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Natural hydrogen seeps called fairy circles have been identified in Mali, Brazil, Russia, and United-States. Natural hydrogen is produced from a field in Mali for 7 years. The natural hydrogen system is still poorly understood and needs to be studied in new geological contexts as to streamline hypotheses on the system dynamics and elements into concepts. In Australia, numerous circular surface features, commonly called salt lakes or swaps, are visible from the sky but no existing work shows nor quantifies any hydrogen content in those features. In this study, we reviewed the existing literature on fairy circles as to determine and directly test with soil-gas measurements if hydrogen surface-emitting features are present in Australia. We determined best candidates to test with a multi-disciplinary approach linking geology, multi-physical imaging, and seismic interpretation. Soil-gas measurements showed persistent hydrogen concentration localized in the external ring of circular depressions aligned along the Darling Fault, a major crustal boundary between the granitic, mafic and ultramafic rocks of the Yilgarn Craton from the sedimentary rocks of the Perth Basin. This work is the proof that fairy circles, in the meaning of H2 emitting structures, are present in Australia and opens the door to new prospectivity pathways by evaluating original hypotheses on natural hydrogen generation, migration pathways and entrapment. This geological setting promotes deep serpentinization of ultramafic rocks as well as oxidation of iron-rich Archean rocks and mafic dikes as potential hydrogen sources that are both of massive potential economic value. This hydrogen can circulate and be entrapped as aqueous hydrogen in low-salinity aquifers or migrate in gaseous phase in fault zones up to intermediate structural reservoir or to the surface.

Studies of near-seabed datasets show that salt tectonics controls the distribution and architecture of deep-water reservoirs in many salt-influenced basins. It is typically difficult, however, to study the distribution and stratigraphic evolution of depositional systems preserved at deeper, economically significant depths, reflecting poor seismic imaging of steeply dipping strata flanking high-relief salt structures. 3D seismic and borehole data from the Santos Basin, offshore Brazil allow us to identify a range of depositional elements that form the building blocks of three main tectono-stratigraphic phases. During the first phase, channel systems and lobes were confined within updip minibasins and to the hangingwalls of salt-detached faults. During the second phase, channel systems and lobes filled updip minibasins to bypass sediment downslope, with coarse clastic deposition then occurring in downdip minibasins, >100 km from the coeval shelf margin. Syndepositional seafloor relief caused: (i) channel system deflection and diversion around salt-cored highs; (ii) channel system uplift and rotation on the flanks of rising salt structures; (iii) lateral and frontal confinement of channel systems. During the final phase, rising salt walls dissected previously deposited deep-water systems, with MTCs deposition becoming increasingly important. Our results have important implications for post-salt prospectivity in the Santos Basin and other salt-influenced sedimentary basins, with a range of reservoirs and trapping styles present in this underexplored interval. More specifically, we show that large volumes of clastic sediment were not trapped behind the ‘Albian Gap’, a salt-controlled depocenter dominating the north-western basin margin, but were instead delivered further basinward.

Sedimentary basins in south Egypt, in particular Komombo and Nuqra basins, have been paid more attention during the last few decades, due to their hydrocarbon prospectivity. The present article is an integrated seismic and petrophysical study aiming at evaluating the hydrocarbon potentiality of the Cretaceous sedimentary sequence in these two basins. Data of four drilled wells including a conventional core, and well log data, in addition to 20 2D seismic profiles (ten for each basin), were studied in detail. The study indicates that the sedimentary sequence in the two basins is represented by the Nubia Sandstone, which is subdivided (from base to top) into Komombo, Six Hills, Abu Ballas, Sabaya, and Maghrabi formations. This sequence in both basins is dissected by a set of NW–SE-trending faults, in addition to a younger set of NNE–SSW to NE–SW trending. The present study indicates that the Komombo Formation is characterized by a good oil potentiality of a net pay thickness up to 65 ft (1 ft = 0.3048 m) in the Komombo basin. The Six Hills Formation may also be prospective, especially near the depocenters of the Komombo and Nuqra basins, due to its wide extension, good thickness (up to 4150 ft), and presence of some oil shows. However, the reservoir of the studied sequence may be of low quality due to cementation with silica, compaction, and the presence of high shale content. Two reservoir rock types (RRTs) were assigned to the Six Hills Formation: RRT1 (clean siliceous sandstone) with good reservoir quality and RRT2 (argillaceous sandstone) with low reservoir quality.

The renewed quest to boost Nigeria’s dwindling reserves through aggressive search for oil and gas deposits in Cretaceous sedimentary basins has re-ignited the need to re-evaluate the hydrocarbon potentials of the Dahomey Basin. Aeromagnetic data are a low-cost geophysical tool deployed in mapping regional basement structures and determination of basement depths and sedimentary thickness in frontier basin exploration. In this study, high-resolution aeromagnetic (HRAM) data covering the Dahomey Basin Nigeria have been interpreted to map the basement structural configuration and to identify mini-basins favorable for hydrocarbon prospectivity. The total magnetic intensity grid was reduced to the equator (RTE) and edge detection filters including first vertical derivative (FVD), total horizontal derivative (THDR), tilt derivative (TDR) and total horizontal derivative of upward continuation (THDR_UC)) were applied to the RTE grid to locate the edges and contacts of geological structures in the basin. Depth to magnetic sources were estimated using the source parameter imaging (SPI) method. Data interpretation results revealed shallow and deep-seated linear features trending in the NNE-SSW, NE-SW, NW-SE and WNW-ESE directions. The SPI map showed a rugged basement topography which depicted a horst-graben architecture on 2D forward models along some selected profiles. Two mini-basins ranging in basement depths between 4.5 – 6.3km were mapped offshore of the study area. It appears the offshore Dahomey Basin holds greater promises for hydrocarbon occurrence due to the presence of thicker succession of sedimentary deposits in the identified mini-basins.

Rock properties in the subsurface are of major importance for evaluating the petroleum prospectivity of a sedimentary basin. The key rock properties to understand are porosity, density, temperature, effective stress, and pore pressure. These rock properties can be obtained or calculated when borehole data are available. However, borehole data are usually sparse, especially in frontier basins. We propose some simple rock-physics transforms for converting P-wave velocity to other rock properties. We found that these rock-physics transforms are predictive in the east and west sides of Campeche Basin. The proposed rock-physics transforms can be used to obtain laterally varying rock properties based on information derived from seismic data.

Investigating the timing, structural style, and development of multiphase extensional fault systems is essential for understanding rift basin evolution and for assessment of structural trap integrity. Borehole-controlled interpretation and analysis of two-dimensional and three-dimensional seismic data sets from the eastern Dampier subbasin indicate that a northeast-trending basement weakness zone was subjected to west-northwest–east-southeast oblique extension in the latest Triassic–late Middle Jurassic, resulting in systematic segmentation of the Rosemary fault system (RFS). Temporal stress change during Cretaceous north-south extension produced complex fault systems along the RFS, including (1) east-west–trending isolated faults with maximum displacement close to their center; (2) east-west–trending abutting faults, which initially nucleated as isolated faults, later abutted against the main structure, showing large displacement accruement on the composite fault; and (3) northeast-southwest–trending splay faults characterized by systematic left-stepping segmentation, with maximum displacement occurring at the point where the splay faults deviate from the main structure. In the Miocene, the RFS was locally reactivated by northwest-southeast compression in the northeastern part of the fault system, developing a compressive fault-propagation fold at the upper tip of the inverted extensional fault. This study suggests that the style of basin boundary fault reactivation depends largely on preexisting structures and temporal stress changes. The fault reactivation style is also a significant factor in influencing basin architecture, sediment distribution, fault linkage processes, and petroleum basin prospectivity.

Azerbaijan is one of the oldest oil and gas provinces, where more than 2 bln tons of oil have been extracted over more than a century. At present, the oil production is declining and mainly determined by production from the Azeri-Chirag-Guneshli offshore block (AChG). Compared to oil, the opportunities for further growing natural gas reserves and production are very promising. For the latest years, a number of large gas condensate fields have been discovered in the deep-water part of South Caspian Sea, such as Shakh-Deniz, Apsheron, Umid. There are a number of prospects that have not yet been drilled in this part of the sea basin. The paper assesses their prospectivity, substantiates the priority exploration targets and, on the basis of the statistical analysis of the quantitative gas/oil ratio data for many other Azerbaijanian and world basins, an attempt is made to assess the reserves in the prospects. The total recoverable oil reserves in Azerbaijan are estimated at 3.5 bln tons, of which slightly above 2 bln tons have already been extracted. Based on the statistically estimated ratio between the volumes of gas and oil in various basins of the world, including Azerbaijan, the total possible natural gas reserves in Azerbaijan are estimated at about 4 trillion m3 . This is in agreement with the other available estimates. Of this volume of natural gas, 0.85 trillion m3 has already been extracted, and the approved geological reserves are estimated at 2.55 trillion m3 . Almost 83% of the extracted natural gas belonged to offshore fields. This trend will continue in the future, and, moreover, will be strengthened due to large volumes of gas condensate accumulations in the deepwater part of the basin. In this part of the basin, the most attractive prospects are Mashal, Shafag, and Israfil Huseynov, total reserves of which are expected at 0.6 trillion m3 of natural gas.

Neoproterozoic sedimentary basins are increasingly gaining hydrocarbon exploration attention globally following results of significant discoveries in these basins as a result of long, consistent and focused research and exploration efforts. The hydrocarbon prospectivity of the unexplored Mesoproterozoic–Early Paleozoic Voltaian basin is reviewed relative to global Neoproterozoic basins. Like the Voltaian basin of Ghana, global Neoproterozoic basins have experienced similar geological event of glaciation with accompanying deposition of marginal–shallow marine carbonates and associated siliciclastic argillaceous sediments. These carbonates and argillaceous sediments coupled with deep anoxic depositional environments, favored the preservation of organic matter in these sediments and carbonates globally making them source rocks and in some cases the reservoir rocks as well, to hydrocarbon occurrence. The hydrocarbon prospectivity of the Voltaian is highly probable with Neoproterozoic basins of similar geologic analogies, Amadeus basin, Illizi basin, the Tindouf and Taoudeni basins of the WAC, having proven and active petroleum systems with some listed as world class oil/gas producing basins together with other Neoproterozoic basins like South Salt Oman basin, Barnett shales and giant gas reserves of southwestern Sichuan basin of China.

Direct hydrocarbon indicator (DHI) expressions observed on seismic could arise due to various geological conditions. Such expression could lead to misinterpretation as hydrocarbon presence if not properly analyzed. This study employs rock physics attributes analysis to evaluate an identified prospect in the undrilled area of the studied reservoir. Prospect identification was actualized by analyzing structural and amplitude maps of the reservoir, which revealed a possible roll over anticline at both the exploited and prospective zone, with a very good amplitude support that conforms to structure. Well-based cross-plot analysis adopted four cross-plot techniques for feasibility study to test the applicability of rock physics for prospect evaluation in the field; Lambda-Rho versus Lambda-Rho/Mu-Rho ratio; Mu-Rho versus Lambda-Rho; and Poisson Ratio versus P-impedance. The result presented Poisson ratio, Lambda-Rho and Lambda/Mu-Rho ratio as good fluid indicator and Mu-Rho as a viable lithology indicator. As such, they were selected for seismic-based attribute and cross-plot analysis to validate the identified prospect. The results from seismic-based analysis showed consistency in the expression of the analyzed attribute at both the exploited and prospective zone. The seismic-based cross-plot analysis result was similar to the well-based analysis and was able to confirm that the observed amplitude expression in the exploited zone is an indication of hydrocarbon-bearing sand.

Tanzania, like other East African countries, is seeking to increase its hydrocarbon discoveries from both onshore and offshore sedimentary basins. Although the Tanga onshore basin has the potential of adding to the hydrocarbon reserve of the country, it has very scanty literature to guide preliminary investigations into the basin prospectivity. This review seeks to highlight the petroleum system elements within the basin and how worthy it is exploring for its hydrocarbons potential. The general geology of the basin seems to have characteristics of a complete petroleum system with dolomitic limestone as source rocks and an obvious shale source rock and evidences of fossils and oil seepage around Kivundo River, although further research is needed to validate this assumption. Feldspathic sandstones are present to serve as a reservoir to economic hydrocarbon reserves. The basin has suitable thickness to provide the needed temperature and pressure for thermal maturity of any existing organic matter (OM) and to expel them from their various ‘kitchens’. Brittle structures are available to facilitate the migration of expelled kerogens. Structural straps are available via micro-folds and faults, to ensure accumulation of economic quantities that could be explored and exploited at profit. Also, the Tanga onshore basin has geological analogies that are similar to other basins’ hydrocarbon discoveries including that in Rovuma, Morondava and Songo Songo basins which are to the south of Tanga onshore basin.

The UK Rockall, located to the west of Scotland and the Hebrides, is a frontier petroleum-bearing basin. Exploratory drilling in the basin took place over a quarter of a century (1980–2006), during which time a total of 12 wells were drilled, leading to the discovery of a single, subcommercial gas accumulation. We argue that the basin, which has seen no drilling activity for more than a decade, has not been sufficiently tested by the existing well stock. We examine the reasons for the absence of key Jurassic source rocks in the UK Rockall wells, which are widely distributed elsewhere on the UK Continental Shelf (UKCS), and argue that their absence in the wells does not preclude their existence in the basin at large. An evaluation of the Permian–Early Eocene successions, based upon the seismic interpretation of new 2D seismic data, has been integrated with legacy data and regional evidence to establish the potential for source, reservoir and sealing elements within each interval. Finally, we look at the future for exploration in the UK Rockall and suggest a way forward in the drilling of a new joint governmental–industry test well that may help to unlock the exploration potential of this under-explored, yet prospective, basin. Thematic collection: This article is part of the Under-explored plays and frontier basins of the UK continental shelf collection available at: https://www.lyellcollection.org/cc/under-explored-plays-and-frontier-basins-of-the-uk-continental-shelf

This paper presents the potential depositional framework of sandstones and unconsolidated sand reservoirs, seals, and traps in the western part of the coastal swamp depobelt of the Niger Delta Basin, Nigeria, through integration of sequence stratigraphy and seismic imaging. The integration of well logs and biostratigraphic (foraminifera and palynological) data with three-dimensional seismic volume established the sequence stratigraphic framework, which has improved our understanding of the impact of sea-level changes in the distribution of sand facies. Four third-order seismic depositional sequences (sequences 1–4) of Serravallian deposits were identified based on the Vail stratigraphic concept. Depositional processes, structures, thickness, and seismic signatures vary in each sequence. Sequence 1, dominated by mud and very fine-grained sand facies, represents the outer shelf–shelf margin setting and has experienced shale tectonics (ductile deformation). Sequences 2 and 3 consist of alternating sand–shale facies and have experienced gravitational tectonics. Although sequence 2 represents middle shelf–inner shelf setting, sequence 3 represents inner shelf–transitional setting. Sequence 4 consists of thick fluvial–coastal plain sand facies and represents deltaic plain or continental sediments. These deposits reflect postgravitational tectonics. Within the third-order sequences are fourth-order sequences that recorded the interaction between small-scale transgressive–regressive cycles and depositional tectonics. The potential reservoirs within these sequences are stacked channel sandstones, shoreface sandstones, and heteroliths. The juxtaposition of the potential reservoirs against transgressive shales provides potential seals and traps. Structural interpretation shows synthetic and antithetic faults. In addition, event maps at various ages document structural closures that indicate the existence of possible hydrocarbon leads and prospects.

The middle Jurassic transgressive limestone with intermitted fresh water clastic facies of Jaisalmer Formation contains reservoir-seal assemblage with fair source rock potential, provide a target for exploration. Till date, very few exploration ventures have been made to explore this formation. The frontier exploration team need to address this sequence with possible accumulation pattern and migration pathways. The objective of current study is to focus on the prospectivity of Jaisalmer Formation that has been established from minor discovery of liquid and gaseous hydrocarbon. In the present study, an attempt has been made to establish the facies model that includes litho-micro-facies, bio-facies, source rock facies and depositional facies. This formation has been tested for hydrocarbon in several wells and in some of the well gas/oil has been flown with water. With exploration background in mind, a detailed examination of Jaisalmer Formation has been attempted in terms of its contribution to the exploration efforts in the basin.

The Larne and Portpatrick basins, located in the North Channel between SW Scotland and Northern Ireland, have been the target of a small programme of petroleum exploration activities since 1971. A total of five hydrocarbon exploration wells have been drilled within the two basins, although as of yet no commercial discoveries have been made. The presence of hydrocarbon shows alongside the discovery of two good-quality reservoir–seal couplets within Triassic and underlying Permian strata has encouraged exploration within the region. The focus of this study is to evaluate the geology and hydrocarbon prospectivity of the Portpatrick Basin and the offshore section of the Larne Basin. This is achieved through the use of seismic reflection data, and gravity and aeromagnetic data, alongside sedimentological, petrophysical and additional available datasets from both onshore and offshore wells, boreholes and previously published studies. The primary reservoir interval, the Lower–Middle Triassic Sherwood Sandstone Group (c. 600–900 m gross thickness), is distributed across both basins and shows good to excellent porosity (10–25%) and permeability (10–1000 mD) within the Larne Basin. The Middle–Late Triassic Mercia Mudstone Group should provide an excellent top seal where present due to the presence of thick regionally extensive halite deposits, although differential erosion has removed this seal from the margins of the Larne and Portpatrick basins. The Carboniferous, which has been postulated to contain organic-rich source-rock horizons, as inferred from their presence in adjacent basins, has not yet been penetrated within the depocentre of either basin. There is, therefore, some degree of uncertainty regarding the quality and distribution of a potential source rock. The interpretation of seismic reflection profiles presented here, alongside the occurrence of hydrocarbon shows, indicates the presence of organic-rich pre-Permian sedimentary rocks within both basins. 1D petroleum system modelling of the Larne-2 borehole shows that the timing of hydrocarbon generation and migration within the basins is a significant risk, with many traps post-dating the primary hydrocarbon charge. Well-failure analysis has revealed that trap breach associated with kilometre-scale uplift events, and the drilling of wells off-structure due to a lack of good-quality subsurface data, have contributed to the lack of discoveries. While the Larne and Portpatrick basins have many elements required for a working petroleum system, along with supporting hydrocarbon shows, the high risks coupled with the small scale of potential discoveries makes the Portpatrick Basin and offshore section of the Larne Basin poorly prospective for oil and gas discovery. Thematic collection: This article is part of the Under-explored plays and frontier basins of the UK continental shelf collection available at: http://www.lyellcollection.org/cc/under-explored-plays-and-frontier-basins-of-the-uk-continental-shelf

Bangladesh is a country with limited sources of energy and since 1990 natural gas has been its main source of energy. Most of the exploration approaches had been conducted onshore especially in the central and eastern part of Bangladesh, particularly in northeastern Sylhet basin. Among the hydrocarbon provinces, the East Delta Hill Tract province is an under explored petroleum province in Bangladesh. An exploratory well drilled in Sitakund anticline was found dry but no reasonable cause was perceived why that well went dry. Although many works had been carried out in Chittagong Hill Tracts but none of them was cumulative and descriptive. In this study, the overall hydrocarbon prospect of the Chittagong Hill Tracts was analyzed by mapping of potential zones on the basis of the evaluation of regional structure and construction of lithocolumn of the prospective zones. The five elements of the petroleum system discussed thoroughly to find overall petroleum prospect of the study area. Source rocks of Chittagong Hill Tracts are mainly Bhuban shale, reservoir rock is sandstone from Bhuban-Bokabil formation, the way of migration path is both through longitudinal and cross fault. The data of source rock and seal is collected from previous researches. Multiple types of traps have been found there. Conventional anticlinal traps which are highly disturbed due to tectonic instability & the core part are shale diapirism. Most of the anticlines are plunging and the nose or plunge area might be prospective to HC for being comparatively less faulted. Broad synclinal areas between tight narrow anticlines are another prospective area for HC. These similar types of synclines are also found in Tripura, India which is a highly prospective area for petroleum and their small anticlinal hums within syncline are also prospective. Some stratigraphic traps have also been found in Tripura from where production has been started already. Both Chittagong Hill Tracts and Tripura Fold Belts are parts of great Arakan Fold Belts, so similar type of structures might be prospective here. Apart from these, Bangladesh is a deltaic country. So stratigraphic trapment like channel sand, pinch-outs is possible. Considering all the elements of petroleum prospectivity of the area and factors discussed above, it is quite clear that Chittagong hill tracts might be the next target for HC exploration program.

This paper outlines a Finite Element modelling workflow using the software package ‘Underworld’ that is applied to sedimentary basin undergoing multiple rifting events. The evolution of the resulti...

Definition of the basement architecture within the Ceduna Sub-basin is poorly understood due to the depth of the basin and limited deep crustal geophysical datasets. This study uses seismic interpr...

The spatial-temporal relationship between high-quality source rocks and reservoirs is a key factor when evaluating the formation, occurrence, and prospectivity of tight oil and gas reservoirs. In this study, we analyze the fundamental oil and gas accumulation processes occurring in the Songliao Basin, contrasting tight oil sand reservoirs in the south with tight gas sand reservoirs in the north. This is done using geochemical data, constant-rate and conventional mercury injection experiments, and fluid inclusion analyses. Our results demonstrate that as far as fluid mobility is concerned, the expulsion center coincides with the overpressure zone, and its boundary limits the occurrence of tight oil and gas accumulations. In addition, the lower permeability limit of high-quality reservoirs, controlled by pore-throat structures, is 0.1 × 10−3 μm2 in the fourth member of the Lower Cretaceous Quantou Formation (K1q4) in the southern Songliao Basin, and 0.05 × 10−3 μm2 in the Lower Cretaceous Shahezi Formation (K1sh) in the northern Songliao Basin. Furthermore, the results indicate that the formation of tight oil and gas reservoirs requires the densification of reservoirs prior to the main phase of hydrocarbon expulsion from the source rocks. Reservoir “sweet spots” develop at the intersection of high-quality source rocks (with high pore pressure) and reservoirs (with high permeability). Keywords: Spatial-temporal coupling, High-quality source rock, High-quality sandstone, Tight sandstone reservoir, Songliao Basin

In this paper, two kinds of knowledge-driven methods, one using the fuzzy logic and another using geometric average, were applied to create the mineral potential maps for Cu sulfide deposits in the greenfield Kapsan Basin, DPR Korea. The ore geology studies for the study area have revealed that Cu sulfide deposits of hydrothermal genesis in Kapsan Basin are closely associated with Jurassic intrusions and faulting tectonics. Based on the conceptual model of Cu sulfide deposits and the available spatial datasets in the study area, we used five independent evidential maps for Cu sulfide deposits potential mapping. They include: (1) faults; (2) aeromagnetic anomaly; (3) Cu geochemical data; (4) Pb geochemical data; and (5) Zn geochemical data. The evidential map values were transformed into continuous values of the [0, 1] range using the non-linear fuzzy membership functions; logistic sigmoid and fuzzy Gaussian functions. Because the fuzzy logic and geometric average methods can use the same fuzzification methodology based on suitable membership functions, it is very economic and efficient to simultaneously apply two predictive models for mineral potential mapping of the study area. The preparation of these evidential layers were performed using spatial analyses supported in ArcGIS 10.4 GIS platform based on geological, geophysical and geochemical spatial datasets. The validation and comparative analysis results for the two predictive models demonstrated that most of known mineral occurrences are distributed in areas with high potential values. The target areas classified by the fuzzy logic occupy 15% of the study area and contain 78% of the total number of known mineral occurrences. Compared with the fuzzy logic, the resulting areas by the geometric average occupy 13% of the study area, but contain 93% of the total number of known mineral occurrences. Although the total number of known mineral occurrences is relatively low for the application of ROC (receiver operating characteristics) technique, the areas under the ROC curve (AUC) obtained by two predictive models were greater than 0.5, suggesting that both predictive models and their resulting potential maps are useful for evaluating the prospectivity of Cu sulfide deposits in Kapsan Basin.

The Canning Basin is a largely unexposed and underexplored frontier basin, formed mostly in the Paleozoic. Geological knowledge of this basin is based predominantly on sparse regional “vintage” two-dimensional seismic and small three-dimensional (3-D) seismic surveys and less than 230 exploration wells. Following seismic interpretation, an integrated interpretation was completed on airborne gravity gradiometer (AGG), magnetic, seismic, well, and complementary data along the southwestern margin of the Fitzroy trough and Gregory subbasin. Seismic data were reinterpreted using AGG data to produce a better constrained geological model. A basement structure map, two intrasedimentary structure maps, and a formation distribution map were produced. The interpretation of seismic profiles, validated through 2.5-dimensional gravity gradiometer modeling, is essential to this workflow. Repeatedly reactivated west–northwest and northwest structural trends, inherited from Proterozoic orogenies, respectively delineate the Fitzroy trough and the Gregory subbasin with its northwestern structural extension into the Fitzroy trough, the Gregory subbasin trend. Subsidence occurred during two periods of extension. An asymmetric extensional system of the Fitzroy trough controlled Ordovician–Silurian deposition of the Carribuddy Group. Devonian–Carboniferous subsidence defines the Gregory subbasin trend. This Pillara extension reactivated structures in the east of the Fitzroy trough. Simultaneous activity of both extensional fault systems and growth faulting controlled the facies and thickness distribution of carbonates and clastics of the early Carboniferous Fairfield Group. The Meda and Fitzroy transpressional phases inverted faults of the Gregory subbasin trend and Fitzroy trough, producing prospects by structural interference. The improved understanding of tectono-stratigraphic relationships, including the 3-D distribution of carbonate reservoirs, benefited the planning of seismic surveys, prospect evaluation, drilling, and acreage relinquishment.

Seismic interpretation, geological mapping and depth conversion of the Zechstein Supergroup (Z2 cycle), using high-quality well-calibrated three-dimensional (3-D) seismic, has revealed the complex palaeomorphology of a deeply-buried ancient carbonate shelf-margin on the southwestern margin of the Southern Permian Basin. The new mapping shows that the margin comprises a series of corrugated embayments and promontories which extend up to 5 km (3 mi) into the basin and locally have a palaeobathymetric relief of >200 m (650 ft). Well calibration across the margin demonstrates a strongly bipartite lateral thickness distribution between a high velocity anhydrite-dominated shelf and a lower velocity halite-dominated basin. Strong lateral and vertical velocity variations in the Upper Permian Zechstein Supergroup are known to have major impacts upon seismic imaging and depth conversion in the SPB. The resulting uncertainty remains one of the major challenges when interpreting and assessing the prospectivity of the underlying Upper Permian, Rotliegend Group (Leman Sandstone Formation) reservoirs in the UK Southern North Sea. An understanding of the Zechstein shelf edge's 3-D physiography and its velocity variation has implications for the delineation of traps containing the prospective reservoirs that lie below. Recognition of the complexity and effects of this shelf-margin contributed to the recent Juliet Discovery whose position outside of the presently defined Rotliegend Group play fairway suggests that prospectivity is more extensive along the basin margin than previously thought. As such, the work provides a means by which to identify and delineate new structures and extend the life of this mature yet prolific gas province.

Mud-rich prograding sediment lobes make for most of the Barremian – Albian stratigraphic record in the SW Barents Sea. Submarine canyons and channels potentially represent key components of sediment transport from shelf to basin floor but geological evidences are lacking. We present high-resolution seismic data and scrutinize an elongated, ∼150-km long bright seismic amplitude and resistive anomaly located alongslope of a NW-sourced Barremian delta in the SW Barents Sea. Seismic interpretation is performed on a comprehensive database comprising 3D/2D high-resolution P-Cable and conventional seismic data, tied to three exploration wells to provide age-control on key horizons. Our results highlight that the elongated geophysical anomaly originates from a soft layer deposited over a harder, erosional surface. The erosive morphology displays three narrow, V-shaped incisions to the NE of the Hoop area which develop into a single, ∼6 km-wide, U-shaped channel towards the transition to the Fingerdjupet Subbasin. The geological feature is named Ceres and interpreted as a submarine channel carved in Aptian, a period of marked sea level rise and sediment starvation in the Hoop area. An evolutionary model of a diverted submarine channel is proposed where a flooded delta lobe acted as a topographic barrier, funneling bottom currents and thereby carving an alongslope, possibly contouritic channel. This is the first documented case of a submarine channel pathway – delta lobe interaction on the Norwegian continental shelf. To account for the geophysical expression of Ceres, two competing explanations are discussed: (1) hydrocarbon-bearing sands, and (2) organic-rich source rock. Both scenarios have important implications for petroleum prospectivity: a faulted stratigraphic trap holding large volumes of hydrocarbons or alternatively the channel-controlled distribution of mature Aptian source rock in the SW Barents Sea. © 2018. This manuscript version is made available under the CC-BY-NC-ND 4.0 license http://creativecommons.org/licenses/by-nc-nd/4.0/

CGG Multi-Client & New Ventures have undertaken new interpretation and modelling, including stratal slicing and attribute analysis on the Schild Phase 2 3D located 170km off the north-west coast of Australia within the Caswell Sub-basin. The key objectives of the interpretation were to enhance understanding of prospectivity, paleogeographic settings and produce new insights into deeper Mesozoic – Paleozoic plays based on broadband imaging of up to 20km of sedimentary section. The following is a discussion on 2 key focus elements of the interpretation derived from the attribute analysis, comprising the identification of extensive vertical fluid / gas migration features, and fluvio-deltaic and submarine channel complexes at multiple stratigraphic levels.

In the Fitzroy Basin of Western Australia, both ground and borehole Nuclear Magnetic Resonance (NMR) techniques have been applied during a groundwater prospectivity assessment of the Cenozoic sediments, and the Palaeozoic and Mesozoic sandstone aquifers. Ground magnetic resonance (GMR) data was acquired at ten sites from the within the basin and the data was inverted to obtain estimates of the one-dimensional water content for the top 100m. Where these sites were co-located with boreholes, the results were consistent with inverted borehole NMR data and other litho-stratigraphic information although with a reduced horizontal resolution. Both the GMR and borehole data suggest that the Palaeozoic Grant Group and Poole Sandstone have high water content and have the potential to be highly productive aquifers. Furthermore GMR can be used estimate the depth to water table for unconfined aquifer, using 5 volume % as the threshold for saturated zone.

The Geological Survey of NSW (GSNSW) has created a 3D geological model of the Sydney–Gunnedah Basin that includes best available geological mapping and new 3D modelling. The onshore Sydney Basin comprises the southern section of the Permo-Triassic Sydney–Gunnedah–Bowen system, which overlies the Lachlan Orogen and Late Carboniferous volcaniclastic rocks. The Hunter–Bowen Orogeny formed the adjacent New England Orogen and resulted in uplift and erosion that deposited Jurassic sedimentary sequences of the Surat Basin over large parts of the Gunnedah Basin. Model generation followed GSNSW’s map development workflow, developed as part of the larger project: 3D Mapping of NSW. The integrated Sydney–Gunnedah Basin 3D model was developed with the aim of advancing the understanding of the geological and structural setting of the region. This will inform areas of investigation such as coal and hydrocarbon prospectivity, groundwater management and exploration, and environmental and land use decision making.

Field development is a very costly endeavor that requires drilling several wells in an attempt to understanding potential prospects. To help reduce the associated cost, this study integrates well and seismic based rock physics analysis with artificial neural network to evaluation identified prospects in the field. Results of structural and amplitude maps of three major reservoir levels revealed structural highs typical of roll over anticlines with amplitude expression that conforms to structure at the exploited zone where production is currently ongoing. Across the bounding fault to the prospective zones, only the D_2 reservoir possessed the desired amplitude expression, typical of hydrocarbon presence. To validate the observed amplitude expression at the prospective zone, well and seismic based rock physics analyses were performed. Results from the analysis presented Poisson ratio, Lambda-Rho and Lambda/Mu-Rho ratio as good fluid indicator while Mu-Rho was the preferred lithology indicator. These rock physics attributes were employed to validate the observed prospective direct hydrocarbon indicator expressions on seismic. Reservoir properties maps generated for porosity and water saturation prediction using Probability Neural Network gave values of 20-30% and 25-35% for water saturation and porosity respectively, indicating the presence of good quality hydrocarbon bearing reservoir at the prospective zone.

The Sahel basin in eastern Tunisia has been subject for hydrocarbon exploration since the early fifties. Despite the presence of a working petroleum system in the area, most of the drilled wells were dry or encountered oil shows that failed to give commercial flow rates. A better understanding of the tectono-sedimentary evolution of the Sahel basin is of great importance for future hydrocarbon prospectivity. In this contribution, we present integration of 2D seismic reflection profiles, exploration wells and new acquired gravity data. These subsurface data reveal that the Sahel basin developed as a passive margin during Jurassic-Early Cretaceous times and was later inverted during the Cenozoic Alpine orogeny. The occurrence of Triassic age evaporites and shales deposited during the Pangea breakup played a fundamental role in the structural style and tectono-sedimentary evolution of the study area. Seismic and gravity data revealed jointly important deep-seated extensional faults, almost along E-W and few along NNE–SSW and NW-SE directions, delimiting horsts and grabens structures. These syn-rift extensional faults controlled deposition, facies distribution and thicknesses of the Jurassic and Early cretaceous series. Most of these inherited deep-seated normal and transform faults are ornamented by different types of salt-related structures. The first phase of salt rising was initiated mainly along these syn-extensional faults in the Late Jurassic forming salt domes and continued into the Early and Late Cretaceous leading to salt-related diapir structures. During this period, the salt diapirism was accompanied by the development of salt withdrawal minibasins, characterized important growth strata due the differential subsidence. These areas represent important immediate kitchen areas to the salt-related structures. The later Late Cretaceous - Cenozoic shortening phases induced preferential rejuvenation of the diapiric structures and led to the inversion of former graben/half-graben structures and ultimately to vertical salt welds along salt ridges. These salt structures represent key elements that remains largely undrilled in the Sahel basin. Our results improve the understanding of salt growth in eastern Tunisia and consequently greatly impact the hydrocarbon prospectivity in the area.

Summary Assessing the impact of magmatic activity on source rock maturation and hydrocarbon generation is highly critical when evaluating the prospectivity of volcanically influenced sedimentary basins. An integrated organic geochemistry and petrographic study was conducted on a variety of bitumen samples and candidate source rocks from the Namibe Basin of Angola, which was affected by multiple magmatic events. Analyses suggest that multiple processes of hydrocarbon generation and emplacement took place, including locally forced thermal maturation of otherwise immature source rocks and source rock thermal maturation via conventional basin-scale burial processes. Imminent future analyses include vitrinite reflectivity and 1-D modelling to characterise the basin thermal regime and quantitatively assess the impact of magmatic activity on source rock maturation and hydrocarbon generation.

Summary Reprocessing and integrated interpretation of vintage and newly available data provided new insight into structural framework of thrust belt in the northeastern part of the Timan Pechora basin. It showed that structural evolution of the fold and thrust belt was influenced by the multiphase development of salt diapirs which finally were squeezed during pulses of the orogenic shortening. This was accompanied with expulsion of salt and the development of divergent thrusting. The improved seismic imaging has allowed for more accurate definition of the structure and stratigraphy below thrust sheets including salt sole in frontal zone of the fold and thrust belt. The updated interpretation shows new exiting opportunities for petroleum exploration provided by subsalt traps.

Summary The North West African Atlantic Margin with the MSGBC basin area covering Mauritania, Senegal, the Gambia, Guinea Bissau and Guinea Conakry being one of the hottest areas in Africa currently, a new modern and continuous 3D dataset finalized early 2020, now allows to correlate a full suite of regional interpretation, well correlation and basin modelling base values to be extended and tested for spectral signature of proposed source rocks, anomaly response of known reservoirs, full scale traps and volumes, and possible migration paths; all in high resolution 3D across the margin. After this study is completed, the results set a well calibrated, modern baseline for the shelf edge and deepwater hydrocarbon exploration offshore the MSGBC basin, providing play fairways and structural details, evaluated for maturity and trap volumes with the future addition of further acquired ultra-deepwater seismic 3D surveys.

Summary Stratal geometries, reservoir and source facies are different in true lakes, in lakes with restricted access to the global ocean, and in “lakes” continuously connected to the global ocean but capped by large quantities of freshwater. We illustrate the importance for exploration and development of addressing these issues in the pre-salt sequences of the South Atlantic. We have achieved this through interpretation of high quality seismic images of the pre-salt section, in a geological context provided by analysis of well and rock data, prediction of palaeoclimate and palaeohydrology, and an understanding of relative plate motions and global oceanic sea levels. We conclude that undrilled reservoir facies are present on the flanks of the main structural highs in the hypersaline basins of south Brazil, and in the freshwater basin of south Gabon.

Summary The UK offshore Forth Approaches Basin has long since been explored as a prospective petroleum system; the few exploration wells failed to point towards an economically viable asset, and hence, the basin was downgraded for further exploration. In this study, this basin is further explored, both in terms of its local hydrocarbon prospectivity and storage potential, using publicly available data. The petroleum system elements of the most prospective play (Scremerston) were assessed based on formation properties and gross depositional environment mapping, source rock maturity modelling and common risk segment mapping. Also, the basin’s carbon storage potential was assessed with respect to its capacity, reservoir and trap quality and seal integrity. Our results suggest that only deeper parts of the depocenter could have generated and stratigraphically trapped vapour hydrocarbons, yet the exact depths of this upper-limit threshold in the Carboniferous depocenter have to be delineated. On the other hand, the Upper-Carboniferous and Middle-Permian reservoir strata, hosting a low-salinity aquifer, illustrate significant storage capacity (roughly 700 Mt for the Worst-Case scenario) and sealing efficiency (through stratigraphic and residual trapping), whereas its proximity to the UK major industrial emitters adds to its applicability.

Summary The evaluation of the coalbed methane (CBM) potential of the Ermelo Coalfield in the Mpumalanga Province of South Africa. Previous studies done by the Agency revealed that the coals vary in rank from high volatile bituminous to medium bituminous and considered favourable for the occurrence of CBM due to the presence of extensive coal deposits and adequate depths for CBM development and preservation. The primary objective of this study is to identify play fairways and assess the petroleum geology and hydrocarbon potential in the Permian coal-bearing Karoo-aged basin. The Ermelo Coalfield is located in the extensive Permian age coals of South Africa’s Main Karoo Basin with the most significant coal seams contained within the Ecca Group. The coalfield is considered highly prospective for coalbed methane and also gassy sandstone overlying the coal horizons. Gas contents have been reported in studies associated with previous mining attempts but no actual measured gas contents are available. The Agency adopted a three-stage process that involved gathering and evaluating the quality of existing borehole data for evaluating the CBM resource potential of the basin. Generally, exploration borehole locations, lithology descriptions, and coal composition (proximate analysis) data are available for the Ermelo coalfield. Because direct gas content data is lacking for the Ermelo coalfield, the gas storage capacity (gas content) was estimated by the indirect method of Kim (1977) which calculates dry, ash-free gas storage capacity of bituminous coal from proximate analysis using temperature, pressure and depth data.

In many basins, hydrogen-emitting structures are now observed, but the estimation of the H2 flow leading to their formation remains poorly constrained since all data show that the H2 emissions are variable in space and time. We present here the data of a long-term monitoring campaign with a high density of permanent hydrogen detectors installed in 2 structures in the Minas Gerais State (Brazil). Results show that two kinds of signals are recorded, large sporadic pulses that affect the H2 content of the soil for one or two days and smaller ones, with a daily periodicity, that last 6 h and during which the near surface soil concentration usually does not exceed 200 ppm. This last signal is very regular in frequency, less in amount, and the daily maximum happens around noon or in the early afternoon. We interpret the large pulses as evidences of a deep hydrogen flux, leaking either from a reservoir located in the subsurface, from an aquifer which is degassing or, although it seems unlikely, directly from the H2 generation area. The time correlation between the pulse and the increase of the daily signal suggests that this last one corresponds to the slow release of the gas that has been captured by the soil during its transport towards the surface. This daily signal is most likely influenced by external factors such as atmospheric pressure and sub-surface bacterial activity. In map view, the lack of correlation between the highest hydrogen concentrations over time suggests that the soil is very heterogeneous and that preferential pathways exist. The results confirm that long-term monitoring, over a few months, is mandatory to catch a certain number of high pulses and so to have a better estimation of the real flow. Data also suggests that sensors with a large concentration range should be used (from 10 to several 104 ppm). Even if quantification of leakage doesn't help to quantify the subsurface reserves, these new data allow a more precise evaluation of the quantity of H2 released in surface by these structures, few hundred of kilo per day, and confirm the high H2 prospectivity of this basin.

Summary The presented study is located within the Tali-Post Basin, which represents one of the Mesozoic-Cenozoic sedimentary basins lying along the southwestern margin of the South-Sudan rift. The complex long tectonic history and the sparse past exploration campaigns led to numerous unanswered questions about the geodynamical evolution, basement relief, stratigraphy, and prospectivity of the basin. This under-explored province lacks high-quality structural data and quantitative models, all necessary to plan future explorations. To shed light on this complex scenario, a potential field workfow was specifically designed to improve the regional understanding in the southern part of Block B3, South Sudan, up to basin scale. The analysis was conducted by integrating all geological and geophysical information from the area and eventually confirming, through the production of a consistent structural interpretation, the presence of the Abu Gabra formation – the main target of the surrounding basins.

Summary The Harper Basin, a frontier area, extends from a narrow shelf to the extensive deepwater domain offshore Liberia. Modern 3D seismic data acquired in 2013, allowed disclosing new elements of a working petroleum system, which allows combining elements from the southern Liberia Basin and western Cote d’Ivoire. The Cretaceous syn-deformational deposition of clastic sediments infers organic-rich lacustrine muds (not yet proven in this area), buried by approximately 4–5 kms of post rift sequences, which include the mapped reservoir packages throughout the passive basin infill phase of the basin evolution. Cretaceous deepwater sequences are anticipated to include shale-rich source intervals containing sand prone carrier beds up-dip, relevant for the thick basin intervals comprised of Turonian to Mid-Albian clastic reservoirs. Basin temperature modelling has confirmed favourable maturation conditions for these possible source rocks. The basin’s structural evolution created numerous undrilled structural-stratigraphic traps identified on the new 3D seismic dataset. The up-dip pinch-out of deepwater channelised sandy fan systems charged by Turonian black shales represents a key play.

Recent exploration has identified a series of Cu-Mo skarn deposits within the Xuancheng-Magushan orefield. The orefield forms part of the Nanling-Xuancheng mining district, which is located within the Middle-Lower Yangtze River Metallogenic Belt (MLYRMB) of central-eastern China. However, this area contains thick and widespread unprospective sedimentary cover sequences that have impeded traditional approaches to mineral exploration. This study presents the results of 3D numerical simulation modeling that identifies possible mineral exploration targets within the entire Xuancheng-Magushan orefield. This modeling enables the identification of unexplored areas with significant exploration potential that are covered by thick sedimentary sequences that cannot be easily explored using traditional exploration approaches. This study outlines the practical value of 3D numerical simulation-based targeting in areas with thick sedimentary cover sequences and uses the Flac3D software package to couple processes involved in ore formation such as stress, pressure, and heat transfer. Here, we use volumetric strain increments calculated during numerical modeling as the thermodynamic representation of the generation of space during prograde skarn formation, with this space filed by sulfides either penecontemporaneously or soon after magmatism. This process occurred during retrograde hydrothermal ore formation and the genesis of the skarn-type mineralization in this area. The results of the volumetric strain increment calculated during this numerical modeling study matches the distribution of known mineralization as well as delineating eight potential targets that have not yet been explored but represent areas of significant exploration potential within the Xuancheng-Magushan orefield, indicating these targets should be considered prospective for future mineral exploration. One of these targets was also identified during our previous Comsol-based numerical modeling of the formation of the Magushan Cu-Mo skarn deposit. The fact that this area has been identified as prospective using two different numerical modeling methods indicates that this area should be prioritized for future exploration and also validates the numerical modeling approaches used here and in our previous research that more specifically focused on the Magushan skarn deposit. Overall, our study indicates that prospectivity modeling using 3D numerical simulation-based approaches can be both effective and economical and should be considered an additional tool for future mineral exploration to reduce exploration risks when targeting mineralization in areas with thick and unprospective sedimentary cover sequences.

Overlooked prospects and underexplored fields in the Niger Delta Basin continue to attract the attention of many stakeholders in the industry as the quest to achieve the national 40 billion barrels oil reserve target continues to gain momentum. A key area of interest is that many wells drilled earlier in the basin were limitedlargely by technology from probing deeper formations. With the availability of 3D seismic data, improved subsurface knowledge, more efficient interpretation tools and skills, this study reevaluated the hydrocarbon potentials of the economically strategic ‘Pateke’ field in the Coastal Swamp Depobelt where the deepest well was drilled to a total depth of 8950 feet (2728 meters). Thereevaluation approach involved high precision fault and horizon mapping, seismic attribute extraction and analysis using the Petrel platform. The interpretation shows the structural framework of the field to be constituted by five faults with two major faults trending east – west and northwest – southeast respectively, thus dividing the field into three fault blocks. Integration of Root Mean Square (RMS) Amplitude, Envelope and Sweetness seismic volume attributes suggest probable hydrocarbon accumulations within the fault blocksthat lie far beneath the reach of the present wells in the field. The implication of this result is that the full potentials of ‘Pateke’ field are yet to be achieved considering the positive indications of economically recoverable hydrocarbons in the deeper sections of the field.

West Africa’s maritime regions, including its onshore and offshore basins and rifts, are experiencing an unprecedented expansion in oil exploration and development as a result of their proven hydrocarbon reserves and high prospectivity. Along the stretch of coastline between the Senegal basin in the north right down to the more profitable Gulf of Guinea and on to southwest Africa, more than 500 oil (and gas) companies from various Western countries and from as far away as India, Malaysia, and Singapore are participating vigorously in the upstream (exploration, discovery, development, and production) and downstream activities (refining, marketing, and shipping) of one of the most important commodities in international trade. In addition to the traditional oil-producing and exporters, such as Nigeria and Angola strengthening their capacity, major new and significant producers have now emerged including Ghana, Equatorial Guinea, and Sao Tome and Principe. There have also been significant new offshore discoveries in Cote d’Ivoire and the under-explored Senegal basin, in the northern tip of West Africa. As a result of this frenetic exploration activities, the region is witness to frequent new basin openings and relatively high discovery success of ‘sweet crude’, one of the world’s most coveted type of crude oil. The subregion, once viewed largely through the prism of Nigerian oil, sub-Saharan Africa’s largest oil producer, is now a central part of the global energy economy, largely due to its ongoing widely dispersed commercially profitable oil finds. The region is projected to increase its crude oil production from 1935.90 in 2018 to 3006.24 thousand barrels per day in 2024. As widespread prospecting and drilling for commercial oil takes hold across the subregion however, concerns are being raised about the rapacious and non-consultative manner of exploitation and its implications for good governance, development, human security, and stability.

International audience; Geodynamic models, geological-geophysical interpretations, and isotope analysis illustrate that there are links between the nickel and gold mineral systems in the Halls Creek Orogen, Western Australia. Whole-rock Nd and 40Ar/39Ar analysis of rocks throughout the region, when compared with the geodynamic models suggest that nickel and gold mineralization in the Halls Creek Orogen can be related to basin development and subsequent basin closure during the convergence of North Australian Craton and Kimberley Craton, respectively. Whole-rock Nd analysis confirmed the input of juvenile melts in the centre of the orogen before the 1835–1805 Ma Halls Creek Orogeny, supporting the upwelling of decompression mantle melts during the basin development. These analyses also revealed the spatial links between nickel and gold mineralization and lithological units with positive εNd values. Spatially the link between these mineral systems appears to be related to the presence of deep-seated shear zones that formed early in the history of the orogen and were later reactivated. The results of geodynamic models, geophysical interpretation, and isotopic analysis are used to understand the critical processes in the gold and nickel mineralization, which are presented by predictor maps. The GIS-based knowledge-driven fuzzy logic method used to integrate the predictor maps and create the prospectivity maps. Herein we show that mafic-ultramafic units prospective for nickel mineralization formed by upwelling of decompression mantle melt during crustal thinning and extension during basin development, and typically consist of the most juvenile magmas in the region. Whereas, gold deposits formed during the compressional regime and basin closure, and are located along a major shear zone separating two terranes. This deep crustal-scale shear zone is implied to be the site of multiple stages of deformation that acted as fluid migration pathways during basin closure and subsequent collision. Another critical element that appears to be related to gold prospectivity is the presence of lithologies with a juvenile signature. In contrast to nickel analyses which are closely related to mafic-ultramafic units, the source component seems less influential when attempting to target orogenic gold deposits.

Summary The discovery of the Rosebank oil and gas field in the NE Atlantic has identified inter-basalt reservoirs as significant targets for future exploration. Top and Base Basalt and numerous overlying amplitude anomalies are mapped on 3D seismic data in two study areas: West of Shetland (UK) and the outer Voring Basin (Norway). We describe seven undrilled elongated ridge structures which are defined at Top Basalt level. Above these ridges are stacked amplitude anomalies interpreted to be caused by hydrocarbon leakage. In the Voring Basin seabed sampling finds that both oil and gas seeps occur at the seabed above these anomalies. In the West of Shetland area, well data from Tobermory (214/4-1) and Bunnehaven (214/9-1) as well as a seismic well-tie indicates that the basalt sequences at the two wells are diachronous. Seismic interpretation shows that the basalt sequences overlie each other and that a clastic sand-rich unit observed at both wells potentially extends between the basalt units. Four of the basalt ridges occur where the sand-rich unit observed at the two wells could be an inter-basalt reservoir. Overlying amplitude anomalies suggest the reservoir may be charged.

Global exploration has seen a dramatic upturn in 2018, with close to 4 billion barrels of oil equivalent discovered in the first half of the year alone, and many exciting wildcat wells still to come. Although the oil price slide of 2014 changed the industry, with the focus now on commerciality and risk reduction, it is of interest that most of the new discoveries this year have been made in commercially challenging deep water. The reason for this is that our industry has been exploring shallow-water oil-prone basins since the invention of marine seismic methods in the 1950s, and they appear now to be ‘mature’ and depleted in material low-risk opportunities. Indeed the future of shallow-water exploration has been portrayed as binary: either mopping up around what we know or exploring new frontiers. However, in South Gabon we challenge the established idea that after 50 years of exploration the basin is mature, by revealing a new generation of prospectivity with modern 3D acquisition and processing (Figures 1 and 2). The play primarily chased so far has been the Gamba Sandstone play, the seismic imaging of which has always been a significant challenge, owing to the complex velocities in the post-salt geology, the heterogeneity and the halokinesis of the Ezanga Salt. Yet with the exception of the Muruba-2 discovery, few wells have deliberately targeted the syn-rift section below the Gamba, leaving the pre-salt section completely unexplored (Figure 1). Diligent planning and acquisition (Esestime et al., 2017, 2018) of 3D data in South Gabon covering an area eight times the size of Greater London (11,500 Km2), has enabled an imaging veil to be lifted. The intra-syn-rift is now visible and is revealing large-scale hydrocarbon prospects, capable of attracting interest from global exploration players (Figure 3).

Upper Permian (Zechstein Supergroup) evaporites have a major control on structural styles and prospectivity in the UK Southern North Sea (SNS). They form the regional super-seal for the main Rotliegend Group (Leman Sandstone Formation) reservoir play fairway immediately beneath. The evaporites have highly variable thicknesses due to the syndepositional basin architecture, differential loading and post-depositional deformation through diapirism and salt withdrawal. The halokinetic activity leads to touchdown (welding) of the supra-salt section onto the sub-salt strata and the development of narrow (up to 15 km-wide) graben systems. The interpretation and depth conversion of well-calibrated, high-quality, 3D post-stack time-migrated (PSTM) seismic data along the southwestern margin of the basin show that a NW–SE-striking elongate extensional Dowsing Graben System transects the area. The graben is defined by a series of large, overlapping, en echelon listric growth faults, with oblique secondary planar faults, which sole-out on two main (deep and shallow) decollement levels in the Zechstein Supergroup and the Middle Triassic Rot Halite Member. Whilst its initial formation was related to Mesozoic extension, the graben system also displays a contractional overprint resulting from regional compression and structural inversion during the Cenozoic. Detailed mapping of the Zechstein Supergroup has revealed that the evolution of the extensional system was influenced by the ESE–WNW-striking anhydrite–carbonate Zechstein shelf-margin. The occurrence of variable-thickness, low-velocity sediments within the graben impacts seismic imaging and depth conversion, leading to prospective structures being overlooked; something that has implications for prospectivity in the SNS and other evaporite basins where similar graben occur.

The integration of three-dimensional (3D) exploration data is important for targeting deep-seated mineral deposits. This paper presents a methodology for 3D mineral prospectivity modeling at the regional scale based on a knowledge-driven method. A mineral prospectivity map of skarn-type mineralization was developed for the southern region of the Taebaek basin in Korea. Criteria generated using the skarn mineral system concept and 3D exploration maps were extracted from the 3D geological model, and then were assigned weights and scores using expert knowledge. The prospectivity map was prepared using a multiclass index overlay method, in which 3D exploration criteria were integrated for the study area. The prospectivity model was quantitatively validated by comparisons with 46 ore body voxels from drill holes in six known historical skarn-type deposits. The success rate for the prospectivity model was 89.04%. This high value appears to reflect the importance of the weighting and scoring process used for the exploration criteria. It is believed that the proposed approach provides a valuable guide to the identification of new deposit-scale, deep-seated exploration target zones.

An attempt to understand the structural and sedimentation framework in the Benin Basin is made herein. Unlike in its contiguous basins in the Gulf of Guinea Province, no significant oil and gas discovery has been reported in the basin. The aim here is to provide a chronostratigraphic framework of sediments build-up as a guide to hydrocarbon prospectivity in the basin. Existing biostratigraphic and sedimentologic data as well as few proprietary reports were integrated to establish a chronostratigraphic correlation in six directions within the Nigerian portion of the Benin Basin. Isopach maps of the chronostratigraphic subdivision of the sequences in the basin were also made. Sedimentation in restricted grabens started in the western part of the basin. Only Ise-2 well penetrated the oldest Cretaceous (Neocomian to Albian) sediments in the area of study with a thickness reaching up to 869 m. During the Miocene the focus of sedimentation predominantly shifted towards the offshore in the basin. Significantly a missing Eocene/Oligocene section was observed both on the seismic section and the stratigraphic record of the basin. Only Epiya-1 shows gas occurrence in the Miocene. Based on this work and locations of hydrocarbons recovery in the other part of the basin, exploration effort should target the Cretaceous sediments in the Nigerian portion of the basin.

The back-arc East China Sea Basin lies on extended continental crust at the leading edge of the Eurasian plate. In this study, the basins are described and subdivided according to their tectono-stratigraphic evolution. In order to distinguish between different phases of deformation in basin development, standard basin evolution patterns related to geodynamic drivers are identified as a first step. On the basis of this, standard patterns are recognized in the sedimentary sequences that characterize the area and its tectonic evolution, and linking them to the petroleum systems present is attempted. This is achieved by characterizing and grouping them into basin cycle-related petroleum system types (PSTs). Finally, the development of plays is examined within the petroleum systems in the context of their tectono-stratigraphic evolution, and groups of sub-basins with similar geological history and, therefore, potentially similar petroleum prospectivity are identified. In the East China Sea Basin, four proven and potential PSTs were recognized: (1) Late Cretaceous to Paleocene oil/gas-prone early syn-rift lacustrine−deltaic PST; (2) Eocene gas/oil prone late syn-rift marine PST; (3) Oligocene to Middle Miocene gas/oil-prone early post-rift fluvial−deltaic PST; (4) gas-prone syn-rift turbiditic PST. The geology and petroleum systems of three major sub-basins of the East China Sea Basin, the Xihu Sub-basin, the Lishui Sub-basin, and Okinawa Trough, are discussed in detail, and their petroleum systems and play development are analyzed. Finally, the sub-basins are grouped into “basin families” distinguished by their tectono-stratigraphic development, namely, Northwest to Northeast Shelf Basin (NWSB−NESB), Southwest to Southeast Shelf Basin (SWSB−SESB), and Okinawa Trough basin families, respectively.

The prolific gas prone Tapti-Daman Block of the Mumbai Offshore Basin is one of the thrust areas for exploration and development along the west coast of India. Hydrocarbon accumulations generally occur in clastic and carbonate reservoirs of Early Oligocene Mahuva Formation and Late Oligocene Daman Formation. During Early Oligocene, the basin experienced the maximum subsidence that led to the deposition of Mahuva Formation. In the proximal part, the Mahuva Formation comprises of thick under-compacted claystone relating to the prograding delta from the northeast which has also resulted in the formation being overpressure in many instances. However, towards the distal part, the clastic influence diminishes and carbonates become more predominant. The close of Early Oligocene is marked by a minor period of non-deposition in Tapti-Daman area. During Late Oligocene, Tapti-Daman Block witnessed reduced subsidence resulting in a regressive coastline. During this period, a fluvial system with distributary channels, coastal bars, tidal deltas and other transitional environments encased in marginal silty and carbonaceous shale known as Daman Formation formed in the proximal part. The depositional regime changes from clastic to carbonate in the distal part particularly towards the southern and western part of the B9 area. Sea-level changes due to regional-tectonic and climatic parameters during Oligocene formed a major controlling factor for sediment deposition. The westerly tilt of the basin created additional accommodation space. The sediment supply during this period in the proximal part was controlled by increasing input of clastic material from northeast. However, in the distal part, a thick carbonate succession was formed due to low sediment supply, adequate rate of subsidence and conducive climatic conditions. As a result, the carbonate factory in the subsiding distal part of the basin was influenced by this interplay which further complicates the understanding of the distribution of reservoir facies. However, in the proximal part, the carbonate build-up was restricted by increasing input of silici-clastics and eventually led to the termination of the carbonate factory during Late Oligocene. The formation of a potential reservoir for hydrocarbon accumulation and seal was significantly influenced by this interplay, particularly along the clastic-carbonate transition areas in the distal part of the basin. Through this study, an attempt has been made to understand: 1. The basic litho-facies deposition, their disposition in time and space and the physical properties associated with these litho-facies that can aid in the prediction of reservoir distribution and in the refinement of geologic models. 2. Its implication on hydrocarbon accumulation through the integrated interpretation of seismic and well data and previous studies in the area. About 20 wells from proximal to distal set-up along B12 and B9 areas have been analysed to develop an understanding of the distribution of potential reservoir rocks and thickness variation. Well correlation is carried out and a number of geological sections were prepared to understand the interplay between the clastic and carbonate litho-facies and its implications on hydrocarbon accumulation. An attempt has been made to delineate the sand, shale and carbonate litho-facies through integrated interpretation of 3D seismic data. Key seismic attributes have been generated to understand the limit of clastic input and carbonate distribution patterns.