First Break December 2018

VO L U M E 3 6 I I S S U E 12 I D E C E M B E R 2 018

SPECIAL TOPIC

Data Processing & Machine Learning REGIONAL FOCUS The Netherlands INDUSTRY NEWS CGG goes ‘asset light’

IN EVERY IMAGE

Least-Squares Q-Migration & Q-FWI Delivering Superior Images PSDM

LSQ-PSDM

These CGG Multi-Cilent & New Ventures images, over the Peon gas field in the Northern Viking Graben, demonstrate the superior imaging provided by Q-FWI and Least-Squares Q-Migration.

CGG least-squares Q-migration delivers improved imaging by addressing both absorption and illumination effects while mitigating migration artifacts. This leads to more balanced amplitudes, reduced noise and better signal-to-noise ratio across a wider bandwidth.

Q full-waveform inversion (FWI) creates a Q model which defines the location and extent of absorption anomalies, alongside velocities and anisotropic parameters derived from refraction and reflection FWI.

The combination of least-squares and Q methods increases both resolution and fidelity.

For more details, please see the CGG paper by Latter et al. presented at SEG 2018.

Exceptional People - Remarkable Technology - Outstanding Service

cgg.com/LSM

FIRST BREAK® An EAGE Publication

CHAIRMAN EDITORIAL BOARD Peter Rowbotham (Peter.Rowbotham@apachecorp.com) EDITOR Damian Arnold (editorfb@eage.org) MEMBERS, EDITORIAL BOARD • Paul Binns, consultant (pebinns@btinternet.com) • Patrick Corbett, Heriot-Watt University (patrick_corbett@pet.hw.ac.uk) • Tom Davis, Colorado School of Mines (tdavis@mines.edu) • Anthony Day, PGS (anthony.day@pgs.com) • Peter Dromgoole, Statoil UK (pdrum@statoil.com) • Rutger Gras, Oranje-Nassau Energy (gras@onebv.com) • Hamidreza Hamdi, University of Calgary (hhamdi@ucalgary.ca) • Ed Kragh, Schlumberger Cambridge Research (edkragh@slb.com) • John Reynolds, Reynolds International (jmr@reynolds-international.co.uk) • James Rickett, Schlumberger (jrickett@slb.com) • Dave Stewart, Dave Stewart Geoconsulting Ltd (djstewart.dave@gmail.com) • Femke Vossepoel, Delft University of Technology (f.c.vossepoel@tudelft.nl)

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Is Machine Learning taking productivity in petroleum geoscience on a Moore’s Law trajectory?

Editorial Contents 3

EAGE News

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Crosstalk

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Industry News

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Regional Focus: the Netherlands

MEDIA PRODUCTION MANAGER Thomas Beentje (tbe@eage.org)

Technical Articles

ACCOUNT MANAGER ADVERTISING Charles Callaghan (ccn@eage.org)

65 AVO inversion on unconventional reservoirs: systematic estimation of uncertainty in the Vaca Muerta shale Gabriel Ernesto Quiroga, Ariel Pablo Kautyian Ziyisyian and Federico Späth

ACCOUNT MANAGER SUBSCRIPTIONS Jack McClean (jmn@eage.org) PRODUCTION Saskia Nota (layout@eage.org) Ivana Geurts (layout@eage.org) EAGE EUROPE OFFICE PO Box 59 3990 DB Houten The Netherlands • +31 88 995 5055 • eage@eage.org • www.eage.org EAGE RUSSIA & CIS OFFICE EAGE Russia & CIS Office EAGE Geomodel LLC Novocheremushkinskaya Str. 65 Build. 1 117418, Moscow, Russia • +7 495 640 2008 • moscow@eage.org • www.eage.ru 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 LATIN AMERICA OFFICE Carrera 14 No 97-63 Piso 5 Bogotá, Colombia • +57 1 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)

75 Seismic wavefield divergence at the free surface Pascal Edme, Everhard Muyzert, Nicolas Goujon, Nihed El Allouche and Ed Kragh

Special Topic: Data Processing & Machine Learning

85 The melding of artificial and human intelligence in digital subsurface workflows: a historical perspective

Matt Breeland 91 Analysis of gas production data via an intelligent model: application to natural gas production

Mohammad Ali Ahmadi and Zhangxin Chen 99 Combined pre-stack and post-stack interpretation for velocity model building and hydrocarbon prospectivity: a learning case study from 3D seismic data offshore Gabon Paolo Esestime, Milos Cvetkovic, Jonathan Rogers, Howard Nicholls and Karyna Rodriguez 105 Increasing resolution in the North Sea Phil Hayes, Luke Twigger, Krzysztof Ubik, Thomas Latter, Chris Purcell, Bingmu Xiao and Andrew Ratcliffe 113 Mode conversion noise attenuation, modelling and removal: case studies from Cyprus and Egypt Jyoti Kumar, Marcus Bell, Mamdouh Salem, Tony Martin and Stuart Fairhead 121 Nonlinear beamforming for enhancing prestack seismic data with a challenging near surface or overburden Andrey Bakulin, Ilya Silvestrov, Maxim Dmitriev, Dmitry Neklyudov, Maxim Protasov, Kirill Gadylshin, Vladimir Tcheverda and Victor Dolgov 127 Is it worth the effort? — why state-of-the art reprocessing of old seismic data was an indispensable tool for a reservoir simulation study in the Murzuq Basin (Libya) Christian Stotter, Alexey Burlakov, Dmitry Ablikov, Robert Rieger and Adel Zeglam 135 Is Machine Learning taking productivity in petroleum geoscience on a Moore’s Law trajectory?

Eirik Larsen, S.J. Purves, D. Economou and B. Alaei 142 Calendar

cover: Geoscientists are harnessing developments in computer technology to development machine learning capabilities, see Industry News on p. 18 and our Special Topic on p. 84 (photo courtesy of DUG).

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European Association of Geoscientists & Engineers

Board 2018-2019 Jean-Jacques Biteau President

Near Surface Geoscience Division George Apostolopoulos Chair Alireza Malehmir Vice-Chair Micki Allen Contact Officer EEGS-NA Riyadh Al-Saad O&G Liaison Xavier Garcia Committee Member Peter Bergmann Technical Programme Representative Esther Bloem Technical Programme Representative Albert Casas Membership Officer Ranajit Ghose Editor in Chief Near Surface Geophysics Musa Manzi Committee Member Andreas Kathage Liaison Officer First Break Koya Suto Liaison Asia Pacific Musa Manzi Committee Member Jiangha Xia Liaison China

Oil & Gas Geoscience Division

Peter Lloyd Vice-President-Elect

Michael Pöppelreiter Vi c e-President

Colin MacBeth Education Officer

Caroline Jane Lowrey Chair Michael Peter Suess Vice-Chair Øistein Bøe Resource Evaluation Committee liaison Phil Christie Chief Editor Petroleum Geoscience Rick Donselaar Technical Programme Representative (Geology) Xavier Garcia NSGD liaison Sebastian Geiger Resource Evaluation Committee liaison Olivier Gosselin Technical Programme Representative (Reservoir), Resource Evaluation Committee liaison Juliane Heiland Committee member David Halliday Technical Programme Representative (Geophysics), YP liaison Tijmen Jan Moser Editor-in-Chief Geophysical Prospecting Ann Muggeridge IOR Committee liaison Walter Rietveld Technical Programme Officer Michael Welch Technical Programme Representative (Geology), NSGD liaison Martin Widmaier Technical Programme Representative (Geophysics) Paul Worthington Resource Evaluation Committee liaison Michael Zhdanov NSGD liaison Conor Ryan Resource evaluation committee Francesco Perrone Young professionals liason

SUBSCRIPTIONS First Break is published monthly. It is free to EAGE members. The membership fee of EAGE is € 50.00 a year (including First Break, EarthDoc (EAGE’s geoscience database), Learning Geoscience (EAGE’s Education website) and online access to a scientific journal.

Caroline Le Turdu Membership and Cooperation Officer

Ingrid Magnus Publications Officer

Everhard Muijzert Secretary-Treasurer

Companies can subscribe to First Break via an institutional subscription.

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Orders for current subscriptions and back issues should be sent to EAGE Publications BV, Journal Subscriptions, PO Box 59, 3990 DB, Houten, The Netherlands. Tel: +31 (0)88 9955055, E-mail: subscriptions@eage.org, www.firstbreak.org.

First Break is published by EAGE Publications BV, The Netherlands.

However, responsibility for the opinions given and the statements made rests with the authors.

COPYRIGHT & PHOTOCOPYING © 2018 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.

Aart-Jan van Wijngaarden Technical Programme Officer

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Caroline Jane Lowrey Chair Oil & Gas Geoscience Division

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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).

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HIGHLIGHTS

EAGE MEMBERS

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A 20th anniversary to remember in Gelendzhik

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Engineering and mining geophysics event makes 15th appearance in Gelendzhik

Time to renew your membership for 2019 We encourage you, all our members, to renew your EAGE membership for 2019 as soon as possible. It’s the best way to make sure you keep receiving all the benefits. To make it easy, you can renew your membership online any time from now on. To help you make your renewal decision, here are some reasons why being an EAGE member provides great value!

Strengthen your knowledge EAGE membership gives you access to EarthDoc, an online EAGE database with over 65,000 titles of event indexed papers and journal articles, with hundreds of new titles added each year.

Strengthen your research papers EarthDoc, combined with the complimentary online access to one of our journals, provides you with a range of tools helpful to support your research papers and conference abstracts, thus improving your work profile and quality of research output.

Stay on top of the latest professional developments Our programme of international workshops and conferences presents some of the latest research conducted on a large variety of topics relevant to members. In addition, a monthly copy of our flagship magazine First Break will help you stay on top of the latest industry developments.

Network and engage with the international geoscience community With approximately 19,000 members, from over 100 countries, you will have the opportunity to meet and engage with people from all backgrounds and experiences. Networking and knowledge sharing not only happens at our events, but online through our Special Interest Communities and online learning platform, Learning Geoscience.

Excellent value for money A membership with EAGE offers great value! We are proud to be able to keep our membership fees as low as possible whilst providing a wide range of membership benefits. Simply accessing three papers via EarthDoc, or registering for one EAGE event as a member, and your membership fee has already paid for itself. We also offer support programmes for those facing financial hardship or unemployment, visit eage.org to learn more.

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EAGE NEWS

Coming soon: Membership Recognition Programme Without our strong and active membership base, EAGE cannot fulfil its mission to promote the development, innovation and technical progress of the geoscience and related engineering fields. To recognize the commitment and contributions of our members, we are launching the Membership Recognition Programme.

This will benefit members based on the number of years they have been an

EAGE member. More information on this coming soon!

Renewing made easy Convinced? Renewing your membership can be done in a couple of minutes. If you were a member in 2018, you would have been sent an email with instructions on how to renew your membership, but you can also log in directly to MyEAGE and follow the prompts to renew your membership for 2019. Make sure you review

your personal details at this time, and update your subscription preferences to ensure you are kept well-informed about all important news, events and education opportunities that EAGE has to offer.

If you have any questions regarding your renewal or if you would like to speak with somebody from the EAGE membership team, do not hesitate to contact us via our dedicated email address membership@eage.org, or give us a call at +31 88 995 5055.

EAGE to host big data and machine learning event in Kuala Lumpur We are closing in on the first EAGE Workshop on Big Data and Machine Learning for E&P Efficiency taking place in Kuala Lumpur on 25-27 February 2019.

The event is inspired by the challenges for the oil and gas industry as we enter the new era of Big Data. The workshop is intended to provide a platform for all the key players of the industry to present and discuss leading edge big data and machine learning applications, as well as to better understand the future potential and impact that these technologies could have.

Joining the workshop will be topnotch keynote speakers including Shankar Trivedi from NVIDIA, Colin

Murdock from CGG and Fransisco Ortigosa from Repsol with more names to be announced.

A one-day short course will follow the workshop entitled ‘New Applications of Machine Learning to Oil & Gas Exploration and Production’ presented by Dr Bernard Montaron from Norwegian company Framework. The short course will address the impact of articifical intelligence in changing the way the oil and gas industry may operated in the years to come.

Ahead of the workshop we will be staging the first ever EAGE Earth Hack Hackathon. This will be an event to bring together machine learning ethusiasts, students, geoscientists, and industry specialists to exchange ideas and develop solutions to the many complex earth imaging problems that the industry is currently facing. Join us and be part of this exciting programme by registering at https://events.eage.org/en/2019/big-dataand-machine-learning/registration.

SEASONS GREETINGS

AND A HAPPY NEW YEAR! 20990-Seasons greetings 2018/2019 advert 1_3.indd 1 4

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08/11/18 09:06 2018

OUR CLOUD HAS A GEOPHYSICAL LINING.

Reach for the sky with DUG McCloud.

DUG is building a unique cloud service tailored specifically to the geophysics community.

The new service, DUG McCloud, will be backed by a huge geophysically-configured supercomputer in a purpose-built exascale compute facility. With DUG McCloud you can reach for the sky and expand your computational capacity whenever you need. In addition, the cloud service will give clients access to DUG’s proprietary software, with the option of source code, to accelerate their research, development, and production. Clients can use DUG’s existing solutions, or modify them, or replace them completely.

Of course, always owning their own IP. Want to find out more? Visit www.dug.com

Want to discover what DUG McCloud can do for your business?

Email McCloud@dug.com for more information.

EAGE NEWS

Inaugural EAGE/IFPEN conference on sulfur challenges in the E&P brings diversity of upstream to downstream topics The first joint EAGE and IFP Energies nouvelles (IFPEN) conference on Sulfur Risk Management in E&P (SRM2018) was held from 18-20 September 2018 at Rueil-Malmaison, a few kilometres from Paris.

This inaugural event was composed of high quality technical presentations, mixed with dynamic scientific discussions and a memorable conference dinner. It attracted around 50 participants from academia and industry covering a large variety of topics related to sulfur, H2S and sulfur-species.

The first SRM2018 conference accommodated 27 oral presentations (including four keynote lectures) divided into four sessions: Novel methods and technologies in sulfur characterization; Challenges and approaches to production of conventional and unconventional reservoirs with H2S; Latest advances in modelling and prediction of H2S; H2S in heavy oil and EOR; and Cases from around the world.

The conference started with a keynote on the biogeochemistry of (organic) sulfur given by Josef P. Werne from the University of Pittsburgh in which he emphasized the importance of sulfur in the global life cycle.

The final day keynote was given by Robert Marriott from the Alberta Sulfur Research Center focusing on aspects of detection of sulfur during oil/gas production, or rather

importance of early detection and preparation for downstream management of this somewhat unwanted byproduct.

These two keynotes nicely framed the depth and diversity of topics, from origin sulfur in the bio- and geosphere, through its diagenetical changes, innovative approaches and technology advances in detection and analysis of sulfur, H2S and sulfur species all the way to downstream processes of treatment during production of H2S. Related to up to date knowledge about numerical approaches developed to predict H2S content in E&P, two other keynote presentations were given by Bart Lomans from Shell highlighting the production side and by Andrew Bishop from PEER Institute for the exploration side. The last day focused on case studies presented by representatives of various oil producers.

To encourage and reward participation of students, the scientific committee awarded a prize of €500 to PhD student Ivan Jovovic from Université de Lyon (France) for the best student presentation. He discussed an innovative method

based on a multi-sulfur isotopic approach to decipher different organic or inorganic bio-geochemical mechanisms taking place during the sedimentation of organic matter.

In order to promote ‘out of the classroom’ discussions and allow for building relationships between participants, the end of the second day was closed by a much appreciated conference dinner. It took place at the La Brasserie du Château restaurant, an old pavillion marking the entrance of the Castle of Napoleon Bonaparte. To conclude, the conference was successful and stimulating thanks to the high quality technical content of the presentations.

Different stakeholders contributed to this success such as the EAGE and IFPEN event coordination teams, Schlumberger as main sponsor and all participants. The smaller group allowed for discussion and exchange of ideas between world academia and industry specialists from both similar and very different scientific fields of expertise. The discussions made it clear that many H2S issues are common and have a similar origin.

EAGE Education Calendar 3 DEC

EAGE EDUCATION TOUR 13

HAMBURG, GERMANY

3 DEC

EAGE EDUCATION TOUR 10

SEOUL, SOUTH KOREA

5 DEC

EAGE EDUCATION TOUR 13

OSLO, NORWAY

5 DEC

EAGE EDUCATION TOUR 10

TOKYO, JAPAN

5-6 DEC

EAGE EDUCATION TOUR 2

VILLAHERMOSA, MEXICO WARSAW, POLAND

7 DEC

EAGE EDUCATION TOUR 13

11 DEC

EAGE EDUCATION TOUR 12

COPENHAGEN, DENMARK

14 DEC

EAGE EDUCATION TOUR 12

DELFT, THE NETHERLANDS

18 DEC

EAGE EDUCATION TOUR 13

MUNICH, GERMANY

20 DEC

EAGE EDUCATION TOUR 13

UPPSALA, SWEDEN

FOR MORE INFORMATION AND REGISTRATION PLEASE VISIT WWW.LEARNINGGEOSCIENCE.ORG.

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EAGE NEWS

Report of the First EAGE Leadership Summit At the EAGE Annual 2018, EAGE hosted its inaugural Leadership Summit, which had leaders in the industry engage in a debate over the future of the E&P business.

Below is an agreed statement on the outcome of this unique meeting.

At the first EAGE Leadership Summit, 12 leaders of the oil and gas exploration and service industries gathered to discuss the attraction and recruitment of top diverse talent in the oil & gas exploration business.

The discussion topic was: “The future has always been uncertain; however, the Paris Agreement has sent a signal around the world.

A new energy system is emerging. It will unfold over decades with increasing public pressure on the exploration for oil and gas to remain relevant. This has clear impacts on our resilience as an industry, particularly in our ability to attract the necessary top talent.

What is it we want to be known for as an industry to ensure our continued success?”

This note summarises key points and action items from the discussion.

In order to continue to attract top talent, and manage reputation, participants agreed that the exploration and its associated service industry should seek to demonstrate how it remains relevant within a new and emerging global energy system, influenced by socio-geopolitical differences.

First, oil and gas producers, and the wider industry, need to improve public

knowledge of hydrocarbon use in various products and sectors, and the reasons why exploration activity will remain necessary for decades to come. It is necessary to become more proactive in delivering a frank, open and honest exploration narrative which explains its positive role in delivering vital and cleaner energy, particularly through the use of more gas in the power-generation sector. Further, it is vital that the oil and gas industry is able to instil a sense of pride amongst those working in it, especially the younger generation of employees, making them ambassadors for the sector and ultimately altogether improving public trust.

Second, it is a reality that the European oil and gas industry faces increasing challenges to attract and retain young professionals, with growing competition for talent from the digital technology sector, perceived to be at the forefront of design and innovation. In reality, digitalisation will be crucial to our industry as we navigate through the energy transition, so companies must adapt and develop. Efficiency improvements can positively affect not just the bottom line but also play an important part in the carbon footprint of greenfield industrial projects. This could mean greater returns for shareholders and reduced environmental impact, thus providing benefits for all. However, this industry evolution must be sensitively handled given the potential impact on its workforce. In isolation, the loss of roles and responsibilities to digital tools and techniques will not help

to attract talent or fill the competence gap which is likely to come in the near future – however this should be balanced by the emergence of new roles and competencies.

Third, company integration and shared value in local communities has become more necessary now, more than ever for maintaining trust, reputation and social licence to operate.

In conclusion, the industry must be ready to provide solutions to back up a newly aspirational and informed rhetoric. It can be envisaged that it will require tailor-made solutions from the industry and individual companies. Oil and gas exploration and service industries must then develop a clear and common external message about the integrated future of energy supply and shine a light on the innovation and opportunities that the industry creates in striving to deliver cleaner and more reliable energy to all.

Tristan Aspray, ExxonMobil Luca Bertelli, Eni Tim Dodson, Equinor Marc Gerrits, Shell Gro Haatvedt, AkerBP Andrew Latham, Wood Mackenzie Howard Leach, BP Kevin McLachlan, Total Maurice Nessim, WesternGeco Francisco Ortigosa, Repsol Rune Olav Pedersen, PGS Sophie Zurquiyah, CGG

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EAGE NEWS

A 20 th anniversary to remember in Gelendzhik

Opening ceremony and general session at 20th Conference.

One of our most popular geoscientific events in Russia — the EAGE Geomodel Conference — took place on 10-14 September 2018, and in the process celebrated its 20th anniversary.

As in previous years, the event summoned its participants to Gelendzhik, a picturesque city on the shore of the Black Sea, known not only for its resorts but also as a scientific and geological centre of Russia. The event was held at the Congress Centre of Yuzhmorgeologiya with general partner Rosgeo and main sponsor Gazpromneft.

The 20 years since the first Geomodel conference have brought a new generation of scientists and engineers who have engaged in the whirlpool of fast-developing technologies and new approaches to geological exploration and oil-and-gas field development. We have seen many new ways to discuss the issues of the day, such as discussion clubs, round tables, educational courses and commercial presentations. Rises and falls in the world and Russian economy have had their impact on the conference programmes, but what has persisted without exception is the passionate discussion on topical subjects and the sizeable number of participants.

The anniversary event brought together 255 participants from 96 organizations, 8

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including oil and service companies, academic and educational institutions, and innovative enterprises. The agenda included scientific and educational sessions and associated events.

To provide interesting and intense scientific discussion, the Programme Committee headed by Igor Kerusov, head of the Seismic Research Centre at Lukoil Engineering, reviewed 169 abstracts. The Committee composed of leading Russian specialists and scientists thoroughly considered every abstract and after a comprehensive discussion selected 149 (119 oral and 30 poster presentations)

to be included in the conference programme.

The plenary session included observational reports devoted to different scientific and industrial issues. The presenters shared their vision on the interaction of business and science during geological exploration and oil field development (Y.V. Fillipovich, Gazpromneft); technology and seismic tools for seismic prospecting in transition zones (A.V. Rudakov, Yuzhmorgeologiya); hydrocarbon prospects of Paleozoic Western Siberia (V.A. Kontorovich, IPGG of SB RAS); and application of neural networks for seismic facies analysis (I.I. Priezzhev, Priezzhev Lab).

Most presentations were given during the sessions devoted to seismic data processing, and kinematic and dynamic interpretation of seismic data. The chairmen noted there was a growing interest in the geological issues of Western and Eastern Siberia which stimulated the most lively discussions involving both the presenters and the audience. Other points of interest were the new sessions devoted to studies of non-anticlinal traps, machine learning, and multi-dimensional data analysis. This did not mean that the traditional sessions devoted to petrophysics, non-conventional reservoirs, hydrocarbon system modelling, basin analysis, and oil-and-gas geochemistry remained unattended. The full list of the scientific

Everybody could congratulate Geomodel on its anniversary.

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EAGE NEWS

Mini-football tournament participants.

sessions and best presentations can be found in the conference report available at eage.ru.

Many participants acknowledged that the organizers had found a very good balance between the papers delivered by experienced and renowned experts and those delivered by young researchers who have just started to pave their way in research.

The conference was also an opportunity for such companies as Priezzhev Lab, Baker Hughes, Rock Flow Dynamics, and Ingeoservice to present their latest developments and software solutions to the participants.

In addition to the intense scientific programme, the participants took part in an excursion around the Gelendzhik region.

The educational programme of the conference included two lectures delivered before the scientific sessions; one on Seismic Facies Analysis: Seismic Images of Geological Processes and Phenomena delivered

by Tatiana Olneva (Gazpromneft Science and Technology Centre); and the other on Oil and Gas Geology and Geophysics 4.0: Trends, Perspectives and Digitalization

Limitations delivered by Valentin Kolesov (Pangea).

To break the ice and strengthen ties among the participants, a mini-football tournament was organized, with not only a lot of participants but also a number of fans who actively supported the competing teams. We wholeheartedly congratulate the winning team of Igor Kerusov, Alexander Kerusov, Arsen Shamurzaev, Alexey Shevchenko and Dmitry Shulykin. The

informal communication continued during the ice-breaker and conference evening which took place in a picturesque restaurant.

Of the conference, one participant echoed the overwhelmingly positive feedback: ‘The conference raises vital and crucial issues and is devoted to the most recent problems of geology and geophysics. For that reason, it brings together bright and unorthodox professionals whose discussions give birth to new ideas and new solutions to difficult problems.

Traditionally Geomodel is famous for its age-diverse audience and this is great. It is important when the priceless experience, knowledge and professionalism of the elder generation can interact with the tech inclination of the young.’ The 21st Geomodel Conference will take place in Gelendzhik on 9-13 September 2019. The Programme Committee headed by Alexey Shevchenko, head of technology and software development, PetroTRace Services, keenly awaits abstracts before 20 May 2019 and hopes to see many participants in person at the event.

The interesting presentations attracted a large audience.

EAGE Student Calendar 4-DEC

SLT EUROPE

LEICESTER, UK

5-DEC

SLT EUROPE

DERBY, UK

6-DEC

SLT EUROPE

MANCHESTER,UK

GEONATURE 2019 STUDENT INTERNATIONAL CONFERENCE

TYUMEN, RUSSIA

25-29 MAR 2019

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

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Engineering and mining geophysics event makes 15th appearance in Gelendzhik The 15th Engineering and Mining Geophysics 2019 Conference and Exhibition in Gelendzhik is due to take place on 22-26 April 2019. This time the event will be held simultaneously with the first Marine Technology 2019 conference in Russia.

Vladimir Shevnin, chairman of the Organizing Committee, says the event is another great opportunity for knowledge sharing and discussion on a variety of scientific and industrial issues. Participants will be able to attend special courses and technical sessions, visit the exhibition, familiarize themselves with the latest software developments and present their own achievements. ‘You can meet colleagues on a shore of the Black Sea under pleasant sunshine,’ Shevnin states, ‘and this will charge you with optimism and good mood and inspire you to further advancements.’

Abstracts of the accepted presentations will be published as a collection in the EAGE EarthDoc and Scopus repositories. Each abstract of 2-10

You can meet colleagues on a shore of the Black Sea under pleasant sunshine!

pages in length is expected to include cross-sections, maps, photos, formulas and algorithm descriptions, so the research can be thoroughtly understood.

Shevnin states that the presence of scientists, practitioners, students, heads of scientific organizations, and software and hardware developers makes it possible not only to test and trial new ideas, but also correct doubtful suggestions and

critique false approaches and imaginary effects. Topics to be discussed during the scientific sessions can be found at eage.ru. The deadline for submitting abstracts is 1 February 2019.

The accompanying exhibition presenting the industry’s latest developments has become an integral part of the event along with field demonstrations of equipment capabilities.

Watch out for the first Russian marine technologies event!

EAGE is to organize its first Marine Technology 2019 conference in Russia to be held simultaneously with the 15th Anniversary Engineering and Mining Geophysics 2019 Conference and Exhibition at the end of April in Gelendzhik (Russia). In addition to the scientific programme, the agenda will include lecture courses, an exhibition, and sports and cultural events!

Recently, there has been a significant growth in offshore oil and gas construction activities. This includes transportation, communications, power systems and other facilities. In addition, the Arctic sea shelf is being developed at a fast pace, so that borehole surveying, field develop-

Gelendzhik will welcome two EAGE events.

ment, and oil-and-gas pipeline installation require a huge amount of geophysical,

hydrographic, geological and ecological studies and surveys.

Against this background EAGE is offering a platform for knowledge sharing and discussion of the latest trends and technical innovations. The scientific sessions at the conference will cover offshore topics such as geodetic and geological surveys, geophysical and geotechnical methods, ecological and hydro-meteorological surveys as well as complex offshore geological studies, engineering surveys and operations, and marine project management.

Abstracts for consideration should be sent before 1 February 2019. See eage.ru for details.

EAGE NEWS

Award winner values career in sedimentology Luca C. Malatesta has been declared the winner of the 2017-2018 Basin Research Early Career award for his recent paper ‘Lag and mixing during sediment transfer across the Tien Shan Piedmont’ for which he was the principal author. Malatesta was recently appointed a lecturer at the Institute of Earth Surface Dynamics, University of Lausanne after Bachelor and Masters degrees at ETH Zurich, a PhD in geology at the California Institute of Technology and a post doctoral fellowship at UC Santa Cruz. Here he tells us a little about his work (subject of a number of awards) and his career to date.

For a more general audience, what is the significance of your Basin Research article?

A large part of the Earth history recorded in the sedimentary archive comes from environmental signals produced in mountain areas. I think that with this work we advanced our understanding of the ways such signals can be modified as they exit the mountains and cross alluvial piedmonts en route for the basins. Alluvial piedmonts are sensitive to climatic variations and their rivers react by aggrading or incising quickly. As a result, sediments can be trapped there for 100’s kyr before being recycled by an incising river.

The neat thing is that we could quantify the degree of mixing and buffering in the Tian Shan making our efforts worth more than a cautionary tale. Finally, we identified which climate driver controls these cycles of aggradation-incision. I am very happy that we were able to use the sedimentary dynamics of alluvial piedmonts themselves as a paleoclimatic archive documenting the central role of the Westerlies winds in controlling Central Asian climate.

What drew you to sedimentology as your research area?

Initially I think that the accessibility of sedimentological processes to the naked

eye played an important role for me. It is possible to grasp the familiar timescale of a sedimentary facies (e.g. a tidal cycle) that was deposited a properly unimaginable amount of time in the past. Importantly, my teachers at ETH — Judy McKenzie, Helmut Weissert, Sébastien Castelltort — were the best guides I could have had. Yet, it has also always been a fancy excuse to spend hours digging channels along beach streamlets.

Are there any specific topics which you would like to study in the future?

At the moment I work on the topographic expression of subduction seismic cycles.

But I am keen to head back to Central Asia and work on the eolian sediment cycle there and try tying its dynamics more precisely to climatic conditions.

Will you always stay in academia or would you like to spend some time in the commercial/industrial practical world?

I will definitely try to stay in academia. I really appreciate the academic freedom of following my interests and freely choosing the people I enjoy working with. I recently started teaching and I find it a stimulating, and practical, counterpart to research.

Much has been said about the difficulty of attracting talent into the earth sciences, how would you encourage your successors in the upcoming generation?

I don’t know that we necessarily have difficulty attracting talent into the earth sciences per se, I have been surrounded by brilliant people since I started my Bachelor. But the field would gain so much by attracting, and keeping(!), talent from much more diverse horizons. We still have a very long road to go toward inclusiveness. The upcoming generation should be aware how the field of Earth sciences has evolved and expanded phenomenally: a geoscientist is not only a rugged outdoorsperson who likes camping in the cold, she or he is a molecular geobiologist, a planetary scientist, a geodynamicist, a field geologist, a seismologist, an isotope geochemist, an experimental petrologist, etc. Geology departments are truly exciting places in which to study and learn, and they should welcome all.

Open access to the Luca C. Malatesta et al. paper is available at: https://onlinelibrary.wiley.com/ journal/13652117.

The EAGE Student Fund supports activities that help bridge the gap between the university and professional environments for students of geosciences and engineering. Thanks to our Student Fund contributors we can continue supporting students around the globe and through this securing the future of our industry. For more information to become a Student Fund contributor, please visit eagestudentfund.org or contact us at students@eage.org.

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A year of transformation Regular followers over the last five years will know that this column of seismic data in their E&P strategies. A clear beneficiary of this treats all forecasts about the oil and gas industry and indeed for the process has been the surge of interest in ocean bottom node (OBN) energy business generally with a healthy degree of suspicion. seismic with its promise of superior imaging of the subsurface Come December, however, there is this irresistible urge to compared with towed streamer solutions. Advances in technology review the year’s activities and, yes, look ahead and improved economics have turned OBN into with all the attendant risk of being held to a serious challenger for market share.

‘Adjustment is now account for prophecies that fail to materialize.

2018 was undoubtedly a momentous year clearly underway Fortunately few people actually remember, when the prevailing trends opened the curtains with a vengeance.’ let alone care, what was written a year ago. on a new landscape. What could be more Notwithstanding, when a prediction turns out stunning than the two biggest and most storied to be correct, then of course pride and/or vanity dictates that this geophysical companies left in the seismic marketplace – Schlumshould be recognized. Jane Austen of Pride and Prejudice fame berger WesternGeco and CGG – totally restructuring their business made a distinction when she noted: ‘Vanity and pride are different models within months of each other. In the process both companies things, though the words are often used synonymously. A person have effectively exited the marine and land seismic acquisition may be proud without being vain. Pride relates more to our opinion business. That surely is what 2018 will be remembered for in the of ourselves, vanity to what we would have others think of us’. geoscience community.

These high profile withdrawals signalled rethinking, arguably So, begging readers’ indulgence, last December’s Crosstalk overdue, of the seismic business model. Management of both comadvised that ‘a return to business as usual, particularly for the panies ultimately acknowledged what has been obvious for a long marine seismic sector, is now most probably a mirage. There is time: that the boom bust cycle of the marine seismic vessel market a limit to how long contractors and many suppliers of equipment is untenable. On land, the business has simply stagnated despite the and services can continue to run up year-on-year deficits … A big best efforts to introduce higher channel count cable-based acquisition adjustment or transformation lies ahead for the seismic community, systems typically for desert regions of the Middle East and market the shape of which is still to be determined’. more cost effective cableless technology especially in North America.

That adjustment is now clearly underway with a vengeance. The The companies’ conclusion is that the value proposition lies in marine seismic services business looks radically different from the building seismic data libraries and providing processing and other 2012-13 model before the collapse of the oil price and the ensuing specialist data enhancement services, not in survey acquisition hiatus in oil companies’ E&P spending. operations. In the case of CGG, there is still some unravelling to do, The global seismic fleet is about a third of the size it was a few and the company will continue to maintain Sercel, the longstanding years ago. But the big adjustment is that multi-client has become the leader in the manufacture of equipment for marine and onshore mode of choice for oil industry customers especially for exploration acquisition. But CGG’s mission aligns with Schlumberger as a projects. Opportunities for proprietary work have diminished. This newly dedicated ‘asset-light people, data and technology company’, has contributed to the consolidation in the towed-streamer market, able to offer a range of geoscience data services from prospect to already beset with low ‘commodity’ pricing caused by persistent reservoir characterization. over-capacity.

To acquire data, Schlumberger and CGG (although still techniFurthermore, oil company customers in the low oil price envically left with three vessels) will in future focus on putting together ronment of recent years have had cause to review the role and value

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Oil company caution, therefore, is an underlying factor in the multi-client projects worldwide, dipping into the global pool of increasingly visible growth of seabed seismic acquisition activity. seismic vessels for hire. As such they will be joining the ranks of The industry continues to adopt a low-risk approach to increasing existing multi-client specialists, notably TGS, as customers for data reserves, focusing more on optimizing production from existing acquisition services. It leaves PGS as the only seismic vessel operadevelopments and on infield exploration close to existing infrastructor still committed to building its own multi-client data library. None ture. These are the applications where OBN seismic acquisition is of the remaining international players, Shearwater Geoservices, rapidly emerging.

Polarcus and BGP, currently have aspirations in this direction.

Perhaps most challenging for the traditional towed-streamer This evolution in the marine seismic sector does not necessarily specialists is that an emerging multi-client OBN market is opening bode well for towed-streamer contractors. We have already seen the up attractive development possibilities in mature provinces. TGS has observable trend of oil companies opting for a multi-client approach recently been talking about reshooting areas of the NW European to exploration seismic. This is not only a cost-saving measure Continental Shelf using OBN acquisition. It is already participating but a reflection of exploration companies’ requirements. Given with Schlumberger in the Gulf of Mexico on a large OBN project the sophistication of today’s data treatments post survey, plus the associated with existing wide-azimuth survey data. In the North ability to tie data to the huge volumes of existing seismic and other Sea it is working on a multi-client survey with Axis Geo Solutions geoscientific information available for practically every corner of (AGS), the recently established OBN acquisition company. the seas, oil companies at the exploration stage are unapologetically Towed-streamer contractors seem unlikely to sit idly by and settling for cost effective rather than super-sophisticated data on watch their market share in the total marine seismic data acquisition which to base their decisions. space being gradually eroded. Shearwater has inherited some The viability of the marine seismic acquisition business remains seabed seismic capacity through its purchase of WesternGeco’s as vulnerable as ever. The retreat of WesternGeco and CGG does Q-Seabed technology and vessel support. BGP is in the market not relieve the over-capacity issue. Following the acquisition of having acquired a substantial number of nodes (17,000) and four WesternGeco’s marine seismic business, Shearwater is now the handling systems from Magseis, initially for a Middle East project. dominant operator with a fleet of 14 vessels, a number of which are That still leaves PGS and Polarcus on the sidelines, although currently laid up. The company’s management has vowed caution both have said they could be open to OBN projects, presumably over reintroducing units into the market next year and onwards, but either through collaboration with existing equipment suppliers/ there is a significant overhead in holding vessels in readiness for an contractors or by purchasing their own systems (assuming that the uptick in demand. investment capital is available). In this context the Seabed GeoShould there be any noticeable improvement in the market, Solutions (SBGS) joint venture of Fugro and CGG, an independent Shearwater would surely not be the only company to bring out vesoperator, is in flux as the latter seeks to dispose of its 40% share. sels-in-waiting. As has happened so often in the past, competition The company is now offering its Manta node deployment and simply increases and customers are able to drive down the cost retrieval system as a single technology for all depths. The only of surveys. Right now in the mid-winter of 2018-19, the current active independent node manufacturer is Geospace Technologies. global seismic fleet is enjoying better utilization than for some time, It recently recorded a major node sale to AGS, although contractors are not seeing a significant and has over time been a successful supplier. In firming in prices that they crave.

‘Optimism about a the wings is Norwegian OBN system developTraditionally the marine seismic market resurgence of E&P er inApril. The company recently announced looks to the price of oil as a likely indicator of enhancements to its Venator highly automated future oil and gas E&P spending and hence a activity has dimmed.’ system promising unmatched operational speed forecaster of survey activity. That correlation and efficiency, but it still awaits a customer or investor to build the is likely to be complicated by the time and organization required first system. to put together multi-client projects compared with proprietary Meanwhile, global leadership in the OBN marketplace now surveys. belongs to Magseis Fairfield, following the Norwegian company’s More fundamentally the global oil supply and demand scenario purchase of Fairfield Geotechnologies’ data acquisition, nodal and has become extremely volatile. For example, oil prices seemed to system sale and rental activities, plus Fairfield’s wholly owned be on an upward trajectory, in the high $70s range for Brent crude, UK subsidiary WGP Group. The transaction itself epitomizes the but have now slipped. As a result, optimism about a resurgence of business model choices that companies are making in the new era.

E&P activity has dimmed. A recent commentary from analyst PwC Magseis is convinced that there is a future in acquiring seabed aptly sums up the dilemma for oil companies: ‘While the supply seismic data on a contract basis. Fairfield Geotechnologies, on the glut may have ended, its after-effects will continue. In the short other hand, believes that data licensing and data processing plus term, companies must maintain capital discipline and the focus on imaging, data analytics and data interpretation are the way forward. productivity improvements and applying new technology’.

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

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Acquisition

Imaging

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INDUSTRY NEWS

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PGS provides data of African basins

CGG to ring changes as it unveils plans for an ‘asset light’ model

CGG will cut the size of its fleet from five vessels to three.

CGG will cut its active fleet from five to three vessels next year, will exit from land acquisition altogether and sell some of its businesses as it moves to an ‘asset light model’.

Unveiling its ‘Strategic Roadmap’ to 2021, the company said that it would ‘reduce CGG’s exposure to the data acquisition business, which has suffered over the years because of structural industry overcapacity, lack of differentiation, commodity pricing and a heavy fixed cost base.’

As a result, CGG said it was looking for a strategic partner to ‘cost efficiently operate and control’ its three remaining vessels that will focus on multi-client acquisition. In the third quarter CGG had three vessels performing multi-client surveys in the North Sea and in Brazil and two vessels working on proprietary surveys in the North Sea in Brazil. It has become the latest geophysical company to announce a divestment of assets after Schlumberger announced the $600 million sale of its WesternGeco marine data FIRST

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acquisition to Shearwater GeoServices in August.

‘Multi-Client also performed well through the cycle and since 2017 has seen signs of a strengthening offshore exploration market,’ said a company statement at its capital market day in London last month. ‘The strategic path will give this business freedom to select the providers of acquisition services best suited for their project requirements and enable the delivery of a full suite of products, from wells and geology to 2D/3D seismic and integrated packages that will greatly improve exploration efficiency.’

Meanwhile, CGG told investors that it will exit the land acquisition market altogether after ‘a wind-down period’.

Its multi-physics business remains for sale and the company has signalled its intention to sell its equity stakes in the 50-year Argas joint venture with TAQA in the Middle East and its 40% stake in its five-year-old ocean bottom seismic joint venture with Fugro, Seabed Geo Solutions.

The company will find an extra $40 million in cuts to its general and administrative expenses and support costs to ‘adapt to the new size and footprint of the company’.

Having divested itself of poorly performing assets, CGG said that it will strengthen its ‘core profitable businesses’: Geoscience, Multi-Client, and Equipment, I

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‘which perform well through the cycles and can best capture the market rebound. Geoscience maintained both its leading market share and margins through the downturn, based on clear differentiation that clients recognize and value. The CGG strategy going forward is to further strengthen its leadership position as the market recovers.

This will be achieved through recruiting and developing talents, investing in algorithms and computer technology’.

CGG expected its Equipment division to continue to perform strongly.

‘As the market continues to strengthen, Equipment will benefit from its very large installed base in land. The marine market will also strengthen as a significant number of streamers need replacement. Gauges and downhole tools growth is driven by the US Land unconventional market, which continues to be strong.’

The company has set a target of segment revenue 2021 of $1.7 billion (a 5% rise) and segment free cash flow of $300 million (a 10% rise). CGG expects 30% of future revenue to be generated from new offerings: ‘Areas of focus include expansion into adjacent markets, leveraging increased reservoir development activity, unconventional market, equipment diversification and rapid advance of geoscience and digital technologies.’

TGS reports third quarter net profit of $17 million TGS has reported third quarter net profit of $17 million on revenues of $141 million in Q3 2018, compared with $46.2 million on revenues $158 million in the second quarter of 2018 and $9.4 million on revenues of $142 million in the third quarter of 2017. Operating profit was $24 million (17% of net revenues) compared to $54.2 million (34% of net revenues) in the second quarter of 2018 and $26 million (18% of net revenues) in Q3 2017.

Late sales of $106 million compared with $135.8 million in the second quarter of 217 and $79 million in the third quarter of 2017.

Net pre-funding revenues were $33 million, funding 33% of TGS’ operational multi-client investments for the quarter. This compared with $20 million in Q2 2018, funding 37% of multi-client investments, and $62 million in Q3 2017, funding 54% of multi-client investments.

Operational multi-client investments were $100 million (33% prefunded). This compares to $56 million (37% prefunded) in Q2 2017 and $114 million (54% prefunded) in Q3 2017. TGS’s non-operational investments were $7 million. Cash balance is $322 million.

By the end of the year TGS expects to have made new multi-client investments of approximately $260 million and additional multi-client investments are expected from sales of existing surveys. Pre-funding of new multi-client investments is expected to be approximately 40% compared to the previous expectation of 45-50%.

TGS CEO Kristian Johansen said: ‘TGS has grown net revenues by 29% in the first nine months of 2018. However, E&P companies have for the most part maintained a cautious approach to exploration spending and a large part of the increased revenues is related to

acreage turnover, either through M&A between E&P companies or asset swaps and purchases. With the market fundamentals continuing to improve, E&P companies are likely to come under increasing pressure to replenish reserves and secure growing production in the longer-term.

Furthermore, many smaller E&P companies which paused spending during the downcycle, will ultimately return to exploration as they move back to a growth agenda. As a result, exploration budgets are likely to increase from the current unsustainably low levels.

‘TGS is well positioned to benefit from improved market conditions going into 2019, supporting further investment growth. TGS’ counter-cyclical investment during the downturn, with high volumes of data acquired at record-low cost, bodes well for continued industry-leading return on capital going forward.’

Norway and Russia agree mutual rights to data in Barents Sea Norway and Russian have signed an agreement on mutual rights to seismic acquisition in the Barents Sea. The new agreement will entail a right for seismic vessels from both countries to cross the delimitation line that was drawn in an agreement between the two nations in 2010. They will now be able to use their 16

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seismic equipment within a distance of 5 km on the continental shelf of the other country.

This will secure both countries the possibility of acquiring good quality seismic data up to, and along the delimitation line. Such data are important in case of a discovery of oil and

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gas extending across the delimitation line.

‘The agreement is a natural follow-up of the signing of the Delimitation Agreement in September 2010 and will benefit both countries, said Norway’s minister of petroleum and energy, Kjell-Børge Freiberg.

Magseis buys Fairfield Geotechnologies seismic technologies business Magseis is using much of the $150 million it has raised in a private placement to acquire Fairfield Geotechnologies’ Seismic Technologies business for an initial $233 million.

The transaction includes Fairfield’s data acquisition, nodal and system sale and rental activities, including all shares in Fairfield’s wholly owned UK subsidiary WGP Group.

The name of the new business will be Magseis Fairfield. Fairfield Geotechnologies will remain privately held by the Sugahara family through Fairfield-Maxwell and focus its efforts on data licensing and data processing, as well as imaging, data analytics and data interpretation.

The purchase price will comprise a combination of cash and Magseis shares. In addition, Fairfield-Maxwell will receive five-year warrants and certain rights under an earn-out payment mechanism related to a project in the Al Shaheen Oil Field located in Qatar. The final purchase price will be subject to closing working capital adjustments.

The deal will create a leading provider of marine seismic solutions, including ocean bottom seismic with a combined backlog of more than $350 million.

Fairfield Seismic Technologies provides marine ocean bottom nodal (OBN) seismic systems. The business has performed 45 OBN surveys globally since 2005 and owns an extensive portfolio of intellectual property for both OBS, land and permanent reservoir monitoring solutions. Headquartered in Houston, the business has approximately 230 full-time employees and 250 contracted personnel.

Byron Sugahara, chairman of Fairfield-Maxwell, the owner of Fairfield, said, ‘My family has owned and invested in Fairfield Geotechnologies for more than 40 years. We are excited to become Magseis Fairfield’s largest shareholder given our positive outlook on the seismic services industry and confidence in the combined management team. We are also pleased that the transaction will provide Fairfield-Maxwell additional capital for potential reinvest-

The Al Shaheen oil field, Qatar.

ment in Fairfield Geotechnologies’ remaining data licensing and data processing business.

Jan Pihl Grimnes, chairman of the board of directors of Magseis, said: ‘This transformational transaction enables Magseis to take pole position in the development of the marine seismic industry with critical mass, leading technology, modern crews and financial capabilities to capitalize on exciting growth opportunities.’

The chairman, CEO and president of Fairfield, Charles W. (‘Chuck’) Davison, has been proposed as the new chairman of the board of directors of Magseis upon completion of the transaction.

Anthony Dowd, president and CEO of Fairfield-Maxwell, has been proposed as a member of Magseis’ nomination committee.

‘Magseis and Fairfield Seismic Technologies combined will have the industry’s largest nodal inventory. The combined entity will have an excellent

technology platform providing optimal ability to meet all client requirements regardless of geography, water depth and acquisition methodology,’ said Per Christian Grytnes, chief executive officer of Magseis.

The combined organization will comprise approximately 430 full-time employees and be structured in three business areas: Eastern Hemisphere Operations (headquarters in Oslo, Norway), Western Hemisphere Operations (Headquarters in Houston, USA) and Technology.

The transaction does not include the data licensing or data processing business of Fairfield, which will be retained by Fairfield. The business will be carved out of Fairfield’s organization and transferred into a newly incorporated company.

Fairfield Geotechnologies will have access to Magseis Fairfield’s equipment and services through a five-year preferred supplier agreement.

INDUSTRY NEWS

DUG builds supercomputer with servers submerged in coolant DownUnder GeoSolutions has built one of the world’s most powerful computing systems featuring more than 40,000 servers immersed in liquid coolant.

The system, which is expected to deliver 250 petaflops, will be housed in the Skybox Datacentre facility in Houston.

‘This facility allows us to install the fastest supercomputer in the world at this time to meet the ever-increasing demand for energy,’ said Dr Matthew Lamont, co-founder of DownUnder Geosolutions.

The project will deploy more than 720 enclosures using the DUG Cool liquid cooling system, which fully submerges servers in tanks filled with dielectric fluid, an approach that reduces energy usage by about 45% compared to traditional air cooling.

DUG and Skybox expect the data centre to operate at a Power Usage Effectiveness (PUE) of 1.05, lower than even the most advanced hyperscale cloud providers.

Rob Morris, managing partner for Skybox, said of the system that is expected to operational in February 2019: ‘DUG has worked for a long time refining this design. It’s the largest immersion project that we’re aware of in the data centre space.’

At 250 petaflops, the DUG system would exceed the current specs for the world’s most powerful supercomputer, the Summit system at Oak Ridge National Laboratory in Tennessee. Summit led the

June Top500 list with a benchmark of 122 petaflops, and has a projected high end of 200 petaflops.

DUG says the 15-megawatt deployment represents the first phase in a project that could eventually become an exascale system. A petaflop is a quadrillion floating point operations per second, while an exaflop would be one quintillion (1,000,000,000,000,000,000) calculations per second.

The DUG cooling system fully submerges standard HPC servers into specially designed tanks filled with a dielectric fluid that is non-toxic, biodegradable, and does not conduct electricity.

Fluid is cooled and circulated around the hot server components. Heat exchangers are submerged with the computer equipment, meaning that no dielectric fluid ever leaves the tank. A water loop runs through the rooms and to each heat exchanger.

The thermal qualities of the fluid used

by DUG allows the use of condensed-water chillers rather than refrigeration, saving 25 to 30% of total power usage. Removing all server fans, which are not needed in a

fluid-immersion system, reduces power consumption by a further 20%.

DUG says its 15 megawatt deployment is the first phase of a longer-term expansion in Houston that could create an exascale system, with the power to process 1000 petaflops of computing power.

The DUG system arrives amid a push by the US government and HPC community to develop exascale systems at three sites – Oak Ridge National Labs, Lawrence Livermore National Labs in California, and the Argonne National Laboratory in Illinois.

The DUG system in Houston will span 10,000 ft2 (930 m2) of space, use up to 15 megawatts of power, and feature more than 40,000 servers.

‘The exascale movement, and the computing requirements that are driving it, will present new opportunities for the commercial data centre industry,’ said DUG. ’As powerful applications such as DUG’s seismic tools move to cloud delivery models, they will continue to push the frontier of data centre infrastructure.’

UK to launch licensing round in Greater Buchan area of North Sea The UK Oil and Gas Authority is launching a ‘supplementary licensing round’ in the Greater Buchan area of the North Sea. The area in the Outer Moray Firth features considerable open, currently unlicensed acreage, including a number of

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undeveloped discoveries and an estimated 150-300 million barrels of oil equivalent (mmboe).

To maximize economic recovery of the significant potential recoverable resources in the area, the OGA will open a Supplementary Licensing Round in Q1

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2019 which will be supported by newly available seismic data.

The OGA was due to host an information session in Aberdeen on 15 November to give an overview on the timing and process of the Supplementary Licence Round and more details on the supporting information.

INDUSTRY NEWS

CGG depth images Norwegian North Sea play CGG has completed seismic depth imaging of its entire Northern Viking Graben multi-client survey in the Norwegian North Sea. The latest visco-acoustic (‘Q’) velocity modelling and seismic imaging technologies have been applied to BroadSeis broadband variable-depth streamer field data, acquired between 2014 and 2016. The final output forms a contiguous data volume covering 35,400 km2.

The Northern Viking Graben contains a wide range of localized near-surface geological anomalies – with shallow gas being a particular feature in this area.

Some of the shallow gas accumulations are identified gas fields, including Frigg and Peon, said CGG. Shallow gas anomalies typically exhibit anomalously high absorption, associated with amplitude attenuation and phase distortion of seismic data. ‘These challenging issues cause unwanted effects during imaging, such as dim zones, uneven image illumination and migration artifacts. Another absorption feature specific to the area is the large body associated with the Norwegian trench, which crosses the entire survey area from north-west to south-east, said CGG. Preprocessing for the imaging consisted notably of a noise attenuation flow targeting swell noise, seismic interference and post-critical energy, as well as broadband deghosting, shortand long-period free-surface multiple attenuation, common-offset binning and regularization.

The model building phase uses both Q tomography and Q full-waveform inversion (FWI) to create a Q

Final PSTM data from NE Horda with interpreted basement surface.

model which defined the location and extent of absorption anomalies.

Advanced tomographic inversion and both refraction and reflection FWI were used alongside the Q work to derive the velocities and anisotropic parameters. This model building encompassed the full 35,400 km² area.

Imaging used advanced Q-compensating migration algorithms, which took full advantage of the velocity, anisotropy and Q models to correct for amplitude loss and phase dispersion and thus delivered improved resolution and continuity.

The final reprocessing clearly highlights near-surface features such as the Peon gas field. A better model and understanding of the shallow geology will also lead to clearer images of the deeper structures.

The Northern Viking Graben data set is complemented by a well study of 100 reinterpreted wells that have been integrated with the seismic results. A southern extension of 8000 km² is currently being acquired, which will be processed through the same sequence and seamlessly merged.

The Q modelling and imaging techniques are widely applicable elsewhere in the world, said CGG. For example, CGG’s 35,000 km² Cornerstone survey in the Central North Sea is currently being processed through a similar sequence, with impressive high-resolution images of the Forties channels already having been achieved.

Further research is testing the benefits of Q least-squares migration algorithms. Least-squares migration inherently favours amplification of signal over noise, thus reducing the risk that the Q-compensation will over-boost noise. This can be applied other areas of low signal-to-noise ratio, such as beneath the kind of shallow gas anomalies discussed earlier, said CGG. FIRST

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UK gives update on first UK Oil and Gas National Data Repository The UK Oil and Gas Authority (OGA) has taken a step closer to the first UK Oil and Gas National Data Repository (NDR) for petroleum-related information that will be launched in early 2019. The NDR will house and publish the collection of UK petroleum-related information, such as well, geophysical, field and infrastructure data.

The NDR will be a critical piece of UK digital infrastructure providing definitive information which will help to unlock the huge prize of the UK Continental Shelf’s remaining resources.

The OGA has reached an agreement with Common Data Access Limited (CDA) (a wholly owned subsidiary of Oil & Gas UK) to operate the NDR for two-years, building on the existing service operated by CDA for more than 20 years. The OGA has started a procurement process for the OGA-operated NDR, with services expected to commence in 2021.

Nic Granger, director of corporate at the OGA said: ’The NDR is key to delivering the opportunities offered by Vision 2035 – to add three billion barrels of production over the next 17 years. It provides a strong foundation to achieve our exploration and production goals, enhance collaboration, and drive innovation and learning as an industry.’

Simon James, chief information officer at the OGA added: ‘The launch of the NDR will allow the OGA to further build on its highly successful policy of creating value by maximizing data transparency and providing digital services and authoritative analysis to industry. It creates the conditions necessary for the application of new and exciting data analysis tools, such as machine learning and AI.’ CDA’s Chief Executive, Malcolm Fleming said: ‘For 25 years, CDA has been collaborating with industry to establish this unique collection of UKCS well

and seismic information. We are delighted to be able to put the collection at the centre of the NDR so preserving data, sharing it between licensees and for disclosure it to all under open licence conditions.

The NDR will ensure use of the broadest range of information in the search for oil and gas, an activity for which access to extensive top quality data is key.

‘The Repository is expected to provide an invaluable resource to technology innovators looking to apply new machine learning and artificial intelligence techniques to the demanding task of locating oil and gas deposits deep in the subsurface.’

The OGA Open Data Centre, which was recently upgraded and redesigned, provides user friendly and free access to a wide range of data. Users can view, map, style, chart, download and share data (under the terms and conditions set out in the Open Government Licence, unless otherwise stated).

Croatia launches second onshore licensing round Croatia has launched its second onshore licence round, including seven blocks in the country’s prolific Pannonian basin that have produced more than 1.1 billion boe.

Most of the blocks contain undeveloped oil or gas discoveries. Blocks available for the first time include Sava-06 (SA-06), Sava-07 (SA-07), Sava-11 (SA-11), Sava12 (SA-12), Northwest Croatia-01 (SZH01) and Northwest Croatia-05 (SZH-05).

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Meanwhile Drava-03 (DR-03), previously offered in Croatia’s 1st onshore licensing round and then awarded to Oando, will be available for the second time. The five other blocks from Croatia’s first onshore licensing round were awarded to Vermilion and INA. Stratigraphic plays, which are frequently observed in seismic data for each basin, are all but unexplored and could yield significant results in areas of sand body pinch-out that are common in both the delta front and distal onlap.

Deeper plays also offer future potential with many as yet untested and poorly understood. Lower Miocene coarse clastic reservoirs could be charged (as they are in Hungary) by localised shales formed within graben like depressions.

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still very much under-explored and poorly mapped.

Modern exploration into these deeper and often poorly defined play types has been hindered by the quality of the legacy seismic data in the basin, with more than 4000 seismic lines acquired from the early 1970s to the 1990s.

Spectrum has reprocessed some 12,000 km of the data using a modern processing suite. Imaging of the data has been greatly uplifted, revealing the potential in deep structures with improved continuity, frequency and amplitude content.

The reprocessing has also encompassed a regional static elevation model that enables surveys from a variety of different vintages to tie seamlessly to each other, allowing full and comprehensive interpretation of the data set. This is also complemented by reconditioned and translated key well data set covering the region.

INDUSTRY NEWS

TGS and Schlumberger acquire survey in US Gulf of Mexico TGS and Schlumberger have announced a new multi-client nodal seismic project in the US Gulf of Mexico.

The Amendment project will comprise acquisition of a 2350-km2 multi-client seismic survey in the Mississippi Canyon and Atwater Valley protraction areas of the US Gulf of Mexico. This prolific area includes open acreage, existing producing assets and new discoveries.

Seismic data will be acquired using Fairfield Geotechnologies’ 4C nodal acquisition technology with operations expected to start in Q4 2018. TGS and Schlumberger will apply their full azimuth processing expertise and expect to deliver final data to customers in Q1 2020.

‘E&P companies are showing increased interest in the benefits of nodal seismic data to overcome imaging challenges in this region. In the Amendment project, TGS and Schlumberger will reimage underlying WAZ seismic data to provide modern, high-quality nodal seis-

mic data to our clients,’ said Kristian Johansen, CEO of TGS. Maurice Nessim, president, WesternGeco, Schlumberger, said, ‘Schlumberger and TGS have built up extensive geophysical and geological knowledge in this prolific part of the US Gulf of Mexico. In line with the WesternGeco asset-light strategy, the application of nodal seismic technology and state-ofthe-art imaging techniques will help to accelerate hydrocarbon discovery, development and production for our clients. This unique dataset will provide a step change in illuminating complex subsurface structures and help E&P companies to maximize the value of their producing assets and rejuvenate their exploration portfolios. This highly integrated project will combine well log data, high-quality orthogonal WAZ and new nodal measurements to provide foundations for the first industry-funded regional nodal survey in the deepwater Gulf of Mexico.’

Seabird reports third quarter operating loss of -$4.2 million Seabird Exploration has reported a third quarter 2018 operating loss of -$4.2 million compared an operating loss of -$4 million in Q2 2018 and a loss of -$25.6 million in Q3 2018.

Revenues for the quarter were $5.4 million, compared to $2.9 million in Q2 2018 and $2.7 million in Q3 2017. Vessel utilization for the quarter was 55%, compared to 22% in Q2 2018 and 22% in Q3 2017.

Meanwhile, the company has received another 30-day extension on an OBN survey in the US Gulf of Mexico that started in late August. The extension for

the vessel Osprey Explorer is up to a total of 120 days. The company has also started a two-week multi-client 2D survey in northwest Europe, to be acquired in November. The survey is pre-funded and approx. cash neutral.

The company is using the Harrier Explorer for the survey.

Finally, the company has won a contract to acquire 2D seismic data for an oil and gas company in America. The survey is expected to take approx. six weeks and will be conducted by the Harrier Explorer in Q1 2019.

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CGG reports third quarter net loss of -$1.5 million CGG has reported a third quarter net loss of -$1.5 million on revenues of $439 million, compared with a net profit of $49 million on revenues of $314 million in Q2 2018 and a net loss of $124 million on revenues of $320 million in Q3 2017.

Segment revenue of $333 million compared to $338 million in the second quarter of 2018 and $320 million in the third quarter of 2017. The company reported segment operating income of $40 million (a 12% margin) compared to segment operating income of $40 million in Q2 and a segment operating loss of -$24 million in the third quarter of 2017. Segment net loss was -$1.5 million, compared with $49 million net profit in Q2 2018 and a net loss of -$124 million in the third quarter of 2018.

GGR segment revenue was $192 million, compared to $203 million in Q2 2018 and $186 million in Q3 2017. Geoscience revenue of $93 million compared with $93 million in Q2 2018 and $80 million in Q3 2017. The sector is holding up as a result of ‘robust demand worldwide for advanced imaging and for reservoir delineation and production geoscience services’.

Multi-client revenue was $99 million, compared to $110 million in Q2 2018 and $105 million in Q3 2017. Prefunding of $36 million, compared to $24 million in Q2 2018 and $70 million in Q3 2018.

Prefunding remained depressed as a result

of regulatory delays which are estimated to have cost the company $25 million in prefunding revenue. However, aftersales were strong in active basins. Q3 aftersales of $63 million compared to $87 million in Q2 2018 and $35 million in Q3 2018.

GGR segment operating income was $59 million (31% margin) compared to $64 million (32% margin) in Q2 2018 and $12 million (6% margin) in Q3 2018.

The multi-client depreciation rate was at 41% owing to a higher mix of fully depreciated sales, leading to a library Net Book Value of $902 million at the end of September 2018.

Equipment segment revenue was $94 million compared to $83 million in Q2 2018 and $40 million in Q2 2018.

Land equipment sales represented 73% of total sales, compared to 63% last year, driven by strong land channels and geophones deliveries in the Middle East and Asia. The well gauges demand remains strong on the back of unconventionals activity.

Equipment segment operating income was $11 million (11% margin) compared to $1 million (1% margin) in Q2 2018 and a loss of -$16 milllion in Q3 2018.

Contractual Data Acquisition segment revenue was $54 million compared to $67 million in Q2 2018 and $99 million in Q3 2018.

Marine Contractual Data Acquisition revenue was $24 million, compared to $40 million in Q2 2018 and $71 million in Q3 2018.

Land and Multi-Physics Data Acquisition revenue was $30 million, compared with $27 million in Q2 2018 and $28 million in Q3 2018. Activity was mainly in North Africa and Asia while Multi Physics benefited from the mining market recovery.

Contractual Data Acquisition segment operating income was a -$17 million loss compared to a -$7 million loss in Q2 2018 and a -$7 million loss in Q3 2018.

Company net debt was -$769 million at the end of September 2018. Liquidity was $412 million.

Sophie Zurquiyah, CGG CEO, said: ‘Our third quarter revenue was up 4% year-on-year, confirming the gradual market recovery. Geoscience saw robust performance and Multi-Client delivered a high level of after-sales but was impacted by delayed pre-funding recognized in October. Equipment sales increased significantly for land achieving double digit operating income margin. Acquisition continues to suffer from low prices in a commoditized market.

‘In that context, we remain on track with our 2018 targets based on sizeable year-end Multi-Client opportunities and strong Equipment deliveries.’

TGS announce partnership for OBN projects in the North Sea TGS has announced a strategic collaboration with Axxis Geo Solutions (AGS) for multi-client ocean bottom node projects in the North Sea. The area of mutual interest covers the core part of the central North Sea up to and including the Utsira area. Under this agreement, the parties will work together to develop opportunities to

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co-invest in multi-client ocean bottom node projects.

The collaboration will start with TGS joining the 1560 km2 Utsira node multi-client project which is currently being acquired

by AGS in the Norwegian North Sea. Kristian Johansen, CEO, TGS said: ‘E&P companies have for a long time recognized that ocean bottom nodes can deliver a

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significant uplift in data quality. Technology development and operational efficiencies are bringing costs down to a level where largescale exploration node surveys are becoming an attractive option to support exploration and drilling decisions. This is TGS’ second ocean bottom node announcement related to 2019 investments and we are excited by the momentum that we see in this market.’

INDUSTRY NEWS

Argentina launches licensing round Argentina’s offshore licensing round has officially opened with interested parties invited to register their eligibility and submit bids by 14 March, 2019.

The country says that very few wells have been drilled in the acreage on offer yet the hydrocarbon system has been proven.

The licensing round includes 24 blocks.

The round includes 24 blocks across the Austral and West Malvinas basins which are covered by Spectrum’s 2018 2D Multi-Client seismic data. This broadband-processed survey consists of 14,000 line km of long offset, continuously recorded data with extended recording lengths and high fold to support full interpretation from Moho to water bottom.

The area covered by this data is considered to be the most prospective in the basin.

Fourteen blocks have been made available in the Argentina Basin.

Spectrum’s new 38,000 km multi-client 2D seismic survey has been specifically designed to image the area included in the licensing round and every block is covered by new long offset data.

Private equity firm buys Ikon Science Ikon Science has announced that Great Hill Partners (GHP), a Boston-based private equity company, will acquire their global business.

This investment creates the opportunity for Ikon Science to accelerate growth plans in line with customer demands and to cement their position as the leaders in bringing innovative and relevant technology to reservoir characterization and production prediction in conventional and unconventional reservoirs.

‘We are very excited about this new chapter in Ikon Science’s growth story,’ said Mark Bashforth CEO. ‘We are investing heavily in growing and improving our data analytics and machine learning capability, and in product innovation to deliver high quality results where and when our customers need it. We look forward to working with Great Hill Partners to accelerate our growth and deliver competitive advantage.’

Martyn Millwood Hargrave, chairman of Ikon Science and Mark Bashforth CEO will be joined on the board by Christopher Gaffney Managing Partner at GHP and Eric Ahlgren Vice President GHP. ‘We are enthusiastic about our new investment in Ikon Science,’ said Christopher Gaffney, managing partner at Great Hill Partners.

‘The company is growing fast while maintaining profitability, a combination that attests to the quality of its products, data, and employees. In the fast-evolving market of data driven solutions, we see a significant growth opportunity for Ikon Science and its unique GeoPrediction software platform, and expect that, with its current track record, strong product innovation and efficient operations, they will continue to lead the industry.’

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INDUSTRY NEWS

Data sales boosted as African nations launch licensing rounds Several African nations have launched licensing rounds at the end of the year creating an active market for seismic data sales in the region. Ghana, Madagascar, Somalia and Congo and Uganda are among the African countries that have launched licensing rounds or announced future rounds in the past few weeks.

Ghana has launched its first oil and gas licensing round for oil nine blocks and is planning to put up another six offshore blocks for auction in the Tano basin next year.

The west African state currently produces 200,000 barrels of oil per day led by its flagship Jubilee field which produces about 100,000 bpd.

ExxonMobil recently signed a deal with Ghana to explore for oil in the Deepwater Cape Three Point offshore (DWCTP) oilfield. Exxon is doing due diligence to find a local partner to explore the block, a condition required to operate a field in Ghana.

Aker Energy AS, controlled by Norwegian billionaire Kjell Inge Roekke,

agreed in February to buy Hess Corporation’s Ghana unit in a $100 million deal, gaining access to a 50% stake in the deepwater Tano Cape Three Points block.

The block holds an estimated 550 million barrels of oil equivalent in contingent resources and potential for a further 400 million barrels.

Eni, which has stake in two blocks in Ghana wants more blocks. Global oil majors such as BP, Shell and some independent producers have shown interest in acquiring stakes in Ghana.

Madagascar Madagascar is offering 44 offshore blocks in the Morondava Basin on the western margin of the island after acquisition of seismic data by TGS and BGP suggested ‘significant potential’ for future discoveries.

The African island state’s Office des Mines Nationales et des Industrires Strategies (OMNIS) launched the licensing round on 7 November. It will close on 30 May 2019.

Contracts are expected to be awarded in September 2019. Roadshows will be

held in Houston, US, on 19 February 2019 and in London, UK, on 26 February.

Exploration in Madagascar began in the early 1900s with the discovery of hydrocarbon-rich sedimentary basins in the west, including the Tsimiroro heavy oil field and the Bemolanga tar sands.

After over 100 years of exploration, the offshore of this frontier region remains largely underexplored. The Island shares a maritime boundary with Mozambique, where large quantities of natural gas have been discovered.

ase map showing the various offshore basins B and seismic data coverage in Madagascar.

Congo

The Republic of Congo is offering 18 blocks in deep-water offshore and onshore sites.

Phase II of the 2018/19 licensing round includes the Koba, Mbesse, Mboloko,

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Mboto, Ntsinga in the onshore Cuvette Basin, the Marine XXV,Marine XXVI, Marine XXIX A/B, Marine XXXI A/B, Youbi shallow offshore blocks, the Marine XIX, Marine XXII, Marine XXIII, Marine XXIV, Marine XXV blocks in deep and ultra-deep waters and the Conkouati, Nanga III, and Niambi onshore blocks in the coastal basin, said the Ministry of Hydrocarbons.

A new broadband depth-imaged MegaSurveyPlus, from PGS and SNPC,

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supports bids and work commitments. It has been constructed from nine datasets that have been reprocessed from field data, using the latest broadband processing techniques. All surveys have been matched and merged prior to migration, providing a seamless depth-migrated volume.

Operators already in the country, which produces about 350,000 barrels per day (bpd), include Chevron and Total.

The closing date for the tender is June 2019.

INDUSTRY NEWS

Uganda Uganda will launch its next bidding round for oil exploration licences in May next year.

Uganda discovered 6.5 billion barrels worth of hydrocarbon deposits 12 years ago in the Albertine rift basin near its border with the Democratic Republic of Congo, but production has been repeatedly delayed by disagreements with oil companies over field development strategy and tax disputes.

Total and China’s CNOOC are aiming to begin production in Uganda but both have said they will not be able to do so before 2021.

Somalia Somalia will launch an offshore licensing round on 7 February comprising some 50 blocks covering 173,000 km2. During a launch event in London the country will reveal the legal and regulatory framework, petroleum laws, local capacity, fiscal terms.

The event will also include geological presentations of final PSDM and PSTM versions of Spectrum’s 2D 20,185 km of 2D long-offset seismic data. The new data complements 20,500 km of data acquired in 2014.

The Spectrum survey design covers water depths of 30 m to 4000 m including the shelf, slope and basin floor with dip, strike and recording time intervals. Streamer lengths of 10,050 m have been used to record information at all offsets, further assisting imaging of the underlying syn-rift geometries.

Modern processing algorithms were applied to the raw data to achieve optimal imaging of steeply dipping extensional and compressional features and illumination of subtle amplitude anomalies.

Roadshows are also scheduled for Houston and Dubai. The round is set to close on 11 July 2019.

PGS provides data of African basins PGS has provided an overview of several surveys and reprocessing projects offshore Africa including Ivory Coast, Benin, Nigeria, Angola and Egypt.

The company is conducting a new megasurvey offshore Ivory Coast to evaluate the Western Ivorian basin in a regional 3D context, providing an overview of all play types.

In 2018, it acquired 8000 km2 of GeoStreamer data in the deepwater and shallow shelf areas, providing data to meet exploration requirements for the round. New surveys cover blocks CI-101, CI-205, and CI-706. The CDI Blk 706 survey combines broadband acquisition and reprocessing to offer multi-azimuth illumination over this open block.

In Benin, PGS has created a geoscience product highlighting plays and prospects on open acreage or farm-in opportunities by integrating 2D and 3D megasurvey data, conventional 3D seismic, and data for 34 wells.

The Benin advanced interpretation package combines data with geoscience to reveal untested prospectivity together with the results of drilled wells. It is based on 4312 km2 of 3D seismic data, 7500 km of 2D seismic data, and pre-stack data for selected 3D volumes along with data and reports from 37 exploration wells.

‘Results from the advanced interpretation highlight a number of overlooked plays and identify numerous new de-risked, ready-to-drill prospects on open acreage or farm-in opportunities.’

In Nigeria, the latest PGS reprocessing project will deliver the first multi-client 3D prestack depth migration dataset for offshore Nigeria, to be delivered in Q2 2019. ‘This provides the missing link

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that enables integrated exploration of the north and western Gulf of Guinea, by joining the West Africa Transform Margin to the Niger Delta Basins,’ said PGS. ‘Mapping the meeting point between the Benin Embayment and the Benue Trough, this 3D dataset covers an area over blocks OPL314, OPL315, OPL321 and OPL323. The original surveys were acquired in 2004 and processed in the time domain. Modern broadband processing techniques will revitalize the data and reveal the details of this structurally challenging environment.’

PGS recently mapped offshore southern Angola with a 12,000 km2 3D GeoStreamer survey, making it possible to unravel and de-risk the pre- and postsalt prospectivity in this undrilled basin.

A comprehensive basin modelling study has been conducted in collaboration with IGI. PGS studied the area to understand and mitigate petroleum system risks, including structure size, CO2 presence, hydrocarbon charge, and reservoir facies. The results predict the burial and maturation history of the pre- and post-salt source rocks and demonstrate hydrocarbon migration to traps.

Offshore Egypt, PGS has completed an acquisition of 22,000 km long-offset 2D data linking mature east Mediterranean acreage and the west Mediterranean frontier. The total seismic coverage in the area amounts to 6000 km2 of 3D and 37,500 km of 2D data. Around 8000 km of the 2D data provides well and field tie lines that link the prolific Nile Delta to the frontier area further west. A comprehensive interpretation has also been carried out, based on a basin modelling study.

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TGS and Spectrum expand Santos 3D programme offshore Brazil TGS and Spectrum have joined forces and expanded the Santos 3D programme to 15,000 km2 over the prospective southern Santos Basin offshore Brazil.

TGS and Spectrum will be equal partners with data processing and imaging to be performed by TGS. The survey covers

an area south of the discoveries of the Santos Basin and the recent sought-after blocks offered in Rounds 2,3,4,5 and 15.

Rune Eng, CEO Spectrum, said: ‘The two companies will be working together to unlock the southern Santos Basin for exploration. The Santos Basin is one of

the hottest exploration basins in the world with a high potential for further discoveries in deep water.’

Kristian Johansen, CEO TGS, said: ‘This will be our second major investment in Brazil this year, expanding TGS’ commitment to this significant exploration play.’

Shearwater completes acquisition of WesternGeco marine seismic assets Shearwater Geoservices has completed the acquisition of the marine seismic acquisition assets and operations of WesternGeco, the geophysical services product line of Schlumberger.

The transaction was completed after regulatory approvals and satisfaction of customary closing conditions.

‘We are now an industry-leading full-range geophysical services company with a solid financial and strategic platform. We are eager to move ahead as one strong combined business with global reach, critical mass and longterm viability and look forward to providing our customers with high-quality acquisition services and technologies’, says Irene Waage Basili, the CEO of Shearwater.

Shearwater now owns and operates a fleet of 14 fully equipped seismic vessels offering a full range of acquisition services including 3D, 4D and ocean bottom

seismic (OBS). The company also holds a portfolio of proprietary technologies and inhouse processing software.

Shearwater has close to 600 employees and operates in all major offshore basins around the world.

‘We welcome all our new colleagues and are ready to immediately start supporting our customers as one company’, said Irene Waage Basili. ‘Since announcing the transaction in August, we are very happy to have received only positive feedback and support from our customers.’

The acquisition and related transactions were executed in accordance with the 22 August 2018 announcement, including an additional $50 million cash injection to Shearwater for working capital purposes. Going forward, Shearwater has three owners with Rasmussengruppen holding 65%, GC Rieber Shipping 20% and Schlumberger 15%.

CEO of Shearwater, Irene Waage Basili.

‘We have a strong balance sheet with the sector’s lowest debt per vessel and a leading cost position, which together with our technology and highly skilled people provide significant competitive advantages,’ said Irene Waage Basili.

Gabon launches licensing round The Republic of Gabon has launched its 12th Shallow and Deep Water Licensing Round.

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undertaken a number of shallow water 3D seismic surveys across the open blocks available in the licensing round.

Seismic data has been acquired in both north and south of the country. The 11,500

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km2 southern survey, now complete, is the definitive dataset to image the pre-salt and, for the first time, intra syn-rift plays can be targeted. In the north, acquisition of a 5500 km2 3D survey images pre and post-salt targets.

INDUSTRY NEWS

PGS reports a third quarter net loss of -$35 million PGS has reported a third quarter net loss of -$35 million on revenues of $163 million, compared with a net profit of $10 million on revenues of $240 million in Q2 2018 and a net loss of -$190 million on revenues of $208 million in Q3 2017. The company’s third quarter operating loss was -$2.7 million compared with -30.4 million in Q3 2017.

Segment revenues were $192.1 million with an operating loss of -$2.7 million, compared to $199 million with an operating profit of $14 million in Q2 2018 and to $207.6 with an operating loss of -$30.4 million in Q3 2017.

Segment multi-client prefunding revenues of $96 million (94% prefunded) compared to $94 million (116% prefunded) in the second quarter of 2018 compared to $102 million (124% prefunded) in Q3 2017.

Segment multi-client late sales were $56 million compared with $69 million in Q2 2018 and $48 million in Q3 2017.

Cashflow from operations was $133 million, compared to $121 million in Q2 2018 and $118 million in Q3 2017.

Rune Lova Pedersen, PGS president and chief executive officer, said: ‘With a

majority of our vessel capacity allocated to multi-client in the third quarter we invested more than $100 million in attractive multi-client projects. We believe we will harvest from these investments in a strengthening market going forward.

Multi-client late sales did not benefit from any specific licensing rounds in the third quarter. Going into the fourth quarter it is encouraging that our leads for multi-client late sales are better than for many years.

‘Contract revenues in the third quarter reflect a still challenging market.

However, the sentiment is improving and year-to-date we have achieved higher contract prices and margins compared to last year.

‘Despite a large opportunity pipeline for acquisition surveys, the process of formalizing projects and getting contracts signed has taken longer than expected. We are not satisfied with how the order book has developed during the quarter, ending at $144 million. We will operate six vessels during the winter in accordance with our plan for the year, but we will incur idle time in Q4 due to late commencement of some projects.

‘Looking beyond the near term challenge on vessel utilization, our market view is unchanged. We believe fundamentals are improving; with a Brent blend oil price in excess of $80 per barrel the total value of bids and leads for contract work at its highest level for more than 3.5 years and a strong increase in multi-client sales compared to last year.’

In its market forecast, PGS expects the higher oil price, improved cashflow among clients and an exceptionally low oil and gas discovery rate to benefit marine seismic market fundamentals going forward.

Based on current operational projections and with reference to disclosed risk factors, PGS expects full-year 2018 gross cash costs of approximately $600 million.

2018 multi-client cash investments are expected to be approximately $285 million. Approximately 65% of 2018 active 3D vessel time is expected to be allocated to multi-client acquisition.

The order book totalled $144 million at 30 September, 2018 (including $110 million relating to multi-client), compared to $187 million at 30 June, 2018 and $167 million at 30 September, 2017.

Weatherford sells laboratory business for $205 million Weatherford International has signed an agreement to sell its laboratory services business to a group led by CSL Capital Management for $205 million in cash.

Under the agreement, Weatherford will divest its laboratory and geological analysis business, including personnel and associated contracts. After exiting the laboratory business, Weatherford said that it will continue to maintain a close, collaborative relationship with CSL Capital that will enable it to continue to provide services to their joint customers.

‘Our intention is to invest in and grow this business to extend the leadership of

this world-class laboratory and reservoir description company to serve the developing needs of the energy industry,’ said Charlie Leykum, founding partner of CSL Capital.

The transaction is one in a series of planned divestitures intended to refocus the company’s portfolio on core businesses most closely aligned with its long-term strategy and to reduce its debt.

CSL Capital partnered with the Carlyle Energy Mezzanine Opportunities Fund II, L.P. to complete this acquisition.

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FIFTH INTERNATIONAL CONFERENCE ON FAULT AND TOP SEALS 8-12 SEPTEMBER 2019 • PALERMO, ITALY

JOIN US IN PALERMO! W W W. FA U LTA N D T O P S E A L S 2 0 1 9 . O R G

REGIONAL FOCUS:

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The Netherlands has been an active region for hydrocarbons exploration since the early Sixties. The country has 12 producing fields, dominated by gas exploration, but many of them are considered to be late in life and close to decommissioning. This month we focus on how geoscientists are continuing to demonstrate the great potential of the Dutch oil and gas sector and how mature fields can be reinviogorated to produce the gas that the country desperately needs.

Hanze platform still going strong It has been 17 years since production started on the F2a-Hanze platform. Dana is operator of the field which is producing light oil from naturally fractured chalks of Danian and Maastrichtian age. Typical chalk porosities of 20-38% are seen, and typical matrix permeability is around 5mD. The field has been developed with four horizontal/high angle production wells. Pressure support is provided through down dip water injection which complements an active aquifer. The chalk reservoir has proved to be a prolific producer and field production has been characterized by a long plateau production period, followed by a gradual increase in water cut. Ultimate recovery is expected to significantly exceed FDP with a recovery factor >50%. Not only is the reserves increase owing to the performance of the chalk reservoir, but it has also been due to diligent reservoir management over the life of the field.

The field was developed using long, horizontal production wells. High field production rates were sustained through cycles of acidization. These were used to

enhance production, both following drilling of the wells, as well as after prolonged production periods, when the wells would show a natural productivity decline. After acidization, the wells exhibited very large increases in production. Further, the production wells were retrofitted with Electrical Submersible Pumps which allowed much higher drawdowns to be realized than the previous gas lifted wells could achieve. This higher drawdown allowed more oil to be produced from the relatively tight chalk matrix.

The platform is now approaching its original design life of 20 years. In 2017, Dana embarked on a lifetime extension project to recertify the installation and ensure that the platform can operate safely for another 20 years. The plan involves careful, continuous investigation of structural integrity of the facility, along with a phased maintenance programme, designed to anticipate upcoming expenditure to aid planning. Finally, near-field exploration opportunities are being considered to provide potential additional production to extend the life of the platform even further.

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Shallow gas traps in the Cenozoic Southern North Sea delta, offshore Netherlands Johan ten Veen1, Geert de Bruin1, Timme Donders2, Hanneke Verweij1 and Kees Geel1 Introduction In the Southern North Sea, shallow gas is defined as gas that resides in shallow marine to continental (deltaic) deposits of the Plio-Pleistocene Southern North Sea (SNS) shelf-edge delta.

It is either structurally trapped in anticlines above salt domes, associated with lateral fault seals, or occurs in stratigraphic or depositional traps. Traditionally, shallow gas occurrences were regarded as hazardous or non-economic because of low gas saturations (‘fizz gas’). Even though the production of shallow gas still is a challenge, to date, four gas fields are producing (Van den Boogaard and Hoetz., this volume).

Kuhlmann et al. (2006) and Kuhlman and Wong (2008), were the first to link to the occurrence of potential gas (or rather acoustic anomalies in seismic data) to specific delta sub environments and stratigraphic intervals. They related variations in sediment properties to changing climate conditions under the inception of Late Cenozoic northern hemisphere glaciations.

Their study was instrumental in illustrating and promoting an improved understanding of external controls on shelf delta deposition to the benefit of exploration and production of shallow gas.

This paper focuses on the depositional setting of the bright spots and trap styles within the SNS delta and is based on a multi-disciplinary study that involved 1) paleoenvironmental- and paleoclimatological reconstructions, 2) seismic interpretation to reconstruct the internally complex delta body, and 3) estimation of temporal and lateral variability in reservoir and seal properties (Ten Veen et al., 2013). The results include a first classification of the shallow gas accumulations in terms of trapping style and sealing capacity. The physical and dimensional properties of the bright spots, i.e. the volumes and saturations of the associated shallow gas, are dealt with in the accompanying paper by Van den Boogaard and Hoetz (this volume) that also assesses the economics of shallow gas prospects.

Figure 1 Map showing study area within the Southern North Sea (SNS) Basin with thickness (metres) of Cenozoic sediments (excluding Danian); after Ziegler (1990) and Huuse (2002), modified from Wong et al.

(2007). Arrows show course of the main river systems that fed the SNS Basin.

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TNO - Geological Survey of the Netherlands | 2 Department of Physical Geography, Faculty of Geosciences

*

Corresponding author, E-mail: johan.tenveen@tno.nl

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Geological setting of the SNS delta The main structural element in the Southern North Sea is the Central Graben, a NNE-SSW Mesozoic structural element along which an intercratonic sag basin (referred to as the Central Trough) developed in the Cenozoic (Huuse and Clausen, 2001; Figure 1). This represents the area of greatest accommodation during the deposition of the Late Cenozoic Southern North Sea shelf delta in the study area (Ziegler, 1990). Rapid subsidence in the centre of the basin and uplift at margins are attributed to intraplate stresses (Overeem et al., 2001). Halokinesis of the Permian Zechstein salt layer occurred during both the Mesozoic and Cenozoic (Remmelts, 1996; Ten Veen et al., 2012) and continued until the Quaternary and attributed to many of the salt structures in the Southern North Sea. In the Early Miocene the Southern North Sea Basin covered most of present-day Denmark, northern Poland, Germany and the Netherlands (Møller et al., 2009). During the Cenozoic period, the North Sea Basin became bordered by the structural highs of Fennoscandia to the north east, by Western and Central Europe in the south and the British Isles in the west (Wong et al., 2007). From the Late Cenozoic period onwards the Baltic River system (Bijlsma et al., 1981), drained an area of ~1 x 106 km2 of Fennoscandia and northern Europe (Figure 1) and fed a giant delta system in the Southern North Sea Basin, which is comparable in size to the modern Amazon delta. The entire fluvio-deltaic system is referred to as the Eridanos delta (Overeem et al., 2001) or the Southern North Sea delta (SNS). In the Dutch northern offshore, it is mainly the shelf-edge delta that is preserved. It is characterized in seismic data (Figure 1) by progradational sigmoidal and oblique shelf-prism clinoforms that downlap on to the Mid-Miocene Unconformity (MMU). Late Miocene to Pleistocene progradation of SNS delta sediments was roughly from east to west and more proximal deposits have been encountered in the subsurface of the German offshore (e.g.

Thöle et al., 2014). This progradation is also reflected by overall upward coarsening, westward fining of the sediments (Schroot et al., 2005) and increased upward occurrence of near-shore biota (Donders et al., 2018). These trends are associated with glacioeustatic sea-level lowering by 100-150 m (cf. Miller et al., 2005) and a general climatic cooling from subtropical to icehouse conditions (Anell et al., 2012). In the adjacent East Anglia basin, the presence of NE- and SE prograding seismic

reflectors in Early Pleistocene deposits suggest that there was riverine input by UK sources into the basin as well (Cameron et al., 1987). The SNS delta is terminated by a fluvial topset of Early-Middle Cromerian age to which the southerly Rhine, Meuse and Schelde river systems contributed sediment as well (e.g. Westerhoff, 2009). The SNS delta system is truncated by the Late Pleistocene glaciogenic unconformity which over a large area is marked by the Elsterian Glacial valleys and overlain by Holocene deposits.

Data and results Seismostratigraphy

For the Plio-Pleistocene interval of the offshore A15 block, 13 key seismostratigraphic horizons and units were initially identified by Kuhlmann and Wong (2008; Figure 2) which were correlated to bio- and magnetostratigraphic levels and log patterns as defined by Kuhlmann et al (2006). All interpreted horizons delineate the top surfaces of distinct clinoform sets and demarcate significant breaks in deposition. The MMU forms the base of the studied sequence. The A15 seismic survey (Z3WIN2000A) has been used as a reference for the seismic interpretation of the entire study area (Figure 1) and was performed on publicly available 2D and 3D seismic surveys (Ten Veen et al., 2013). Well data and stratigraphic markers were converted to the time domain using a seismic-to-well tie, sonic- and checkshot data enabling the tracing of the seismostratigraphic units beyond the well-studied AB blocks.

Next to horizon interpretation, a seismic geomorphological analysis was performed on 3D seismic data. This resulted in the recognition of elongated contourite bodies, (incised) channels, pockmarks and other features that are of relevance for understanding the controls on delta evolution.

For all key seismic surfaces, the distribution of delta elements, such as topset-, foreset- and toeset-to-prodelta, has been determined, resulting in zonal maps indicating the distribution of these delta elements (Figure 3). Determination of delta element type was based on 1) the geometry of the surface, 2) palynological properties, 3) seismic attribute analysis to recognize paly-nological features (e.g. Stuart and Huuse, 2012), and 4) the relation with internal geometry of the zone beneath and above (downlap, toplap, etc.). Since the clinoforms represent shelf-prism clinoforms, the topset,

Interglacials

Glacials

• Relatively warm climate and relatively high sea surface temperatures • High freshwater input at the base of the interglacials • Relatively open marine conditions • Relatively coarse grainsize (moderate to good reservoir properties) • Relatively high sea level • Relatively high TOC content (possible source for biogenic gas) • Agradational-to-progradational clinoforms

• Relatively cold climate and relatively low sea surface temperatures • Almost no freshwater input • Relatively restricted marine conditions (water stratification) • Very fine grain sizes (excellent seal properties) •R elatively low sea levels • Relatively low TOC content • During seal-level fall: Strongly progradational and lowering clinoforms (forced regressive wedges) •D uring low stand: predominantly clay deposition (condensed section) • Ice berg scouring in shallow shelf areas • Fluvial incision in exposed areas

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Table 1 Listing of interglacial vs. glacial conditions and associated reservoir and seal characteristics.

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Figure 2 W-NE seismic cross-section (see Figure 1 for locality) showing the westward prograding Southern North Sea delta of Plio-Pleistocene age.

Seismostratigraphic units according to Kuhlmann et al. (2006).

Figure 3 Regional distribution of shelf-prism clinoform elements through time, with shelf (yellow), slope (green) and basin floor (blue) for units S4-S6 showing the regional distribution of delta elements (delta evolution) through time.

foreset and bottomset represent the shelf, the slope and basin floor (pro delta), respectively (Harding, 2015). The rollover point between the topset and foreset defines the shelf break.

Smaller-scale clinoforms, i.e. delta-scale clinoforms associated with individual prograding delta lobes, also exist and are sometimes superposed on the shelf clinoforms (Harding, 2015) and are not further considered here. Several zones only consist of one delta element, such as the S1 unit (basin floor facies) and the S12 and S13 units, which consist entirely of delta topset facies.

Paleoenvironmental and paleoclimatological reconstruction

An excellent chronostratigraphic framework available for the SNS succession enables the underlining of the strong coupling of sediment deposition and climate. The A15-3 key well (Figure 1) provides geomagnetic polarity data which enables the precise coupling to global standards (i.e. benthic ocean d18O) by several well calibrated biostratigraphic events and local d18O data (Donders et al., 2018). Based on palynological analysis, Kuhlman et al.

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(2006) demonstrated the long-term cooling trend from the MMU to the top of the SNS succession.

Quantitative palynological data (pollen) were used to calculate the ratio between tree pollen and herb pollen (the AP/NAP ratio), which positively correlates with temperature. A decrease in the SSTdino ratio, i.e., the ratio between ‘warm preference’ and ‘cool preference’ dinoflagellate cysts, is indicative of cooling trends in the marine environment (Figure 4). This trend is punctuated by a couple of distinct higher-frequency cold and warm peaks, interpreted as glacial-interglacial couplets controlled by 41,000year obliquity cycles. Palynological analysis also measured the sporomorph to dinocyst ratio (SD ratio), which shows the relative contribution of terrestrial vs. marine organic matter input and is a measure for proximity to the coast. A more extensive overview of the palynological and organic geochemical proxies is given by Donders et al. (2018).

In the lower part (S1-S4), the SNS succession contains open marine dinoflagellate cyst and benthic foraminifera assemblages.

These correlate roughly with the toe sets of the delta. The middle part (units S5-S7) represents deposition during an alternation

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of glacial- and interglacial periods. These contrasting climate conditions control the sediment supply both in quantity and type.

During the glacial periods the basin was starved and the limited terrestrial supply resulted in a condensed shale layer (Kuhlmann et al., 2004). During the interglacial periods there was a higher sediment influx and sand was deposited that was prone to being captured by contourite currents and accumulated in sandy contourites. Also, the source region of the delta varied in relation to climate change in the Late Cenozoic period. Cold periods coincided with Archean provenance from the Scandinavian shield with a high percentage of illite and chlorite owing to physical weathering of metamorphic rocks by glaciers (Kuhlmann et al., 2004). During the warmer climate conditions, coarser sediment was delivered to the basin by the Baltic river system. These grainsize variations are clearly expressed in both the measured silt fraction and the Gamma-Ray log. The climatically controlled clayey intervals deposited during cold conditions occur basinwide and act as regional seals. Thus, surprisingly, the warmest intervals or interglacials are coupled to the most coarse-grained sediments, and the coldest intervals or glacials are linked to the most fine-grained sediments.

Geochemical analysis indicated that high TOC content occurs in the silts (low gamma ray), coupled to high SST ratio (based on dinoflagellate cysts), and relatively warm climate (increased forest cover based on high AP/NAP) (Donders et al., 2018).

From S5 upward the SNS succession changes via transitional assemblages to restricted marine (S7-S10), with high-dominance and low-diversity dinoflagellate cyst assemblages.

The youngest depositional interval (S8-S13) was deposited in a shallow sea under arctic conditions with sea ice cover. Glacial plow marks are a frequent sight. Some of the units represent warmer periods with an open vegetation and more open marine conditions.

Bright spot mapping

Bright events can be caused by many geological and physical phenomena that cause a local and anomalous impedance contrast that differ from its surrounding. This study only focused on bright spots as DHI’s for gas-filled sand layers that appear as low impedance layers with anomalously high amplitude (Figure 5). If the gas-bearing layer is thick enough, the gas-water contact might be identifiable as a flat spot (Figure 5C).

It should be noted that the high amplitude, considering the absence of pre-stack amplitude information, is not indicative for gas saturation as even low saturations will produce high amplitude effects detected in post-stack data (Van den Boogaard and Hoetz, this issue).

The bright spots were mapped using an auto-tracker on all available 2D and 3D seismic data. This resulted in stacked bright spots being mapped separately. If bright spots are stacked it is common that the shallowest bright spot reflects most of the seismic energy back to the surface. Because of this transmission effect, the events below have very low amplitudes (Figure 5).

Consequently, bright spots below other bright spots sometimes do not meet the criteria for being an anomalously high amplitude event. However, in most cases bright spots become larger with depth (halo-shaped) and can therefore be partially mapped and extrapolated over the transmission domain. Additionally, the gas-filled sand exhibits a pull-down effect which increases with the number of stacked reservoirs (Figure 5A). Next to stacked bright spots, single elongated, bright spots occur that are associated with sandy contourites (Figure 5D) and bright spots that are aligned with the dipping clinoform foresets (Figure 5B); both types represent stratigraphic traps. Some bright spots types are associated with faults and if reservoirs thicknesses are above tuning thickness, gas-water contacts may be visible as flat spots (Figure 5C).

Figure 4 Correlation and interpretation of chronostratigraphy, Gamma-Ray log, seismic units, geochemical and palynological proxies, grain size. Data from Kuhlmann et al.

(2006), Kuhlmann and Wong (2008), Donders et al. (2018) and Ten Veen et al. (2013).

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Depositional model — synthesis The presented results enable to draw several important conclusions regarding the coupling between palaeoclimate, paleo sea level, the arrangement of sediment bodies, their morphological expression, rock properties and the occurrence of bright spots.

These conclusions enable the delineation of clear characteristics for reservoirs and seals deposited under interglacial (S1-S4), transitional (S5-S7) and full glacial conditions (s8-S13) as presented in Figure 6. Sea level is strongly controlled by paleoclimate and is in line with the expected trend associated with ice sheet build up: high sea levels during the interglacials, low sea levels during the full glacial and highly variable levels during the glacial-interglacial transition. The long-term sea-level trend shows shallowing from the MMU upward and is explained by the progressive infill of accommodation space through the advancing delta.

Distribution of bright spots Within the study area, bright spots are not present in the units S1-S3 but only in overlying units up until depths of ~450 m below the seafloor. Bright spots occur in delta topset, foreset and prodelta environments throughout all stratigraphic units.

Large foreset-type bright spots occur in the S5 foreset delta element in the north-eastern sector of the Dutch Central Graben and are also associated with faults and salt structures delineating the Dutch Central Graben. This suggests that the structural setting may have had a large control on the formation of shallow gas trapping. In the stratigraphically higher units, i.e. S7-S10 and S13-S14, bright spots only occur in topset beds (Figure 7), indicating that the other delta elements are outside the study area, i.e. farther west. Units S11 and S12 have bright spots in all three delta elements.

Elongated bright spots (Figure 7) occur throughout the area in unit S5, S6, S11 and S12, and are related to bright spots in sand contourite fields. Stuart and Huuse (2012) made paleographic reconstructions of the epicontinental North Sea Basin and hypothesised that tidally generated contour currents formed sandy contourites. This suggests open marine conditions prevailed.

Sequences S5 and S6 were deposited in a time of alternating glacial and interglacial periods. These contrasting climate conditions control the sediment supply both in quantity and type. During the glacial periods the basin was starved and the limited terrestrial supply resulted in a condensed shale layer (Kuhlmann et al., 2004). During the interglacial periods there was a higher sediment

Figure 5 Seismic examples of the various types of identified bright spots . A) Stacked bright spots with ‘pull-down’ effect indicative of multi-layer gas fields.

B) Small-stacked bright spots in clinoform foresets associated with fault zone. C) Bright spots in anticlinal closure with lateral fault seal with GWC visible as flat spot. D) Stacked bright spots in anticlinal (4WD) and bright spots in sandy contourites. Note the presence of amplitudes attenuation below the stacked bright spots owing to the transmission effect. All data was converted to and represented as zero-phase negative polarity, i.e. with bright spots in gas sands kicks represented as peaks (red).

Figure 6 Three depositional megasequences corresponding to specific paleoenvironmental conditions. Colours of the intervals correspond to those in Figure 4.

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Figure 7 A) Sandy contourite type bright spots in S5 and S6. B) Auto-tracked high amplitude reflections associated with sandy contourites of S5.

influx and sands were deposited that were prone to being captured by contourite currents and which accumulated in sandwaves.

Considering that sufficient sea-bottom current activity requires open marine conditions, the presence of contourites in units S11 and S12 indicate a short-lived revival of open marine conditions during the arctic period. This is corroborated by the lower SD ratio in this interval that indicates higher marine influence, which was possibly invoked by a temporal change in oceanic circulation causing melting of the existing sea ice cap.

The spatial distribution of stacked bright spots is closely related to salt domes and ridges forming the structural control on anticlinal closures. Many of the stacked bright spots are not only salt-related, but also fault-related since the salt structures incite fault systems in the overburden as well (e.g. Figure 5C).

References Anell, I., Thybo, H. and Rasmussen, E. [2012]. A synthesis of Cenozoic sedimentation in the North Sea. Basin Research, 24, 154-179.

Bijlsma, S. [1981]. Fluvial sedimentation from the Fennoscandian area into the north-west European basin during the late Cenozoic.

Geologie en Mijnbouw, 60, 337-345.

Cameron, T.D.J., Stoker, M.S. and Long, D. [1987]. The history of Quaternary sedimentation in the Uk sector of the North Sea Basin.

Journal of the Geological Society, 144, 43-58.

Donders, T.H., Weijers, J.W.H., Munsterman, D.K., Kloosterboer-van Hoeve, M.L., Buckles, L., Pancost, R.D., Sinninghe Damsté, J.S. and Brinkhuis, H. [2009]. Strong climate coupling of terrestrial and marine environments in the Miocene of northwest Europe. Earth and Planetary Science Letters 281, 215-225.

Donders, T.H., Van Helmond, N.A.G.M., Verreussel, R.M.C.H., Mun-

Conclusions The depositional model presented for the SNS delta is important for understanding the trapping of shallow gas within the SNS delta and is made explicit through a series of palynological proxies. The delta sediments were laid down at the time the first ice caps appeared on the Scandinavian shield. This so-called onset of northern Hemisphere glaciations resulted in a series of glacial-interglacial cycles that had a profound impact on the SNS delta behaviour and on the resulting basin-fill. The relevance of the climatic cycles is the fact that they occur basin-wide and control the deposition of clay/silt couplets with good sealing capacity (clays) and reservoir bodies with enhanced TOC. Consequently, the shallow gas occurrences in the northern Dutch offshore are constrained to specific stratigraphic intervals with recurring combinations of physical properties. The physical properties of reservoirs and seals are determined to a high degree by paleoenvironmental parameters such as climate, productivity and sea level.

sterman, D.K., Veen, J. Ten, Speijer, R.P., Weijers, J.W.H., Sangiorgi, F., Peterse, F., Reichart, G.-J., Sinninghe Damsté, J.S., Lourens, L., Kuhlmann, G. and Brinkhuis, H. [2018]. Land-sea coupling of early Pleistocene glacial cycles in the southern North Sea exhibit dominant Northern Hemisphere forcing. Climate of the Past, 14 (3), 397-411.

Harding, R. [2015]. Evolution of the giant southern North Sea shelfprism: testing sequence stratigraphic concepts and the global sea level curve with full-three dimensional control. PhD thesis, University of Manchester, 293.

Huuse, M. and Clausen, O.R. [2001]. Morphology and origin of major Cenozoic sequence boundaries in the eastern North Sea Basin: top Eocene, Near-top Oligocene and the mid-Miocene unconformity.

Basin Research, 13, 17-41.

Huuse, M. [2002]. Cenozoic uplift and denudation of southern Norway: Insights from the North Sea basin. Geological Society, London, Special Publications 196, 209-233.

Kuhlmann, G., de Boer, P.L., Pedersen, R.B., Wong, Th.E. [2004].

Provenance of Pliocene sediments and paleoenvironmental chang-

Acknowledgments The workflow and some of the results presented here were developed for the Joint industry Project ‘Shallow Gas’ (TNO, 2013) which was sponsored by Dana Petroleum Netherlands B.V., Total E&P Nederland B.V., Oranje Nassau Energie B.V., Petrogas/Chevron Exploration and Production Netherlands B.V., Energie Beheer Nederland. We would like to thank the sponsors of the project for sharing their insights.

es in the southern North Sea region using Samarium–Neodymium (Sm/Nd) provenance ages and clay mineralogy. Sedimentary Geology, 171, 205-226 Kuhlmann, G., Langereis, C.G., Munsterman, D., van Leeuwen, R.-J. Verreussel, R., Meulenkamp, J. and Wong, Th. E. [2006]. Chronostratigraphy of Late Neogene sediments in the southern North Sea Basin and paleoenvironmental interpretations. Palaeogeography, Palaeoclimatology, Palaeoecology, 239, 426–455.

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Kuhlmann, G. and Wong, Th.E. [2008]. Pliocene palaeoenvironmental

Ten Veen, J.H., Geel, C.R., Kunakbayeva, G., Donders, T.H. and Ver-

evolution as interpreted from 3D-seismic data in the southern

reussel, R.M.C.H. [2011]. Property prediction of Plio Pleistocene

North Sea, Dutch offshore sector. Marine and Petroleum Geology,

sediments in the A15 shallow gas system. TNO Report TNO-060-

25, 173-189.

UT-2011-01184/C12.

Miller, K.G., Kominz, M.A., Browning, J.V., Wright, J.D., Mountain,

Ten Veen, J., Verweij, H., Donders, T., Geel, K., De Bruin, G., Munster-

G.S., Katz, M.E., Sugarman, P.J., Cramer,B.S., Christie-Blick, N.

man, D., Verreusel, R., Daza Cajigal, V., Harding, R. and Cremer,

and Pekar, S.F. [2005]. The Phanerozoic record of global sea level

H. [2013]. Anatomy of the cenozoic Eridanos Delta Hydrocarbon

change. Science, 310, 1293-1298.

system. TNO report 2013 R10060.

Møller, L.K., Rasmussen, E.S. and Clausen, O.R. [2009]. Clinoform

Thöle, H., Gaedicke, C., Kuhlmann, G. and Reinhardt, L. [2014]. Late

migration patterns of a Late Miocene delta complex in the Danish

Cenozoic sedimentary evolution of the German North Sea – a

Central Graben; implications for relative sea level changes. Basin

seismic stratigraphic approach. Newsl. Stratigr., 47 (2014), 299-

Research, 21, 704-720.

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Overeem, I., Weltje, G.J., Bishop-Kay, C. and Kroonenberg, S.B.

Van den Boogaard, M. and Hoetz, G. [2018]. Prospectivity analysis

[2001]. The Late Cenozoic Eridanos delta system in the Southern

of shallow gas in the Netherlands. First Break, 36 (12), 59-

North Sea Basin: a climate signal in sediment supply? Basin Research, 13(3), 293-312.

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Westerhoff, W.E. [2009]. Stratigraphy and sedimentary evolution.

Remmelts, G. [1996]. Salt tectonics in the southern North Sea, the

The lower Rhine-Meuse system during the Late Pliocene and

Netherlands. In: Rondeel, H.E., Batjes, D.A.J. and Nieuwenhuijs,

Early Pleistocene (southern North Sea Basin). PhD thesis, Vrije

W.H. (Eds.), Geology of gas and oil under the Netherlands. Kluwer Academic Publishers (Dordrecht), 143-158.

Universiteit Amsterdam, 168.

Wong., Th.E., de Lugt, I.R., Kuhlmann, G., Overeem, I. and Herngreen,

Schroot, B.M., Klaver, G.T. and Schüttenhelm, R.T.E. [2005]. Surface

G.F.W. [2007]. Tertiary. In: Th.E. Wong, D.A.J. Batjes and J.

and subsurface expressions of gas seepages to the seabed – exam-

De Jager (Eds.). Geology of the Netherlands. Royal Netherlands

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Academy.

Ziegler, P.A. [1990]. Geological Atlas of Western and Central Europe

Stuart, J.Y. and Huuse, M. [2012]. 3D seismic geomorphology of a large Plio-Pleistocene delta – ‘Bright spots’ and contourites in the

(3rd edition). Shell International Petroleum Maatschappij B.V., 239.

Southern North Sea. Marine and Petroleum Geology, 38, 143-157.

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Oil Fields in the Dutch Offshore: from 2D to depletion Bert Manders, CGG

Figure 1 Dutch offshore oil production from 1982 to 2018.

Gas dominates the Dutch Offshore, but about 10% of the extracted hydrocarbons consists of oil. The E&P history of the 12 developed oil fields is reviewed below.

Exploration started in the 1970s with 2D seismic surveys. Most of the oil finds date back to the early 1980s and were located in the southern sector. Early exceptions are Amstel in 1962 (based on gravity surveys) and F3-FB in 1974, while Hanze and De Ruyter of 1996 were relatively late. Rembrandt in 2012 was the last oil discovery.

A cumulative 250,000 km of 2D seismic had been shot in the late 1970s. This corresponds to an average line-spacing of 250 m, which was dense enough to delineate most oil prospects.

After 2D activity peaked in 1985, 3D seismic acquisition took over in the 1990s. Although Hanze and Rembrandt are the only discoveries made with 3D, all oil-producing fields received 3D surveys later, mainly to improve the reservoir image and optimize in-fill drilling.

Reservoirs occur at depths of between 1500 m (fields in block Q1) and 2500 m for F3-FB. This is much shallower than the 3000m for the standard Rotliegend gas reservoirs. Early Cretaceous sandstones are the common oil reservoirs, while De Ruyter and F3-FB are in Triassic and Jurassic sandstones. Hanze has Upper Cretaceous Chalk and, thanks to good permeabilities, the field is remarkably efficient. The fractured carbonates produced 60 million barrels (Mbo), almost double the predictions. The worst recovery is in the poorly permeable Lower Cretaceous sandstones of the Horizon field, which delivered less than 10% of the in-place oil.

Development of the oil fields was remarkably fast. The usual time between discovery and first oil was only five years. Exceptions are again Amstel and F3-FB, which took 50 and 20 years to come on stream. The very first oil delivery came from the Helder field in the Q1-block in 1982. Already in 1986 the combined output peaked at 75,000 barrels of oil/day (bopd), reducing in a typical saw tooth pattern to 10,000 bopd in 2018 (see Figure 1). A total of 400 Mbo was produced up to 2018.

Operators changed hats often and none of the assets is with the original developer. Early birds were Union, Amoco and Conoco.

F3-FB was connected by NAM, which sold it to GDF later.

Petro-Canada started Hanze and De Ruyter before Dana took over. Other long gone names include Chevron, BP, Veba and Clyde. Even the latest field Amstel switched ownership from Engie to Neptune already. Operators with currently active oil fields are Petrogas, Taqa, Neptune and Dana.

Depletion and decommissioning are the final inevitable steps in the E&P cycle. Few new production wells were drilled in the older fields during the last decade, although Taqa recovered 10% extra oil so far by refurbishing Rijn. Reducing operational costs (Opex) is the main challenge for the depleting tail-end fields. Opex is spent on work-overs, injecting water and processing vast volumes of oily formation waters. For instance, Kotter and Logger treated 12,000 barrels of liquids a day to recover 500 bopd. These two fields together with Helm, Hoorn and Haven of Petrogas were closed in the last few years. Three platforms are producing less than 1000 bopd and may shut down in the short term, especially at the current oil price.

The marginal L5a-E (Neptune) and Horizon-West (Petrogas) are unlikely to be developed, while Wintershall continues to delay the final investment decision for Rembrandt.

The final step for the five companies responsible for oil platforms will be plugging about 100 producers and injectors and removing the 12 facilities.

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Seismic discrimination of an overlooked basal Rotliegend reservoir opens a new play in the Dutch offshore C.L. Burgess1*, J.E. Clever1, O.J. Corcoran1, F.M. Cram1, N.T. Hall1 and S.F. Lunn1 Introduction The Ruby discovery in the summer of 2017 has been cited as the largest gas discovery in the Netherlands offshore for the last

Figure 1 ONE’s acreage in the Netherlands and Germany. The N05-A field, formerly Ruby, discovery in 2017 is shown in the GEms acreage. The various licences, GEms, 4Quads, Geldsackplate and H&L make up the collectively named Geldsack.

25 years (Het Financieele Dagblad, 2017), opening a new Dutch play with more than 1 tcf of low risk prospectivity. The Ruby discovery has since been upgraded to a field and renamed N05-A. The play comprises the basal Rotliegend sandstone reservoir — fluvial, alluvial and aeolian sands deposited on the variable topography of the Base Permian Unconformity. The seal is provided by intra-formational shales and evaporites of the Lower Silverpit Formation and the source rocks are coals of the Westphalian Coal Measures.

Ruby was a seismically driven prospect. Historical wells targeting the Rotliegend in this area were sited on structural highs that mostly proved to have poor reservoir development.

Significantly, these were all drilled on 2D seismic data. The key advance made in the exploration workflow in recent years was to use geological knowledge and 3D seismic data to delineate reservoir fairways within the play. In particular, key learnings from well and seismic data on the German side of the median line were used to map the basal Rotliegend sand directly on 3D seismic data in the Netherlands and thereby challenge the established industry perception that this area of the Dutch offshore was shale prone.

This paper describes the work undertaken over the last ten years by Hansa Hydrocarbons Ltd. (Hansa), and subsequently its partner Oranje-Nassau Energie B.V. (ONE), which led to the drilling of the commercial discovery in 2017. After the acquisition of Hansa by Discover Exploration in early 2018, ONE took over

Figure 2 Upper Rotliegend stratigraphy architecture.

The previously published stratigraphic model indicates that Hansa’s acreage (now ONE’s) in the Dutch sector is shale prone (after Van Adrichem Boogaert and Kouwe, 1993-1997).

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Oranje-Nassau Energie B.V. (formerly with Hansa Hydrocarbons Ltd.)

*

Corresponding author, E-mail: camille.burgess@onebv.com

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operatorship of the three Dutch and German licences (GEms, Geldsackplate, 4Quads). Discover remains a partner in all three of these licences and the adjacent H&L licence in Germany. EBN is also a partner on the Dutch licences (GEms and 4Quads).

Exploration history Figure 1 shows ONE’s Dutch and German licences, collectively called the Geldsack, named after a sand bar in the Ems estuary.

This area is relatively underexplored with sporadic exploration activity on both sides of the median line since the 1960s. A number of discoveries in the German area (L1-1 (1975), L2-D1x (1965) and H18-1 (1982)) and several water-bearing wells (P1A, M1 and A1) proved a thick (11-44 m net) basal sandstone sequence with excellent reservoir quality. In the Netherlands, a number of wells (G18-01, H16-01, M03-01, N04-01 and N0402) were drilled to test a series of structural highs. These five wells encountered thin (1-5 m) gas-bearing basal Rotliegend sandstones (Figure 2). Consequently reservoir development was seen as the key risk in the Dutch area. As a result of the additional risks of seal integrity and nitrogen content, explora-

tion ceased and the area remained overlooked. At this point in time, no well had been drilled on 3D seismic data to test this play.

Figure 1 shows the current distribution of the 3D seismic datasets. In 2014, Hansa acquired 1000 km2 of 3D seismic data, the ‘4Quads’ survey, filling a large gap in 3D coverage with the Rotliegend basal sand target in mind. Generally, 2D seismic coverage in the Netherlands is dense but comprises a variety of vintages and quality is generally poor sub-salt.

In Germany there is virtually no 3D seismic coverage in the southern German North Sea, but the 2D seismic data quality is better.

Sonic and density logs from the German wells show that the basal Rotliegend sand has a lower relative acoustic impedance (AI) than the overlying Rotliegend shales and the underlying sub-cropping Carboniferous. This sand signature can be seen on the vintage 2D seismic data. Despite the well-to-seismic correlations, there was still scepticism that a sub-salt, approximately 25 m sand, could be discriminated on the vintage 2D seismic data.

Figure 3 L1-2 well drilled in Germany shows the sands corresponding to a low acoustic impedance unit, the mapped negative (red) interval on the coloured inversion (after Corcoran and Lunn, 2014).

Figure 4 The basal Rotliegend sand can be mapped from Germany into the Netherlands where the reservoir is proven. No low acoustic impedance body is mapped at N0402 where only thin basal Rotliegend Sandstones were encountered. Inset map is top reservoir depth.

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allowing the prospectivity to be matured quickly, resulting in a number of prospects and leads being identified. Despite numerous cross-border challenges, the Ruby prospect was seen as the best play-opening well and was worked up to drill-ready status.

Figure 5 Upper Rotliegend stratigraphy architecture adapted to reflect the new geological model (after Van Adrichem Boogaert, and Kouwe, 1993-1997 and Schröder et al., 1995).

Figure 6 Line through N05-01-S1 and S3 on the coloured inversion volume. Both wells display gamma ray curves. Inset map is top reservoir depth surface.

Play enabler: seismic discrimination of the basal Rotliegend sand Hansa entered into the German offshore in 2009 when it farmed into the ‘H&L’ blocks. In 2010, Hansa participated in the drilling of well L1-2, an appraisal well to the L01-Alpha basal Rotliegend discovery. The well was water-bearing, but did encounter an excellent quality, 28 m net basal Rotliegend reservoir section.

The acquisition of modern Vp, Vs, density and VSP enabled the generation of a good-quality synthetic and seismic tie to be established.

L1-2 confirmed the low AI basal Rotliegend sand signature as seen in the vintage wells. Furthermore, it demonstrated that the top and base of the reservoir package corresponded to a peak-trough pair on seismic data that could be interpreted from line to line. Simple coloured inversion proved to be the most effective approach for enhancing the seismic response of the sand (Figure 3).

Direct mapping of the low AI unit enabled the basal Rotliegend reservoir fairway to be extended from Germany across the median line into open acreage in the Netherlands which historically was seen as non-prospective (Figure 4). Having gained confidence in reservoir presence, Hansa applied for the open acreage on both sides of the median line.

In conjunction with the regional seismic mapping, a multi-disciplinary approach was taken to try to correlate the basal Rotliegend across the whole Geldsack area, integrating chemostratigraphy, petrography, provenance studies and biostratigraphy to further develop the geological model and mature the play.

Fortuitously, the play extension from Germany to the Netherlands continued into areas covered by 3D seismic data, 40

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Ruby gas discovery (N05-01) and the confirmation of a new Dutch play With reservoir presence largely derisked, seal integrity was now the critical risk. Undaunted by this, in 2016, ONE farmed into part of the Geldsack acreage. In May 2017 the partnership drilled well N05-01, which encountered 28 m of high permeability gas-bearing sand. The pre-drill thickness prediction from the seismic data was 29 m. A core was taken over the whole reservoir interval and a DST was run, which flowed at 53 mmscf/d constrained by surface facilities. After the discovery, a geological side-track was drilled. Both wells targeted the low AI unit seen on the coloured inversion (Figure 6), proving the seismic signature of the basal Rotliegend sand.

Forward work ONE and its partners are now embarking on an extensive work programme for the area: • A drilling campaign across the whole of the Dutch and German Geldsack acreage.

• A large 3D seismic reprocessing project.

• 2D seismic reprocessing.

• A new 3D seismic survey acquisition.

Conclusions Seismic discrimination of the Rotliegend basal sand through routine geophysical techniques has allowed the challenge of the established industry perception. An area thought to be barren of sand actually has a significant sand development. The Ruby discovery well, N05-01, is the culmination of a decade of work on the basal Rotliegend play in Germany and the Netherlands and has proven to be a significant discovery, opening up a new play with more than 1 tcf of low risk prospectivity.

Acknowledgements The author would like to thank Hansa Hydrocarbons for the opportunity to work on the play, and to ONE for retaining the team to continue to work the area. ONE would like to thank their partners, Discover Exploration and EBN, for their continuing support and contributions to the work on the Geldsack play.

References Corcoran, O.J. and Lunn, S.F. [2014]. Old play, new prospectivity - the revival of the basal Rotliegend play, offshore Netherlands and Germany. 76th EAGE Conference & Exhibition (abstract).

Het Financieele Dagblad, accessed online 28/9/2017.

Schröder, L., Plein, E. and Bachmann, G.H. [1995]. Stratigraphische Neugliederung des Rotliegend im Norddeutschen Becken (New Stratigraphic subdivision of the Rotliegend formation of the North German Basin). Geologisches Jahrbuch, Reihe A, Band A 148.

Van Adrichem Boogaert, H.A. and Kouwe, W.F.P. [1993-1997]. Stratigraphic Nomenclature of the Netherlands. https://www.dinoloket. nl/permian.

REGIONAL FOCUS: THE NETHERLANDS

An integrated field-wide isolation strategy as a key enabler of high-quality, durable and cost-effective abandonments (case history of Roswinkel field abandonment, onshore NL) Malte Schluter1* and Dimas Kodri1 Introduction ‘Decommissioning is part of the normal life cycle of every oil and gas structure and must be done safely and responsibly when a facility reaches the end of its life’ (Shell Sustainability Report, 2016).

A critical part of a successful decommissioning and restoration (D&R) project is the plug and abandonment (P&A) of the existing wells. An appropriate subsurface P&A ensures that any kind of fluid, including unproduced hydrocarbons, is kept safely underground. This could be especially challenging for mature assets with old wells which may have developed integrity issues that need to be remediated.

Projects such as the D&R of a field with several production locations and multiple associated wells, are best done in a campaign mode so that the project can benefit from the synergy of various disciplines, assets or even between operators. In 2016, the Nederlandse Aardolie Maatschappij (NAM) started the journey of abandonment campaigns by identifying and maturing the opportunity to plug and abandon a Triassic sandstone gas field in the eastern part of the Netherlands, Roswinkel (Figure 1). A dedicated Roswinkel abandonment team was put in place consisting of various disciplines, e.g. reservoir engineering, production geology, petrophysics, geophysics, production technology, well engineering, completion engineering and specialists on an as needed basis, e.g. geomechanics, geochemistry or structural geology.

Roswinkel field The Roswinkel field is located in the eastern part of the Netherlands and can be geologically described as an ENE/ WSW trending anticlinal structure. The Triassic sediments are subdivided into a clastic Lower Germanic Trias Group (RN) and an evaporitic Upper Germanic Trias Group (RB). The deposits of the RN mainly comprising the sandstone reservoir and can be further subdivided into three producing formations: Volpriehausen, Detfurth and Basal Solling Sandstone. The source rock for the gas is Upper Carboniferous. The thick RB formations of the Solling Claystone and the evaporitic Röt salt directly overlying the Lower Triassic reservoir units are creating the top seal, while a four-dip closure structure is providing the lateral seal (Figure 2).

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Corresponding author, E-mail: malte.schluter@shell.com

The Roswinkel field was discovered in 1976 and production started in 1980 from seven out of the nine wells that were drilled.

The field eventually ceased production in 2004 after a cumulative production of 17.1 BCM (recovery factor of around 82%). From the pressure data at end of production, it was apparent that the Volpriehausen sandstone is at a high pressure (~300 Bar) compared to the Detfurth and the Basal Solling sandstone (60-100 Bar). It was not possible to assess whether the Detfurth and Basal Solling are at different pressure regimes as they have never been produced separately and there was also no separate pressure point aside from the initial RFTs. However, there is a clear indication of aquifer support from the pressure recovery observed in both the

Figure 1 Geographical location of the Roswinkel field.

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Figure 2 Schematic cross-section of the Roswinkel field, incl. overburden. The stratigraphic chart defines further which formations can be generally grouped into reservoir, caprock and overburden with associated fluid fill and evaluated pressure regime, respectively.

Figure 3 Schematic well status diagram with respect to reservoir units and stepwise improvement of zonal isolation at Roswinkel.

Volpriehausen and Detfurth-Solling sandstone, which is expected to bring the reservoir closer to initial pressure in the future.

Isolation strategy General

The easiest method to identify a suitable caprock for a reservoir is to use the directly overlying seal, as this is proven by nature to keep fluids in the ground on a geological timescale. However, the subsurface team needs to evaluate the overburden data in more detail to identify formations with similar sealing potential as the directly overlying seal might not be available for restoration, for example owing to mechanical issues in the wellbore. The integrated view of the various disciplines within the team should at least cover field scale, or even, region or basin scale to identify the main risks to loss of containment over large lateral and temporal range. The benefit of understanding the subsurface system and interaction of the various

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formations is to provide a durable zonal isolation strategy which is based on the natural, geological processes and is supported by latest industry standards, i.e. NOGEPA45. The integrated understanding of the subsurface with respect to the pressure regime, lithology, fluid types, the identification of potential flow-zones with their natural seals associated, and the interaction of all those elements, is therefore crucial. The focus should be on front-end loading of available data from all disciplines involved, followed by sharing and alignment in a joint team discussion. Experience shows that it is beneficial to create this common understanding in a single event, such as a multi-disciplinary workshop with a facilitator setting up the objective, preparing the meeting and summarizing the outcome with tangible action points. The key outcome is a risk-based field wide isolation strategy which needs to be geologically consistent across the field, but also in line with regulations at an individual well level.

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Initial

For Roswinkel, the team started the design work with the focus on avoiding any unintended flow, including sub-reservoir to sub-reservoir flow. After every discipline gave their individual input, the recommendation was to put an isolation plug between all reservoir units, i.e. to isolate the Volpriehausen, Detfurth and Basal Solling sandstone in addition to the isolation plug above Volpriehausen (Figure 3). The intra-reservoir isolation plug was deemed to be required as the pressure differential is at the current stage high and a concern existed that fluid movement between Volpriehausen to Detfurth/Basal Solling might have negative consequences. This isolation strategy was then transferred from the subsurface team to the well engineering team and translated into technical solutions at individual well level.

During further maturation of the project, it became obvious that the initial strategy would be challenging during execution leading to low probability of success and increased cost, eventually.

Finally, the Roswinkel project team went back to the drawing board to further understand the residual risk of accepting crossflow between the individual reservoir flow units, once realizing that the technical solution of the initial three-plug reservoir isolation strategy is very challenging. Part of this re-assessment was a fit-for-purpose, dynamic reservoir model to assess the pressure behaviour and risk of cross flow. From the model, two important conclusions were established: 1. The pressure of the Detfurth-Basal Solling is on an increasing trend, likely to be owing to aquifer support, which means the pressure difference with Volpriehausen will decrease with time, 2. Any crossflow from Volpriehausen could be accommodated by the Detfurth-Basal Solling owing to the reservoir size itself where Detfurth-Basal Solling is approximately three times bigger.

The model outcome was supported by a pressure point taken prior to the execution in one of the Roswinkel wells to validate the conclusions of the modelling work.

The dynamic model therefore reaffirmed that the entire sub-reservoir of Lower Germanic Trias of the Roswinkel field is in hydraulic connection at a geological timescale. This is supported by the information that all reservoir flow units share same initial gas-water contact, i.e. can be treated as one hydraulic unit during further evaluation of field-wide isolation strategy.

At this stage it was critical to reflect and align the common understanding of the field data and implications at well level within the full Roswinkel abandonment team. This was achieved by combining all data and all involved disciplines in a single session. The available subsurface data, e.g. lithology, gamma-ray, density, caliper and all well engineering data such as well status diagram, casing size, shoe depth and cement bond logs (top of cement evaluation included) was displayed side by side, discussed with all team members and risk evaluated with respect to the best position of the plug setting depth (Figure 4).

Plotting the plug depth with respect to expected pore pressure and associated fracture pressure is very valuable for the risk assessment and to find a common understanding on the shallowest recommended plug depth. This was accompanied by a check of the structural geology to identify formations which need to be of sufficient thickness and consistently present across the whole field without any large fault offset to ensure seal integrity.

Based on the understanding of the long-term dynamic reservoir behaviour, the decision was taken during the integrated isolation strategy session that a single plug isolation is adequate. It was recommended to set the plug across the natural, regionally available seal of Upper Germanic Trias evaporitic sediments, e.g. RĂśt Main Evaporite (mainly salt). The detailed design work on the technical solution of the individual wells resulted

Figure 4 Integrated data visualization on geological, petrophysical, well engineering and geomechanical data. Only three wells are shown as examples. During the Isolation strategy session all wells are plotted and discussed. Note that the mechanical well data is reflecting the final isolation status, including cement plugs across the full wellbore diameter. The focus of this article is on the reservoir isolation.

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in a simpler and more robust approach with a higher technical probability of success, based on the updated final field-wide isolation strategy (Figure 3).

The updated strategy was discussed and accepted by the regulator prior to the start of the abandonment campaign, which was executed safely and successfully in 2017, on time and at competitive cost. The lessons learnt from this project are applicable for any scale of abandonment. It is for now considered as best practice standard for continuing and future abandonment campaigns by the NAM.

the initial plan using a more traditional approach of separating individual flow units (i.e. defined by different pressure during production time) of the sandstone reservoir, resulted in a technically challenging solution with low probability of success. The integrated reassessment of the approach by the multi-disciplinary team resulted in a solution which was considered fit for purpose and as-low-as-reasonably-practicable (ALARP). The new strategy has proven to be the key enabler for safe, in-time and at competitive cost abandonment for the Roswinkel field.

The end of the Roswinkel field P&A is just the start for future P&A campaigns in NAM. More than 770 wells currently in use onshore Netherlands (Nexstep, 2018) will need to be plugged and abandoned in a safe, durable and efficient manner and it will be therefore crucial to replicate and apply the onshore learnings to the offshore realm, eventually.

Conclusion Profound subsurface understanding and integration of various disciplines is a key enabler to identify a fit for purpose fieldwide isolation strategy. The initial focus should be to minimize the risk of harm to people and the environment owing to loss of containment or even induced seismicity, while considering the geological context and future subsurface activities, such as further exploration or geothermal development. In particular, the ALARP approach on the individual well solutions should be integrated in the standard workflow of future abandonments.

The multi-disciplinary integration needs to happen in line with government requirements (law), the latest industry standards (NOGEPA 45) and if applicable with other operators of the same basin (Nexstep). The case study of Roswinkel showed that

References Nexstep [2018]. Re-use & decommissioning report, https://nexstep. nl/wp-content/uploads/2018/07/Re-use-decommissioning-report-2018-English-Version.pdf NOGEPA [2018]. Standard 45 – Well Decommissioning, https://www. nogepa.nl/download/standard-45-well-decommissioning/ Shell [2016]. Sustainability Report, http://reports.shell.com/sustainability-report/2016/managing-operations/decommissioning-and-restoration.html

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Geophysics in the driving seat of multi-disciplinary integration Eva-Maria Rumpfhuber1*, René Frijhoff 2 and Clemens Visser 2 Introduction One of the key challenges for oil and gas companies holding a mature development portfolio is to maximize the value of their assets. The goal is to look for ways to increase the ultimate recovery of (poorly drained) producing fields, and for undrilled near-field opportunities. The first category is worked by drilling of additional drainage points or the execution of a well, reservoir and facility management (WRFM) programme. The second category typically consists of geologically complex structures with limited associated gas initially in-place (GIIP) volumes, which reduces the economic feasibility of such projects. Both categories can benefit from a thorough revision and update of the reservoir models, thereby incorporating all information from well, production and seismic data acquired over the lifetime of the fields.

Such an integrated reservoir model update usually takes place while production is continuing, and therefore the associated time and cost are often heavily scrutinized. It is essential to ensure that the ever more detailed knowledge on a field is honoured by taking a truly multi-disciplinary approach. This effectively enables integration and allows the reservoir model updates to be done faster, cheaper and better.

The technical disciplines involved in a reservoir model update are production geology, petrophysics, reservoir engineering and geophysics. The first three disciplines spend a majority of their time analysing data and information from existing wells in a field and/or within a particular reservoir. Geophysicists, in contrast, spend the majority of their time with seismic data.

The challenge for geophysicists is that seismic data measures impedance contrasts (velocity times density), and therefore statements about the reservoir properties net-to-gross (NtG), porosity (Por), and saturation (Sat) can only be made indirectly. Yet seismic

Figure 1 Concept of Check the Loop as a two-stage forward modelling workflow: 1) Convert a reservoir model with net-to-gross, porosity and saturation properties into a velocity and density model. QC at well locations by comparing with wireline velocity and density logs. 2) Convert the velocity and density model into synthetic seismic data and qualitatively assess against measured seismic data.

data, if understood within the geological framework, can help to unravel lateral variations of reservoir properties away from existing well locations. Therefore, it can address the critical question about whether the existing wells provide a representative sample of the hydrocarbon accumulation. This is crucial for uncertainty range estimation, more specifically for defining a robust low case, i.e. to reduce the risk of pursuing an uneconomic project.

To fully exploit seismic data, the NAM reservoir modelling community has employed the simple and fast workflow called ‘Check the Loop’ (ChTL) on a number of projects. ‘Check the Loop’ is a long-standing seismic forward modelling workflow within Shell, as opposed to ‘Close the Loop’, which involves seismic inversion and hence takes more time and effort. The ChTL workflow is a two-step process where by the reservoir model (NtG, Por, Sat) is first converted into acoustic/elastic properties (velocity and density) and then turned into synthetic seismic data (Figure 1). The resulting synthetic seismograms can subsequently be qualitatively assessed against the actual seismic data.

The workflow requires integration of all data (seismic, wells, and reservoir model), which reinforces a multi-disciplinary discussion and enables a feedback loop between the reservoir modeller and the geophysicist. Once set up, any model update can be calculated within minutes and therefore any question from the reservoir modeller can be addressed with fast turnaround.

The case studies below show some of the examples where geophysics was closely interlinked in reservoir modelling via the Check the Loop workflow, and as a result the true multi-disciplinary integration had a significant business impact. The questions that can be addressed with this workflow are wide-ranging, from checking updated petrophysical analyses (case study 1) and selecting representative wells for modelling (case study 2), to a comparison between a static and an upscaled dynamic model (case study 3).

Case study 1: Testing petrophysical updates with seismic data (offshore UK) Rebuilding of an existing reservoir model triggered this check the loop analysis, while static modelling and a petrophysical re-evaluation of the log data was continuing. The petrophysical analysis tested various ways of evaluating net-to-gross ratio for the prospect, which is an important aspect of estimating uncertainties. The forward modelling of the original static model from 2016 shows a good fit (Figure 2) between sonic and density logs (red) and its predictions (blue). In 2017 an alternative reservoir model was tested with a significantly lower NtG and

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shows a dim response at the same location. After a discussion with all technical disciplines involved, it was decided to exclude the second well from the reservoir model based on the data quality concerns mentioned above. Excluding this well in the model led to a more robust estimation of GIIP, and a better match of actual and synthetic seismic data. The turnaround for this integrated analysis was only three days.

Figure 2 Left: GIIP estimates derived from static models in 2016 and 2017, and a dynamic model from 2017, compared to cumulative production at the end of 2017. Right: Well panel with logs in red indicating net-to-gross (NtG), porosity (Por), hydrocarbon saturation (SH), density (Den), velocity from sonic (Vp), and acoustic impedance (AI). Original 2016 model results in blue and updated 2017 model in green.

associated lower GIIP (green). While the NtG input was deemed plausible in a range of possible input parameters, this alternative reservoir model was disregarded because a similar good match compared with the 2016 model could not be achieved, and given an unrealistic delta between GIIP and the cumulative production of the field. Therefore, the integrated discussion and feedback loop between geology, petrophysics, reservoir engineering and geophysics was central to building a robust static reservoir model, which is also consistent with both seismic and production data.

While it is crucial to have a robust uncertainty range for any development project, a low case that is too conservative can unnecessarily put a project into economic jeopardy.

Case study 2: Selection of representative wells of an existing field (offshore Netherlands) Revision of a static reservoir model for a project offshore Netherlands triggered an integrated discussion on how representative the wells are for the closure they are drilled in. Two wells have been drilled into the main fault block, with significantly varying NtG values. The first well has a NtG of 72%, which is consistent with neighbouring closures. The second well at a distance of ~1.5 km has a NtG of 54%. The low NtG values from the second well, which had not previously been included in the reservoir model, would have resulted in a GIIP decrease of 25% for the overall structure.

However, some doubt was raised about the quality of the wireline results, as logging was performed through casing with only a limited set of logs.

These questions prompted a ‘Check the Loop’ analysis, comparing synthetic seismic of the static model honouring the well 2 log data with actual field seismic. The analysis showed that the low NtG values for well 2, in combination with anomalously high values for porosity, not only resulted in significant lateral changes from well 1 to well 2, but also in significant vertical contrasts in acoustic impedance. Thus, the simulated seismic data from ChTL showed strong, bright amplitudes, while the actual seismic data 46

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Case study 3: Indications for rising contacts (onshore Netherlands) A static and dynamic model update was carried out for a sizable gas field onshore Netherlands. After producing this field for many years, while acquiring a rich dataset on production behaviour (downhole and surface pressure, pulsed neutron logging, gravity), there were still areas in the field where no satisfactory history match could be achieved for all matching parameters together.

One element rebuilding the static model included seismic inversion for porosity. The resulting porosity cube was used to steer the porosity distribution away from areas with good well control, thereby avoiding a potential bias because wells are preferentially targeting better reservoir. A Check the Loop study was carried out to make sure that the synthetic seismic data of the updated model showed a satisfactory match with measured seismic data. This was the case for a larger part of the field, but some areas still showed discrepancies.

Seismic data was acquired at a stage in the lifetime of the field when significant depletion had already taken place. A 4D seismic feasibility study, which tests the changing seismic signature owing to production of a field over time, showed that no 4D seismic signal would be expected over most of the field. However, if depletion would have resulted in a rising contact, as seen in only some wells, this may have sufficiently changed the seismic response to affect the property modelling. As a result, a second Check the Loop iteration was carried out to test this, now based on the upscaled dynamic model with pressure and saturation properties representative for the point in time at which seismic data was acquired.

The difference with the results of the first iteration, i.e. with initial reservoir conditions, is subtle but real for selected areas (Figure 4).

It was thus concluded that the Check the Loop process can be used to better understand certain aspects of dynamic reservoir behaviour.

This in turn may lead to an improved history match.

Figure 3 Cross-section from the static reservoir model from well 1 to well 2 displaying porosity (top left) and net to gross ratio (top right). The predicted acoustic impedance from the reservoir model (bottom left) and synthetic seismic data (bottom right) show the strong lateral changes porosity and NtG ratio, which are inconsistent with the actual seismic data (backdrop).

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Summary When it comes to discussions on reservoir property modelling, it may not be a common practice to include the geophysicists, given that they are working with seismic data, which does not

Figure 4 Subtle differences in synthetic seismic data based on initial (T0, left-hand seismic section) and on depleted reservoir conditions (T1) (right-hand section) reveal a rising contact owing to production of hydrocarbons. The same effect is shown in the log panels to the right.

measure reservoir properties directly. However, the simple ‘Check the Loop’ modelling workflow shows that this can be a missed opportunity. The workflow is simple, fast and serves to relate the amplitude response of the seismic data to the reservoir model and its properties. It is applicable to both clastic and carbonate environments, is available in a variety of software tools, and has much untapped potential for implementation. This presents an opportunity for geophysicists to be closely involved in the reservoir modelling process, and the case studies above provide only a few representative examples. However, first and foremost, the workflow provides a platform where different disciplines are encouraged to quality check their respective inputs and work towards a fully integrated reservoir modelling product. All models are wrong, but fully integrated models are useful.

Acknowledgments We would like to acknowledge the NAM asset teams for their contributions to this article. We would also like to thank ExxonMobil for permission to publish this paper.

Prospectivity analysis of shallow gas in the Netherlands M. van den Boogaard1* and G. Hoetz1 Introduction Cenozoic sediments in the Dutch North Sea host abundant seismic amplitude anomalies, or bright spots, of which several are proven to be related to hydrocarbons. The Netherlands was the first country in the North Sea region in which these accumulations have been developed. Currently, four Dutch shallow gas fields are successfully producing, and additional fields are planned to come on stream in the coming years. The success of the producing fields has raised industry interest. The play has proven to be a valuable resource and with several tens of undrilled shallow leads, largely covered by 3D seismic data.

It is worth further evaluating the development potential of the play.

The occurrence of bright spots in the northern Dutch offshore at depths up to 1000 m was already known from seismic data in the early Seventies. Subsequently, in the Eighties and Nineties the presence of producible gas was proven in several accumulations by wells. This resulted in the discovery of eight gas fields in Cenozoic clastics. However, owing to expected early water breakthrough relating to the geometry and sand production as a result of the unconsolidated nature of the structures, the play remained undeveloped. After years of studying the area by

several operators, the first shallow field in the Netherlands was developed by Chevron – now Petrogas – in 2007. This field (A12FA) ranked at the time among the best producing gas fields in the country with production rates of some 3 million Nm3/day via six producers. Nowadays, three more fields are producing (Figure 1): F02-Pliocene operated by Dana Petroleum (2009), and B13-FA (2011) and A18-FA (2015) both operated by Petrogas. The producing fields do not show significant sand or water production.

Features such as conformity to structure, flat spots, velocity push-down effects, attenuation, gas chimneys and pockmarks at the seabed (Schroot et al., 2005) emphasize the potential for the presence of gas in the shallow play. First-order estimates pointed out significant potential for shallow gas in the Netherlands in terms of volumes (Muntendam-Bos et al., 2009). Because of these encouraging results, a further play analysis was carried out.

The focus area is the northern Dutch offshore, where most of the bright spots are located.

For developing shallow gas accumulations the following success factors appear key: size of the accumulation in combinations with distance to existing infrastructure, reservoir quality and gas

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Figure 1 Study area showing the eight shallow fields (red), of which four are currently producing (black outline), and the identified shallow leads. Case study 1 (F01-A-Pliocene) and case study 2 (F12-A-Pliocene) are also indicated. The 3D seismic data coverage in the area is shown in blue.

Figure 2 Seismic section through the study area showing the Cenozoic foresets of the Eridanos delta system in white.

saturation. This paper focuses on the latter and presents an inventory of the occurrence of shallow amplitude anomalies based on seismic reflection data. To help select attractive leads, a seismic characterization system was developed in which more than 150 bright spots are ranked. One of the critical factors is the presence of mobile gas and estimating gas saturation prior to drilling. This remains because the seismic attributes included in the ranking system do not distinguish between high and low saturation or even lithological effects.

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Nevertheless, the system is a valuable tool for selecting those amplitude anomalies that have the highest potential for development and for justifying further assessment, including volumetrics. This paper includes two case studies of high ranking leads.

Geological setting The study area includes the A-H quadrants in the northern offshore of the Netherlands (Figure 1). Most of the shallow anom-

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alies in the area occur above the Mid-Miocene Unconformity, in formations that are deposited in a late Cenozoic fluvio-deltaic system (Figure 2), generally referred to as the Eridanos Delta (Overeem et al., 2001). The sediments were transported from the uplifted Fenno-Scandian shield in the north east, while later the source area shifted southwards. The delta system covers a large part of the current Southern North Sea and comprises an alternation of shales and clean-to-shaley sands (Rasmussen et al., 2008). The sandy layers form the reservoirs, sealed by shales of various thicknesses. Those shales are believed to have a maximum sealing capacity after which breaching takes place (Verweij et al., 2014), often resulting in a stacked reservoir-seal alternation.

The origin of the gas is debatable. While often it is believed that the gas is biogenic, based on the gas composition which is > 99% methane in most wells (Verweij et al., 2018). There are also indications that the gas has a (partly) thermogenic origin, such as the presence of gas chimneys below the amplitude anomalies and the gas isotopes in some of the wells (Schroot et al. 2005). Often the amplitude anomalies occur above deeper salt domes and many of the bright spots are four-way dip closures, sometimes associated with faults. Amplitude anomalies relating to stratigraphic traps are also observed (Figure 1). However,

the current Dutch shallow gas discoveries are all dip-closures and so far no stratigraphic traps are proven gas fields in the area.

Shallow gas portfolio Shallow gas developments

Four shallow gas fields are currently producing in the northern Dutch offshore: A12-FA, B13-FA, A18-FA (the A & B fields) and F02-Pliocene (Figure 1). Additionally, development of three more fields is under consideration. The field in the F quadrant is a combined development with a Cretaceous oil reservoir, producing gas from one shallow sand at a depth of 700 m. The reservoir is a four-way-dip closure crosscut by a fault. The fields in the A and B quadrants all produce from several stacked reservoirs with depths of 300-700 m. The sediments are deposited in the Pliocene and Pleistocene (2.2-1.4 Ma). Analysis and development of the A & B fields is based on 2D seismic lines, since this area was not covered by 3D data until recently. The fields are low relief dip closures and the number of producing intervals per field range from one to four with scope for additional infill reservoir sands (Figure 3). Gas saturation is typically reasonable to good. Porosity and permeability are good to excellent. Expected ultimate recovery factors are 50-70%.

Figure 3 Seismic lines through four producing shallow gas fields in the Netherlands (location indicated on Figure 1). The arrows indicate the producing reservoirs. The Base Upper North Sea Group (yellow), Base North Sea Group (orange), Base Chalk (green) and Top Zechstein (pink) are indicated.

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Figure 4 A) Amplitude extraction plotted on the top reservoir map (TWT) of a four-way dip closure bright spot (area 5 km2). B) Amplitude extraction plotted on the top reservoir map (TWT) of a faulted dip closure bright spot (area 40 km2). The white stippled line indicates the brightest part of the anomaly that is conforming to structure.

Figure 5 A) Soft event (blue loop) at the top reservoir reflector (indicated by the yellow, dotted line) showing a strong decrease in acoustic impedance at the lead F12-APliocene. B) The top reservoir reflector (indicated by the yellow, dotted line) showing a strong decrease in acoustic impedance resulting in a phase reversal at the gas lead in quadrants F04-F05.

Sand thickness (net) is in the order of a couple of metres, varying per reservoir, and net-to-gross ratio ranges 60 to 100%. Despite the modest reservoir pressures (~50-60 bar) as a result of the shallow depth, initial production rates are in the range of 2-3.5 million Nm3/d.

Water depths in the area are 30-50 m. Whereas the F02-Pliocene gas is treated on the F02 production platform and partly used as fuel for the Chalk oil production, the A & B fields all connect to the A12 central processing platform. The unmanned A18 and B13 satellite platforms do not contain any significant processing or compression facilities. Based on production experience, the operator has simplified the satellite design to a minimum over time, thereby enabling the commercial future production of additional, smaller gas fields in the area. The production wells contain horizontal sections in the reservoir of up to 600 m length. Sand handling is a crucial part of the well design, because of the unconsolidated nature of the reservoir sands. This comprises expandable sand screens (Campbell et al., 2014) in most of the wells. These sand screens have proven to be highly successful. Furthermore, most wells have

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no or very limited water production and the few wells that do produce water not before 65% of the gas in place has been produced.

More shallow gas opportunities

The success of the producing shallow fields encourages further exploration of the Cenozoic play in the Southern North Sea. Moreover, the availability of 3D seismic data (Figure 1), a tax incentive for developing marginal fields and a guaranteed offtake contribute to the attractiveness of the play. A lead inventory in the study area resulted in more than 50 bright spots mapped from 2D and 3D seismic data. This inventory excludes anomalies shallower than 250 ms TWT (~250 m) and a lateral area smaller than 2 km2, since those are likely to be sub-economic.

The bright spots show significant variation in geometry including area, depth, vertical relief and number of stacked amplitude anomalies, all relating to the potential of the lead.

Also the trapping mechanism plays an important role in the ranking of the leads; four-way dip closures and faulted dip

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closures (Figure 4) are considered to have highest potential for development, because of their analogy to the currently producing reservoirs. Closures that show (crestal) faults do have a slightly higher risk of low saturations.

The geometric characteristics relating to the size of the potential accumulation described above are used for a first-order ranking of the bright spot structures. This results in 52 leads with a four-way-dip or faulted dip closure, of which 13 are larger than 10 km2. For some high-ranking leads, a detailed subsurface analysis was conducted including a volumetric assessment. Because shallow gas was long considered a drilling hazard, only few of the bright spots have been penetrated by wells, which typically went for deeper targets.

Hence, well data from offset wells (i.e. nearby wells that did not penetrate bright spots) are used to constrain reservoir properties.

Gas saturation is one of the key subsurface uncertainties in the volumetric assessment, because of the non-linear relation between seismic amplitude and saturation. In total, 16 of the 52 leads with a four-way-dip or faulted dip closure have been drilled. All but one of the 14 public wells report gas shows at the depth of brightening, strongly indicating that there is gas in the system. However, detailed log and hydrocarbon data is most

Figure 6 Schematic explanation of Figure 5A and B showing a case in which substituting brine with gas in the reservoir sand results in an amplitude decrease only (left) and a case in which this results in a phase reversal (right).

often absent since these wells generally had deeper primary objectives. Results of the continuing work on volumetrics for each of the high-ranking leads look promising, especially when considering the relatively cost-efficient development options for these shallow reservoirs.

Seismic lead characterization In order to further evaluate the development potential of the shallow leads, the seismic character of the individual amplitude anomalies was assessed on migrated stacks. The following features, which can be regarded as Direct Hydrocarbon Indicators (DHIs), have been evaluated: 1) (relative) amplitude, 2) flat spots, 3) velocity push-down, 4) attenuation, and 5) gas chimneys. Based on the geometrical parameters relating to the size of the accumulation as described above and on the DHIs relating to the presence of gas, each bright spot is ranked semi-quantitatively.

Amplitude

Rock physics modelling shows that substituting brine with gas leads to a strong decrease in the P-wave velocity, which can result in a significant increase in acoustic impedance contrast at the shale-sand boundary. This effect is observed by a soft event at the top of the gas reservoir (Figure 5A). Depending on the sediment characteristics, a phase reversal at the top sand reflector might occur at the boundary of the bright spot (Figure 5B) as is schematically indicated in Figure 6. The sand layers can be relatively thin (metre-scale), which is significantly affecting the seismic signature of the top reservoir due to tuning effects.

Often it is not possible to define a separate top and bottom reservoir reflector.

Note that amplitude anomalies might also be the result of lithological effects, such as locally increased porosity. Although, strictly, a lithological effect cannot be excluded without an exploration well, the conformity to structure of most of the amplitude anomalies as well as the presence of other DHIs helps to reduce the risk of a lithology effect causing the brightening rather than the presence of gas.

Figure 7 A) Amplitude anomaly F12-A-Pliocene with a clear flat spot, indicative of a GWC. B) No flat spots are visible in producing field A12-FA.

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Figure 8 A) Amplitude anomaly in quadrant F01 with a push-down effect, increasing with depth. Also attenuation of the seismic signal is observed. B) Amplitude anomaly in quadrant B14 that does not show a push-down effect nor attenuation.

Figure 9 The combination of velocity push-down and attenuation gives rise to the doughnut effect: an artefact that is fairly typical for stacked shallow gas occurrences in the Netherlands.

Flat spots

Since seismic amplitudes are not sensitive to variations in saturation above a low threshold saturation value, additional seismic signatures that relate to the presence of gas are analysed. A flat spot can often be observed on seismic data (Figure 7A) and indicates the presence of a gas-water contact (GWC). However, the absence of a flat spot does not necessarily direct to the absence of gas, as is illustrated by Figure 7B, showing one of the producing fields with high gas saturation, but no visible flat spots.

In case of stacked reservoirs it is common that the push-down effect increases with depth. The apparent push-down can have significant impact on the lead analysis, especially regarding the gross rock volume, since it masks the real structure of the bright spot. Modelling shows that the amount of push-down is hardly related to saturation, but reflects the total gas column height.

Hence it is difficult to draw conclusions on gas saturation once a push-down has been observed. However, the absence of a velocity push-down below an amplitude anomaly suggests that it is unlikely that the structure is substantially gas-filled (Figure 8B).

Velocity push-down

The decrease in seismic velocity when substituting brine with gas causes delayed arrival times of the seismic wave at the receiver, resulting in an apparent push-down effect below the gas zone on the seismic events depicted in time. This effect can be observed on the top reservoir reflectors owing to gas in the system above (Figure 8A) or on the flat spots (Figure 11C).

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Attenuation and gas chimneys

Whenever gas is present in a reservoir, it is likely that the seismic signal underneath the reservoir is masked owing to the absorption of the seismic energy. This attenuation effect underneath a bright spot is a strong hydrocarbon indicator (Figure 8A). On the contrary, when no attenuation is observed,

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the likelihood for substantial amounts of gas is low. Figure 8.B shows an example of a low ranking bright spot, based on the absence of a push-down effect and attenuation, in addition to its relatively small size. Note that using the attenuation ranking criterion assumes that no special noise suppression techniques or Q compensation filters have been used to hide attenuated zones.

Structural definition

The presence of shallow gas above any target zone causes specific challenges in mapping the structure and hence in assessing the trap size. The velocity push-down effect is reflected in the structure and creates a doughnut-like closure (Figure 9). The central part is severely depressed and the amplitude brightening effect is absent in the core area owing to the attenuation described above. In particular, the topographic distortion at top reservoir should be corrected as it strongly impacts the gross

rock volume of the structure. Without correction, the prospect volumetrics will be severely underestimated. Correction can be achieved with careful time-depth conversion.

Portfolio ranking The work described in this paper indicates that observations of amplitude conformity to structure, flat spots, velocity push-down, attenuation and gas chimneys all contribute to the likelihood of a gas occurrence, although saturation remains uncertain. In total, 26 of the 52 selected four-way dip and faulted dip closure bright spots show a push-down effect, of which 22 leads are also affected by attenuation. For six leads a flat spot can be observed.

These DHIs are used for a semi-quantitative ranking of the lead portfolio, together with the geometrical characteristics defining the size of the potential accumulation as discussed earlier. Based on this approach, a number of high potential leads have been selected for further study.

Figure 10 Figure A) Time map of the main reservoir of lead F01-A-Pliocene showing amplitudes. B) Seismic line through this faulted dip closure (location shown on Figure 10A). The top of the main reservoir is indicated by the yellow dotted line.

Figure 11 A) Time map of the main reservoir of lead F12-A-Pliocene showing amplitudes. B) Seismic line through this four-way dip closure (location shown on Figure 11A).

The top of the main reservoir is indicated by the yellow dotted line.

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Case study 1: F01-A-Pliocene

Lead F01-A-Pliocene is a four-way-dip closure with crestal faulting (Figure 10) covered by a high-quality 3D seismic survey (2012). The amplitude anomaly has not been drilled yet.

Several stacked bright spots are observed, of which one single sand is considered the main reservoir. The structural spill point fits the outline of the lead. Velocity push-down, attenuation and a gas chimney can be observed. The reservoir parameters are poorly constrained as no proximate wells are available for control. With N/G, porosity and saturation ranges are similar to those in the producing shallow fields, GIIP has been estimated by means of Monte Carlo simulation. With these assumptions, results show a volumetric range from 0.8 to 3 bcm (P10-P90 GIIP) and a P50 volume of 1.5 bcm. These numbers do not include the upside potential of the other sands of the stacked amplitude anomalies. Regarding the presence of several other bright spots in the area (Figure 1) and the potential for deeper exploration, this lead is worth further exploration.

Case study 2: F12-A-Pliocene

F12-A-Pliocene is another high-ranking lead (Figure 11). This structure is a four-way dip closure with a sand thickness of ~50 m and a net-to-gross ratio of around 0.85, based on several offset-wells. The porosity is expected to be more than 25% and gas saturation around 60%. The lead is covered by 3D seismic data and the outline of the amplitude anomaly conforms very well to structure (Figure 11A). A flat spot, a push-down effect and attenuation can be observed below the top sand reflector (Figure 11B). When including uncertainty ranges on the reservoir parameters using Monte Carlo simulation, the static GIIP is 0.8 bcm (P50), with P10 and P90 volumes ranging 0.5 to 1.1 bcm. Considering the presence of several other shallow leads in close proximity (Figure 1) and the opportunity to explore for deeper targets, this lead ranks high for further, detailed analysis.

of the top reservoir reflector. Therefore, the gas saturation of these leads remains uncertain. In order to better understand the potential, a semi-quantitative analysis based on the seismic characteristics of the leads has been used for further ranking of the bright spots. The presence of DHIs, including amplitude, flat spots, velocity push-down, attenuation and gas chimneys, has been included in the ranking analysis, resulting in several amplitude anomalies that justify further exploration. Gas saturation remains a risk though, since the presence of a flat spot and velocity push-down do not directly relate to saturation, but to geometrical factors and gas column respectively. Further analysis of the shallow gas leads is possible by deploying advanced technologies, such as inversion of pre-stack data or integration with gravimetry or CSEM data. However, the ultimate derisking of the leads demands an exploration well.

Several shallow leads in the area justify an exploration campaign, especially when considering the additional potential of deeper targets nearby.

Acknowledgements We would like to thank our partners TNO, Petrogas, Dana, ONE, Total and Wintershall for helping us to understand the shallow gas prospectivity of the northern Dutch offshore.

References Campbell, A.E., Borowski, K. and Hamers, M.M.H. [2014]. AB gas fields – From drilling hazard to commercial development. 76th EAGE Conference & Exhibition, Extended Abstracts, We EL12I2 10.

Gassmann, F. [1951]. Elastic wave through a packing of spheres.

Geophysics, 16, 673–685.

Muntendam-Bos, A.G., Wassing, B.B.T., Ter Heege, J.H., Van Bergen, F., Schavemaker, Y.A., Van Gessel, S.F., De Jong, M.L., Nelskamp, S., Van Thienen-Visser, K., Guasti, E., Van den Belt, F.J.G. and Marges V.C. [2009]. Inventory of non-conventional gas. TNO report, TNO-034-UT-2009-00774/B.

Conclusions Since the first Cenozoic gas field in the North Sea area was developed in 2007, the shallow play has proven to be successful, with nowadays four producing fields offshore the Netherlands. These fields typically comprise a stacked set of bright amplitudes that conform to structure and mainly produce from horizontal wells with sands screens or gravel packs to prevent sand production. Reservoir sands generally show good porosity and permeability and are sealed by intercalated shales. As discussed in this paper, the northern Dutch offshore hosts ample additional bright spots that are likely to be associated with producible gas. Most of these amplitude anomalies are four-way dip or faulted dip closures with varying size, vertical relief, depth and number of stacked reservoirs. These geometrical parameters relate to the size of the potential accumulation and help with ranking the individual leads. However, substituting brine with minor, non-producible amounts of gas already results in a strong brightening effect

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Overeem. I., Weltje, G.J., Bishop-Kay, C. and Kroonenberg, S.B. [2001]. The late Cenozoic Eridanos delta system in the Southern North Sea Basin: a climate signal in sediment supply? Basin Research, 13, 293-312.

Rasmussen E.S., Heilmann-Clausen, C., Waagstein, R. and Eidvin, T. [2008]. The Tertiary of Norden. Episodes, 31 (1).

Schroot, B.M., Klaver G.T. and Schüttenhelm, R.T.E. [2005]. Surface and subsurface expressions of gas seepage to the seabed – examples from the Southern North Sea. Marine and Petroleum Geology, 22, 499-515.

Verweij, J.M., Daza Cajigal, V., De Bruin, G. and Geel, K. [2014].

Capillary seal capacity of Cenozoic mudstone caprocks of shallow occurrences, Dutch offshore. Fourth EAGE Shale Workshop, Extended Abstracts, Mo P08.

Verweij, J.M., Nelskamp, S.N., Ten Veen, J.H., De Bruin, G. and Donders, T.H. [2018]. Generation, migration, entrapment and leakage of microbial gas in the Dutch part of the Southern North Sea Delta. Marine and Petroleum Geology, 87, 493-516.

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Exploration in the Netherlands: a sense of urgency Eric van Ewijk1* Introduction The Southern North Sea is generally considered to be a mature basin for the exploration and production of hydrocarbon resources even though incremental reserves additions have yet to plateau in the Dutch SNS (Figure 1). Incremental reserves additions have indeed been modest in recent years, supporting the view that traditional hydrocarbon plays located in the Dutch SNS are almost fully creamed off, using prevailing economic screening criteria. In addition, the Dutch SNS has experienced the same reduction of drilling activity that has occurred throughout the industry globally in recent years (Figure 2) exacerbating the recent reduction in reserves additions.

Although it is estimated that many exploration opportunities still remain in the Dutch SNS (Figure 3)1, the E&P industry is clearly confronted with a number of challenges to successfully identify, mature and screen remaining opportunities against internal investment criteria. These challenges are undoubtedly varied but likely comprise a mix of technical, commercial and strategic considerations.

Northwest Europe, including the Netherlands, has stated ambitions to transition to sustainable energy sources. In reality, the energy transition is likely to span several decades and will be costly. Consequently, natural gas is predicted to remain an important contributor to the Dutch energy supply mix during

the energy transition. However, the majority of currently producing gas fields in the Dutch SNS are in decline and many are nearing their economic end-of-field life (EOFL) for low gas price scenarios. This situation has resulted in the timing of decommissioning of infrastructure being brought into focus, with decommissioning plans now being matured and readied for execution. Economic production is generally reliant on existing infrastructure for evacuation. The timing of infrastructure decommissioning thus impacts the economic attractiveness of many remaining exploration prospects and the economic viability of new discoveries. In addition, many identified exploration opportunities have economically marginal Mean Success Volume (MSV) and/or are assessed with a low Probability of Success (PoS), both technically and economically. Opportunities with these characteristics are economically and strategically unattractive for investment. In addition, the planning and execution of exploration activity is being made more challenging by the gradual reduction of space available offshore owing to the emplacement of windfarms and increasingly restrictive environmental constraints. The increasing activity along shipping lanes and fisheries also makes the deployment of modern acquisition systems increasingly difficult and costly.

Unsurprisingly, analysis indicates that from a Dutch state perspective, gas sourced from domestic production is the more economically attractive option, with additional

Figure 1 Historical Dutch Gas Resources Onshore and Offshore and % GIIP per Stratigraphic Unit.

1 The cumulative resources (category 8 and 9) are the simulated expectation volumes calculated from all prospects and leads in the EBN database with ExploSim (with a gas price of 21.5 ct and 40% marginal field measure). The cumulative resources including category 10-11 represents the upside and is calculated as the cumulative resources of category 8 and 9 multiplied by an estimated scaling factor of 1.5.

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Corresponding author, E-mail: Eric.Ewijk-van@ebn.nl

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Figure 2 Cumulative drilling activity in the Netherlands.

Figure 3 Gas Volumes derived from an exploration simulation exercise using all NL prospects and leads known to EBN.

intangible benefits gained when geopolitical factors are taken into consideration. Studies also indicate that Dutch gas has a lower environmental footprint compared to imported gas, including greenhouse gases.

It is highly beneficial for the Dutch state to ensure that undeveloped gas resources remaining in the Dutch SNS are exploited to support the energy transition, both economically and environmentally.

In summary, it is ‘now or never’ for the E&P industry to boost the Dutch SNS gas reserves creaming curve by actively exploring for remaining economically attractive ‘yet to find’ gas. Exploration and development need to be undertaken prior to decommissioning of critical infrastructure and before the currently open window for economic exploitation of these resources closes for good. To make this a reality, what are the realistic options available to the industry to overcome the technical, economic and strategic challenges that currently restrain investment in both the mature plays and those less-mature plays that remain relatively underexplored in the offshore Dutch SNS? This paper suggests some ideas on what might be done and encourages operators to be proactive.

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The Netherlands gas balance Why the urgency for offshore exploration now? Analysis indicates that the balance between produced gas and consumed gas plus contractual export obligations in the Netherlands is negative (Figure 4). The shortfall between demand and the supply of natural gas of approximately 20 bcm is predicted to continue into the foreseeable future requiring a need for substantial gas imports to meet projected domestic demand. The shortfall is owing, in part, to the decision by the Dutch government to progressively reduce production from the Groningen field to zero production in 2030.

This decision has been made to reduce and finally eliminate gas production related earthquake activity in the Groningen field area. In addition, a decision has also been taken not to award any new exploration licences onshore the Netherlands. Another factor adding to the shortfall is the late-life production status of many producing fields. Paradoxically, the Netherlands will require substantial volumes of natural gas to help meet societal energy demand during the transition to zero carbon-based and sustainable energy sources in the decades ahead.

One option to change this challenging outlook and help to balance Dutch energy demand is to find innovative ways, both

REGIONAL FOCUS: THE NETHERLANDS

Figure 4 Projected gas supply/demand until 2035.

technical and commercial, to reinvigorate the exploration for gas resources in the Netherlands offshore. Given the already prevailing negative gas balance, it would be desirable to start this process sooner rather than later.

Decommissioning and restrictions in the North Sea Many producing gas fields in the Dutch SNS are in late-life production decline which is bringing many closer to their economic EOFL when screened at low gas price scenarios. The key to optimising EOFL is a good understanding of the factors that impact profitability, and where these factors are headed for the short-, mid- and long-term. The three main factors are production volumes, cost and price.

EBN has investigated the prospectivity of the Dutch offshore and combined that information with the current estimated year of Cessation of Production (COP) of the existing platforms. This analysis is presented in Figure 5. The determination of the year of COP for a platform is based on gas price, production and operating cost (OPEX). The year where the OPEX from a platform is higher than the revenues from the sales of the gas produced at the platform is determined as year of COP. A conservative gas price of 20 EUR ct/m3 has been used and combined the individual COPs into three periods as indicated in the legend of Figure 5: years 2018-2025, 2025-2035, 2035-2055.

A current prospectivity snapshot of the Dutch offshore has been generated by EBN by contouring the cumulative volume of SPE resource categories 6-9 to generate an undiscovered resource density map. EBN can share this analysis, the underlying data and information with all our operators when the data covers open acreage. For areas under licence, the results can be shared with the relevant operators and to discuss possible courses of action.

Several platforms and pipelines are already being decommissioned with others considered for CO2 storage. Alternative options for platform and pipeline infrastructure include reuse either for E&P activities, possible synergies with sustainable energy options or decommissioning. In the absence of infrastructure, the economic hurdle faced before exploration opportunities are drilled will be higher and any newly discovered gas will require evacuation via longer pipeline routes to remaining infrastructure, which is expensive and might prevent economic development. Using EBN data on reserves, resources and decommissioning projects, the effect on potential natural gas volumes has been calculated. Figure 6

shows the projected volumes as a function of increasing distance to existing infrastructure.

In 2018, prospects with a total volume close to 20 bcm are located less than 3 km from existing platforms. This volume increases to 65 bcm for a distance of more than 10 km from production facilities. In 2028, the total volume less than 3 km from platforms is projected to decrease to 11 bcm. The total volume of natural gas at a distance of more than 10 km from existing infrastructure in 2028 has increased to more than 115 bcm. As this volume is associated with a large number of volumetrically small opportunities, we expect that much of the 115 bcm will not be economic to develop if the distance of the prospect to a platform is more than 10 km. With time, the number and areal distribution

Figure 5 Cessation of Production (COP) timing.

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Figure 6 Exploration volumes as function of distance to infrastructure.

of decommissioned platforms will increase, which in turn, will negatively impact the economic attractiveness of those remaining exploration prospects located in proximity to the decommissioned infrastructure. This could mean that significant volumes may be left in the ground undiscovered and undeveloped, and the time window available to explore and develop remaining exploration resources is closing rapidly.

Wind parks, existing and planned, are also increasingly impacting options for exploration activity offshore. Figure 7 indicates the areas (in green) which are designated for future wind parks. Existing wind parks prevent deployment of towed-streamers and may require any future exploration and development wells to be deviated to target any identified opportunities underlying the wind-parks, increasing drilling costs and drilling risks. In addition, the optimal placement of platforms may also be impacted by the presence of wind farms, existing and planned. The E&P industry is encouraged to undertake due diligence and take a ‘final look’ to investigate and confirm that no prospectivity remains in areas where wind parks are planned.

Dutch gas: environment and economics Why the need for domestic production of natural gas? As indicated above, the Netherlands has a shortfall in supply/demand which, if addressed with imported gas, will be both costly to the Dutch State and more environmentally damaging. To help minimize the need for imported gas the Netherlands could intensify the search for remaining domestic resources, the intention being to reduce its reliance on imported gas.

Gas can be imported as liquified natural gas (LNG) by boat or through pipelines from other exporting countries. Studies (NRC, 29 November, 2017), later verified by independent investigations (NRC check, 1 December, 2017), indicate that the CO2 footprint of LNG is 10% higher than from domestic production. The CO2 footprint from pipeline gas imports is substantially higher with a footprint of 30% above domestic production. These higher percentages are owing to the required transport to bring natural gas to the Netherlands and account for some associated methane (a significant greenhouse gas) leakage. The Netherlands has, like many other countries, established targets to reduce the emission of greenhouse gasses. Hence, minimizing the need for natural gas transportation will aid in achieving a reduction in CO2 emissions and associated methane leakage.

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From a Dutch State perspective, the economics of domestic gas is also preferred compared to imported gas. Imported gas requires state payments to supplier countries with the revenue supplied by Dutch society. In comparison, domestic production generates significantly more economic activity within the Netherlands, resulting in income for Dutch citizens and revenues for the Dutch state.

A final consideration are the geopolitical factors and risks associated with imported gas. Some third-party gas may be sourced from or transported through regions with politically less stable or hostile regimes. Reliance on imported gas will impact security of supply, increasing the risk of abrupt and unscheduled future supply shortfalls to the Netherlands.

In summary, for both economic and environmental reasons, the production of domestic gas is a preferred option compared to imported gas. The continued successful exploration for gas resources in the Dutch SNS is therefore a prerequisite to maintaining domestic production and mitigating geopolitical risks associated with imported gas.

3D data availability and quality The basis for almost all play-based exploration work and subsequent prospect maturation relies heavily on 2D and 3D seismic data. This data should be of sufficient quality at target play levels to robustly identify the required play elements together with their associated uncertainties. However, much of the existing 3D data covering the Dutch SNS (Figure 8) dates back to the 1980s and 1990s. Although largely adequate for the maturation of

Figure 7 Future and existing restrictions to exploration activity in Dutch SNS.

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Figure 8 Time-slice illustrating extent of 3D seismic coverage across the Netherlands.

prospectivity associated with main plays present in many areas, the data acquisition parameters and associated processing workflows are not optimal for imaging opportunities located below complex overburden geology and within the Carboniferous. This has inevitably resulted in many opportunities either being poorly defined structurally or completely missed.

The majority of existing 3D data offshore the Netherlands has typically been acquired with a narrow azimuth range, conventional source and cable (non-broadband), limited maximum offsets and low fold. Although the use of modern processing tools can still be applied to this data with some success, the acquisition parameters preclude the optimum application of many modern processing algorithms and workflows which provide incremental improvements in signal processing, imaging and signal penetration.

As a result of poor bandwidth, under-illumination and offset limitations, a number of areas at important play levels located in the Dutch SNS suffer from inadequate seismic data quality to allow effective identification and maturation of exploration opportunities that may be present. By implication, areas exist in the Dutch SNS with unidentified potential or poorly constrained leads located within established play fairways in proximity to presently available infrastructure. If these opportunities could be imaged more robustly, identified and assessed more reliably, a number of attractive exploration opportunities would likely arise.

Despite the limitations imposed by the acquisition parameters of vintage 3D data, there are still benefits in reprocessing the data in areas were the available data quality has reached the current limit of usefulness. Given the appropriate business case, if reprocessing has not been undertaken in the past five years, the application of a modern processing suite, including bandwidth enhancement, should be considered.

Alternatively, if reprocessing of existing 3D data is not likely to provide the required seismic data imaging uplift, it is proposed that these areas will benefit from the reshoot of 3D seismic data using modern acquisition parameters and technology.

A 3D reshoot survey should be carefully designed and planned to ensure the required sub-surface illumination, sampling and ideally use both broadband source and receiver acquisition technology together with sufficiently long-offsets. Geophysical service providers have indicated that deployment of broadband systems in areas with water depths of 30 m or deeper is desirable.

The 30 m water depth constraint permits a significant area in the Dutch SNS, which includes existing fields and infrastructure, to be targeted by broadband acquisition and processing (red contours on Figure 9). Broadband acquisition combined with the latest processing algorithms and workflows including deblending, deghosting, demultiple, denoise, FWI and RTM/LSM PSDM, will provide improved 3D seismic data. This allows for the identification of new opportunities, improved well placement (reducing drilling risk), improved PoS polarization of existing leads and prospects and improved inversion data. Furthermore it enables the interpretation of critical play elements deeper in the stratigraphy than has been achieved to date e.g. within the Carboniferous.

Accepting some technical compromise (streamers run shallower) and in the absence of seabed obstacles, broadband acquisition could be deployed in water depths of 25 m or deeper (Figure 9).

This relaxed water-depth constraint makes it possible to acquire broadband 3D seismic data across the majority of the Dutch SNS heartland area for gas production and where infrastructure is available.

A final sprint with our operators The time available to economically explore for and develop remaining gas opportunities in the Dutch SNS is running out. The

Figure 9 Water depth >25m offshore the Netherlands. 30-m water depth contour indicated in RED.

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Dutch state will need access to gas supply to support the energy transition for the foreseeable future. Domestic gas supply is the preferred option for economic, environmental and geopolitical reasons. EBN therefore encourages all operators to review their exploration portfolios with a sense of urgency and to assess the need for either 3D reprocessing using existing data or a 3D survey reshoot using the latest broadband acquisition and processing technology. EBN is both willing and able to support operators that present a viable business case for investment in 3D reprocessing and/or 3D acquisition within their licence.

Acknowledgements The contributions from the EBN exploration team were invaluable in writing this article. I would like to thank Annemiek Asschert, Kees van Ojik, Marcel Hoenderdos, Guido Hoetz, Linda Janssen, Sabine Korevaar and Martin Ecclestone for reviewing and their suggestions. I would also like to thank EBN for permission to publish this article.

Maastrichtian chalk reservoir quality in the Rembrandt and Vermeer oilfields, Dutch offshore block F17 Henk van Lochem1* and Marc Beller 2 Introduction In 2012 Wintershall Noordzee BV, as operator of Joint Venture Group F17a Deep (Netherlands offshore) (Figure 1), discovered oil in the Upper Cretaceous Chalk interval with well F17-10. This discovery was later renamed the Rembrandt Field and was subsequently appraised in 2014 by vertical well F17-11 and horizontal well F17-13x. In the same year, well F17-12 discovered oil in a separate Chalk structure, now known as the Vermeer Field.

Extensive core material is available for wells F17-11 and F17-12, covering most of the Maastrichtian chalk reservoir. A sedimentological evaluation of these cores was performed including macroscopic and microscopic descriptions. For the microscopic evaluation both thin sections and SEM/BSEM images were used, which was supplemented by XRD analyses. For the petrophysical characterization of the reservoir, porosity and permeability measurements are available, as well as pore-throat size distributions from MICP (Mercury Injection Capillary Pressure).

A rapid decrease of porosity within the 40-50 m thick Maastrichtian reservoir from around 37% at the top of the reservoir to 22% at the base of Chalk can be observed. The causes of this decrease have been investigated and based on the results a predictive model was made, which was used to guide the porosity modeling in the static reservoir model.

Stratigraphy and Inversion Block F17 is located at the southern end of the Dutch Central Graben, centrally on the inversion axis of the basin. During the Late Cretaceous to Paleogene period the basin was inverted. It

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was uplifted and eroded to such an extent that on the axis of the basin the Cretaceous and Upper Jurassic sediments have largely been eroded (De Jager, 2003). On the axis of the Dutch Central Graben the Chalk Group is generally very thin (less than 100 m) or in some areas absent (Duin et al., 2006). Biostratigraphic analysis shows that this thin Chalk interval is the upper part of the Ommelanden Formation, Maastrichtian in age. Below the Maastrichtian Chalk, a Middle Campanian conglomeratic and siliciclastic-rich interval is found locally. Below the Maastrichtian Chalk, or below the Middle Campanian interval, if present, a significant unconformity is observed. Below this unconformity rocks of Early Cretaceous (Barremian) to Cenomanian age have been found in the Rembrandt and Vermeer wells.

Based on the integration of the well data with detailed 3D seismic interpretation it can be determined that the main inversion event in the southern Dutch Central Graben is the Sub-Hercynian Phase (Van Lochem, 2018). After this event, an island was formed in the Chalk sea during the Campanian and Maastrichtian.

Around this island, erosion products can be found in the Chalk intervals. These sediments are time and facies comparable to the Vaals Fm. in the south of the Netherlands. Maastrichtian sediments are seen to onlap on to the island, decreasing it in size and influence as a sediment source. During the Danian period, no deposition took place on the inverted Dutch Central Graben and a marine hardground is found at the top of the Maastrichtian Chalk. The inversion and chalk sedimentation stopped during the Paleocene period when deep marine claystones where deposited in this part of the North Sea Basin.

1

Argo Geological Consultants BV, formerly of Wintershall Noordzee BV | 2 Wintershall Noordzee BV

*

Corresponding author, E-mail: j.h.vanlochem@argo-geoscience.com

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Figure 1 Location of Dutch Offshore block F17a and the Rembrandt and Vermeer Fields.

Maastrichtian Chalk sedimentology Both well F17-11 (Rembrandt Field) and well F17-12 (Vermeer Field) have been extensively cored and show in general the same phenomena in the Maastrichtian Chalk. In this paper, well F17-11 is taken as an example and discussed in more detail (Figure 2).

Figure 2 Interpreted well results F17-11. Tracks (from left to right): Depth MD (m), Depth TVDss (m), Lithostratigraphy, Biostratigraphy, Cores, Lithology and Image Log with Biostratigraphical ages. Depths are deliberately masked for confidentiality purposes. Location of samples Figure 3 marked by arrows A and B.

One of the objectives of this well was to fully core the Chalk reservoir interval, including part of the Paleocene overburden (Landen Fm.). This resulted in a 71-m cored section, although there was a 13-m lost section in the middle of the Chalk interval.

A surprise in this well was the presence of an 8-m conglomerate and sandstone interval at the base of the Chalk, dated mid-Campanian. The total reservoir interval is 56 m, overlying an interval of 19 m of Early Cretaceous Vlieland Claystone Fm., which rests on Zechstein caprock.

The log evaluation, calibrated by core porosity/permeability measurements every 25-100 cm showed the porosity of the Maastrichtian Chalk to decrease from 37% at the top of the formation to 22% at the base. The question was raised: was this rapid porosity change was caused by primary sedimentological differences or by diagenesis or by compaction? To investigate this a detailed sedimentological evaluation was initiated. Thin sections have been prepared of the trim-ends of core plugs with a circa 2-m interval. SEM and BSEM images of these plugs have also been made. On the thin sections, point counting has been performed to quantify the main rock forming elements.

A distinct difference can be seen between top and base of the formation (Figure 3). The top is what can be called a ‘clean’ chalk.

It is classified as a wackestone and consists mainly of a chalk mudstone matrix of typical coccolith platelets with a large amount of microporosity between them. Floating in this mud matrix are common skeletal grains of calcispheres, benthonic foraminifera, fragments of Inoceramus bivalves and other skeletal debris. Authigenic minerals are present in the form of micrite and microsparitic calcite. Dolomite, pyrite and diagenetic glauconite minerals have rarely been observed. Rare and isolated macropores consist of calcisphere, benthonic foraminifer and bryozoan intraskeletal pores.

The XRD analysis typically shows 97% of carbonate and 3% of other material, mainly quartz, to be present.

From the sedimentary and diagenetic point of view the basal interval is rather similar compared to top of the formation. However, the most notable difference is the higher content of siliciclastic material and to a lesser degree an increased amount of skeletal grains. The siliciclastic grains consist of very

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Figure 3 Well F17-11: Thin sections of Upper Maastrichtian clean chalk (A, MD depth xx42.6 m), Lower Maastrichtian sandy chalk (B, MD depth xx77.6 m). Depths are deliberately masked for confidentiality purposes, but compare to Figure 2.

Note that the chalk mud matrix is dark in these thin sections; the around 45% microporosity in the chalk mud is not resolved in the thin section.

fine- fine-to-medium sand graded detrital quartz and glauconite/ green clay grains. Grains are either dispersed through the matrix or concentrated within burrows, along coarser material laminae or as component of foraminifera agglutinated tests. No differences were seen in the thin sections and (B)SEM images that pointed to increased diagenesis in the lower section, nor did the (B) SEM images and MICP pore-throat data indicate a significantly increased compaction.

The point count results (Figure 4) of the thin sections show an inverse relation between the amount of grains in the Chalk and the porosity. However, the porosity increases if the amount of mud matrix is increasing. It should be noted that the thin sections cannot resolve the microporosity present between the micronscale coccolith platelets, which is thus included in the count for the mud matrix.

These correlations can be explained by the fact that the presence of skeletal and siliciclastic grains diminishes the space available for the microporous mud matrix. The grains themselves do not contribute at all to the porosity, so exchanging mud by grains results in a direct loss in porosity. Extrapolation of the trendline suggests that in this area and depth, the Chalk could have a maximum porosity of 45% if no grains were present. The same inverse relationship between the presence of larger grains to porosity has also been described in the Ekofisk Formation of the Tyra Field (Danish North Sea) by Røgen et al. (2001).

Reservoir porosity model and conclusion Based on the observations in the thin sections, it is clear that the main cause of the decrease of porosity with depth is the admixture of grains in the chalk matrix, not diagenesis nor compaction. When plotting calibrated porosity logs versus depth and facies over the Maastrichtian Chalk interval, this insight from thin section observation is nicely captured by simple equations to predict porosity with depth laterally over the entire field area (Figure 5). For the main Rembrandt and Vermeer wells and selected nearby off-structure wells, the porosity relation can be described by two functions. First a compaction trend, which describes the decrease of porosity with depth of a comparable stratigraphic position, e.g. the top of the Chalk interval. This trend only has a minor impact, around 1.6 p.u. per 100m.

The second trend describes the decrease of porosity down section of the well- this is the lithology trend- caused by the admixture of grains in the chalk mud. In the F17-11 well this is

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around 25 p.u. per 100 m. The impact of this last trend seems to be diminishing in the deeper wells. This effect has also been captured in the set of equations. Using the Top Maastrichtian depth map and the obtained equations, a predictive 3D porosity model has been generated for the Rembrandt and Vermeer area.

It is widely recognized that porosity and seismic acoustic impedance are highly correlated in carbonate fields and more particularly in Chalk fields (Herbert et al., 2013). Therefore, porosity from seismic elastic inversion is often considered as trend information during porosity geomodeling and this approach was indeed applied to an early iteration of our static porosity model. However, fluid saturations also have an influence on seismic impedances, although smaller and less correlated than porosity. Neglecting the fluid effect would introduce a small bias into porosity prediction using seismic porosity. A usual workaround would be to introduce facies and/or fluid geobodies in the static model to separate various areas of the model and to treat porosity modelling and relation to seismic acoustic impedance differently according to these areas. In our

Figure 4 Point Count Results of F17-11 thin sections. Chalk porosity increases with increasing amount of matrix (Note: the mud matrix also contains the microporosity) and decreasing amount of grains (skeletal and siliciclastic grains). Samples Figure 3 marked by circles A and B.

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Figure 5 Relationships between porosity and depth for Maastrichtian Chalk in the Rembrandt and Vermeer Fields area. Two trends can be captured by equations: a compaction trend and a lithology trend.

case, considering the thin Chalk interval over Rembrandt and Vermeer fields in relation to seismic resolution, as well as the complex fluid saturation heights function, we believe that this workaround would introduce more uncertainties than benefits.

The equation-based predictive model from Figure 5 has the advantage not to be affected by fluid effect, and to capture in a simple way, our understanding of the lithology and depth-based porosity variation in these Chalk fields. In this instance, it was decided for our latest iteration of the static porosity model not to include porosity from inverted seismic acoustic impedance.

Instead, the predictive model was used as a 3D porosity trend co-kriged with the well porosity data, under the assumption that the reservoir quality does not largely vary laterally.

References De Jager, J. [2007]. Geological Development. In: Wong, Th.E, Batjes, D.A.J. & De Jager, J. (eds). Geology of The Netherlands. Royal Netherlands Academy of Arts and Sciences, Amsterdam, 5-26.

Duin, E.J.T., Doornenbal, J.C., Rijkers, R.H.B., Verbeek, J.W. and Wong, Th.E. [2006]. Subsurface structure of the Netherlands – results of recent onshore and offshore mapping. Netherlands Journal of Geosciences - Geologie en Mijnbouw, vol. 85 – 4, 245-276.

Herbert, I., Escobar, I., Arnhild, M. [2013]. Modelling Fluid Distribution in a chalk field using Elastic Inversion, 75th EAGE Conference & Exhibition, Extended Abstracts, WE 1407.

Røgen, B., Gommesen, L. and Fabricius, I.L. [2001]. Grain size distributions of chalk from image analysis of electron micrographs.

Computers & Geosciences, 27, 1071-1080.

Acknowledgements The authors greatly acknowledge the F17a Deep Area partners EBN, Neptune, Rosewood, and TAQA for permission to publish this paper. The support of Wintershall Noordzee BV and its shareholders is acknowledged, as well as colleagues and contractors that contributed to the underlying work.

This article is the extended abstract (Van Lochem and Beller, 2018) of an oral presentation at the 80th EAGE conference in Copenhagen, with minor modifications.

Van Lochem, H. [2018]. F17-Chalk: New Insights in the Tectonic History of the Dutch Central Graben. In: Kilhams, B., Kukla, P.A., Mazur, S., McKie, T., Mijnlieff, H. and van Ojik, K. (eds.). Mesozoic Resource Potential in the Southern Permian Basin. Geological Society, London, Special Publications. 469, 537-558 Van Lochem, H and Beller, M. [2018]. Rembrandt and Vermeer Oil Fields, Dutch Offshore Block F17-The Impact of Grains on Maastrichtian Chalk Reservoir Quality, 80th EAGE Conference & Exhibition, Extended Abstract.

CALL FOR REVIEWERS FOR THE EAGE ANNUAL 2019 IN LONDON! CHECK OUT OUR WEBSITE FOR DETAILS WWW.EAGEANNUAL2019.ORG

LON19 Stopper 171x69.indd 1

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ENERGY IN THE NETHERLANDS SUPPLY

DEMAND

Energy is a basic need and everyone uses it. It is produced from various sources and transported to end customers, often converted into power or heat. Supply has to match energy demand every single day. Energy makes sure the lights go on, houses are heated and hot water is available, it powers cars and ships and is ubiquitous in our daily lives. The production and use of fossil fuels causes emissions of greenhouse gases. This infographic shows the Dutch energy system and its greenhouse gas emissions. We hope this information will provide the basis for good discussion.

More information can be found on www.energieinnederland.nl.

Energy production

Primary energy demand

2018

Nuclear energy 2% Other 2% Oil 4% Renewable energy 9%

Natural gas 83%

1827 PJ

Electricity 1% (net import) Nuclear energy 1% Other 1% Renewable energy 5%

Coal 14%

3147 PJ

Oil refining 11 Mton

Gas and oil production 2 Mton

International transport: 685 PJ

Natural gas 39%

Oil 39%

Total

Power production companies 1) 52 Mton

197

Mton CO 2-eq

(allocated to sectors)

Other greenhouse gases

Services, Waste & Water

29 Mton

28 Mton

Households

(CH4, N2O, F-Gases)

(11 Mton direct)

31 Mton

Industry & Construction

(17 Mton direct)

54 Mton

(De)centralised energy conversion

(34 Mton direct)

Agriculture & Fisheries

Traffic & transport

9 Mton

Oil 4%

Nuclear energy 4%

Renewable energy 11%

(32 Mton direct)

Electricity 378 PJ

Natural gas 44%

1107 PJ

33 Mton

(9 Mton direct)

Coal 37%

Final consumption Net export

Net supply (primary)

445 PJ

Natural gas 40%

1243 PJ

Oil 39%

1217 PJ

Coal 14%

428 PJ

Biomass 4%

115 PJ

Other sources 1%

40 PJ

Nuclear energy 1%

38 PJ

Wind energy 1%

29 PJ

Electricity import/export <1%

20 PJ

Solar energy <1%

7 PJ

Other renewable <1%

7 PJ

Geothermal energy <1%

3 PJ

5 PJ

â&#x20AC;˘ Production â&#x20AC;˘ Net import

(Residual) heat: 165 PJ For energy conversion: 1107 PJ

7,5

50% Raw materials Oil Natural gas

65% Heating Natural gas 51% Heat (incl. from CHP) 42% Geothermal heat 3% Biomass 3% Oil 1%

99% Transport Oil Electricity

Losses: 729 PJ

15% Transport Oil

100%

17% 82% Heat Natural gas 87% Biomass 6% Heat (incl. from CHP) 4% Electricity 2% Ambient energy 1%

1 PJ = 0.28 TWh

18% Power & light Electricity 100%

98% 2% 100%

12% Services, Waste & Water 286 PJ 52% Heating Natural gas 85% Heat (incl. from CHP) 7% Ambient energy 3% Oil 2% Biomass 1% Electricity 1% Other 1% 45% Power & light Electricity 100% 2% Transport Oil

100%

1% Raw materials Oil

100%

Cost effectiveness and potential of CO2 savings measures in 2030

2,5

Source: EnTranCe 2017 Jan

Feb

Mar

Apr

May

Jun

Jul

Aug

Sep

Oct

Nov Dec

Emission Electricity generation companies allocated to end-use sectors based on EBN analysis.

For an explanation, datasets and disclaimer see www.energieinnederland.nl.

Source: CBS unless otherwise indicated. Reporting year 2016.

energie in nederland.nl

1000 800

Annual savings potential

600

>10 Mton CO2

400

5-10 Mton CO2

200 0

<5 Mton CO2

Source: National costs energy transition in 2030, PBL 2017

2018 / realisation: a-design.nl

1200

1)

100%

1% Raw materials Oil

20% Power & light Electricity 100%

Households 416 PJ

Direct consumption: 1875 PJ

5

0

85% 15%

37% Heating Natural gas 43% Oil 27% Heat (incl. from CHP) 24% Coal 5% Other 1%

2% Mobility Oil

Annual gas and electricity consumption

- Trend line of gas consumption 2016 - Electricity consumption 2016 - Gas consumption severe winter (2012)

Transport 443 PJ

11% Power & light Electricity 100%

Direct: 2040 PJ

18%

7% Agriculture & Fisheries 157 PJ

En er gy EUR per avoided ton of CO2 sa G vin eo gs th in er ind m al us gr try ee nh ou se s G as re CC W S ind plac i ng en co er gy al of fsh or e Bi om as So s lar pa ne l G s Ho re en us G Ho es as i ns u u Ho ses - h latio us e n es - n at p um et ze ps ro en er gy

PJ per day

10

46% Industry & Construction 1116 PJ