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Chasing the Orange Basin from Namibia to Brazil

Preliminary interpretation of a vast swath of three dimensional(3D) seismic data in Namibia’s hydrocarbon rich Orange Basin, has provided clues for a contiguous relationship between the Orange basin and the Pelota basin in Southern Brazil and Uruguay.

“The time for a conjugate leap from the significant discoveries of Namibia’s Orange Basin to the unexplored Pelotas Basin of Southern Brazil and Uruguay is upon us”, write Neil Hodgson, Lauren Found and Karyna Rodriguez, all geoscientists at Searcher, the Australian geophysical company.

In the last two years, the Orange Basin, which is present in both Namibia and South Africa, has yielded discoveries of hundreds of millions of barrels of crude oil and gas after exploratory drilling in its Nambian segment by Shell and TOTALEnergies.

From late 2022 to June 2023, Searcher completed acquisition of 6,700square kilometres of three dimensional (3D) seismic data in two phases, representing the largest multi-client 3D offering in the entire Basin, in Petroleum Exploration Licences PEL 85 and PEL 3 respectively.

“The Aptian source rock of Namibia can be correlated to its twin in the Pelotas Basin of Southern Brazil and Uruguay”, Hodgson et al assert, in an article published in Geo Expro, a Norway based earth science journal. “The Aptian source rock is clearly identifiable in the seismic of the Orange Basin in Namibia as a soft topped unit with lower internal frequency, little internal structure, standing out in AVO space as a classic strong type IV anomaly”, the authors collectively note.

The Aptian is an age in the geologic timescale or a stage in the stratigraphic column; a subdivision of the Early or Lower Cretaceous Epoch or Series. It encompasses the time from 121.4 ± 1.0 Million years ago (Ma) to 113.0 ± 1.0 Ma, approximately.

The authors argue that Aptian source has proved so effective in Namibia with TOTALEnergies’ Venus-1 discovery and Shell’s four up-slope discoveries, all charged from the Aptian source rock, potentially offering tens of billions of barrels of recoverable light oil.

Hodgson and his co-authors talk of using a geophysical tool, the amplitude versus offset (AVO) or amplitude variation with offset, in an innovative way, to tease out how the source rock of Aptian age in Namibia’s Orange Basin correlates with the Aptian source rock in the Pelotas basin. “AVO has historically been used as a tool to look for oil or gas in clastic reservoirs i.e., a Direct Hydrocarbon Indicator (DHI) tool”,  the scientists declare. “Yet in our process (and multiple other examples since the technique was promoted by Løseth et. al. in 2011), we turn this on its head and use AVO to characterise and identify source rock”.

It is no surprise at all, they contend, “that this source rock can also be identified from its seismic character in the Pelotas Basin of Brazil and Uruguay where it presents the same as Orange Basin but thicker and has a similar Type IV AVO response. The only surprise is that the Aptian sourced plays in this basin remain untested on this margin”.

The three scientists say that “Like human un-conjoined twins though, the Pelotas Basin’s lifestyle choices have varied somewhat from its Orange Basin twin. The continual dynamic topography induced instability of the Namibia margin and a lower sediment supply via the Orange River has led to a comparatively thin sedimentary section than is observed in Pelotas, whose  sedimentary section is, however, demonstrably stable, where no dynamic topographic inversion and shelf collapse has occurred and sediment supply via the proto-Platte River has been prodigious, generating a rather more generously proportioned sedimentary deposit than its West African twin”.

Therefore, only at the edges of the Pelotas Delta is the Aptian source rock buried just deep enough to generate Oil. In such places, the Aptian is prodigious and is no-doubt charging some of the worlds’ biggest prospects in the Cretaceous counter regional play.

“It is here that Searcher is acquiring 3D seismic in 2023/4 season”.


Angola’s Onshore Kwanza Basin offers an underexplored basin with a world class petroleum system.

By Matt Tyrrell and Alessandro Colla, Trois Geoconsulting BV; Mike Oehlers, Tectosat Ltd

Seasoned explorers of Africa and the Atlantic margins will be familiar with the quandary of choosing between offshore and onshore acreage. Offshore acreage typically offers large, inexpensive seismic datasets with which to identify prospects, but the costs of drilling and developing these require significant inward investment. Conversely, onshore acreage allows numerous wells to be drilled at a low cost, but the ability to locate and de-risk prospects is limited by the expense and paucity of exploration datasets, particularly seismic.

This quandary is particularly apparent in the coastal basins of West Africa, where the Mesozoic sedimentary successions, including salt, extend into the onshore domain. In this basin, seasoned explorers will be tantalised by the opportunity to drill salt-induced prospects within a proven petroleum system and will be seeking the necessary datasets with which to de-risk them.

There are, however, onshore basins where this quandary is not so apparent; where extensive high quality datasets are available and early exploration has suitably de-risked proven pre- and post-salt petroleum plays. One such example is the Onshore Kwanza Basin of Angola – a Mesozoic salt basin with numerous undeveloped fields, a library rich in accessible yet low-cost exploration datasets and local refineries and markets for hydrocarbons once they are produced.

Furthermore, a licence round that opens towards the end of 2020, supported by new oil and gas laws and fiscal incentives, provides the opportunity for oil companies to secure rights to this acreage, appraise discovered fields and potentially fast-track commercially viable hydrocarbon production.

Underexplored Pre-Salt

To understand the future potential of the Onshore Kwanza Basin, we must first understand its exploration history.

A key milestone occurred in 1955 when the post-salt Benfica oil field was discovered just south of Luanda, after which exploration drilling peaked; by the late 1970s 133 wells had been drilled. This era of activity saw the discovery of 11 oil fields, as well as a few gas fields, with the largest containing more than 200 MMboe, made possible by the availability of 11,500 line-km of dynamite 2D seismic data. The last onshore field discovery was in 1972 and the last well was drilled in 1982, from when on interest in the onshore declined, in part due to socio-political stability risks but more likely due to the early successes of offshore exploration. Only nine oil fields have ever been reported as having been put onto production, which include the Cacuaco and Puaca fields, both with pre-salt reservoirs.

Although at first it appears that the Onshore Kwanza has been considerably drilled, analysis of well penetrations and results tells a story of high success rates in post-salt wildcats contrasted with a prospective yet significantly underexplored pre-salt succession. Of the 237 wells drilled, just 28 penetrated beneath the salt; four pre-salt fields were discovered prior to 1971 (Cacuaco, Uacongo, Puaca and Morro Liso) despite only three wells testing a meaningful section of pre -salt stratigraphy. When our seasoned explorers analyse the results of these pre-salt wells they must be left pondering what might have been found had the operator drilled a little deeper.

An initial observation is that the majority of pre-salt penetrations were drilled from wellheads located for post-salt prospects with only a handful of wells spudded with a pre-salt objective. Furthermore, assumptions about 1960s and 1970s technology and know-how suggest that modern field appraisal methodologies could reveal where discovered fields may actually be commercial, whilst advanced well stimulation techniques could lower the commercial threshold.

Updated Datasets Support Exploration

In 2010 and 2011, 2,581 line-km of high quality 2D seismic data was acquired followed by the acquisition of high resolution aeromagnetic data. A new GIS GeoDatabase named KMAP-2020, commissioned by Sonangol in 2015, was then completed as part of the reassessment of the remaining oil potential ahead of licence rounds. This product, available for the whole onshore basin or for individual blocks, includes outcrop information, petrographic studies and palaeontological reports from recent field trips together with seismic profiles, well stratigraphy panels and geosections.

The KMAP-2020 database has recently been further refined by the inclusion of modern satellite imagery supplied by specialist, Tectosat Ltd. Using Landsat imagery, SRTM DEM, ASTER and PALSAR Radar data*, the whole basin has been remapped at a much more comprehensive 1:50,000 scale involving interpretation at 1:25,000 scale, with additional integration of lithological detail from some 3,000 field sample points.

The resulting updates to the surface geology maps within the KMAP-2020 database have positive implications for de-risking the underlying petroleum systems. Halokinetic activity is evinced in anomalous domes and basins showing salt withdrawal and folding adjacent to the main bounding faults of the Tertiary troughs.

Fault expressions mapped at surface have been used to understand structural controls related to various tectonic episodes. Where it is shown that many of the Tertiary-aged faults are soft-linked to deeper syn-rift structures, the charge of post-salt reservoirs with pre-salt oil can be de-risked.

Similarly, areas of Tertiary uplift are observed in the vicinity of Blocks 11 and 12 where present-day river systems are seen to have incised; this uplift may have hinged to the north at the Cabo Ledo fault. These details are key in determining long-distance migration paths from known source kitchens, including the offshore, into pre-salt and post-salt structures; indeed, the presence of basin margin oil seeps together with the pre-salt Cacuaco Field north-east of Luanda suggest that the sub-salt section should be suitably charged.

Underexplored Area in New Licence Round

An integration of past exploration results, available seismic and well datasets with the KMAP-2020 database (which includes the satellite imagery interpretation) demonstrate that the Onshore Kwanza Basin is a world class petroleum basin that in recent decades has been considerably underexplored.

The post-salt section has numerous anticlinal closures that are untested; where these have been drilled the structures exhibit good reservoir qualities and host viable oil fields, such as those at Quenguela and Benfica. Where sampled, the pre-salt is shown to exhibit good quality carbonate reservoirs formed by coquina.


shoals with vuggy porosities as well as fluvial-deltaic sandstones. The hydrocarbons encountered here are light oils with gas and with no known encounters of CO2 or high sulphur content.

When the results of the updated ArcGIS geological study are combined with available seismic and well datasets, conclusions can be drawn that suggest that the upcoming licence round may be the trigger for the first commercial production of oil from onshore Kwanza.

Recent announcements by the newly formed ANPG (National Agency of Petroleum, Gas and Biofuels) have defined a strategy for the allocation of petroleum concessions including open acreage within all of Angola’s basins. Concessions will be awarded through a process of public tender, restricted public tender and direct negotiation over a period of seven years, starting in 2019 and culminating in 2025. 

The blocks offered by public tender are those that are deemed exploration blocks that have not formerly been abandoned and restored to the state. The blocks of the Onshore Kwanza Basin have been announced as a part of the 2020 licensing round, which will open in the fourth quarter of 2020. Blocks KON5, KON6, KON8, KON9, KON17 and KON20 are offered by public tender and these blocks all offer excellent potential for exploration as well as opportunities to appraise and develop discovered fields.

In August this year, the ANPG held a Clarification Session as a precursor to the opening of the round; during this session senior members of ANPG gave informative presentations and clarified the timeline for the submissions of bids and signature of the contracts.

Exceptional Opportunity 

The history books of exploration bear witness to a multitude of junior exploration companies that secured onshore acreage, within a known petroleum province, yet were unable to successfully demonstrate to investors and potential farm-in partners that they could cost effectively de-risk a drilling location.

The Onshore Kwanza Basin is different in that it offers the opportunity to secure acreage containing a post-salt field or prospect that can potentially be appraised and brought into production, providing cash-flow to fund further pre-salt exploration where the prize may be bigger. The 2020 Angola Licence Round, which kicks off April 30, 2021, should therefore be in the plans of all junior and mid-sized oil companies. 

* SRTM DEM (Shuttle Radar Topography Mission – Digital Elevation Mapping), ASTER (Advanced Spaceborne Thermal Emission and Reflection Radiometer), PALSAR (Phased Array type L-band Synthetic Aperture Radar)

This paper was first published in the October 2020 edition of GEOExPro magazine

TGS, CGG, PGS In New Partnership for Shared Multi-Client Data Offerings

TGS, CGG and PGS, industry leaders of multi-client geoscience data, have announced a pioneering strategic partnership to offer a shared ecosystem providing direct access to their subsurface multi-client data libraries.

The independent, cloud-based ecosystem will offer a single search point to access all three companies’ multi-client data and allow customers to interactively find, visualize and download their subsurface assets and entitlements all in one place.

Kristian Johansen, CEO at TGS, said: “Proactively supporting our clients’ digital transformation initiatives through the development of this one-of-a-kind vendor collaborative ecosystem, accessible from the users’ desktop, is essential to the foundation for any future development of modern subsurface workflows and beyond.”

A beta version is targeted for release in the first quarter of 2021, enabling clients who own data to review the technology and provide feedback, as well as giving other commercial data suppliers the opportunity to evaluate the potential of joining the collaborative approach.

Sophie Zurquiyah, CEO at CGG, said: “The industry historically lacked an ecosystem that provided a vendor neutral single point of access to the industry’s commercial data. This new ecosystem is platform agnostic, which will enable clients to access multi-client seismic and geologic data, when and where they need it.”

A full launch of the ecosystem is expected in the second half of 2021. TGS, CGG, and PGS intend to expand the scope of the project in the future to include additional features, vendors and data types.

Rune Olav Pedersen, President & CEO at PGS, said: “This partnership shows the possibilities when you combine a collaborative approach with the power and breadth of data and the vision to improve customer experience. Combining cloud agnostic direct access to three of the largest multi-client data libraries in one place ensures enhanced efficiency, usability and reduced lead times, raising the bar on customer experience globally.”


A Historical Review of Earth Model Building

By Dr. Ian F. Jones1, Dr. John Brittan1, Johnny Chigbo1, Dr. Gloria Awobasivwe2, Christopher Osolo2 and Paula Ukerun2 1: ION Geophysical;  2: Bulwark Services Nigeria


In this review article, we consider the development of subsurface parameter estimation for use in building subsurface images for geological interpretation and reservoir evaluation using seismic migration procedures. We outline the progressive evolution form a purely linear approach wherein no reference was made for consistency between the various steps in the procedures, to the emerging approach of a closed-loop iterative workflow wherein each step is checked for internal consistency, and the parameter fields updated until all steps in the procedures are mutually consistent (Brittan and Jones, 2019).

In seismic data processing we aim to: separate ‘signal’ from ‘noise’; build an anisotropic velocity model; migrate the data, producing ‘true amplitude’ angle classes that are then used for elastic parameter estimation for reservoir characterisation. The parameter estimation techniques we have are limited in their resolution, and this restricts the accuracy and precision of the images we can produce. In general, with conventional tomographic velocity update we are limited by the ray-theory ‘scattering limit’ to a resolution of perhaps 5x the available sound-wavelength. Hence we are modest in what parameters we try to estimate tomographically, at best obtaining a smooth anisotropic velocity field suitable for migration, with features with lateral scales of about 500m.  Many excellent results have been obtained with ray methods, and developments (such as well and structural constraints) continue to improve them. Conversely, parameter estimation using ‘full waveform inversion’ (FWI) can perhaps deliver resolution of about half the available sound-wavelength, so theoretically perhaps ten-times the resolution of ray methods. FWI primarily uses the transmitted (refracted) wavefield rather than the reflected wavefield, and typically ignores density contrast, attenuation (Q), etc., (e.g. Virieux and Operto, 2009; Jones 2010, 2018).

For the majority of geological environments, building a model with FWI will not result in an image that is radically different than that obtained using tomography. The exception to this observation would be in shallow water with small-scale anomalies (e.g. over-pressured gas), or for deep subsalt reservoirs (and then only if we have low frequencies and long offsets). Along with better well-ties and potentially better images, the additional promise of FWI is in delivering high resolution interpretable attribute fields directly and quickly

Here, we’ll assess the development of the data processing procedures involved in obtaining subsurface parameter fields for use in migration, and consider how these methods have developed over the past thirty-odd years, and what their future development direction might be.

Figure 1. The ‘S-curve’ development profile for any technology development, in the context of tomography and FWI.

Historical Background

In the life-cycle of any technological development, there is a slow development phase when our initial understanding is poor but growing, followed by rapid development once the fundamentals of the process are fully comprehended, and finally further development levels-out as the method is then fully exploited (Figure 1).

Historically, seismic data processing workflows were purely linear. Field data were ‘processed’, a rudimentary velocity model was estimated from stacking velocity picking, using map migration to depth-locate picked time-horizons, and migration was performed. These tasks happened just once.

From about 1995 onwards, with the introduction of ray-based tomography, the model building element changed to become doubly iterative, in that repeated ray-trace modelling was utilized within an inversion scheme, so as to converge on a model that produced flat common-reflection-point (CRP) gathers, after several iterations of migration. As it is comparing data after migration, this technique is an ‘image domain’ inversion scheme, and hence it is not looking for consistency with the raw input data.

Since about 2005, FWI has been gradually introduced, modifying the tomographic solution by using wavefield-extrapolation modelling so as to iteratively match forward modelled synthetic data with measured field data. Hence, this methodology does indeed ‘refer back’ to the raw input data, but as the inversion is performed in the ‘data domain’, and still has limiting assumptions, the resulting model is not guaranteed to produce ‘flat gathers’ in the ensuant migration

What are the respective parameter resolutions available from these two methods? The resolution of ray-tomography is limited to cell-sizes of perhaps 100*100*25m, as on scale lengths smaller than this, the ray theory approximation fails. Conversely, waveform methods use a cell size of potentially less than 15*15*15m … hence we can expect much better lateral resolution in the parameters in the near surface, and overall better resolution in the deep section.

However, none of these approaches and subsequent migrations attempted to compensate for the underlying ‘bad physics’ or ‘bad data’ that we were employing. For example, using a one-way acoustic wave equation, and with field data that are poorly and/or irregularly sampled, and containing remnant multiples and possibly mode-converted energy. Hence, the least-squares migration technique was introduced to attempt to compensate for some of these issues, in that another iterative inversion loop is introduced so as to form an image (and/or gathers) consistent with the input field data (Schuster, 1997). However, this does not simultaneously try to modify the subsurface model, and still assumes that data are multiple-free.

Figure 2. Flow chart representation of: a) the historical ‘linear’ approach to imaging, b) image-domain ray-based tomography, c) data-domain FWI, d) least-squares update (which can be applied in either the image or the data domain). (Adapted from Vershuur and Berkhout, 2015).

Figure 2 outlines the above methods in a series of flow-charts, and indicates a gradual transition from incremental modification of existing ‘open loop’ solutions, to more transformational and fully ‘closed loop’ solutions. A ‘closed loop’ solution would use a two-way elastic description of sound propagation, iteratively referring back to the field data, iteratively updating the model, and at each step iteratively constraining image gathers to be flat. And ultimately, evolving into inversion for high frequency elastic Earth parameter models, having made use of the full wavefield (including multiples and elastic mode conversion effects).

What are the main differences between incremental and transformational developments? Conventional methods, and their associated incremental developments, primarily are non-iterative over the entire workflow: some bits may be iterative (such as tomographic model update, or LS image enhancement), but the overall flow, from input data to final elastic parameters, is dealt with as a more or less a linear single-pass approach. Conversely, the transformational routes offer adaptive iteration over a larger part of the entire workflow, with the possibility of exploiting the full wavefield (multiples, conversions, etc.).

What is the motivation for moving beyond current ‘best-practice’? Ultimately, resolving a number of reservoir attributes to the extent that they can directly influence drilling decisions and further reduce risk. And, to exploit the full wavefield to the maximum extent possible (exploit multiples, elastic effects, etc., to make full use of all energy in the recorded data).

At present, the limiting assumptions we make in waveform inversion limit what we can achieve: we can currently forward model with a priori parameters for: anisotropic Vp, density, attenuation, (and perhaps Vs), but generally we invert only for P-wave anisotropic velocity. However, if we can push the frequency range of the inversion (which is very expensive), and invert for: anisotropic Vp, density, attenuation, (and perhaps Vs). Then we can directly output the desired elastic parameter volumes, rather than resorting to the intermediate step of migrated gathers which would then be used to perform very approximate reservoir parameter estimation.

What technologies are required to fulfil these ambitions? It is well known that low frequencies are required to facilitate the convergence of FWI (typically with less than perhaps 1.5 Hz). This requirement has led to a recent surge in development of low frequency (or enhanced frequency) sources (Brenders et al., 2018; Brittan et al., 2019). Long offsets are also of benefit, hence ocean bottom recordings are beneficial (Brittan et al. 2013). And, elastic modelling and associated parameter estimation will also be beneficial, and perhaps crucial for land data, were elastic effects severely affect sound propagation.

The Road Ahead

Currently, migration algorithms assume that all multiple energy (reverberation within layers) has been removed from the input data. Removing this restriction would enable us to make use of virtually

all the recorded energy in the field data. One method to achieve this goal is referred to as ‘full wavefield migration’ (FWM), outlined in Figure 3 (Verschuur and Berkhout, 2015). Adding a simultaneous update of the velocity field to this work-flow produces the ‘joint migration inversion’ scheme (JMI – Figure 3b). But ultimately, the objective would be to input the field data (with all its various arrival events) into an inversion scheme, and then directly output all requisite elastic parameters at a resolution sufficient to facilitate direct interpretation (Figure 3d): this was the goal originally envisaged by Tarantola (1984). However, this latter route is still beyond the reach of application as a routine process, but has been demonstrated in a few examples (e.g. Routh et al., 2018).

As an intermediate solution, we can employ the velocity field from FWI to better constrain conventional post-migration impedance inversion: this approach was first suggested by Cobo et al. (2019), and is outlined as a flow-chart in Figure 3c. Below we show an example of their approach (Jones et al., 2018), comparing a impedance inversion using a ‘conventional-constraint’ employing well-logs and interpreted horizons, with an FWI-only-

Figure 3. Flow chart representation of: a) full wavefield migration, b) joint migration inversion, c) impedance inversion constrained using FWI, d) full elastic FWI for direct multi-parameter estimation. (Adapted from Vershuur and Berkhout, 2015).

constraint, that uses no wells nor any picked horizons. Figure 4 shows results from Ophir’s Fortuna field (offshore Equatorial Guinea). This compares the result of a blind-test at the location of well-log which was not used to build the conventional constraints. Here, we are away from the location where the conventional result’s constraints were built, and as seen in the well-log comparison, use of the FWI constraint has resulted in a better match than the more conventional approach.


The evolution of FWI as a tool to improve velocity models for migration, and the move towards using such models for more direct reservoir characterization, has transformed and continues to transform the application of closed-loop’ transformational processes within exploration and production imaging projects. There remain, however, some key challenges to further successful exploitation of such methodologies: namely developing a better understanding of elastic wave propagation effects, and in obtaining the computer power to implement numerical schemes based on such an enhanced understanding.

Figure 4. In the blind-test, the FWI constrained results match the well more closely than the conventional result (courtesy of Ophir Energy and Jones et al., 2018).


The authors would like to thank the ION and Bulwark teams that have contributed to this work:  Tristram Burley, Carlos Calderón, Shihong Chi, Yannick Cobo, Paul Farmer, Juergen Fruehn, Stuart Greenwood, Claudia Hagen, Gary Martin, Ross O’Driscoll, Jeet Singh, Chao Wang and David Yingst. 


Brenders, A., Dellinger, J., Kanu, C., Li, Q., Michell, S., [2018].  The Wolfspar© field trial: Results from a low-frequency survey designed for FWI.  Expanded abstracts for the 88th SEG meeting, FWI 2.1

Brittan, J., Bai, J., Delome, H., Wang, C. and Yingst, D., [2013]. Full waveform inversion – the state of the art. First Break, 31, 75-81.

Brittan, J., and Jones, I.F, [2019]. FWI evolution – from a monolith to a toolkit, The Leading Edge, 38, no.3, 179-184.

Brittan, J., Farmer, P., Bernitsas, N., and Dudley, T., [2019]. Enhanced low frequency signal to noise characteristics of an airgun technology based source. Workshop 9, 89th SEG meeting,

Cobo, Y., Calderón-Macías, C. and Chi, S., [2018].  Improving model resolution with FWI for imaging and interpretation in a Gulf of Mexico data set. Expanded abstracts for the 88th SEG meeting, FWI 2.2

Jones, I.F., [2018]. Velocities, Imaging, and Waveform Inversion (The evolution of characterizing the Earth’s subsurface), EET 13, EAGE, 234 pages.

Jones, I.F., Singh, J., Greenwood, S., Chigbo, J., Cox, P. and Hawke, C., [2018].  High-resolution impedance estimation using refraction and reflection FWI constraints: the Fortuna region, offshore Equatorial Guinea. First Break, 36, November, 39-44.

Jones, I.F., [2010]. An introduction to velocity model building, EAGE, ISBN 978-90-73781-84-9, 296 pages.

Routh , P., Neelamani , R., Lu , R., Lazaratos , S., Braaksma , H., Hughes , S., Saltzer, R.,  Stewart , J., Naidu , K., Averill , H., Gottumukkula ,V.,  Homonko , P., Reilly , J., and Leslie, D., [2017]. Impact of high-resolution FWI in the Western Black Sea: Revealing overburden and reservoir complexity. The Leading Edge, 36(1), 60–66.

Schuster, G., [1997]. Acquisition footprint removal by least square migration: 1997 Annual UTAM Report, 73-99.

Tarantola, A., [1984]. Inversion of Seismic Reflection Data in the Acoustic Approximation, Geophysics, 49, 1259-1266.

Verschuur, D.J. and Berkhout, A.J., [2015]. From removing to using multiples in closed-loop imaging. The Leading Edge, 34 (7), 744–759.

Virieux, J. and Operto, S., [2009]. An overview of full-waveform inversion in exploration geophysics.  Geophysics, 74, WCC1-WCC26.


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Why Didn’t They See It?’

“The Shorouk area had been held by another operator (actually Shell, a big major) for ten years, during which nine wells were drilled without commercial results. How is it possible that they didn’t see the “big potato”?

The explanation of ENI’s explorers is that they were looking for a different geological game, a classic of the Nile Delta (Miocene sands), not the sea-mount carbonate variety…See: Zohr: The Making Of A Mega Discovery

ZOHR: The Making of a Mega discovery

By Marco Alfieri, ENIDAY

The backstory of the largest hydrocarbon field in the Mediterraean

The story of Zohr began in mid-2012 when EGAS, the Egyptian state exploration agency for the offshore Nile Delta, announced a competitive bid, or “bid round” to use the technical term, in the Mediterranean offshore, with the offer to oil companies of 15 blocks to be evaluated.

Politically the period was full of uncertainty, it was the post-Arab Spring. In Cairo in June the Muslim Brotherhood came to power, and the major oil companies were having difficulty in collecting the arrears due to them. ENI decided to keep a regional base in Egypt and continue to study, from a geological point of view, the area of the Levantine basin.

For as long as possible, the first rule of an energy company is that contingent and geopolitical factors should never make you stop searching (and trying to understand). Oil is a long-term business; tomorrow things can be different, maybe even better.

But there is a second factor. The IEOC, historically the driver of exploration activities in Egypt, for the first time in forty years was about to run out of areas to explore. Uncertainty, as Mao Tse Tung would have said, is an excellent opportunity to try to reconstruct the portfolio with more or less limited investment (the competition would be low), pending an improvement in the conditions for investing in the country.

Ok, but how? Exploration of the Mediterranean in the last twenty years had not produced very exciting results for the oil industry; many wells drilled have proved to be “dry” or with few hydrocarbons. The view from San Dona to was that new permits with good prospects were needed and to find them there had to be a paradigm shift.You have to imagine a different “game”, less costly and associated with large volumes. A circle that is not easy to square!
But it was in this context and against this background that the story of Zohr actually began.

At the announcement of the tender, the IEOC made a preliminary screening with the available data of all 15 blocks (for experts on the subject this means examining the regional gravimetric and magnetometric data and old seismic lines) and information on the Levantine basin where Texans and Israelis were making interesting findings offshore Israel and Cyprus. At that point the decision was made by ENI to buy the government’s “data packages” for 10 of the 15 blocks in order to extend the technical evaluation. This was in September 2012, and there were just a few months to decide whether to participate in the bid. We had to hurry.

At the end of the monitoring period the exploration team brought three of the 15 blocks to the technical and economic assessment stage; and of these only Block 9 (Shorouk) ended up on the desks of ENI’s senior management.

Why Shorouk? Initially, the goal was to search in Egyptian waters for the geological model tested by the recent giant gas discoveries (Leviathan, Tamar and Aphrodite) made by the Delek-Noble Energy consortium in offshore Israel and Cyprus. ENI explorers looked for similar structures with the same “play concept”, on the assumption that the oil system discovered in the Eastern Mediterranean might also extend to Egypt.

However, on the basis of the evaluation work made by the IEOC team in Egypt, and with the lack of available seismic data, what emerged was an area in Block 9 where there appeared to be a “high regional” situation: not the classic theme in Miocene sands like Leviathan, Tamar and Aphrodite or the Nile Delta, but a huge bio-structure. A “reef”, as geologists would call it.

To have an idea of just how big, you have to think of a large massif in the Dolomites, such as the Sella-Pordoi , but buried under three thousand metres of sediment and 1,500 metres of water.

Could there be geological objects like this in the Eastern Mediterranean? How old are they? And might it not be a volcano or a crystalline basement rather than a bio-structure? These were all questions ENI had to answer quickly.

The search was extended to Egypt’s neighbouring countries. All of the data from the scientific drilling carried out in Cypriot waters on the top of Eratosthenes, a large submerged carbonate platform, were re-examined.

To take a closer look, the team acquired two regional 2D seismic lines that were not included in the government “data package” that enabled them to connect the Egyptian area of interest with the Israeli-Cypriot area and better define the shape of the bio-structure identified. In addition, the explorers decided to reinterpret internally, using sophisticated Egyptian “imaging” technology, the old seismic data: the results were surprising!

This is another fascinating aspect. One thinks that geologists are all numbers and formulae, but the creative mind of a geologist is full of 3D images, enlargements of coloured rocks and seismic lines. In fact, geologists are more inventive than one might think, and they can even compose an authentic “digital picture” of an exploration.

In the new geological model, the “lead”, or the potential object of exploration, is actually described as a bio-structure of the Miocene age (about 10 million years ago) that has grown on a pre-existing plain of the Cretaceous period.

The interesting thing is that the “big potato” (for geologists the bio-structure is simply the “big potato”) is covered with evaporite rock (rock salt) of Rosetta formation (the equivalent of the chalky-sulphurous Apennines and Sicily), notoriously good for sealing the reservoir (hence the “big potato”). Moreover, we know from the fields discovered in Cypriot and Israeli waters, that the hydrocarbon system of migration of biogenic gas should be active in the area.

This means that Block 9 has all three of the basic conditions for a potential accumulation: a reservoir, a cap that seals, the source rock. But time is running out and it will not be easy to get the green light for the project from the top floor. What’s more, the Shorouk area was held by another operator (a big major) for ten years, during which nine wells were drilled without commercial results. How is it possible that they didn’t see the “big potato”? The explanation of ENI’s explorers is that they were looking for a different geological game, a classic of the Nile Delta (Miocene sands), not the sea-mount carbonate variety that seems to be the case with the “big potato”, and currently the only one of its kind.

At the headquarters of ENI Corporation in San Donato, the explanation was deemed convincing and in February 2013 the IEOC sent an offer to the Egyptian government. During the summer ENI informally learned that it had won the bid, even though the official signing came only in January 2014 when 100% of Block 9 was assigned to the IEOC. As expected competition was limited; the majors had held their positions without exposing themselves, waiting for better times.

Meanwhile in Egypt the political conditions were changing. With the fall of the Muslim Brotherhood, the new government of President Sisi started to pay the old debts. In a few months they renegotiated gas contracts. Production in the country was falling, and new resources would have to be found from exploration.

In this new context, ENI considered it important to show signs of a recovery in its activities to Cairo, firstly in the Nile Delta and in the deep offshore. It awarded contracts for 3D acquisition in the Shorouk block and evaluated the exploration of Zohr ahead of the contract schedule (fixed for the second exploratory phase), and bringing the Saipem 10000 drilling rig to Egypt.

For some this was a premature, even risky, step. “We still don’t have the seismic 3D, how can we optimise the location of such an important well…?”

It should be noted that in Egypt, where the six-legged dog has been present for decades, the classic exploratory activity is for gas in the sands of the Nile Delta. The Zohr model would be sensationally new. It is not easy to convince yourself about something that is out of the ordinary, but when a team believes passionately in a project, and is able to present it to management, they will defend it vigorously.

But I’ll tell you one thing to give you an idea of the climate of those hectic days. One evening in April (2015) in San Donato all the geologists and geophysicists of the team were called to a meeting. The questions were few but clear:

“Are we confident that the structure exists?” The answer was yes.
“Are we confident that we have a controlled structural closure with the existing seismic2D?”The same unanimous answer.

Ok, let’s go for it.

“And if we really do find something really, the 3D will be useful later, but not to decide whether to drill such a large object …,” my explorer friend explained.
However, the well will be expensive and risky. Insiders call such prospects “high risk/high reward”. The company started to look for partners willing to take a minority stake to reduce the risk and the investment. Several oil companies visited the “data room”, but they all considered Zohr too uncertain; the model was not proven and might turn out to be totally wrong.

So ENI decided to go it alone. It believed in it. The timing was tight, and everything was still to be organised: acquiring permits and authorisation from Cairo, organising the logistics, preparing the drilling programme. The Egyptian system was extremely cooperative and everything was set up in just a few months.

On 25 June, 2015, the huge Saipem 10000 was located in Block 9 and work on the well physically started on 3 July. Fingers crossed.

The moment of truth is always the well

Operations progressed quickly but at that depth it takes thirty days to arrive at potential reservoir rock. On 18 July, 2015 the well emerges comes from the evaporite (salt) of the Rosetta formation and there were immediate signs of gas.

Fingers still crossed.

Very cautiously and carefully drilling begins. The first carbonate rocks are reached.
“Just think, when we arrived at that point it was like cutting through butter…” my explorer friend says.

The indications of gas continue. Fingers crossed again …
For many days and nights no one sleeps. Explorers, drillers and top management are in constant contact, the meetings are endless. “You have to understand where we had got to from a stratigraphic point of view, it is very important! And what geological age the rocks we were cutting through are.”

After feverishly analysing the drill cuttings, the first reports were prepared: we were, in fact, in the presence of Miocene carbonates. The team’s model really seemed to work!
Drilling continues and they continued to find gas. One hundred, two hundred, three hundred metres into the reservoir. The time was right to start collecting data and securing what had already been drilled.

From the ship’s log of those days:

“Electric logs were acquired, fluids sampled, formational gradients were measured. Rock samples were taken for stratigraphic analysis, the seismic model was calibrated with seismic acquisitions from the well … “

Meanwhile, the first confirmations arrive: the well is mineralized natural gas and carbonate reservoir rocks are of excellent quality.

Drilling begins again. Four hundred, five hundred, six hundred metres in gas! The numbers start to get big, very big, and we began to be aware of the scale of the Zohr discovery.
“600 metres of gas permeated rock with pressure points so aligned has never been seen before…” It’s like the famous four pyramids of Cheops one on top of the other.

You know the rest already. Everyone has been talking about Zohr but giving an account of the discovery is first of all to describe a way of working that is typical of ENI. We could cut and paste for the fields discovered in Congo, Angola and Mozambique.

Throughout the four corners of the globe there is always a time when we Italians are able to change the game by combining a capacity for synthesis and inventiveness. We are able to do different things working on traditional territory, even in mature areas already worked in the past (such as Egypt), looking at things from another viewpoint.

The intuition of trying something other than the typical game used in the Nile Delta; of applying the discoveries of offshore Israel to Egypt; not stopping at the “data package” as it was, but going beyond; following the regional paths of gas migration and using geological references already tested in other countries (Libya, Venezuela and Kazakhstan), these are typically Italian attitudes and the result of ENI’s worldwide experience worldwide. Our competitors are perhaps more organised, with richer and more numerous teams, but they don’t know how to discard as we do …

“From a professional point of view – my explorer friend concludes – I can say that there is nothing more exciting than seeing what was only a model built from a puzzle of little information being confirmed. It is even more exciting to discover that others before you did not see the potential or declined the invitation to join the game believing it was worthless or too risky. This is exploration, the best job in the world.”

A three-year journey – together with an extraordinary team of geologists, geophysicists, drilling engineers and logistics specialists, experts in IT and economic evaluations – that it was was to tell from the inside.

PS It is said that fortune favours the brave, right? Right. If ENI had not decided to bring forward the exploration of Zohr, we would not be here talking about it …
Marco Alfieri, an Italian journalist, is content strategy and Newsroom manager at ENI’s Daily newsletter at Il Foglio. He was Editor in chief at and hasworked at Il Sole 24 Ore and La Stampa.

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CGG Provides Overview of East African Rift Basin

NPA Satellite Mapping, a unit of CGG GeoConsulting has launched the multi-client EARS BasinMap for exploration de-risking across the vast region of East Africa, from regional-to-prospect or play scale. The EARS Basin Map is part of a new NPA Mapproduct suite that offers world-leading satellite imagery-based geological mapping at different scales on either a proprietary or multi-client basis through PlateMap, BasinMap, BlockMap and FieldMap products.

“The EARS BasinMap provides an entirely new 1:200,000 scale geological map and database of the East African Rift System and integrates structural history, drainage analysis and sediment provenance”, CGG says in a release. “Compiled by expert interpretation of satellite optical imagery and topographic data (the latest Landsat 8 OLI and SRTM 1 DEM data),the data base extends across approximately 2.5 million km2 of East Africa taking in Kenya, Uganda, Tanzania, Rwanda, Burundi, Malawi and parts of Ethiopia, Mozambique, Zambia and the Democratic Republic of Congo. New Ventures & Exploration teams can use the EARS BasinMap for regional screening to rapidly gauge and understand the structural dynamics of ongoing rifting and predict the location of favorable sediment sequences with high reservoir potential.

“Across the under- and unexplored rift basins, where exploration data quality and quantity are limited, the EARS BasinMap provides a regional analysis of the timing and history of regional fault movement, uplift and erosion, which control sedimentation and accommodation space within the basins. The style and geometry of the rift-related structures in the region have an inherited relationship with the mapped basement trends, and control both compartmentalization of the rift basins and the drainage systems. The combined elevation data and map data provide valuable insight on geological evolution, source-to sink depositional systems and reservoir quality. When coupled with Seep Explorer (CGG’s on- and offshore seeps database) and Tellus (CGG Robertson’s strategic new ventures tool), structural, reservoir and source risk can be even further reduced in this developing hydrocarbon province”.

CGG boasts that this product’s “rich, geological database is easily accessed and interrogated through NPA Satellite Mapping’s proprietary ArcGIS*Onshore Analyst Tool (OAT), which allows user-driven queries of thematic data sets, encompassing fully referenced lithologies, local names, stratigraphic age, and type and timing of structures.Once leads and prospects have been identified, the database can be leveraged to provide the context for more detailed block studies, which can include more advanced section building, geological modeling and fieldwork, and for seismic planning. The EARS BasinMap is available for licensing for either the entire East Africa region or cropped large sub-regions”.

Geoscientists Plot Season of Rahaman

By John Celestine-Akobata

A committee of geoscientists is plotting a month long series of activities, anchored on the most current thinking in geosciences, to mark the 70th birthday of the Nigerian scholar Omar Rahaman.

“It’s more than a committee of his colleagues, friends, former and current students”, says Kenny Ladipo, a former top Shell geologist and earth science thinker and founder of the Centre of Excellence in Geosciences &Petroleum Engineering at the University of Benin, in the Niger Delta region. “It’s a way  of celebrating the subject of geoscience itself. “Professor Rahaman has been a selfless builder of capacities in the subject”.

At the centre of activities being planned is a book to document the current research frontiers and thinking in geosciences in Africa. The  book is proposed to cover ALL aspects of Nigerian geology, including the basement (Igneous and metamorphic) and their economic potentialsincluding solid minerals, as well as the stratigraphy, sedimentology and petroleum systems of Nigeria’s sedimentary basins and petroleum and potentials. It is expected to highlight concepts and research output in hydrogeology, applied geophysics and geochemistry as they apply to the improved understanding of the geology of Nigeria.

Omar Morufu Rahaman is a widely quoted expert on the Precambrian (the earliest rock unit) geology of Africa and has served in the academia, mainly at the Obafemi Awolowo University for over 40 years, but perhaps his most distinguishing trait is the training of geoscientists. Professor Rahaman’s main ambition is to produce high quality geoscience graduates that can be employed anywhere in the world. For nine years he was the coordinator of the aptitude examination used by the Petroleum Technology Development Fund (PTDF) to select beneficiaries of the Funds Overseas Scholarship Scheme for the skills acquisition at the Master’s level in selected Universities in Britain.

For the unique anniversary of the day of his birth, the planned activities include

  • an hour long talk by the celebrator himself at the May 2016 edition of the monthly Technical/Business Meeting of the Nigerian Association of Petroleum Explorationists (NAPE) on May 18, 2016 at the Eko Hotel, overlooking the Atlantic in Lagos.
  • Symposium (featuring oral presentation of many of the technical papers proposed for compilation in the book) on May 31, 2016
  • Gala Night (Dinner) including the launch of an endowment of a Foundation, on May 31, 2016.

“The proposed book will be a follow up to the publication of May 2006 published to mark Professor Rahaman’s 60th birthday anniversary”, notes Kehinde Olafiranye, who is the secretary of the committee and anchor person driving the project.

Ladipo, who is Chairman of the overall Season of Rahaman Committee, says that a First call for contributions of research and technical papers to the book Contemporary Geosciences in Nigeria in honour of Rahaman at 70 has gone out. Industry professionals, academics and students are invited to submit  full length papers that relate to any of the following themes: (1) The Mother Rock: Developments in Basement Geology (2) Innovations in petroleum Exploration and Exploitation (3)Solid minerals exploration, exploitation an viable policy framework (4) Strategy for a sustainable, robust geoscience manpower development.

Short Papers are to be emailed to: Deadline for submission is March 31, 2016. Contributors will be advised to give oral presentations during the symposium on May 31, 2016.

CGG Gets In Bed With Baker Hughes

Seismic company and well services provider in unique partnership

CGG and Baker Hughes Sign Exclusive Long-term RoqSCAN Agreement as Part of Shale Science Alliance. Baker Hughes has signed an exclusive agreement with CGG for RoqSCAN™ technology offered by CGG.

“RoqSCAN is a real-time, fully portable, quantitative and automated rock properties and mineralogical analyzer”, Baker Hughes says in a release. Developed by Robertson, a CGG company, and Carl Zeiss Microscopy Ltd., RoqSCAN “delivers highly quantitative compositional and textural mineralogical data from drilling cuttings or core pieces, revealing the mineralogical DNA of the reservoir”, the release claims. “This service can be provided at the wellsite during drilling operations, or later in core stores, field offices and laboratories”.

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