility companies to provide automated readings. The second term is an ‘Edge’ device or ‘Edge’ computing – these are terms used to describe a device that brings computation and data storage closer to the source of data collection, a sensor. Such devices improve response times and most important-

LPWAN network The enabler and backbone of the implementation of IoT technology on seismic operations is the communications coverage provided by the latest generation of LPWAN gateways which receive the signals from the deployed devices. LPWAN network coverage was established over the data acquisition areas using solar powered portable gateways as pictured in Figure 1. The gateway installations consisted of an antenna, LPWAN gateway, battery and solar panel mounted on 10-m telescopic

RemEX Technologies Ltd | 2 OMV | 3 OMV Petrom

Corresponding author, E-mail: andrew.clark@remex.tech

Figure 1 Portable gateway.

DOI: 10.3997/1365-2397.fb2024005

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Figure 2 Example of theoretical gateway coverage map. Colour shading indicates expected signal strength in dBm (dB ref 1 milliwatt). Dark-blue areas have weaker signal strength than green areas, and uncoloured areas will likely have no coverage at all. A total of six gateways were planned for this 400 km2 foothills project in Romania.

masts. In addition, motion-activated video cameras were incorporated for security and to enable remote monitoring of the installation. Communication ranges obviously vary due to physical conditions including elevation changes and vegetation density, which in itself varies due to season. The gateways were optimally located to provide coverage over the maximum area of interest with an average location density of one every 70 km2. The actual locations were selected after an analysis of satellite data of the terrain and the modelling of theoretical signal reception and coverage (Figure 2). Encrypted data packets transmitted from the remote devices (‘uplinks’) are received by one or more gateways, and forwarded to dedicated servers, usually using an LTE network if one is available, but failing that a satellite connection can be used. The data can then be accessed and displayed to any authorised end users. Ambient noise in nodal data acquisition The adoption of nodal single sensors in seismic data acquisition has become almost universal as they provide great improvements in operational efficiency, parameter design and therefore imaging, with reduced acquisition costs. However, these benefits usually come at the cost of not being able to see the data acquired until the nodes are collected from the field and the data harvested. This is a compromise that is acceptable in most cases because of the high reliability of modern seismic nodes. However, there are situations where it is advantageous to monitor the signal-to-noise ratio of the acquired seismic records. Examples of these are surveys with: difficult near-surface conditions, complex geology (high-velocity layers, interbed-multiples), holes in the coverage/low fold (no-permit zones, difficult topography, or surface infrastructure), weak energy sources (small vibrators, shallow explosive, weight-drop). In these instances, the seismic crew needs to carefully consider ambient noise resulting from wind, rain and third-party activities which may negatively impact the signal-to-noise ratio. Unfortunately, this is where most nodal systems have a problem in not 66

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being able to provide real time data and this has resulted in their use not being accepted on some projects despite their operational benefits. Until now the solution to provide real time ambient noise monitoring has been to deploy a ‘hybrid’ spread of receivers with lines of cable-connected receivers spaced through the nodal spread to monitor noise in real time. A cabled noise sampling line, with its closely spaced receivers typically every 25 m or 50 m, gives a good indication of noise levels but over a restricted area. Its location must therefore be carefully selected to ensure it is representative of the whole area. This is feasible in uniform terrain but difficult to be representative over large surveys in variable terrain without considerable resources. In addition, this practice is expensive and negates many of the benefits of nodal data acquisition. Another common practice is the mandating of wind speed limits at which recording operations will cease, with wind speeds being measured at one or two locations in the survey area. Sometimes this practice is combined with a pause in acquisition while a sample of nodes are collected from the field, the data downloaded and a rapid analysis of ambient noise levels are carried out. The problem with this method is that wind speed limits are fairly arbitrary, and the actual measurement limited to a few places with convenient access, not reflecting localised wind speeds, ground conditions and cover, or the possible sheltering effect of terrain over the active spread. In addition, the relationship between noise amplitude and wind speed is non-linear (Bland and Gallant, 20011 reported a doubling in noise RMS for each 6 km/h increase in wind speed). Moreover, the process of gathering a subset of nodes for verifying noise levels is not only labour-intensive but also occurs after the fact. Typically, by the time the analysis is completed, the environmental conditions have already altered. Hence, this secondary strategy to mitigate ambient noise might lead to avoidable delays in recording operations and incur significant standby costs. Cable-free ambient noise monitoring IoT technology was deployed to establish the feasibility of real-time ambient noise monitoring, whilst still maintaining the benefits of cable free data acquisition, on three surveys in Romania and Canada. Figures 3a & 3b show the ambient noise monitor (ANM) used which consists of a proprietary designed ‘Edge’ device

Figure 3 a) ANM deployed with external antenna. b) ANM deployed with internal antenna only.

SPECIAL TOPIC: LAND SEISMIC

Figure 4 Map display and tabulation of RMS noise values received from ANMs. Colour denotes the level of noise with green being within specifications and red outside. The combined average RMS level is shown in the lower left corner of the map view.

connected via an industry-standard KCK connector to a geophone of the same type as used in the nodes being deployed for the data acquisition. The ANMs are autonomous with solar battery charging and easily deployed and redeployed. Therefore, they have the same deployment advantages as nodes compared to cable systems and can be distributed across a 3D spread to be truly representative of noise levels both spatially and in varying terrain conditions – grasslands, agricultural, woods, hills and valleys. Each ANM transmits ambient noise values via the LPWAN network which in turn are displayed via an app (Figure 4). This enables crew observers and client representatives to make informed and objective decisions on whether to continue, or to increase source effort to compensate for higher ambient noise levels. The wide area monitored also allows for a decision to

move acquisition to a different part of the project where the signal-to-noise ratio is less critical. Importantly, the system also enables normal operations to resume as soon as possible after a weather event or other noise source has passed. The average Noise RMS indicator is useful for making decisions on wind noise, which commonly have an impact on the entire survey, but for rain events which can be more localised, the map view providing an interesting insight. In Figure 4, a band of rain is affecting the ambient noise levels in the SW corner of the survey. An analysis of the data from one ANM located in the lower-right quadrant for that day shows that the rain lasted most of the day with a short break leading up to midday (Figure 5 in blue), similar to the data recorded from a centrally located crew weather station 12 km to the NW which registered the same rain bands some 30 minutes later (green overlay).

Figure 5 Ambient noise recorded on one ANM sensor (ANM210) over an 18-hour period (blue) with the rain precipitation rate from a crew weather station 12 km away overlain in green.

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The method described above gives a good indication of varying noise levels across the active spread and the prospect in general in real-time. Lone worker situation monitoring (Minder) The nature of land seismic data acquisition is that it can encompass very large areas, often hundreds of square kilometres extending over remote, hilly, and heavily vegetated terrain with poor access. In some extreme cases, seismic lines are accessible only on foot. In the past, when warranted, access was augmented by the use of helicopters although more recently this has become rarer because of environmental and safety concerns. The lack of access requires all equipment to be ‘ported’, manually deployed and operated (in both recording and shot hole drilling). In addition, in heavy vegetation seismic lines must be manually cut, cleared and surveyed. Therefore seismic crews can vary in size from a few dozen workers in flat, open terrain to as many as 3000 workers deployed on these “man-portable” operations. This obviously represents a significant HSE risk with exposure of thousands of man hours per day, often exacerbated by the need for workers to camp and live in the field. Controlling this exposure to HSE risk remains the greatest challenge in the industry. The advent of mobile phone networks has assisted emergency communication coverage in some areas where there is a sufficient population density to justify the network infrastructure investment. However, many surveys are conducted where the coverage is incomplete or is expensive, and field personnel are required to use their personal phones. Satellite communication is also available for emergency communications, but is usually cost prohibitive if provided to a large number of workers. Therefore, the second issue addressed by the application of the IoT technology is the mitigation of risk to workers in remote or harsh locations, particularly with regards to emergency communications. This has sometimes been addressed in the past by the establishment of expansive radio repeater networks. However, this solution has limited capabilities and is still largely reliant on periodic status ‘call-ins’ by the user. Radio logistics and cost prohibit the issuing of handhelds to hundreds of end-users. Typically, a radio would be assigned to each ‘group’ on larger

crews, with the assumption that members of a group will always be close together. In many cases though, the mitigation of risk has been by simply ensuring that workers are at least paired using the ‘buddy’ system to ensure that there is someone available to provide immediate assistance if necessary or to travel to a communication point to raise an alarm. The establishment of a LPWAN network over the survey work area described earlier adds a second independent communication network complementary to the handheld radios used for voice comms. The network supports the use of compact, GPS-enabled Emergency Pager (EP) devices that fit in a shirt pocket and offer a battery life of many days. The low device cost, simplified operation and charging logistics mean that a device can be issued to every crew member, not only the group leaders. Devices are ‘always on’, and position updates are sent at least every minute when the device is in motion. The single button is used to summon help in case of an emergency, and the onboard accelerometer and temperature sensor can be configured to send fall alerts or advise when temperature thresholds have been exceeded. An integrated buzzer is used to convey warnings to the user, or page them if they need to contact base. As the system is fully digital, it provides capabilities that directly help to address the risk mitigation challenge, notably: • Automated buzzer alerts upon entry into hazardous, no-permit, or restricted areas • Automated journey management logs with departure and return times • Emergency Response texts and email alerts to SOS activations containing the exact location and best route for first responders • Journey reconstruction for ‘Lost Man’ emergencies • Situational awareness of the entire crew in case of emergency, and proximity of paramedics and ambulances. Proprietary software (Minder) analyses the transmitted GPS locations as they arrive, determines whether any actions need to be taken or alerts issued based on the payload received, and updates the device positions on a secure web-based (or local) portal. The SOS feature was tested several times during the surveys (Figure 6). An example of such a drill would be for a field worker to raise the alarm by pressing the button on his emergency

Figure 6 Minder™ map display showing the highlighted location of the SOS and nearby personnel.

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Figure 7 Yellow dots represent individual staff locations transmitted.

pager. This encrypted message is picked up by one or more of the LPWAN gateways and sent to the server, where it is decrypted, and the payload decoded. The SOS flag triggers the automatic sending of an emergency alert message via email and/or SMS, containing the current coordinates of the device with an attached map link for directions and routing to the emergency location. This instant alert is sent to anyone listed in the crew emergency response plan (ERP) and allows everyone to be notified within seconds. Those without email or cell phone coverage can be advised by radio, and the journey manager can quickly identify the nearest resources using the real-time map. One issue that needs careful consideration is the privacy of individuals, and how to reconcile that with the rights of the employer to know where their personnel are particularly in an emergency response situation. The default mode of the Minder™ system is ‘Incognito’ mode where only device identifiers are shown. A device functional group ID would be assigned, which can help when filtering the map to find only the paramedics or HSE personnel for example (as seen in Figure 6). The app can be fully personalised by the end user to assign personal details such as names, or nicknames. However, this information remains within the local app and is not stored or shared on the server, so a Recording Crew Manager might be able to see the names of his line crew, while other users see only the device ID numbers. Of course the system can also be used for vehicle situational awareness or asset tracking in a similar manner. Figure 7 shows an illustrative summary of positions recorded of staff on a recent 2D data acquisition project in Canada covered by just two LPWAN gateway locations shown as light-blue circles. The receiver lines are overlain in dark blue. The cluster of points to the bottom-right indicate the crew’s accommodation. Results and conclusions The three data acquisition surveys have proven the practicality of establishing, with careful planning, a robust LPWAN commu-

nications network over hundreds of square kilometres, including wooded and rugged terrain, in a quick, efficient and cost-effective manner. Data collected from the deployed ambient noise monitors verify their ability to reliably inform data acquisition managers of the prevailing ambient noise levels in the project area affecting the seismic data and can thereby guide their operational decisions. Care must be taken, however, to match the ANM sensors with the sensors used in the nodes and their method of deployment – for example if nodes are buried then the ANM geophones should be similarly buried. It is also recommended that during the initial phase of spread deployment a sample number of ANM sensors and acquisition nodes are collocated for a period and the data compared to provide a correlation check or base line between the sensors. Future surveys combining the use of ANMs, nodes and co-located weather stations could add significantly to the body of knowledge regarding weather-related ambient noise in different terrains. The provision of remote worker monitoring in rough terrain and the ability to quickly summon and guide assistance in an emergency was proven. The EP edge devices also have the capability to automatically detect and report falls or other critical situations and these will be tested on future projects. The practicality of being able to communicate with lowpower devices over long distances using IoT technology on seismic surveys was proven and can be extended to include other sensors that utilise the same network, such as H2S detectors. References Bland, H.C. and Gallant, E.V. [2001]. Wind noise abatement for 3-C geophones: CREWES Research Report, 13, 1, 15.

Acknowledgements The authors wish to thank OMV Petrom, SAExploration and IoTDynamics (Canada) for their permission to include references and examples from their projects.

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IS NOW OPEN! GO TO SEISMICINVERSION.ORG

SPECIAL TOPIC: LAND SEISMIC

Revisiting the single sensor vs array debate in the light of new nodal system technology Amine Ourabah1* explores how compact nodes are affecting the transition from geophone arrays to single-sensor seismic acquisition. Introduction How many single-sensor nodes should I replace my geophone array with? This is a question that resonates within the seismic acquisition community, especially with the emergence of nodal acquisition systems as contenders for high-channel-count seismic surveys. While a legitimate query from an operational standpoint, answering it remains a complex task, one that usually necessitates a field data comparative study, that, even if it were obtained, its validity would be limited to the specific survey area. In essence, this question reignites the longstanding debate between single sensor and array configurations — a debate that divides the land seismic community based on factors such as industry, geographical location, schools of thought, and, more importantly, the seismic acquisition systems available to stakeholders. The growing popularity of cable-less nodal systems has led to an increasing number of operators replacing traditional cabled geophone arrays – renowned for their robust filtering capabilities, with point receiver nodal systems – characterised by their daunting raw data output. In the subsequent sections, we delve into comparative data examples, discussing how this shift from geophone arrays to single-sensor nodes impacts seismic acquisition, processing, and the resulting seismic image. We will aim to get a clearer understanding of the trade-offs involved in this paradigm shift, the factors that might influence the choice between single-sensor nodes and traditional array configurations and the potential hybrid solution of digital array forming, which might become the method that finally unites the two approaches. Arrays and single-point surveys The concept of analogue receiver arrays in geophysics, particularly in seismic exploration, traces its roots back to the mid-20th century. Seismologists, armed with seismic acquisition systems with limited seismic trace recording capabilities and tasked with studying large-scale targets, sought ways to improve the quality and precision of their seismic data by attenuating unwanted signals, defined as ‘noise’, while enhancing the signal coming from the targeted area. Over the years, the technical evolution of digital seismic acquisition systems has allowed more seismic traces to be recorded simultaneously, which in turn has enabled smaller receiver point intervals to be used in the field. At the same

time geophone arrays have also evolved, but their fundamental objective has remained unchanged: noise attenuation. Coherent noise, such as ground-rolls, and random noise, including wind noise and aliased backscatter, represent the primary challenges that any array strives to overcome. With the successful application of seismic technology in oil and gas exploration, we saw the development of very large capacity acquisition systems using cost-effective geophones arrays and versatile new source techniques. The 1990s and 2000s witnessed a wave of creative array designs (Meunier, 2011). Eventually, the industry gravitated towards simpler geophone array configurations like the 12-geophone linear array or the 3x3 box array, aiming to strike a balance between operational efficiency, minimising undesirable array effects, while still capitalising on noise filtering capabilities inherent to arrays. For a long time, especially in large-scale seismic exploration, receiver and source arrays constituted the cornerstone of acquiring seismic data. Arrays allowed limited channel systems to offer sufficient offset and azimuth distribution, as well as a high enough signal-to-noise ratio (S/N) for downstream processing to generate meaningful images and attributes. However, a notable shift in this paradigm has emerged in the last couple of decades, with a preference for trace density over fold (Ourabah et al, 2015). This transformation commenced with the replacement of source arrays by single source points, often operating in simultaneous shooting mode, resulting in remarkable source operation efficiency and a significant increase in source density, outweighing by far the residual blending noise. Subsequently, on the receiver side, the seismic industry witnessed the introduction of compact, lightweight, and cost-effective single-sensor seismic nodes, some approaching the size of traditional geophones (Manning et al, 2018). These nodes liberated operators from their cumbersome cabled acquisition systems with heavy geophone arrays, and its associated high technical downtime, allowing them to deploy the small lightweight nodes very efficiently in all types of terrain. The equipment constraints that originally prompted the use of arrays appear to have been gradually lifted and a growing number of single-sensor surveys are conducted worldwide. In fact, single-point receiver acquisition was considered the ideal type of design by many experts in the early 2000s, provided the spatial sampling was high enough to empower it (Baeten et al., 2000); It is therefore tempting to think that single-sensor surveys should

STRYDE

Corresponding author, E-mail: amine.ourabah@strydefurther.com

DOI: 10.3997/1365-2397.fb2024006

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Figure 1 Examples of raw stack vs final PSTM stack of three seismic surveys acquired in the Middle East with point receiver geometries (from left to right: Jordan (Ourabah et al, 2014), Iraq (Dvorak et al, 2015), UAE (Ourabah et al 2022). We note the overwhelmingly noisy look of the raw single-sensor data and the significant leap in quality of the final processed image.

ultimately supplant array systems globally, yet this transition seems to happen at a slower pace in some geographical locations than others, and for legitimate reasons. Single-point acquisition, particularly with single sensors, has a characteristic that can be challenging to accept: it generates raw data that, while very dense, appears daunting, displaying every conceivable noise recorded during the survey. Admittedly, this noise is sampled well enough to be efficiently attenuated during processing, but it necessitates a ‘leap of faith’, sometimes hard to take, especially for field professionals which bear the heavy responsibility of delivering the expensive raw dataset. This represents a significant departure from array data, characterised by upfront filtering and raw data already exhibiting a decent S/N. This difference in data characteristics has contributed to the slower adoption of single-sensor data in certain regions, notably from the perspective of field quality control. Evaluating the seismic data’s quality by solely inspecting raw data, as is often done with cabled geophone array data, becomes a challenging endeavour with single-sensor raw data. This leap of faith however, is gradually becoming more manageable, thanks to numerous publications featuring successful examples from various regions that have historically favoured cabled arrays (Figure 1) and the streamlining of processing workflows, allowing for fast-track processing and in-field quality control for these types of surveys. Arrays and single sensors in challenging terrain Arrays, even when being meticulously deployed according to survey plans, are not without their drawbacks, as is well-documented in the literature (Meunier, 2011; Monk, 2021). Some of these drawback’s stem from the cumulative effects of the sensors within the array, including inter-array statics (attributable to changes in 72

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elevation and ground velocity between sensor’s locations) and variations in geophone responses (attributable to factors such as manufacturing differences in natural frequency, temperature sensitivity or coupling). Others are inherent properties of the array as a whole, such as directionality, uncertainties in the frequency and dip characterising the targeted noise. All these effects can subsequently impact steps in processing, like Surface Wave Inversion (Figure 2), Surface Consistent Processing, AVO / AzAVO analysis (Orza and Panea, 2008) or even imaging, knowing that arrays are not considered in most modelling processes. Nevertheless, in easy access terrains, and when the channel count is limited, these effects can still be tolerable, particularly in cases where near-surface scattering is very pronounced, as these effects can severely dominate sparse single-sensor data, affecting the image of deeper targets, or at best slowing down the processing significantly (Bakulin, 2023). In challenging terrains with limited accessibility, planting individual sensors on a predefined pattern to form an array is seldom feasible. This limitation can arise due to obstacles such as rocks, vegetation, or rugged terrain, or human errors. Consequently, the response of the array may deviate significantly from its initial design (Figure 3), and reversing this effect during processing is not possible, resulting in the loss of high-frequency content and the introduction of highly variable residual noise. The latter is notably observable on array filtered ground rolls which display uncharacterised residual noise (Figure 4), making it very challenging to remove with a single process, often requiring a surgical approach, introducing complexity and delays in land processing projects. Array to single-sensor replacement ratio ‘How many single-sensor nodes should I replace my array with?’ This is a question frequently posed by operators when planning

SPECIAL TOPIC: LAND SEISMIC

new acquisitions using nodes. It’s evident that replacing an entire geophone array with one single-sensor node at the same station interval is not a prudent choice, as group spacing in array design is usually too sparse to allow an adequate sampling of the noise by single-sensor stations. Conversely, replacing every individual geophone in an array with a single-sensor node may be excessive and impractical, particularly for large surveys. Consequently, finding an appropriate replacement ratio that falls between these two extremes is frequently sought after to ensure the correct sampling of noise that will allow processing to produce the expected high-quality results. Finding this parameter often involves conducting a field test with a tight sensor spacing and implementing a decimation study

of some sort to determine the optimal receiver spacing. It’s not uncommon to observe arrays of 12 or 6 geophones being replaced with approximately 4 equally spaced single-sensor nodes, yielding comparable or superior results for the latter. However, this replacement ratio cannot be generalised blindly, as what truly matters is not the replacement ratio as such, but the spacing between the single sensors. Recent trends indeed indicate the selection of smaller station intervals, ranging from approximately 5 m to 12.5 m (Naranjo, 2018; Yanchak, 2018), when the line spacing stays relatively sparse. In reality, this replacement ratio is a misleading quest, as a more holistic approach to single-source, single-sensor survey design is preferred, seeking an increase in trace density across

Figure 2 A) Cross-spread time slices of: left, single-sensor node system at 2.08 m receiver station spacing; right, 12-geophone array cabled system at 25 m station spacing. We note the directional effect of the array B) their respective dispersion curve analysis for Surface Wave Inversion. Dispersion curves are less ambiguous when it comes to picking on high-density single-sensor data than on the array data (Ourabah et al. 2018).

Figure 3 Effect of misplacement of arrays element on the array response for a 1000m/s event. A) black dots planned position of the array, red dots randomly misplaced position in a 2 m radius. B) Array frequency vs azimuth response of the regular array. C) Array frequency vs azimuth response of the misplaced elements array. Note the reduction in attenuation as well as the displacements of frequency notches.

Figure 4 Example of dense single-sensor shot gathers acquired alongside cable arrays systems in forested environment (left) and desert environment (right). Note the attenuation of the ground rolls performed by the array leaves a residual noise that is difficult to characterise and varies from shot to shot. Removing this residual noise is usually a very surgical and tedious process. (Ourabah et al., 2018).

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Figure 5 Left, legacy data using large receiver and source arrays, Right, high trace density single-source single-receiver data showing improved image. Although trace density of the latter was higher, the source and receiver efforts were significantly larger on the legacy data. (Nehaid et ., 2019, Buriola et al., 2021).

the entire survey rather than being constrained by legacy cable designs that are no longer optimal. By doing so, operators can harness the full available potential of source and receiver technologies to increase trace density while simultaneously incorporating long offsets and diverse azimuths. An illustrative example from (Nehaid et al., 2019, Buriola et al., 2021) demonstrates this concept effectively: the high-density survey achieved an exceptional trace density of 184 million traces per square kilometre by utilising autonomous single sensor nodes on a carpet grid of 12.5 x12.5 m and implementing an aggressive simultaneous source shooting using 16 vibroseis sources on a 100 x12.5m grid. Compared to the legacy survey, the single-source, single-sensor survey was of higher trace density, (legacy design employed receivers at 100m x 50m and sources at 200m x 50m). However, the legacy design required a much higher source and sensor

effort due to the use of powerful arrays (48-geophone arrays and 4-vibrator array stacked up to 6 times). Nevertheless, the single-source single-sensor design proved more efficient and delivered superior results (Figure 5), underscoring the significance of prioritising high trace density over fold by distributing source and receiver efforts across a finer grid (Ourabah and Crosby, 2020). Digital array forming (DAF) and variable trace density designs Digital Array Forming (DAF), also known as Digital Group Forming (DGF), is a technique that emulates a physical array by combining data from individual single sensors within the processing sequence. DAF offers a notable advantage: it enables the correction of various sensor-related variations and can

Figure 6 Shot gathers from: A) single-sensor node system at 2 m spacing B) after digital array forming to 25 m (12 traces stack) C) real 12-geophone array cabled system at 25 m alongside A. A’) after GR removed with FK, B’) DAF filter applied after GR removal with FK. C’) FK applied on 12-geophone array. We note the enhanced reflection of the DAF after filtering (B’) compared to both filtered single-sensor (A’) and filtered 12-geophone array data (C’).

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Figure 7 Examples of a 3x3 Digital array forming using a carpet receivers deployed on a 7.5x7.5 m grid. (Ourabah et Chatenay, 2022). A) no DAF, B) DAF applied on the raw data (C) DAF applied on pre-processed data before migration. Note the effect of raw DAF (B) and pre-processed DAF (C) on shallow event (orange arrow). Deeper events (green arrow) seem less affected by the order of the DAF in this example.

incorporate filtering before the combination is executed (Baeten 2000, El-Emam and Khalil, 2012). This correction process significantly mitigates some of the disadvantages associated with traditional arrays. Furthermore, DAF can be employed in more sophisticated array formations, allowing for variable filter designs and weights to be used across the survey area to adapt to local data quality variations. One of the strengths of array formation is its effectiveness in enhancing weak signal coming from a targeted area (usually deep target) and attenuating undesirable signal (typically shallow scatterers). Nevertheless, the often overbearing ground-rolls noise, which is usually targeted by arrays, can be efficiently removed when sampled adequately by single-sensor data, thereby enhancing the DAF capability – when applied afterwards – to bring more subtle events to the forefront of this new reduced noise floor (Figure 6). Pre-processed DAF can also be less detrimental to shallow targets enhancing this area of very low S/N and protecting horizon continuity (Figure 7), as well as allowing a reduction in the number of elements required in the group forming to match a legacy cabled array design, and therefore reducing operational efforts.

Access to individual measurements within the array also opens the door to innovative processing approaches. For instance, the original single-sensor data can be progressed through an iterative approach, employing variable array filters throughout the processing sequence and in different domains. These filters can serve as a preconditioning tool or as a means of guiding single sensor processing (Figure 8). Finally, particularly in the context of very large HD single sensor seismic surveys, DAF can be a solution to reduce data volume and speed up processing and imaging turnaround while resusing existing array processing workflows and hardware set-up. Where might the industry be heading? It’s undeniable that if the operational constraints of having receivers and sources a few metres apart in a carpet design were not so drastically difficult to overcome, and the subsequent data generated not so expensive to handle, the debate between arrays and single sensors would be closed. But that’s unfortunately not the case; although we see examples of ultra-high trace-density surveys appearing on small scale (Ourabah and Chatenay., 2022), there are still serious challenges to overcome before we

Figure 8 Radial mixing (gaussian weighted) across Offset vector tiles on COCA gathers abondance of traces within a small radius result in significant enhancement of S/N used to pick subtile orthorhombic moveout (Davison et al, 2014).

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can implement these types of super dense designs at scale on any terrain. High-trace density surveys with single-sensor single source have been successfully acquired in parts of the Middle East at large scale for some time (Rached and Al-Fares, 2006), (Pecholcs et al., 2012), (Yanchak et al. 2018). However, there are some areas where implementing the correct spacing to overcome challenging near surface scattering would be too onerous, and therefore transitioning from arrays to single-sensor designs might require the use of digital array forming which provides the flexibility of the latter combined with the familiar outcome of the former. This flexibility can also lead to the emergence of variable trace density surveys, where challenging areas can be sampled with finer grid to allow the use of digital array forming techniques while other areas would use a more affordable type of spacing all in one unique survey. Operationally, this is very much possible with current technology: for instance, compressive sensing patterns (Herrmann, 2010) already represent a type of variable trace density surveys, although processing workflow will differ. Survey designs are not only being reshaped by new nodal and source technologies but also by the diverse industries these technologies are penetrating. For instance, we see the geothermal industry acquiring more seismic data in urban environments where use of arrays, although useful, might not be very practical. We see CCUS projects using dense and compact seismic surveys not only to image the subsurface but also as baseline for monitoring (4D seismic), capturing the source, the receivers and environmental noise variability in this case is very important. We also observe an increased interest in passive seismic, which is a byproduct of most nodal systems. This passive seismic data can be used to acquire a baseline for induced seismicity or even to derive a velocity model using interferometry; both methods might benefit from clustered digital arrays that will be able to fast track the processing by enhancing the S/N and reduce the exorbitant data volume of passive recording.

best chance to achieve a high-quality seismic image and seismic attributes with current or future tools. Seismic equipment technology and processing have all significantly evolved in the last few decades, and it is important to break ties with legacy concepts and look at the new seismic acquisition designs more holistically where technology, operational efficiency, processing, and interpretation are all part of the equation, as the ultimate goal is a reliable representation of the subsurface regardless of what the raw data looks like at the start of that journey. References Baeten, G.J.M., Belougne, V., Combee, L., Kragh, E., Laake, A., Martin, J.E., Orban, J., Özbek, A. and

Vermeer, P.L. [2000].

“Acquisition and processing of point receiver measurements in land seismic,” SEG Technical Program Expanded Abstracts: 41-44. https://doi.org/10.1190/1.1816083 Bakulin, A., Ramdani, A., Neklyudov, D. and Silvestrov, I. [2023]. “Meter-scale geologic heterogeneity in the near surface explains seismic speckle scattering noise,” The Leading Edge 42: 683–694. https://doi.org/10.1190/tle42100683.1 Buriola, F., Mills, K., Cooper, S., Hollingworth, S., Crosby,A. and Ourabah, A. [2021]. Ultra-high density land nodal seismic – Processing challenges and rewards. European Association of Geoscientists & Engineers. 82nd EAGE Annual Conference & Exhibition, p.1-5. https://doi.org/10.3997/2214-4609.202112916. Davison, C.M., Grimshaw, M.J., Murray, E.M., Kowalczyk-Kedzierska, M., Angio, S. and Ourabah, A. Orthorhombic Extension to HTI Velocity Analysis – Theory and Application to a High Density Acquisition. European Association of Geoscientists & Engineers.

76th

EAGE Conference and Exhibition 2014, Jun 2014, Volume 2014, p.1-5. https://doi.org/10.3997/2214-4609.20140781. El-Emam, A. and

Khalil, S. [2012]. “Maximizing the value of

Single-Sensor measurements, Kuwait experience,” SEG Technical Program Expanded Abstracts : 1-5. https://doi.org/10.1190/ segam2012-1000.1

Conclusion Geophone arrays have played a key role in allowing the right seismic data to be acquired in complex geological setting with limited channel systems. This status quo is being challenged by compact, lightweight, and low-cost single-sensor nodal systems that reduced a lot of the cabled array constraints, especially in difficult access terrain. There are still areas with challenging near surface geology that might require a very high spatial sampling to take advantage of single-sensor systems benefits. For those areas, the use of arrays might still be required to overcome strong scattering noise. However, these arrays do not have to be the irreversible analogue systems they have been anymore but can instead be replaced by digital array forming of single-sensor data acquired with vey compact nodes, simplifying seismic operations, improving seismic products and future proofing the recorded data. The flexibility associated with single-sensor nodal systems can also accommodate variable trace density survey designs if this approach becomes viable in the future. Today processing tools can handle the additional steps required around the digital array forming while still allowing us to revert back to the original single-sensor data when required, giving the stakeholders the 76

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Ghassan Rached and Abdulaziz Al-Fares, [2006]. “Single-sensor 3D land seismic acquisition in Kuwait,” SEG Technical Program Expanded Abstracts : 61-64. https://doi.org/10.1190/1.2370337 Herrmann, F.J. [2010]. ‘Randomized sampling and sparsity: Getting more information from fewer samples,’ Geophysics 75: WB173-WB187. https://doi.org/10.1190/1.3506147 Meunier, J. [2011]. Seismic Acquisition from yesterday to tomorrow. Society of Exploration Geophysicists. Pages 83-85, 130-147. Monk, D.J. [2020]. Survey Design and Seismic Acquisition for Land, Marine, and In-between in Light of New Technology and Techniques., pages 14-17. SEG 2020 Nehaid, H., Ourabah, A., Cowell, J., Brooks, C., Stone, J., Dieulangard, D., ... and O’Connell, K. [2019]. November). Acquisition of an ultra-high-density 3D seismic survey using new nimble nodes, onshore Abu Dhabi. In Abu Dhabi International Petroleum Exhibition and Conference (p. D021S035R003). SPE. Orza, R.L. and Panea, I. [2008]. “Single sensors versus hard-wired arrays in amplitude analysis,” SEG Technical Program Expanded Abstracts : 528-532. https://doi.org/10.1190/1.3063709 Ourabah, A. and Chatenay, A. [2022]. “Unlocking ultra-high-density seismic for CCUS applications by combining nimble nodes and

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agile source technologies,” The Leading Edge 41: 27-33. https://doi.

of a New Nimble Node and Cabled Systems in a Desert Environment.

org/10.1190/tle41010027.1

81st EAGE Conference and Exhibition 2019, Jun 2019, Volume 2019,

Ourabah A., Popham, M. and Einchcomb, C. [2021]. “New node design ,

p.1-5 DOI: https://doi.org/10.3997/2214-4609.201901136

enabling higher density seismic acquisition could be a game chang-

Pecholcs, P.I., Al-Saad, R., Al-Sannaa, M., Quigley, J., Bagaini, C., Zarkh-

er”, First Break,39(6), 81-88. https://doi.org/10.3997/1365-2397.

idze, A., May, R., Guellili, M., Sinanaj, S. and Membrouk, M. [2012].

fb2021046

“A broadband full azimuth land seismic case study from Saudi Arabia

Ourabah, A., Bradley, J., Hance, T., Kowalczyk-Kedzierska, M., Grim-

using a 100,000 channel recording system at 6 terabytes per day:

shaw, M. and Murray, E. [2015]. Impact of acquisition geometry on

acquisition and processing lessons learned,” SEG Technical Program

AVO/AVOA attributes quality – A decimation study onshore Jordan:

Expanded Abstracts : 1-5. https://doi.org/10.1190/segam2012-0438.1

77th Conference & Exhibition, EAGE, Extended Abstracts. https://doi.

Yanchak, D., Monk, D. and Versfelt, J. [2018]. “Egypt West Kalabsha 3D broadband ultrahigh density seismic survey,” SEG Technical

org/10.3997/2214-4609.201413301 Ourabah, A., Crosby, A., Brooks, C., Manning, E., Lythgoe, K., Ablyazina, D., Zhuzhel, V., Holst, E. and Knutsen, T. A Comparative Field Trial

Program Expanded Abstracts : 4080-4084. https://doi.org/10.1190/ segam2018-2997973.1

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Has the importance of ‘signal’ been forgotten in the signal-to-noise ratio of land seismic acquisition? Spencer L Rowse1* and Robert Heath1 discuss how the signal strength of a source affects the SNR, fold, and productivity. Abstract Since the inception of the seismic reflection method in the 1920s, equipment availability and limits in technology (not forgetting cost) have restricted the acquisition methods needed to achieve a desired level of ‘quality’ in any survey. Although great changes have occurred over recent decades, the aim of any survey remains the same; to obtain the highest ‘quality’ of data by using the best methods and equipment available to achieve the greatest enhancement of ‘signal’ and/or reduction of the ‘noise’ (signal-to-noise ratio) during acquisition. Recent technological improvements in the sensors, positional and recording equipment, have also permitted greater productivity and a decrease in cost per recording channel – survey designs are now less dependent on equipment limitations than in previous decades. The sort of equipment offered by most current manufacturers means that the primary method of acquiring the ‘best quality’ data is by means of high fold/high density surveys utilising a single source, single sensor and a multitude of ‘blended sources’ to achieve both the required SNR and productivity. Increasing the ‘quality’ of a survey is now synonymous only with increasing fold (number of traces that fall within a designated area). While it is undeniable that high values of fold and high source and receiver densities can be very effective, this ‘brute force approach’ relies on a multiplicity of shots and receivers to improve the SNR with little consideration of the source ‘strength’ (the energy / amplitude of the propagating seismic signal recorded in each trace). In this article, we discuss how the signal strength of a source affects the SNR, fold, and productivity. Introduction In any decade, the objective of a seismic acquisition survey could be simplistically stated as using what is portrayed as state-of-the-art equipment, methods and technologies to achieve the greatest possible signal-to-noise ratio (SNR) at an affordable cost by either enhancement of the ‘signal’ generated by the seismic source and/or reduction of the ‘noise’ during acquisition. However, while there has been little innovative in terms of source ‘strength’ for the last 30 years, the definition of what is considered noise has changed with the methods and techniques

Independent consultant

Corresponding author, E-mail: slrowse@aol.com

used for signal enhancement and noise reduction also varying. Arguably, until recently, acquisition design parameters (source and receiver intervals, bin size, maximum offsets etc.) were determined by the field equipment limitations of physical size, weight, power requirements, and maximum number of recording channels. However, thanks to improvements in the positional accuracy and fidelity of sensors, power consumption and weight/ channel of individual channels, it has been affordable to deploy greater numbers of channels and thus channel count is no longer the restriction on survey design it used to be. Such channel counts were almost unimaginable even at the turn of this century. A romantic view of 2D recording in the 1980s was that each seismic trace was a precious commodity. So valuable was it that many crews had an independent ‘artisan’ who had the ability and experience to oversee proceedings and authority from the client to change recording parameters on a shot-by-shot basis to achieve the best SNR on each trace. This was only possible due to a central recording system, sequential shooting (from a single source or an array of synchronised sources operating per record length), a low number of recording channels (96-120) and – most importantly – an ability to examine each record in real time for bad or noisy traces, or changes in the observed SNR. The emphasis of most 2D surveys typically being to maximise the signal ‘strength’ at each shot location by using multiple (4-6) synchronised sources and vertically stacking of 6-16 shots to increase the signal with 6-24 geophone in an array to reduce the random noise. The average survey operation today is technically and philosophically different. In relative terms, there are massive numbers of recording channels meaning that the quality of individual traces, if not large groups of them, is considered expendable. For example, given that no real time monitoring of channels is possible (either for noise, theft or system failure) the operator hopes that such loss will not seriously impinge on overall quality. The philosophy is that with perhaps 100,000 or more single sensors deployed, today’s technology permits much smaller bin size (5-10 m) and hits per bin which provides the expectation that, almost by definition, things have to be far better. The same goes for source effort: nowadays, there tends to be a very large number of single sources operating with a single sweep or shot (minimal

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source effort) per record also requiring very high fold to achieve the desired ‘quality’. With productivity rates of > 10,000 shots per day, compared to a 1980s 2D survey, this is data gathering on an industrial scale! But to what extent is it also gathering noise which is not realised until it’s too late? Arguably, the most significant technological development in field acquisition since the 1990s has had nothing to do with geophysicists. It is the introduction of the Global Positioning System (GPS), not only for positional data, but also as an accurate timing clock for both the source and receivers. It is the combination of lower cost and weight per recording channel, improved reliability, easier deployment and lower power requirements, which has led to today’s cable-less recording systems (remote acquisition units, nodal systems etc.). This, together with the introduction of simultaneous recording techniques, has enabled an almost exponential growth in the number of recording channels from 120 to 500,000+ with a corresponding increase in productivity (number of shots recorded per day) and greater spatial resolution. With the industry trend to single source and single receiver for greater spatial resolution and bandwidth, emphasis is now on maximising the fold to improve the S/N with many proponents of increasing fold predicting one million or more recording channels becoming routine within a decade. While there are no technical issues with the recording equipment preventing the deployment of so many recording channels, in practice the high costs of the recording equipment and crew, as well as mobilisation/ demobilisation, charges can only be economically viable for very large surveys and high production rates. While this trend in ever-increasing fold, is good for the equipment manufacturers, one must ask ‘is there a better way to improve S/N’? Quality, fold, trace count, signals, and noise Most modern acquisition systems continuously record and store the seismic data and timing information at the sensor location with QC normally limited to ensuring the sensor is operating within its specified parameters prior to deployment. For any meaningful judgment on the quality of the acquired data to be made, some means of ‘harvesting’ and processing of the stored data needs to be performed. Few modern recording systems have the ability to download, record and display the sensor data in real time. However, because of the ‘source noise’ from the many simultaneous sources generating overlapping signals, little information on the quality/SNR of the recorded data can be immediately deduced unless shooting is interrupted and a ‘single shot’ or ‘noise spread’ recording is made. For most surveys, QC of the data requires further processing from the ‘harvested data’ to isolate an individual shot record by using the GPS timing and removal of the ‘overlapping’ source noise (‘de-blending’) of the data. Because of the time delay involved in the retrieval /processing of each sensor’s stored data, the methods of ‘real time’ examination of an individual shot-point for quality/SNR, as in a 2D system of the 1980s, is no longer feasible on a shot by shot basis. Quality has now become synonymous with fold with the assumption that increases in fold equate to increased quality. However, this comes at greater costs in field equipment, and time taken to acquire the data. 80

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From Mayne, the inventor of the common depth point method, the increase in SNR is proportional to the square root of the number of summed traces ((n)1/2). In deriving this relationship, for 2D recording, Mayne stated the following assumptions: 1. The reflections in individual channels are sinusoidal, equal in amplitude and equally spaced in-phase over the indicated total interval. 2. The noise in each of the individual channels is random between channels and has the same amplitude with respect to the reflections in each. Based on these assumptions, the noise amplitude in the resultant summation signal will be proportional to the square root of the number of individual channels. Fold is a metric used to indicate the number, azimuthal and offset distribution of the sub-surface source-receiver traces that fall within a specified area (bin), and, as Lansley has observed, fold is a meaningless number unless the bin size is stated. He also suggested trace density as being more useful in indicating the potential quality of a 3D survey. Trace density is the number of recording channels per shot point multiplied by the number of shots per square kilometre. The relationship between fold and trace density (or trace count) is that fold multiplied by number of bins per km2 is equal to the trace count. In recent years, trace count has gained popularity as the ‘better’ metric in accessing both the expected ‘quality’ in a survey and the ‘field effort’ (number of sensors deployed, number of shot-points per km2) that, together with the average time needed to record each shot, can give an estimate of the time needed for the survey. Unfortunately, both fold and trace density are derived from the recording parameters and the ‘geometry’ of the survey without any knowledge of the signal ‘strength’ (amplitude or energy of the propagating wave), nor that of the noise on the individual traces recorded at the time of acquisition. Signal ‘strength’ and its effect on multiplicity From field experience (or intuition), it is widely believed that the greater the energy or force output of the source, the greater the ‘strength’ of the seismic signal and the ‘better’ the S/N ratio of a trace. In general, this is true for similar types of sources. For instance, given a choice of using either, 1kg of dynamite (~5 MJ of energy released per 1kg) or a ‘weak’ source using a 5Kg hammer (1-2kJ output), to shoot a survey, most, without regard to the costs involved, would opt for using dynamite as the impulsive source. Although the estimated fold and trace density for both sources will be identical, the SNR for the same shot-points will be vastly different, hopefully endowing the final processed data of the dynamite survey with higher quality. This simple example shows that, in addition to the metrics of fold or trace count, knowledge of the source ‘strength’ and background noise levels (SNR) is necessary when estimating the expected ‘quality’ of a survey. Unfortunately, when comparing the ‘strength’ of different sources the manufacturers stated maximum output is of little value. From controlled comparison tests of different sources, (Sopher, Miller) it has been shown that the manufacture’s source specifications have little relationship to the energy/amplitude of the signal recorded by a remote downhole, or surface sensor. This is due to the inefficiencies,

SPECIAL TOPIC: LAND SEISMIC

Figure 1 SNR increases vs number of stacks for different signal amplitudes

or losses, inherent in any system, in the conversion of energy from one form to another. From experiments by O’Brien, only 1-6% of dynamite energy is converted into the seismic signal. Estimates by Sallas also show similar losses for vibroseis. As the type of ground surface and moisture content, as well as the type of energy source, will affect the amplitude and frequency of the seismic signal, it is difficult to accurately compare the outputs of different land seismic sources without performing some form of test at the survey location. For simplicity. in the following hypothetical comparisons on fold, the ‘S’ in SNR is the ‘strength’ of the propagating wave and is the seismic energy generated by a single source that is received at a single sensor with a dimensionless reference value of 1. Similarly, the energy of the random noise level at a single sensor is also 1 giving a reference trace SNR of 1:1 and is displayed as the blue curve in figure 1. Although the x-axis is in dimensionless units of fold, if the average time duration taken to generate and record the seismic signal and move between source locations is known, it can also be an indicator of the amount of time needed in a survey to achieve the required SNR. Using Mayne’s assumptions, that all signals generated by the source are identical in both amplitude and phase and that the amplitude of the random noise is the same at each sensor, the expected SNR improvements will be proportional to the square root of the fold (number of traces stacked). The blue curve in figure 1 represents the theoretical improvement of a reference trace with SNR of 1/1 at each source and receiver location versus the number of summed traces. As shown by the purple markers on the blue curve, to obtain a doubling of the SNR requires a quadrupling of the fold and a corresponding increase in acquisition time. Also displayed in figure 1 are SNR ratios of 2:1 (black curve) and 1:2 (red curve) for each trace versus fold and are representations of the improvements in SNR acquired with different source ‘strengths’.

Most geophysicists, when selecting a source for a survey, will make a choice based on survey terrain, (ability of the source to access all locations), source availability, cost, reliability, and performance (the source that will generate the best signal strength and frequency bandwidth) and personal experience. Without prior experience or knowledge of a source’s performance, it is difficult to judge the signal ‘strength’ when comparing different sources as all source manufacturers’ specifications are the available energy/ force outputs of the source mechanism at, or near, the earth’s surface in the generation of the seismic signal. For dynamite, and most other impulsive sources, the units of measurement to describe the output ‘strength’ of a source is in energy units (Joules) whereas force (newtons) are the measurement units of a vibrator’s output. With different methods of generating the seismic signal (high energy delivered over a few milliseconds vs a low force (and energy) delivered over 12-24secs), and inherent losses and inefficiencies present in any mechanical system, the manufacturers stated output is not a good measure of the energy/ amplitude (signal strength) of the propagating seismic signal. Vibroseis is the most widely used land source today and is viewed by some as the ‘perfect’ source being able to accurately reproduce, by means of a hydraulic force acting on two masses and the ground, almost any desired range of frequencies in the seismic bandwidth. By means of a ‘calibrated downhole test,’ using several vibrators Dean was able to confirm the following relationship (equation 1) for a vibrators output (1) Where, nVibs is the number of vibrators in the array and FGF, the fundamental ground force of each vibrator. It should be noted that the equation 1 is valid for sweeps of the same bandwidth, where the maximum force output (FGF) is ≈ the weight (mass x gravity) of the vibrator but are normally operated at ‘70% of maximum drive’ to avoid decoupling. The main disadvantage of vibroseis is the time taken (8-32 seconds) to generate the seismic signal (the sweep time) and the relatively low amplitude of the propagating wave. In the past, a method commonly used in 2D surveys to reduce, what was then, troublesome source-generated noise (ground roll) was the use of linear receiver arrays where a multitude of geophone ‘elements’ were connected together in a string and laid out over a distance equivalent to the wavelength of the dominant ground roll frequency. In addition to reducing the ground roll, the multiplicity of elements in the receiver arrays were also beneficial in increasing the SNR by constructive summation of the coherent P-waves and/or reducing the background noise by destructive interference of the random noise at each receiver position. This is shown in figures 2(a) and (b). Although large linear receiver arrays are no longer used to reduce ground roll, a group of 6-9 geophones at each location can improve the SNR and therefore of the final CMP stack. These sensors do not need to be laid out in a linear fashion but, from Meunier, require an optimal geophone interval (OGI) for maximum attenuation given by (2)

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(a)

(b)

•

Figure 2 Noise reduction /SNR improvements for various sensors and sources for low values of stack.

Where K max is the maximum wavenumber of the noise (which will vary from area to area) Multiple versus single sensors is often a contentious issue within the geophysical community. Dean (2015) states, from experimental results in different areas, that the theoretical √n improvement is often a significant overestimate. From informal discussions with experienced field personnel, most agree that a spacing of >1-2m between sensors is a sufficient distance for the environmental noise to be considered incoherent at each sensor in most areas.

u sing two (or more) identical sources with synchronised timing (proportional to a number of sources in array) • sweeping four times longer (proportional to √(sweep time)) • increasing the CMP fold by four (proportional to √(fold) • increasing the geophones from one to four at each location (proportional to √(number of sensors) • selecting a source with twice the force output (proportional to FGF) • vertically stacking of four signals (proportional to √(number of stacks and sweep time))

SNR improvements and productivity For 3D operations, fold is merely the number of traces that fall within a designated area (bin) and is a good indicator of the azimuthal and offset distribution of the traces. While it is undeniable that greater bandwidth, smaller bins, and greater fold has been effective in improving the spatial and temporal resolution of a survey, increasing fold (and trace count) are often now regarded as being the only method to increase the quality of a survey. To be sure, some complex structures, such as a salt dome, will benefit from imaging the structure at all azimuths and multiple offsets resulting in large fold. In this instance, while large increases in fold are beneficial in increasing the quality of the data, one must ask: are these improvements due to the reduction of ambient noise (proportional to √n) or from imaging the structure from the increased azimuthal and offset distributions in each bin (proportional to n)? Although single-source, single-sensor, simultaneous shooting is becoming the de-facto method of acquisition, it is best suited for large surveys in open terrain to obtain the high productivity necessary to offset the high equipment and crew mobilisation costs. However, most parts of the world do not have such luxuries and operational realities dictate different approaches, such as in difficult terrain, ‘no-permit’ areas, man-made structures, lack of vehicular access to all source locations to name just a few. All these can severely limit the number of shot points possible/ affordable and reduce the fold/quality. In these circumstances, it may not be possible to obtain the required SNR by high fold numbers. An alternative would be to improve the SNR on each trace. From the above figures and equation 1, compared to a single sensor, single shot recording configuration, it is possible to double the SNR for vibroseis by implementing one, or more, of the following methods:

All but the last two items involve either extra time or equipment to achieve an increase in SNR. The maximum force output of a vibrator is approximately the gross weight (hold down force) of the vehicle. Until now, improvements in vibrator force output (which is assumed to increase the maximum amplitude of the seismic signal) have been achieved by merely increasing the weight of the vibrator. Today, vibrators come in a range of sizes from ~7,000kg to 36,000kg. 28,000kg vibrators are the most popular, having the best combination of physical size, manoeuvrability, ease of transportation, force output and cost. As, at 36,000kg, vibrators are ‘maxed out’ in their gross weight and restricted in their areas of operation, without a major breakthrough in converting the vibrator force into greater amplitude of the propagating seismic wave, the ‘signal strength’ of a vibrator is unlikely to change in the near future. The use of vertical stacking of signals has declined in recent decades in favour of single sweeps and increased fold. However, vertical stacking of a small number of sweeps has advantages. The first is the ‘compaction effect’ observed on many different types of ground surfaces, where the seismic signal generated by the first sweep is noticeably ‘weaker’ than subsequent sweeps at the same location. This has been attributed to some of the vibrator energy being ‘lost’ in the compression/compaction of the ground on the first sweep with subsequent sweeps having improved ‘coupling’ (greater energy being transferred/ converted into the seismic signal) due to the compacted ground. Most surveys today use some form of ‘blended’ acquisition where multiple sources are operating and generating undesired ‘overlapping’ signals on each record – by uniquely encoding and vertically stacking a small number of sweeps at each location, such as phase encoding

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Table 1 Comparisons of various recording parameters with a single sweep of 24 seconds

of four consecutive sweep (0, 90, 180, 270 degrees), identification of the desired signal from the noise generated by the overlapping signals can be more easily accomplished. In order to evaluate/compare different acquisition methods, for both productivity and expected SNR, a reference needs to be established and some means of ‘ranking’ the different source configuration needs to be derived. In table 1 are comparisons of a single ‘reference sweep’ (single source, 24 seconds, 16 second move) displayed together with various recording parameters. The ‘figure of merit’ (FOM) is derived from equation 1, being the cumulative effect of each recording parameter (square root of the number of sweeps, sweep length, and number of geophones). As a base line for comparison purposes only, the FOM (highlighted in green) is for a single sweep (# swps) of 24 seconds (swp time) and a single geophone (#geos) is the product of √1*√24*√1 giving a reference FOM of 4.90. Productivity of a single source is the number of shots recorded in an hour (or day) and is determined by the time spent generating the seismic signal plus the average time taken to move between source locations. Average ‘move-up time’ is dependent on source interval, terrain and driver experience and can vary greatly for different areas. For comparison purposes only, in table 1, a move up time of 16 seconds is shown. For vibrators, when vertical stacking of several sweeps, there is a ‘reset time’ needed after each sweep for the hydraulic system to return to normal operating pressures and to generate a start command. In this example, the reset time is given as 2 seconds. To compare the effects of different recording parameters on quality and productivity the two right-hand columns in table 1 are the CMP fold needed to achieve the same SNR improvement of 100 for the different FOM values (calculated from FOM* √(fold) =100) and the time in minutes needed to achieve this reference SNR. Comparing a single sweep of 24 seconds with four, 6-second sweeps the table shows that the fold to achieve a SNR is the same (417) with an increased time required when acquiring the four stacked sweeps (319 minutes vs 278). If the sweep time is increased by 50% (from 6 to 9 seconds), the fold required to achieve a SNR .of 100 and a time of 269 minutes is reduced to 278 stacked traces. By far the greatest impact on obtaining increased SNR is by the use of multiple geophones to increase the multiplicity of the signal/reduce random noise at each receiver position. Obviously, this incurs extra cost and time needed to lay out (and retrieve) the geophone strings prior to recording, but this is offset by either the reduced fold (~25%) and time needed to acquire a SNR of 100,

or (for a single sweep of 24 sec) a doubling of the SNR (200) for the same fold (417) and acquisition times. Future needs ‘Signal strength’, the energy/amplitude of the propagating seismic signal generated by a vibrator or impulsive source, is an important determinant in the final quality of the processed data but research into increasing signal strength has been neglected over the last decades in favour of higher fold and greater productivity. At 36,000kg, today’s vibrators have reached their practical limits in size and force output with increases in signal strength, at present, only possible by increasing the sweep length or by synchroniding two or more vibrators. Impulsive sources for land have several advantages over vibroseis; the seismic signal is generated over several milliseconds instead of several seconds and the energy/force used to generate the seismic signal is not as dependent on the vehicle size or weight. In addition, impulsive sources have greater low frequency content than vibroseis and, properly designed, can have cycle times of 1-3 seconds enabling timecoded sequences of shots and higher production rates. For both types of source, the signal strength can be increased by reducing the losses in the conversion of the mechanical energy/ force of the source into the energy of the seismic signal. Conclusion At the zenith of 2D recording, ensuring quality was by means of the visual observation of each record in real time for ‘good SNR’ with an emphasis on high signal ‘strength’ and reduction in ambient (random) noise by the use of source and receiver arrays and vertical stacking of multiple signals at each shot-point. In contrast, today’s surveys, by using a single source and blended acquisition, have reduced the signal strength and increased the background noise (‘overlapping signals’) resulting in a greatly worsened SNR for each recorded shot. Under these recording conditions, a greater fold is needed to achieve the desired quality in the processed data. In some sense, moving to this form of acquisition threw the signal baby out with the data quality bath water while self-limiting where the method can go. A crew using one million channels is technically feasible (and for manufacturers, highly desirable), but it is unlikely that we’d adopt such a brute force approach if we were learning to do land seismic from scratch today. The square root of fold has been shown to increase the SNR in CMP acquisition under certain circumstances and, today, fold and trace count have become common metrics that are synonymous FIRST

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with ‘quality’ when comparing different surveys. However, these metrics are meaningless as both are a consequence of the recording geometry and do not account for either the signal strength or noise present on each trace. Increasing the signal strength by vertical stacking of encoded multiple shots can be advantageous in the final quality of the processed data by compaction of the ground on the first shot or sweep to improve ‘coupling’ and signal separation during the ‘de-blending’ operation. In addition, multiple sensors at each location can, in some instances, also improve the SNR /reduce the noise at each receiver location. It seems, to get the best SNR for its dollar, land seismic, in terms of both sources and recorders, could well benefit from a little more imagination and better understanding of relatively basic physics.

Dean, T. et al. [2015]. The coherency of ambient seismic noise recorded during land surveys and the resulting implications for the effectiveness of geophone arrays Geophysics, 80(3), (May-June 2015). Lansley, R.M. [2004]. CMP fold: A meaningless number? The Leading Edge, October 2004. Mayne, W. [1967]. Harry Practical Considerations in the use of Common Reflection Point Techniques, Geophysics, April,1967. Meunier, J. [2011]. Seismic Acquisition from Yesterday to Tomorrow, 2011 Distinguished Instructor Short Course, No. 14. Miller, Richard D. et al. [1992]. Field comparison of shallow seismic sources near Chino, California, Geophysics, 57(5), (May 1992). O’Brien, P.N.S [1968]. Some Experiments Concerning the Primary Seismic Pulse. Presented at the 30th meeting of the European Association of Exploration Geophysicists, Salzburg, June 1968. Sallas, J.J. [2010]. How do hydraulic vibrators work? A look inside the

References

black box, Geophysical Prospecting, 2010, 58, 3-17.

Dean, T. [2010]. High Productivity Without Compromise – The Rela-

Sopher, D. et al. [2014]. Quantitative assessment of seismic source perfor-

tionship between Productivity, Quality and Vibroseis Group Size.

mance: Feasibility of small and affordable seismic sources for long

Developments in Land Seismic Acquisition for Exploration, 17-19

term monitoring at the Ketzin CO2 storage site, Germany. Journal of

May 2010, Cairo.

Applied Geophysics, May, 2014.

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09/11/2023 16:34

SPECIAL TOPIC: LAND SEISMIC

Understanding land seismic scattering noise through careful simulation Christof Stork1* explores the characteristics of scattering noise through careful seismic elastic modelling using the finite difference approach. Introduction Some of the most difficult noise with land seismic reflection data is near surface scattering noise, which doesn’t follow typical understanding of coherent noise. When the noise is strong, massive expensive fold (~10,000) is needed to produce a reasonable, yet still imperfect image. Better understanding of this noise can help us to optimise the acquisition and processing for this data, improve the image and reduce acquisition costs. Simulating synthetic data lets us focus on this problem without other complicating types of noise. We explore the characteristics of scattering noise through careful seismic elastic modelling using the finite difference (FD)

approach using code developed by Jan Thorbecke. We find that two key characteristics are necessary to model realistic scattering noise: A) a very low velocity (~100 m/sec shear velocity) surface layer that initially traps much energy and B) small-scale heterogeneities, often less than 1 metre in size, that scatter the trapped energy. These two characteristics produce the complex micro-scattering speckle noise that we often see in real data, such as Figure 1. We note that for 50Hz energy with 100 m/sec velocity, the seismic wavelength is 2 m. Many previous land seismic data simulations, such as the SEG SEAM-2 project, do not have these key characteristics, and as a result have only simpler seismic noise. There

Figure 1 Sample seismic shot gathers showing strong scattering noise. There are also significant P and shear irregular refraction multiples, which are marked by the arrows. This is sometimes confused as surface waves.

Land Seismic Noise Specialists

Corresponding author, E-mail: cstork@landnoise.com

DOI: 10.3997/1365-2397.fb2024008

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have been some recent data simulations that also share these characteristics: Henley et al. (https://csegrecorder.com/articles/ view/time-lapse-survey-repeatability-an-elastic-modeling-study) and Bakulin et al. (https://doi.org/10.1190/tle42100683.1). Our results are consistent with these studies. Modelling For the modelling, we use 0.2 m grid spacing over a volume 8000 m wide and 3000 m deep. We use a vertical surface force that simulates a vibrator and record vertical velocity that simulates a geophone. This small grid spacing and associated small time step is expensive, taking about 10 hours on a 40

Figure 2 Cross sections of the P velocity. Figure 2a on top is the whole model showing regular flat reflections, which have impedance contrasts of 0.22. Figure 2b on the bottom is a zoom on the near surface showing the heterogeneities. The average velocity of the top 10 m is 500 m/sec. Shear velocity and density models have similar patterns to this. The average shear velocity of the top 10 m is 120 m/sec.

core machine. Because of the expense, we restrict ourselves to 2D modelling. We believe the 2D approach will understate the scattering effect, especially since all of the scattering energy will be inline and none will be crossline. From the modelling and analysis of the data, we learn that A. Regular, unaliased acquisition is not very beneficial since there is little organised linear energy in the inline direction, B. A key metric for acquisition quality is simply the total number of sources and receivers with little impact from the exact geometry of the sources and receivers, C. Much of the noise is not from unwanted surface energy, but from distortion of the reflections, D. Refraction multiples, both P & shear, are stronger than usual, E. Statics provides only a limited quantification of the near surface distortion of the reflection signal, F. And performing surface scattering corrections is more complex than SC-Deconvolution and provides significant uplift. A cross section of the P velocity is shown in Figure 2a. A vertical zoom of the P velocity in Figure 2b shows the scatterers of the surface layers, which have size ranging from 1 m to 30 m. The shear velocity and density have similar scatterers. A sample shot gather for the model is in Figure 3 along with shot gathers for the model without scattering, for acoustic modelling without scattering, and for the original shot gather but with the surface energy removed which shows only reflections. The surface reflections have been strongly distorted by travelling through the near surface. The refraction multiples for this simulation are not as strong as is often observed in real data.

Figure 3 Various modelled shot gathers with AGC. First gather is for acoustic modelling without near surface heterogeneities using just the P velocity and density. The second gather is elastic modelling without near surface heterogeneities. The third gather is elastic modelling with the near surface heterogeneities. The fourth gather is elastic modelling with only reflections, which shows that the reflections are strongly distorted. The fourth gather is produced by taking the third gather and subtracting a modelling run with only the near surface model and without reflections in the model. The ‘A’ arrow marks acoustic surface waves travelling at ~500 m/sec. The ‘B’ arrow marks P refraction multiples, which are sometimes called guided waves. The ‘C’ arrows mark the strong reflection from the bottom of the model. The ‘D’ arrow marks the elastic surface waves travelling at ~200 m/sec. The ‘E’ arrow marks the artificial reflections from the side edge of the model. The ‘F’ arrows mark elastic shear refraction multiples, which are often strong and often confused with surface waves. The ‘G’ arrows mark P refraction multiples. The ‘H’ arrows mark interbed multiples. The ‘I’ arrows mark likely shear reflections. Some letters appear more than once.

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Figure 4 The same shot gathers as in Figure 3, but with statics and radon to remove slow surface energy. Receiver spacing is 1 m. AGC distorts some of the relative amplitudes. The first two gathers have reflections and multiples nicely enhanced but the last two gathers still have much noise. Statics and radon with dense receiver spacing did not remove all the noise and signal distortion. High frequencies are attenuated.

Figure 5 Stacks from conventional processing of the data types for the shot gathers above. From left, acoustic modelling without scattering, elastic modelling without scattering, elastic modelling with scattering, elastic modelling with scattering but surface energy subtracted out. The acquisition for the stacks consists of 401 shots with spacing of 20 m and split spread receivers with spacing of 5 m and maximum offset of 2000 m. The 10 m CMP bins have a fold of 400. There are about 320,000 traces in total. The processing sequence is listed in the text. It is interesting how different the acoustic and elastic without scattering are. The stacks with scattering are not very good. The stack of data with surface energy subtracted out of the shot gathers is not much improved over the stack with surface energy. This shows that much noise is corruption of signal, not unwanted energy. The red arrow marks the strong reflection from the bottom of the model. All energy below this is multiples.

The shot gather with surface energy removed shows significant distortion, which is consistent with the analysis of a previous EAGE conference paper by the author (https://doi. org/10.3997/1365-2397.fb2020062), The same shot gathers are shown again in Figure 4 with refraction statics and radon filtering of slow surface energy. Much noise remains on the shot gathers with scattering after the radon filtering. Processing We analyse the results of processing using a conventional land

seismic processing flow in Figure 5. The processing steps are: 1. First break picking 2. Refraction statics (2-layer solution) 3. Surface consistent amplitude balancing 4. Radon filtering of slow surface energy 5. NMO 6. Residual statics 7. Surface consistent deconvolution 8. Random pre-stack noise attenuation (statistical method) 9. Median stack FIRST

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10. Post-stack random noise attenuation (statistical method) 11. Spectral balancing The acquisition for the stacks consists of 401 shots with spacing of 20 m and spilt-spread receivers with spacing of 5 m and maximum offset of 2000 m. The 10 m CMP bins have a fold of 400. There are about 320,000 traces in total. The stack of data with scattering is of poor quality, which is what we often see with strong scattering noise. This is consistent with theory that shows how 90% scattering at the source and receiver can reduce signal quality by 100x. (https://doi. org/10.1190/segam2021-3594534.1)

Figure 6 shows the stacks with additional processing of surface scattering corrections using the methods described in the conference paper https://doi.org/10.3997/2214-4609.2023101073. These additional corrections have a large impact on this data since scattering is the dominant effect on this data. In Figure 7 we compare the effect of different acquisition geometries on the stacks without the surface corrections. Figure 8 shows the acquisition geometries. Figure 9 compares the different acquisition geometries on the stacks with the surface corrections. This simulation analysis is useful for focusing on the problem of scattering noise without additional noise complications. It shows that distortion of the reflection signal is a strong

Figure 6 Stacks from improved processing using scattering surface corrections. The surface corrections have significantly improved the stacks of data with scattering.

Figure 7 Stacks using conventional processing from elastic data with scattering using different acquisition geometries. The geometries are shown in Figure 8. More data produces better results. The three middle stacks have the same number of prestack traces and are of similar quality. The differences between the three middle stacks despite having the same number of total traces are interesting and is likely a result of the sensitivity of processing steps 6, 8, & 10 to small changes of the data. Statistical enhancement breaks down when the noise is strong.

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Figure 8 The different acquisition geometries for the stacks in Figure 7. The middle three have the same number of traces.

Figure 9 Stacks using processing with enhanced surface corrections for different acquisition geometries. Results are much improved.

component of the noise and that statics and SC-Decon is not effective in addressing this strong complex distortion. However, there is hope in improving processing with more advanced surface corrections. The use of very detailed 2D simulation is crucial to understanding the scattering of the near surface within reasonable compute capability. But the 2D nature of the simulation is limiting. We desire to repeat this work in 3D, but the very slow velocities and need for representing the near surface at 1 m scale is a computational challenge.

When there is strong scattering noise, there are often also strong refraction multiples. This simulation only produced moderate refraction multiples and is not effective in testing their issues. Addressing refraction multiples can be the topic of a future modelling study. Acknowledgements I appreciate the FD modelling code developed by, and made available by, Jan Thorbecke, with contributions from Max Holicki. This code is available on github.

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Using advanced fibre-optic point sensors at high temperatures to expand downhole deployment use cases Brett Bunn1* and Paul E. Murray 2 present a new fibre-optic sensing system, which consists of a highly configurable suite of 3-component optical point receiver accelerometers for true vector wavefield recording at very high temperatures and pressures. Introduction Downhole tools provide essential data required to better understand subsurface conditions. Unlike other geophysical survey methods which must infer depth from some inverse method, downhole tools provide direct depth-dependent measurements that are critical as both primary investigation methods and complementary ‘ground truth’ measurements to calibrate the larger geophysical reconnaissance surveys that are part of the exploration and development life cycle. This improved knowledge reduces risk and allows operators to make field development decisions with lower costs, fewer dry holes, and better hazard mitigation. The ultimate representation of this kind of geophysical risk management is the reservoir monitoring system—installing sensors and data telemetry equipment on a permanent (or semi-permanent) basis to provide highly repeatable, time-dependent measurements which can be correlated with the production and drilling data to provide real-time subsurface monitoring and surveillance. Just as with reconnaissance surveys, the role for downhole measurements is equally important for long-term monitoring, and building a tool that can survive for months or years in the downhole environment remains a well-understood challenge for equipment manufacturers. In some downhole environments, ‘traditional’ electromechanical sensors such as geophones and hydrophones perform adequately over long periods of time. Many companies (including Geospace Technologies) market downhole tools with arrays of these sensors to that end. For other applications, the downhole environment quickly turns hostile for sensors that work reliably in relatively benign environments. Operators are increasingly drilling deeper where temperatures and pressures increase to the point that no traditional sensor can survive long enough to provide more than a single set of reliable measurements. It is also not simply a matter of the sensors themselves surviving the duration; the sensitive electronic components in the downhole data acquisition and telemetry systems required to bring those measurements to the surface cannot withstand the pressure, temperature, and chemical hazards any better.

Geospace Technologies Corp. | 2 FIP Geophysical Services

Corresponding author, E-mail: bbunn@geospace.com

As we look towards the future of cleaner energy production on this planet, geophysical methods are now being tasked to manage risk in new markets beyond oil and gas exploration, and the hostile environments for our geophysical sensors are simply multiplying. When one considers the requirements of performing continuous, reliable subsurface monitoring for a geothermal energy production facility or a carbon capture, utilization, and storage (CCUS) reservoir, we see the problem. The hostility of the environments the market demands our sensors must work within will only increase going forward. Operators that have attempted to use traditional downhole tools in these harsher environments now have given us a compendium on their usable lifetime in extremis (refs. 3-8). An early alternative with an equally large body of documentation is the use of fibre-optic distributed acoustic sensing (DAS) technology (Hill, 2017). The results of DAS experiments are decidedly mixed at best; while the fibre itself can survive in scenarios where electromechanical systems fail, the data suffer from inadequate coupling, low resolution, poor signal-to-noise ratio, and lack of directionality (i.e., the vector nature of the wavefield is lost). While proponents of DAS technology assert that it is a simple matter to convert the measurement of optical phase in these systems to strain (and therefore to particle motion and wave propagation), there are several assumptions about both the nature of a distributed sensor and the methods by which these systems attempt to interrogate specific sections of fibre that complicate the issue. Electromechanical sensors that are small relative to the wavelength of interest can easily be treated as point receivers, and the methods for calibrating the output of a point receiver to an exciting seismic (or acoustic) wavefield are well known to those skilled in the art. For distributed sensors, this is decidedly more complicated, and for some embodiments of DAS-type systems, impossible to truly calibrate sensors for the rapidly varying conditions as may occur in a dynamic borehole environment. This is a serious complication because the standard for high-fidelity 4D petrophysical characterisation for a reservoir has been set using high figure of merit multi-component point receiv-

DOI: 10.3997/1365-2397.fb2024009

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Figure 1 A diagram of the optical interferometer of the type used in the Insight downhole system.

ers with high vector fidelity. To see the subtle changes in seismic wavefields that arise from changes in the subsurface conditions, we need the calibrated output and accuracy of traditional sensors with the additional requirement that the sensors can survive in all deployment environments for decades. We seek to address these challenging complications with fibre-optic point receivers. To accomplish this, Geospace Technologies developed the Insight™ by OptoSeis® downhole fibre optic sensing system, which consists of a highly configurable suite of 3-component optical point receiver accelerometers for true vector wavefield recording at temperatures and pressures beyond the capability of any electromechanical system. We have recently completed a field demonstration of this system and provide a brief introduction to the technology and our field test results which demonstrate fitness for the proposed applications. fibre-optic point sensors past and present The fibre optic accelerometer as point receiver is a mature technology that has been used for decades but has only been used in exploration seismology since the early 2010s. Notably, OptoSeis developed the world’s first deep-water reservoir monitoring system for the Jubarte field in 2012 (Thedy, 2013, Seth, 2013) using these types of sensors. Those optical accelerometers, like those in the

Insight systems, are a variant of the Michelson interferometer first used in the Michelson-Morley experiments of 1887. As particle motion causes each leg of the interferometer to change length with opposite polarity, a laser interrogator directly and continuously extracts optical interference phase of the interferometer, within the demodulator and delivers real time particle motion to the data acquisition system (Figure 1). Optical interference phase is filtered to the desired bandwidth and scaled to acceleration units with ultra-high dynamic range and a high degree of linearity, meaning the resulting measurements are repeatable even as the environment around the accelerometer (temperature, pressure, etc.) changes. The data acquisition itself is time-continuous, i.e., the optical data recorded from each sensor are from individual signals which are then digitised. The same types of sensors were also deployed in high density, high channel-count 3D land systems (with 1C sensors) by OptoSeis. It is this combined experience with multi-component subsea sensors and land systems that created the enabling technologies for this downhole system. The Insight system is an all-optical monitoring solution with no electronic components in either the downhole components or telemetry cabling. The laser interrogator/data acquisition system can be anywhere from adjacent to the borehole to tens of kilometres away in a remote location depending on the use case. The sensors themselves are discrete 3-component fibre-optic accelerometers designed for slimhole tools to accommodate any sized wellbore and borehole deviations. The number of sensor stations and spacings are highly configurable, allowing users to simultaneously acquire hundreds of multi-level, real-time continuous 3-component measurements of the vector wavefield. The downhole components of the Insight system are rated to operate for years at temperatures up to 150ºC with a maximum pressure rating of 20,000 psi. Since there are no electronic components throughout the telemetry, this system has the added advantage of being immune to electromagnetic interference (EMI) as either an EMI source or receiver.

Figure 2 Hodograms of the X-Y plane projection of the direct arrival waveforms from the circle of sources onto a single 3-C sensor station. The data have been rotated from the Galperin configuration to an orthogonal basis for display and interpretation.

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are creating opportunities to apply these technologies to new problems with similar limitations. CO2 injection wells utilise high pressures and temperatures; the hostile environments of both natural and purpose-built closed-loop geothermal systems are self-evident. The primary design challenge for tools to work in these applications will be their ability to survive at duration in those environments. Now, fibre-optic solutions represent the state of the art. It will also be pointed out there is a significant cost difference between DAS and discrete sensor fibre-optic systems (or between DAS and traditional multicomponent VSP tools). If the resulting data are too noisy, do not measure the directional nature of the wavefield, or cannot discriminate seismicity from other environmental changes, the authors suggest these represent real opportunity costs which must be factored into any evaluation of a geophysical tool that is being proposed to mitigate their E&P risks. Field test results of the fibre-optic 3C downhole tool In the Spring of 2023, Geospace performed a field test of the Insight tool at the Devine Test Site in near Devine, Texas, operated by the Bureau of Economic Geology, University of Texas at Austin. In this test, we deployed a five-level, 3-component downhole testing tool with magnetic collar clamps on each receiver station down a 1,417-metre steel-cased well. During this field test, we acquired two suites of data to examine different aspects of the sensors’ performance in a real-world setting. One suite of data was acquired using a circle of near-offset source points arranged in 22.5-degree increments around the wellbore. The second suite of data was acquired as a walkaway VSP with shot points at regular spacings along a radial line in a constant azimuth from the wellbore. We acquired both using an accelerated weight drop source. The purpose of the circular arrangement was to analyse the vector fidelity of the sensors. In Figure 2, we see a plot of the hodograms of the direct arrival waveform projected onto the horizontal plane after rotating the data from their Galperin in situ configuration to an orthogonal arrangement. Using the

Figure 3 Semblance analysis revealing the underlying radiation patterns of the rotated sensors. From the dipole radiation patterns we can see the sensors within this station are behaving as independent sensors that are mechanically coupled to the environment and not interfering with each other.

With this combination of data acquisition features and survivability characteristics, we believe this tool is suitable for use in active source VSP surveys, 4D time lapse monitoring of P- and S-wave behaviour related to changes in subsurface stress conditions, microseismic (passive) recording of induced seismicity, check shot surveys, and cross-well tomography in a variety of conditions and depths previously unavailable to geophysicists. New markets and relative cost It bears repeating that while the use cases for downhole seismic measurements in oil and gas development are well known to the working geophysicist, the emerging new energy markets

Figure 4 Unrotated data from a mid-distance common source point into the receivers shown in A), and the data rotated to the fast (N68W) and slow directions corresponding to the regional anisotropy in B).

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methods of Murray et al. (2016), we rotated the data through the entire circle and computed the semblance at 1-degree increments to recover the actual radiation patterns of the sensors (Figure 3). We interpret these results to show that the individual sensors in each 3C station are well coupled to the environment and are neither mechanically nor optically coupled to each other. The orthogonality of the resulting radiation patterns with deep nulls shows the individual sensors behave as independent dipole sensors. Examining the data from one of the common offsets of the walkaway VSP (Figure 4), we observe down-going P- and S-waves emanating from the vertical point source. Rotating the data to the known maximum and minimum local stress directions, we can see the S-waves organise into fast and slow components as predicted by the local anisotropy conditions. Localised changes in subsurface fluid pressure conditions can be inferred from these measurable changes in anisotropy. While such vector wavefield measurements are considered de rigueur for electromechanical multi-component sensors, this type of directional wavefield analysis is beyond the capability of current DAS offerings. The ability to measure S-wave polarisation changes will be a key factor in any system used to monitor subsurface fluid movement and changes in stress in either storage or recovery.

providing the kind of vector wavefield data required to solve the difficult monitoring problems that will dominate the geophysical market for the coming decades in both traditional oil and gas exploration and the emerging markets.

Conclusions The future of borehole seismic data is one that is not suited to the last generation of electromechanical sensors. The demand for better seismic data in more hostile environments will only increase with drilling depth, and the emerging markets of CO2 sequestration monitoring and geothermal energy will only increase that demand to operate where traditional sensors cannot work. DAS systems may function better in these environments, but they cannot provide vector wavefield information that is critical for VSP surveys, microseismic monitoring and 4D analysis of subsurface stress conditions. Discrete 3-component optical point receiver systems such as the Insight tool offer the best solution to

Meehan, N. [2012]. Reservoir Monitoring Handbook, Elsevier Science &

References Craig, B. [2008]. Deep oil and gas well construction. Adv. Mater. Processes. 2008, 166, 33–35. David Hill Illuminating insights into well and reservoir optimisation using fibre-optic Distributed Acoustic Sensing SPE 2017 DeBruijn, G., Skeates, C., Greenaway, R., Harrison, D., Parris, M., James, S., Mueller, F., Ray, S., Riding, M. Temple, L. and et al. [2008]. High-pressure, high-temperature technologies. Oilfield Rev. 2008, 20, 46–60. Gysling, D. and Bostick, F. [2002]. Changing paradigms in oil and gas reservoir monitoring—The introduction and commercialization of in-well optical sensing systems. Proceedings of the 2002 15th Optical Fiber Sensors Conference’, Portland, OR, USA, 6–10 May 2002. Hoffmann, L., Muller, M.S., Kramer, S., Giebel, M., Schwotzer, G. and Wieduwilt, T. [2007]. Applications of fibre optic temperature measurement. Proc. Est. Acad. Sci. Eng. 2007, 13, 363–378. Makhlouf, A.S.H. and Aliofkhazraei, M. [2015]. Handbook of Materials Failure Analysis with Case Studies from the Oil and Gas Industries. Butterworth-Heinemann: Oxford, UK, 2015. Technology Books: Contoocook, NH, USA, 2012. Seth, S., Maas, S., Bunn, B., Metzbower, R., Wersich, E., Johann, P., Thedy, E. and Lisboa, W. [2013]. Full Solution Deep-water PRM Project in the Jubarte Field in Brazil for Petrobras by PGS. Second EAGE Workshop on Permanent Reservoir Monitoring 2013 – Current and Future Trends, Jul 2013, cp-351-00007. Thedy, E.A., Ramos Filho, W.L., Johann, P.R.S., Seth, S.N., Souza, S.C. and Murray, P.E. [2013]. Jubarte Permanent Reservoir Monitoring - Installation and First Results. 13th International Congress of the Brazilian Geophysical Society held in Rio de Janeiro, Brazil, August 26-29, 2013.

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Digital sensors – The next steps C. Jason Criss1* demonstrates how the merging of the MEMS sensor with standard land seismic nodes combines the benefits of both technologies to form a unified solution for seismic acquisition. Abstract The all-digital MEMS (Micro-electromechanical system) based sensor designed for seismic acquisition was first introduced in the 1990s. Early implementations of the sensor showed great promise in ocean bottom cables where properties such as low-frequency sensitivity and tilt insensitivity were particularly advantageous. Further implementation of the technology on land yielded three-component sensors (P and S wave) and finally single-component sensors (P wave) that are currently utilised on land production projects in several regions of the world. The seismic MEMS-based sensor has matured into a time-tested, highly refined tool for seismic exploration. The next evolution is merging of the MEMS sensor with the standard land seismic nodes. Until recently, all seismic nodes have been implemented and deployed with analog sensors. However, nodes are currently getting deployed with MEMS-based sensors combining the benefits of both technologies to form a unified solution for seismic acquisition. Fifth generation digital MEMS sensor The MEMS sensor is etched from silicon wafers forming a tiny mass suspended with silicon springs that is approximately 1cm2. Tolerances on the manufacture of the primary sensor component are so tight that Brownian motion of air particles becomes a concern requiring the manufacture to be completed in a vacuum. Once the chip with the suspended mass is formed the MEMS

Figure 1 MEMS chip after fabrication from a wafer.

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Corresponding author, E-mail: jason.criss@inovageo.com

sensor unit is completed with a tiny ASIC (Application specific integrated circuit) that controls the function of the MEMS chip. In operation, the suspended mass is held stationary by the ASIC and the ratio of the hold charge is fed to the sigma-delta A-to-D converted at a fantastic rate of more than 150,000 updates per second. The result is an all-digital MEMS sensor that delivers acceleration data from 0-400Hz with a nearly flat amplitude and phase response and a dynamic range of 118dB at all frequencies. The sensor is tilt insensitive, temperature tolerant, and due to a continual self-calibration function, it does not age or become worn with usage. These fundamental properties set the digital MEMS sensor apart from the traditional analog sensors. The sensor has progressed through several generations. The 5th generation sensor has a lower noise floor and minimal power consumption making it ideal for all seismic experiments. Self-calibration, which is an automated process that the MEMS sensor executes during power-up, re-establishes the precise function of the unit. This yields a sensor that responds to motion with a uniform result for every deployed sensor. This reduces sensor-to-sensor variation minimising data jitter observed with analog sensors resulting in the purest seismic response possible and eliminates sensor ageing which means the sensor responds with identical fidelity for each deployment. Integration – Digital node Along with the MEMS technology, the node technology has advanced along similar lines. Several generations of nodes have resulted in the single channel nodes that can be implemented with any analog sensor type with the correct form factor. As an example, INOVA’s Quantum node technology is a single channel, all in one recording system that stores data continuously, has precision timing and self-locates, making pre-survey of projects increasingly obsolete. The form factor of the node optimises deployment and recovery due to its compact size and shape. The node can be planted by field personnel the same way a traditional geophone is planted which assures the best possible coupling and alignment with the vertical orientation. In the case of Quantum, the node requires no additional electronics for deployment, once the node is placed vertically in the ground the node becomes active and begins recording seismic data. The node automatically performs self-check routines at predetermined intervals and can report status at the discretion of the operating crew.

DOI: 10.3997/1365-2397.fb2024010

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ious methods including handheld, vehicle-mounted and airborne devices. Since LPWAN enables long-range communications, large areas of deployed nodes can be managed with less field effort. In some areas drones have proven to be highly effective and further reduce the exposure of field personnel. Monitoring large areas of MEMS-enabled digital nodes enhances the command-and-control of the operational aspect of seismic projects, further benefiting the contractors and clients. Combining the state-of-the-art Quantum node with the 5th generation MEMS sensor technology is yielding a next generation node product which will change the strategies currently used for seismic acquisition.

Figure 2 INOVA Quantum with Accuseis.

The node technology is no longer a blind acquisition technology. The Quantum node utilises low power long range radio technology (LORA), which can transmit status data to a central location continuously while recording at ranges of 5 kilometres depending on the terrain and vegetation. Previous versions of nodes were limited to mesh technologies or limited range communication technologies such as Bluetooth. The unique capability built into the Quantum node to monitor quality utilises a Low Power Wide Area Network (LPWAN) technology allowing tens of thousands of seismic nodes to broadcast status updates continuously with minimal additional power consumption. The status updates can be captured, recorded, and displayed with var-

Benefits – All digital node The benefits of the MEMS-based Quantum node are profound. The node technology has matured to the point that most regions of the world are node-based operations. Crews in an open desert environment where exceptionally large projects are executed have realised cost benefits with nodes greater than a 13% reduction in the overall cost of operations, and up to 70% reduction in field resources such as personnel and vehicle requirements. This is because nodes are smaller, lighter, and easier to deploy. They require fewer personnel on the ground, as well as smaller and fewer vehicles. Nodes eliminate cable handling issues and eliminate the need for managing quantities of large batteries that further reduces QHSE concerns and operational complications. The simplicity of node operations has motivated operators to begin using innovative geometry deployments that create operations that are source restricted rather than equipment restricted meaning that the project can be completed as fast as shooting can be accomplished. The latest generations of the MEMS sensor use minimal power and can be deployed in a node recording

Figure 3 shows a data comparison between single component 5 Hz high sensitivity geophone (left) and MEMS (right).

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continuously for 50 days or more using duty cycles. Due to the combination of the tilt insensitivity of the MEMS sensor and deployment optimisation features built into the Quantum node, the vertical alignment of the node and sensor is improved, further enhancing the uniformity of large deployments and the response to seismic data. Combining the benefits of the MEMS-based sensor with the successful node technology further enhances the benefits of the nodal operations. MEMS-based sensors have no spurious frequencies that are usual with analog sensors, and no amplitude distortions across the useful seismic bandwidth. The MEMS sensor is a true broadband sensor in every respect. These properties simplify the initial data processing steps by eliminating the need for geophone response corrections that are required with analog sensor data. The resultant seismic data derived from MEMS-based sensors has acceleration units as its native format. No special processing of acceleration data is required unless the end user requires the data to be converted to a different domain for data matching purposes. The seismic data shown in Figure 3 illustrates the subtle advantages derived from MEMS sensors. Both sensor types were recorded simultaneously with a single source type. On the left side of the picture is the result from a single component high sensitivity geophone and on the right side of the illustration is the result from a MEMS-based sensor. The processing steps for each section were identical with the exception of a 90-degree phase shift of the MEMS data so that the phase would match the analog result. It can be noted that the MEMS-based sensor produced slightly better amplitudes and frequency response when compared with the result of the analog geophone. The data benefits of the true broadband sensor are realised in processed data. Unprocessed MEMS data will commonly appear to have more noise than unprocessed analog data. This is partly because the MEMS-based sensor does not discriminate any frequency response, particularly with the lowest frequencies. While analog sensors have a 12dB/octave amplitude response reduction below

the resonant frequency, the MEMS sensor does not, and will record the lowest frequencies, below 5Hz with full fidelity. Historically, nodes and MEMS sensors have been compared with analog sensors deployed in arrays. An array response creates a spatial filter that effectively limits higher frequencies greater than 100Hz regardless of noise or signal. With current trends in most projects implementing receiver group spacings as short as 25 m or less, any benefits realised by an array need to be carefully weighed against the benefits of high-fidelity broadband recording that does not limit the frequency response and that further results in the dramatic operational advantages inherent in node operations combined with the MEMS technology. Conclusions Merging the latest seismic node with the 5th-generation MEMS sensor delivers a node which is the result of two mature technologies that benefit from both in a product with proven operational and economic benefits. The MEMS sensor further enhances the all-digital node with true broadband recording which overcomes the drawbacks of traditional analog sensors. References Criss, C.J.[2022]. Digital MEMS and Seismic Nodes – Technology Fusion, Asia Petroleum Geoscience Conference and Exhibition (APGCE), Nov 2022, Volume 2022, p 1-5. Criss, C.J.[2017]. Improving Data Quality and Operational Efficiency through Recent Advances in Acquisition Technology, 15th International Congress of the Brazilian Geophysical Society & EXPOGEF, Rio de Janeiro, Brazil, 31 July-3 August 2017. August 2017, 45-47. Criss, C.J. and Selvakumar A. Field experiments with digital sensors. Jason Criss, The Leading Edge 2016 35:7, 586-588, A look at the field response of MEMS sensors compared to analog geophones, The Leading Edge 2023 42:5, 321-323. Tessman, J., Reichert,B.

Marsh, J., Gannon, J. and Goldberg,H.

[2001]. MEMS for geophysicists, SEG Technical Program Expanded Abstracts 2001. January 2001, 21-24.

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www.eagegeotech.org

23-25 Apr May 2024

EAGE Events

FIRST

BREAK

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VOLUME

JANUARY

2024

CALENDAR

June 2024 10-13 Jun

85 th EAGE Annual Conference and Exhibition www.eageannual.org

Oslo

Norway

August 2024 12-13 Aug

3 rd EAGE Conference on Carbon Capture and Storage www.eage.org

Perth

Australia

14-15 Aug

4th EAGE Workshop on Fiber Optic Sensing for Energy Applications www.eage.org

Perth

Australia

18-23 Aug

Goldschmidt 2024 conf.goldschmidt.info/goldschmidt/2024/meetingapp.cgi

Chicago

United States

September 2024 2-4 Sep

Fourth EAGE Marine Acquisition Workshop www.eage.org

Oslo

Norway

2-5 Sep

ECMOR 2024 European Conference on the Mathematics of Geological Reservoirs www.ecmor.org

Oslo

Norway

8-12 Sep

Near Surface Geoscience Conference and Exhibition 2024 www.eagensg.org

Helsinki

Finland

12-13 Sep

First EAGE Workshop on The Role of AI in FWI www.eage.org

Cartagena

Colombia

16-18 Sep

Eighth EAGE High Performance Computing Workshop www.eage.org

Jeddah

Saudi Arabia

17-19 Sep

Fourth EAGE Conference on Pre-Salt Reservoir www.eage.org

Rio de Janeiro

Brazil

23-24 Sep

Asia Petroleum Geoscience Conference and Exhibition (APGCE) icep.com.my/apgce

Kuala Lumpur

Malaysia

October 2024 3-4 Oct

Third EAGE Workshop on EOR www.eage.org

Buenos Aires

Argentina

6-8 Oct

EAGE Workshop on Naturally Fractured Rocks (NFR) www.eage.org

Muscat

Oman

14-16 Oct

Third EAGE Conference on Seismic Inversion www.seismicinversion.org

Naples

Italy

15-16 Oct

EAGE Conference on Unleashing Energy Excellence: Digital Twins and Predictive Analytics www.eage.org

Kuala Lumpur

Malaysia

21-24 Oct

GEO 4.0: Digitalization in Geoscience Symposium www.eage.org

Al Khobar

Saudi Arabia

24-25 Oct

Third EAGE Workshop on Advanced Seismic Solutions in the Gulf of Mexico www.eage.org

Mexico City

Mexico

29-30 Oct

EAGE Workshop on Borehole Geophysics for CCUS and Energy Transition www.eage.org

Hangzhou

China

29-31 Oct

Fourth SPE/EAGE Geosteering and Well Placement Workshop www.eage.org

Al Khobar

Saudi Arabia

November 2024 4-6 Nov

First EAGE Workshop on Tectonostratigraphy of the Arabian Plate www.eage.org

Al Khobar

Saudi Arabia

4-7 Nov

Fifth EAGE Global Energy Transition Conference and Exhibition www.eageget.org

Rotterdam

The Netherlands

5-7 Nov

First EAGE Conference on Energy Opportunities in the Caribbean www.eage.org

Port of Spain

Trinidad & Tobago

25-27 Nov

Ninth EAGE Arabian Plate Geology Workshop www.eage.org

Kuwait City

Kuwait

EAGE Events

Non-EAGE Events

FIRST

BREAK

VOLUME

JANUARY

2024

Fourth EAGE Marine Acquisition Workshop 2 - 4 S E P T E M B E R 2 0 2 4 • O S LO, N O R WAY

TOPICS • Seismic Source Technology • Seismic Acquisition and Modelling • Other Geophysical Applications • New Energy Applications

W W W. E AG E .O R G

Deadline: 31 March 2024

Submit your abstracts! MAW24 V2H.indd 1

27/11/2023 08:21

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30th

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4th

European Meeting of Environmental and Engineering Geophysics

Conference on Geophysics for Mineral Exploration and Mining

Conference on Airborne, Drone and Robotic Geophysics

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IS NOW OPEN! LEARN MORE AT EAGENSG.ORG

8-12 SEPTEMBER 2024 I HELSINKI, FINLAND

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