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An integrated interpretation of processed 3D seismic data, a suite of well logs, biostratigraphic data and core photographs of AMO Field, deep offshore Niger Delta is carried out for the sequence stratigraphic analysis of strata penetrated by wells. Lithologic and key stratigraphic surfaces, that is the maximum flooding surfaces (MFSs) and sequence boundaries (SBs), are identified based on bioevents and log motifs. Biostratigraphic data help the delineation of MFSs and SBs, as well as dating, determination of depositional environment and paleobathymetry. The sequence stratigraphic study reveals seven MFSs (of 13.0 Ma, 11.0 Ma, 9.5 Ma, 7.4 Ma, 5.8 Ma, 5.0 Ma and 2.7 Ma) and six SBs (of 12.1 Ma, 10.3 Ma, 8.5 Ma, 6.3 Ma, 5.5 Ma and 4.2 Ma). The key stratigraphic surfaces identified involve three depositional sequences characterized by lowstand, transgressive and highstand system tracts respectively. The studied section is deposited in a deepwater environment ranging from Lower to Upper Bathyal and can be dated back to the Middle Miocene - Middle Pliocene in age. Seven faults and two horizons (corresponding to reservoir units) are identified and mapped across the seismic data volume to establish a continuity of the reservoir to areas lacking well control. The established sequence stratigraphic framework displays successions of sediments (system tracts) where the reservoir sand units of the lowstand and highstand system tracts are of hydrocarbon prospective units in the field.

Exploration success at Breagh demonstrates that western parts of the Mid North Sea High area are prospective despite the absence of an Upper Permian (Rotliegend Group) Leman Sandstone Formation reservoir and source rocks belonging to the Upper Carboniferous Westphalian Coal Measures Group. Detailed seismic and well interpretation shows that the Breagh trap was a long-lived footwall high, the prospectivity of which was enhanced by Variscan folding and uplift, leading to the truncation (subcrop) of Lower Carboniferous reservoirs beneath the Base Permian Unconformity. Its drape (supra-crop) by Upper Permian (Zechstein Super Group) evaporites creates the seal. The complexity of its overburden means that an accurate picture of the Breagh structure only emerges after accurate depth-conversion that takes the effects of the Mesozoic graben into account. Pronounced easterly tilting during the Cenozoic affected the area and controlled gas migration into the structure from palaeostructures lying to the east. However, evidence that Breagh is not filled to spill point (underfill) suggests that charge limitation remained an issue. The study demonstrates that a poorly-documented and under-explored Lower Carboniferous play exists in Southern North Sea, which relies upon careful structural mapping and basin modelling to be undertaken for the play to be understood and its further potential to be realized. 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

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

The occurrence of fault-related folds in extensional settings has been gaining increased recognition during the past 20 yr. Passive margins and rift basins often present intriguing structural complexities that are potential sites for the development of extensional fault–related folds. Fault-related folds are important anticlinal traps for hydrocarbon exploration, and understanding their evolution is critical for derisking the timing of trap formation and hydrocarbon generation. This study presents folds from three areas across the North West shelf (NWS) of Western Australia and aims to determine their relationship to associated extensional faults. A series of kinematic forward models are presented as well as detailed structural and stratigraphic interpretation of folding at the three locations. The models suggest each of the three examples have formed under extension that impacted the region during the Mesozoic. The modeling also highlights different characteristics of folding that are caused by fault geometry (ramp–flat) and a propagating fault tip (trishear) that can be used as diagnostic features to distinguish different fold mechanisms. Historical exploration across the NWS has targeted a relatively small number of these anticlinal traps, some of which have been successful (e.g., Marina-1 well, Petrel subbasin) and some have not (e.g., Candace-1, Sholl Island fault anticline). This paper suggests that the prospectivity of anticlinal structures should be more carefully assessed to determine whether or not they are related to extensional activity and hence likely to have formed prior to the bulk of the hydrocarbon charge. Similar structures undoubtedly exist in other basins that have experienced repeated extension.

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.

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 identification of additional hydrocarbon reserves to buffer pressure from increasing energy demands in Nigeria necessitated the application of sequence stratigraphic framework in the analysis of sedimentary successions in the central portion of southern Anambra basin. Wireline logs and biofacies data from three exploratory wells (S-1, S-2 and S-3) were used for the study. The stratigraphy of the study area observed from the three wells showed an overall regressive succession with short-lived transgressions. Lithofacies associations deduced from well log signatures defined four lithostratigraphic units: The Mamu and Ajali formations of kate Maastrichtian age; the Nsukka Formation of kate Maastrichtian — Danian age and Imo Formation of Paleocene age. The study further used the depositional sequence model to identify sequences and accompanying systems tracts that are bounded at the top and bottom by unconformities. Dating of identified key stratigraphic surfaces was achieved by correlating chronostratigraphic biofacies data to third order cycle charts. Correlation across the three wells highlighted spatial distributions of reservoirs and some useful stratigraphic and structural discontinuities that could form hydrocarbon traps. It also showed profitable stratigraphic surfaces that would aid basin-wide correlation for improved horizon(s) mapping and hydrocarbon prospectivity in the Anambra basin. Erosional unconformities identified in the wells that correlated with major drops in global sea level, fingerprinted the influence of eustacy on sedimentation and sequence development. Other factors such as subsidence and sediment supply have direct relationships to the identified structures (faults) which also initiated the accommodation created for sedimentation in the study area.

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.

Compared to the success of Mesozoic play in Westralian Superbasin (WASB), the lack of hydrocarbon discovery in West Timor within Timor Trough and North West Shelf Australia is still an enigma. The West Timor is still frontier petroleum province with problems in uncertainties of working petroleum system play as well as the hydrocarbon prospectivity. This paper tries to approach this issue by integrating of fieldwork data with published well data and offshore seismic data from recent publication to re-evaluating potential hydrocarbon prospectivity in this area. Using the dataset, this study identifies structural framework across West Timor Island and offshore area, as well as potential petroleum system plays including source rock, reservoir presence and trap configuration. The results of this study identify two potential petroleum province region including Timor deformation front and Australian passive continental margin. Within these areas, three main plays based on structural configuration were identified which are fold related fault, sub-thrust, and tilted fault block. Reservoir targets for these main plays are Jurassic sequences including sandstone of the Early-Middle Jurassic of Plover equivalent and Late Triassic Malita equivalent with seal rock including Early-Middle Jurassic shale of Wai Lui Formation and Early Cretaceous shale interval. These plays are expected to be charged from source rock interval of Triassic Formation. The novelty of hydrocarbon prospectivity in this study will guide exploration screening of petroleum system analysis in West Timor area where current play analysis has not been tested yet.

The article deals with the prospects of Iraq’s oil and gas potential. It should be noted that there has not been much attention payed to the desert regions of Iraq located on the Arabian plate. However, recent studies show prospectivity of the Iraq deserts. As a result of the recent investigation of river valleys in the region, the following main morphotectonic processes were identified: rejuvenation of the river network and emergence of new river basins; division of individual rivers into two or more parts; interception of the river network. As a result of long-term field and cameral geological and geomorphological studies in the area of the Western and Southern deserts, it was possible to reconstruct the existing tectonic activity of the area from the Miocene period to the present day. It is established that the regional Euphrates fault on the territory of Iraq occupies an exceptionally important place, which was previously underestimated. Adjacent echelon faults of the following order formed a system of pre-existent tectonic blocks with different kinematics and morphology. The causes and mechanism of neotectonic Neogene-Quaternary movements of the earth’s surface are established. Thus, separate tectonic blocks are identified, which generally form zonal regions of uplifts or valleys. The areas of elevated blocks (for example, the raising of Al-Najaf Al-Ashraf of the third order) are created by plicative dome structures in the cover near the Euphrates fault, favorable for the accumulation of HC.

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.

The Muglad basin, regarded as a typical passive rift, had undergone three-phase rifting-sagging cycles during Early Cretaceous, Later Cretaceous, and Tertiary respectively. The primary plays in the first cycle had been testified, and hydrocarbon was also discovered in the second one. However, the hydrocarbon prospectivity in the third cycle has been much less explored. Hence, the sequence stratigraphic framework of the third rifting-sagging cycle was built, and the depositional systems of each system tracts were thoroughly analyzed by using the comprehensive analysis of tectonic evolution, geological features, cores and cuttings, well logs, and seismic faices. Furthermore, favorable plays were also discussed. The third rifting-sagging cycle, approximately corresponding to Paleogene Nayil formation and Neogene Tendi formation, can be classified into five third-order sequences and eleven parasequence sets, meanwhile, five sedimentary faices and related sub-facies and micro-faices were identified. The braided delta and lacustrine deposits were widely distributed in SQ1 and SQ2, whereas fan delta and alluvial plain were locally developed. The braided delta was dominated in the western slope, and lacustrine was distributed in the Kaikang trough. The delta and alluvial plain deposits were massively developed during SQ3, while the braided delta was deposited in the western slope and northern Gudaim area. As a result, the lacustrine began to shrink in the north of the Kaikang trough and expanded to the southern Gurial area. The lacustrine continued to expand from SQ4 through SQ5, and the delta and braided delta were locally distributed. The hydrocarbon, generated in the first rifting-sagging cycle, migrated vertically for long distance along major or boundary faults, and finally accumulated again in SQ1 and SQ3, should be expected to have great hydrocarbon prospectivity.

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 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.

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.

[Abstract A glossary of commonly used terms related to the geometric forms and geological settings of basement highs is presented to assist cross‐disciplinary understanding, qualifying prefixes for the term basement are discussed and a scheme for characterising basement highs is presented. This scheme is designed to standardise, and to add rigour to, description of basement highs. It will thereby enhance basement high comparisons and assist understanding of basement highs across technical disciplines. The scheme enables systematic characterisation of: the geometry of a basement high; the lithologic units and structures in, above and around it; timings; tectonics and origins of the basement high and play elements relating to resource prospectivity. Use of this scheme is demonstrated using the southern Rona Ridge (West of Shetland, UK Continental Shelf). The tectonic, isostatic, erosional and stratigraphic processes that form basement highs are also discussed, and examples in proven petroleum systems are presented., Example of geometric features of a basement high, illustrated using the south Rona Ridge 3D Top Basement depth structure map. A = Lancaster Field oil‐water contact at 1678 m true vertical depth sub sea level (TVDSS) (Hurricane Energy, 2019c). B = Lincoln oil discovery “oil down to” at 2258 m TVDSS. C = Whirlwind Discovery “oil down to” at TVDSS. The basement high covers an area of ~ 1200 km , so it is a 4th order basement high. It has an approximately trapezoid shape in map view shape (including the Whirlwind downthrown block). The topography of the upper surface can be described as an undulating wedge (area i) and an undulating planar slope (areas labelled ii). Structures segmenting the basement high include: 1 = Westray Fault Zone; 2 = Brynhild Fault Zone. Contour increment 100 m. ]

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.

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.

This study evaluates the petroleum prospectivity of the East Coast Basin, an element of the Hikurangi convergent margin of New Zealand. The basin tectonic environment changed from a dormant convergent margin to convergent margin around the early Miocene, likely causing a decrease in the basin thermal regime. Two end-member paleoheat flow scenarios were used to evaluate thermal maturation of two key source rocks, the Waipawa Black Shale and Whangai Formation, based on calibration to six wells across the basin using vitrinite–inertinite reflectance and fluorescence analysis, as well as Rock-Eval Tmax (the temperature at which the maximum rate of hydrocarbon generation occurs during pyrolysis analysis), thermal alteration index, apatite fission track analysis, and present-day temperatures. This study finds that paleobasal heat flow ranged between 40 and 55 mW/m−2 and decreased to 30 mW/m−2 between 15 and 5 Ma, as bracketed by the two end-member heat flow scenarios. The heat flow scenarios were applied to a palinspastically reconstructed basin and petroleum system model across Hawke Bay. We find that the two distinct heat flow scenarios cause a 3–6.5 m.y. difference in the relative timing of hydrocarbon generation across the basin. Structural events in the basin associated with convergent margin tectonics act as the main control on the timing of generation. Modeling results show transformation of kerogen to hydrocarbons began between early and late Miocene for both source rocks depending on the structural regime in the basin. The structural control on source rock maturation highlights the need for robust palinspastic reconstructions in addition to paleothermometric data to evaluate the petroleum prospectivity of convergent margin basins.

This paper uses multivariate regression to create a mathematical model for iron skarn exploration in the Sarvian area, central Iran, using multivariate regression for mineral prospectivity mapping (MPM). The main target of this paper is to apply multivariate regression analysis (as an MPM method) to map iron outcrops in the northeastern part of the study area in order to discover new iron deposits in other parts of the study area. Two types of multivariate regression models using two linear equations were employed to discover new mineral deposits. This method is one of the reliable methods for processing satellite images. ASTER satellite images (14 bands) were used as unique independent variables (UIVs), and iron outcrops were mapped as dependent variables for MPM. According to the results of the probability value (p value), coefficient of determination value (R2) and adjusted determination coefficient (Radj2), the second regression model (which consistent of multiple UIVs) fitted better than other models. The accuracy of the model was confirmed by iron outcrops map and geological observation. Based on field observation, iron mineralization occurs at the contact of limestone and intrusive rocks (skarn type).

Based on detailed seismic and well data interpretation, a Berriasian-Early Hauterivian voskhodnaya sequence of shale was distinguished as a part of Akhskaya suite in the south-west of the Yamal Peninsula. Subsequent conventional west dipping clinoforms are pinching-out on the top of the sequence, forming stratigraphic traps, characterized by seismic anomalies. Hydrocarbon prospectivity of the traps is proved by well tests.

This multidisciplinary study describes the burial and exhumation history of the frontier Galilee Basin in central Queensland, Australia, with implications for understanding its geohistory and unconventional gas prospectivity. Seismic interpretation, stratigraphic mapping, and an analysis of exhumation through quantifying overcompaction show total subsidence of approximately 2 km (∼6600 ft) from the Carboniferous to the Late Cretaceous, punctuated by two major exhumation events. Triassic exhumation was less than 600 m (

Glacial reservoirs have been the focus of numerous studies in various basins around the world, often with the aim of supporting hydrocarbon exploration and development. These reservoirs present a significant challenge due to their inherently complex internal architectures and significant lateral heterogeneities. This is of significant importance, not only for both exploration and reservoir production optimization, but also as an opportunity for stratigraphic trapping and enhanced prospectivity in mature areas. This study is focused on a major glaciogenic reservoir, of Late Ordovician age, in the Murzuq Basin (SW Libya). It aims to integrate subsurface datasets, such as 3D seismic with well-based sedimentological data (core, conventional wireline logs and wellbore resistivity images). The study proposes a comprehensive facies scheme optimized for the sub-surface but consistent with outcrops, and aims to generate depositional models, characterize the complex internal architecture of the reservoir, establish a genetic stratigraphic framework and evaluate facies in terms of reservoir properties and stratigraphic trap potential. Results, integrating subsurface facies analysis and well-calibrated seismic stratigraphy support previous models, derived from outcrop analysis, suggesting that these complex reservoirs cannot be characterised by purely lithostratigraphic criteria. To aid in the assessment of these formations, a facies scheme is proposed, focused on subsurface data but also considering other published, outcrop-based, schemes. Additionally, an interpretation is presented of the internal architecture of the Upper Ordovician based on a succession of several ice advance-retreat cycles, not all of which are present across the study area. Each cycle corresponds to a seismic package interpreted to comprise the deposits of several key sedimentation phases, resulting in a complex mosaic of genetic packages generated by multiple, often areally-restricted, cut and fill events. Predictive stratigraphic models are proposed for this complex package, based on both seismic stratigraphy and well-based sedimentology. The implications for future prospectivity and the significance for stratigraphic trap potential are also discussed.

The onshore and shallow marine conventional hydrocarbon resources around the world are mostly at the maturation phase and hence, exploration activity globally, showing increasing interest into progressively deeper water hydrocarbon prospects such as South China Sea basins. However, a comprehensive understanding of basin tectonics, depositional history, and petroleum systems of the basin is required to deduce the exploration prospectivity of these deeper reservoirs. The Sabah Basin is a prolific hydrocarbon province in Southeast Asia and has a significant economic impact on this part. Recent discoveries in the deep-water hydrocarbon prospects in the NW Sabah Trough prompted a comprehensive investigation of the surrounding area, e.g., Dangerous Grounds for hydrocarbon prospectivity. Previous studies in the Dangerous Grounds mainly focused on the sparse 2D seismic and gravity-magnetic data analysis. A systematic review of stratigraphic evolution has not been presented thus far in the published literature. In this paper, recently acquired high-resolution 3D seismic data with the core and cuttings and conventional well log data from the adjacent areas have been combined to characterize the stratigraphic evolution of the Dangerous Grounds in the NW Sabah Platform. Seven horizons interpreted from the 7570 sq. km 3D seismic data, calibrated with the global sea - level curve and geological time scale, to establish the stratigraphic evolution in the study area. Based on distinct structural and seismic characteristics, and calibrated with the adjacent regions well data, two mega-sequences, namely, lower syn-rift and upper post-rift mega-sequences, have been identified and evaluated. The Paleocene to Early Oligocene syn-rift sequence consists of clastic sedimentary fill in grabens and half-grabens is overlain by Late Oligocene to recent post-rift sedimentary successions represented by siliciclastic and carbonates deposits. Major depositional units within these two mega-sequences, including carbonate, channel, mass transport deposits, and turbidites have been identified and evaluated. During Late Oligocene to Middle Miocene, the area has witnessed the deposition of carbonate platform and reefs on top of pre-existing structural highs. Late Oligocene to Middle Miocene channel-levee complexes with convex upward sand filling features is prominent in the seismic data. Mass Transport Deposits and turbidites have also been observed above the Middle Miocene Unconformity with distinct seismic characteristics. The pelagic and hemipelagic nature of the sedimentary succession deposited from Pliocene to recent in a passive margin condition have also been interpreted from their unique seismic features. Paleocene-Early Oligocene syn-rift siliciclastic hydrocarbon play, Late Oligocene-Middle Miocene carbonate play, and Late Miocene turbidite play within the study area have been interpreted.

During the Serpukhovian (late Mississippian) Stage, the Pennine Basin, now underlying much of northern England, consisted of a series of interlinked sub-basins that developed in response to the crustal extension north of the Hercynic orogenic zone. For the current study, mudstone samples of the Morridge Formation from two sub-basins located in the south-eastern part of the Pennine Basin were collected from the Carsington Dam Reconstruction C3 Borehole (Widmerpool Gulf sub-basin) and the Karenight 1 Borehole (Edale Gulf sub-basin). Detailed palynological analyses indicate that aside from the dominant (often 90% or more) heterogeneous amorphous organic matter (AOM), variable abundances of homogeneous AOM and phytoclasts are present. To complement the palynological dataset, a suite of geochemical and mineralogical techniques were applied to evaluate the prospectivity of these potentially important source rocks. Changes in the carbon isotope composition of the bulk organic fraction (δ13COM) suggest that the lower part (Biozone E2a) of Carsington DR C3 is markedly more influenced by terrigenous kerogen than the upper part of the core (Biozones E2a3–E2b1). The Karenight 1 core yielded more marine kerogen in the lower part (Marine Bands E1–E2b) than the upper part (Marine Band E2b). Present day Rock-Eval™ Total Organic Carbon (TOCpd) surpasses 2% in most samples from both cores, a proportion suggested by Jarvie (2012) that defines prospective shale gas reservoirs. However, when the pyrolysable component that reflects the generative kerogen fraction is considered, very few samples reach this threshold. The kerogen typing permits for the first time the calculation of an original hydrogen index (HIo) and original total organic carbon (TOCo) for Carboniferous mudstones of the Pennine Basin. The most prospective part of Carsington Dam Reconstruction C3 (marine bands E2b1–E2a3) has an average TOCo of 3.2% and an average HIo of 465 mg/g TOCo. The most prospective part of Karenight 1 (242.80–251.89 m) is characterized by an average TOCo of 9.3% and an average HIo of 504 mg/g TOCo. Lastly, X-ray diffraction (XRD) analysis confirms that the siliceous to argillaceous mudstones contain a highly variable carbonate content. The palynological, geochemical and mineralogical proxies combined indicate that marine sediments were continuously being deposited throughout the sampled intervals and were punctuated by episodic turbiditic events. The terrestrial material, originating from the Wales-Brabant High to the south of the Pennine Basin, was principally deposited in the Widmerpool Gulf, with much less terrigenous organic matter reaching the Edale Gulf. As a consequence, the prospective intervals are relatively thin, decimetre-to meter-scale, and further high resolution characterization of these intervals is required to understand variability in prospectivitiy over these limited intervals.

The Kusa orthomagmatic Ni-Cu sulphide deposit is situated c. 13 km west of Falun in Bergslagen, south-central Sweden. Ion probe data on zircon from the mafic to ultra-mafic host rocks yield a 207Pb/206Pb weighted average age of 1798 ± 4 Ma, suggesting a genetic connection to intrusive activity forming the Transscandinavian Igneous Belt (TIB-1 phase). TIB-1 ages have recently been reported also for the Kleva deposit of similar type in Southern Sweden. The presence of these two occurrences suggests prospectivity potential for Ni-Cu mineralisation in mafic to ultramafic members of the areally extensive TIB.

The southern Canadian Rockies is an excellent area in which to examine and discuss compressional hydrocarbon traps for three main reasons: (1) the Foothills host numerous large hydrocarbon fields, many of which were discovered decades ago and continue to produce today, providing a growing subsurface database and documentation of the history of applicable structural models over time; (2) the thrust belt is well exposed and provides many outstanding examples of seismic-scale structures associated with thin-skinned fold-thrust hydrocarbon traps and play types, including surface expression of several of the producing hydrocarbon fields; and (3) many published maps and papers from the Canadian Rockies have contributed significantly over several decades to our evolving understanding of the geometry, evolution, and hydrocarbon prospectivity of thin-skinned fold-thrust belts worldwide.

The Stavely Arc developed during the Cambrian above a continent (west) dipping subduction zone within the Grampians-Stavely Zone in present-day western Victoria. Siluro-Devonian regional dextral trans-tensional strike-slip faults recently mapped by the Geological Survey of Victoria in Cambrian basement, previously only recognised in Grampians Group cover, have segmented what was a relatively simple Cambrian configuration of Stavely Arc volcanic fault slices into a complex array of segmented and variably rotated arc fragments, including the until now enigmatic “Crab Nebula” in the Black Range. Inversion of magnetic data has provided an understanding of the 3D geometries of the three volcanic belts in the Black Range. Applying this understanding, together with over-printing criteria evident in filtered potential field data, within the context of a trans-tensional strike-slip stress regime, has enabled a retro-deformation of the Black Range belts into a single, west dipping belt of arc volcanics — an untangled, pre-Silurian “Crab Nebula”. The proven prospectivity of the Black Range Belt (by the presence of the McRaes/Eclipse prospect) can now be extended to all three of the Black Range belts.

The potential oil shales of the Palaeogene Muwaqqar Chalk Marl and Umm Rijam Chert Limestone formations are investigated from a subsurface location in the west of Jordan. Detailed organic geochemistry data is placed in the context of a sequence stratigraphic framework derived from vertical foraminiferal biofacies and lithological changes and biostratigraphically calibrated using planktonic foraminiferal biozonation. This shows that the transgressive systems tract of a Selandian (P4, probably P4a) sequence has the best potential in the studied section to generate oil if subjected to induced pyrolysis. A Ypresian (no older than E2) transgressive sequence has some potential, whilst highstand systems tracts offer the least potential. Both the sequence model and oil shale potential compares well with equivalent age sediments in Egypt and highlights that whilst the Maastrichtian portion of the Muwaqqar Chalk Marl Formation is often regarded as the key interval for oil shale prospectivity, parts of the Paleocene succession also have some potential.

Summary The Carson, Bonnition and Salar Basins offshore Newfoundland and Labrador, Canada comprise and area of approximate 150,000 km2 situated southeast of the oil prolific Jeanne d’Arc Basin. Previous exploration rounds in the 1970s and 1980s were unsuccessful at discovering hydrocarbons in the basins; however, renewed exploration efforts are ongoing in the region with recent 3D seismic acquisition, an exploration license acquired in 2015 and a land sale scheduled for 2019. Recent 2D seismic acquisition by TGS and PGS, as well as fluid inclusion studies, updated biostratigraphic reports and multibeam and seabed coring programs have enhanced our understanding of the region. This area is a branch of the North Atlantic Mesozoic rift network which experienced two main periods of rifting – Late Triassic to Mid Jurassic and subsequent reactivation in the Late Jurassic-Early Cretaceous. The multiple rift phases and salt diapirism have led to multiple structural, stratigraphic and combination play types. The Kimmeridgian has not been encountered in this region and is an unproven source rock. Other potential source rocks include Middle Jurassic, and Cenomanian-Turonian as seen at the ODP 1276. The regional studies and recent 2D seismic data are providing positive indications of an active petroleum system in the region.

Summary Easier shallow clastic reservoir targets within Malay Basin have been depleted, and test of new play such as deeper reservoir is needed. PETRONAS Carigali is shifting the focus to explore the potential of synrift play in North East of Malay Basin. However, to date there is no significant commercial discoveries have been made from syn-rift play in Malay Basin.

The Jeffara Basin, located offshore central Tunisia, covers an area of about 20,000 km2. It is a hydrocarbon productive area situated between the two main productive basins of Tunisia: the Ghadames and the Pelagian Provinces. The present work aimed to reconstruct the main tectonic styles and phases by means of seismic, well logs and geological data, for better understanding their role in hydrocarbon trapping and exploration. The interpreted key seismic lines showed a lateral variation of structural style in the Jeffara basin. They depicted that after the major upper Triassic-early Jurassic rifting phase, the NE–SW extension process continue during the upper Jurassic and lower Cretaceous. This tectonic phase was dominated by NW–SE to E–W normal faults disclosing the early stage of the halokinetic activity. From the Santonian period, the Jeffara basin was influenced by regional wrench, with disconnected major E–W oriented right lateral strike slip faults. The reactivation of these deep faults caused numerous structural elements toward Jeffara basin. Indeed, the halokinetic activity in the southern part of the Jeffara basin discloses different salt structures: pillows, domes and salt walls, which affect the surrounding strata differently. The detected salt bodies at different stages of growth enabled the prediction of subtle facies controlled hydrocarbon traps.

Summary A multi-dimensional approach is utilized on regional 2D seismic and modern 3D seismic data offshore Lebanon that significantly improves and evolves the geological understanding of the Levant region. The results of studies including: basin modeling, extensive fieldwork, forward modeling, 2D and 3D seismic interpretation, geochemical assessment and Synthetic Aperture Radar (SAR) data are presented in this work. The integrated reiterative approach along with the latest exploration results in the Eastern Mediterranean paved the way for an evolved insight into the petroleum prospectively of Lebanon. The seismic data, as this paper will show, promises prospective plays in the North Levant Basin offshore Lebanon that have similar geological affinities with existing discoveries in the Eastern Mediterranean. The first exploration wells scheduled to be drilled at the end of the year are an exciting next step in Lebanon's contribution to delivering the hydrocarbon potential of the Eastern Mediterranean.

Summary The West of Shetlands represents an underexplored area and remains at the frontier of exploration, principally due to uncertainties in the hydrocarbon charge and seismic imaging. In recent years, efforts were made to address the quality of data within the area in addition to increasing offset and record length to take into account renewed commercial interest in the former acoustic basement. The Westray 3D multiclient survey released in 2018 allows us to address major imaging challenges that must be overcome to reduce exploration risks. Interpreting this new seismic data set provided insight into details of enigmatic discoveries and have later been integrated into petroleum system modeling to better understand the complex charge history of the Paleocene and fractured basement plays. In addition, the new imaging allows a better delineation of Triassic and Jurassic intervals that have been tested as a potential analogue for the Strathmore- and Solan-type discoveries in the Westray survey area. This seismic interpretation and petroleum system modeling study has taken a major step towards completing our understanding of the individual petroleum systems in the various tectonics settings of the Westray area and, ultimately, advances our knowledge of the greater Faroe-Shetland Basin.

Compared with the rest of the Zagros foreland, the Kurdistan Zagros foreland basin is a relatively poorly explored and geoscientifically data-scarce province. Traditionally, oil companies have focused their exploration efforts on areas close to the Zagros Mountain foothills, where major elements of a viable petroleum system exist, especially anticlinal traps that have four-way closures. Conversely, large areas in the high-amplitude fold–thrust zones are avoided. The obvious reason for this conservative exploration approach is that severe compressional folding and thrusting in this area have led to the uplift/emergence and subsequent obliteration of prolific Jurassic–Cretaceous reservoirs and breached potential deeply trapped hydrocarbons in the Triassic and Permian. The regional structural style deduced from seismic and outcrop data frequently displays the development of major fore thrusts at the front of the anticlines. These thrusts have proven to be viable exploration targets in similar basinal settings in the neighboring Iranian Zagros and other parts of the world. Nevertheless, such trap configurations have rarely been explored in the Kurdistan Zagros. In this study, we argue that the Jurassic successions that outcrop in the imbricated zone could be the result of duplication of the Jurassic units by thrusting rather than uplift and deep erosion. Therefore, equivalent and deep-seated Jurassic and older reservoirs in the footwall are most likely still well-preserved in the subsurface. Thus, in such areas, Jurassic and older rocks are justifiable targets for exploration that need to be seriously considered. Several conceptual geological models of stacked thrust faults are proposed and linked to outcrops in the area to illustrate the significance of structural evolution in this part of the Zagros, which have led to the duplication of Jurassic–Cretaceous reservoirs. The approach proposed here allows a new venture assessment of hydrocarbon prospectivity in the supposedly high-risk areas of the Kurdistan region of Iraq.

Summary The Penyu Basin is moderately explored that may still have undiscovered hydrocarbon potential, and recent studies suggest that the basin remains prospective with excellent data coverage of both 2D and 3D seismic. The basin was formed in continental crust, although the exact origin is not properly understood and most authors generally considered it as a pull-apart or “rift-wrench” basin. This is supported by the presence of major strike-slip faults and associated normal faults as being the main basin-bounding faults. The initial half-graben basins evolved into isolated lacustrine systems that provide source-rock facies habitat that could potentially charge the traps in the syn-rift and post-rift sequences. Trap styles in the Penyu Basin include the compressional anticlines, basement drape structures and syn-rift stratigraphic/structural traps. The results of the syn-rift exploration are encouraging, albeit a detailed understanding of the reservoir distribution is essential for identifying future drilling targets in this interval. Undoubtedly, more detailed mapping of new structures with application of new techniques such as basin modeling, integrated structural and high-resolution potential field data interpretation will help in identifying new play types and enable a better understanding of the structural evolution and hydrocarbon prospectivity of the basin.

Summary The interaction of drift (or coast parallel bottom currents) and turbidite (or gravity) processes has only been recently recognized. The resulting mixed/hybrid turbiditic-contouritic systems are therefore just beginning to be understood. These are deep water depositional systems located in relatively frontier basins where modern 2D seismic is proving to be an essential tool in their identification and hydrocarbon potential evaluation, which must include a full petroleum systems review. This study focuses on recognizing and evaluating these mixed systems on seismic data using several examples from a comprehensive global long offset 2D seismic dataset. The huge potential already proven offshore Mozambique and Sergipe indicates that this depositional system should be a main target in deep water exploration. The Argentina Basin has strong indications of a significant accumulation offering a very attractive opportunity in the ongoing licence round.

Seismic interpretation of southern Tunisia (Ghadames basin) was carried out to identify the relationship between the geodynamic context and the petroleum play of the basin. This study encompasses the elaboration of regional structural maps of the different hydrocarbon bearing reservoirs (Paleozoic). These maps indicate that in Southern Tunisia, Ghadames basin is marked by master NE-SW trending faults interference with E-W and N-S direction. Advanced seismic interpretation (seismic attributes) was applied to evince that the reactivation of the ancient faults (inherited from the basement) played an important role in the structuration of the Paleozoic series. In fact, by using seismic attributes, we can prove that almost all faults affecting the Paleozoic are originated from the basement. We utilize seismic attributes to shed the light on the idea that high number of producing field of Ordovician and Silurian “which are traditionally admitted as purely stratigraphic traps” occur along faults alignment. This explains that these fields are in part the result of a specific depositional environment and in part the result of the basement involvement in the formation of these petroleum fields. This study illustrates that advanced seismic interpretation can provide additional understanding and a new concept about the prospectivity of southern Tunisia.

TGS have enjoyed a longstanding relationship with Malta, having first acquired ~10,000 km of 2D seismic data surrounding the islands in 2000/01. In 2013/4, ~6,500 km was reprocessed to better delineate a range of features from Triassic to Tertiary. With 11 wells drilled in Maltese waters between 1971 and 1998, exploration has significantly slowed down with only two wells being drilled since. Despite an absence of commercial hydrocarbons encountered, there have been numerous oil and gas shows ranging from Triassic to Tertiary. The petroleum potential of Malta is prospective and varied since the various working petroleum systems from the prolific neighbouring offshore regions of Tunisia, Sicily and Libya are postulated to be present. TGS have been granted data from the Maltese government to produce an updated temperature model. Using Fobos Pro, TGS’ internal basin modelling software package, a regional temperature model will be built and adjusted to to output ‘optimal temperature zones’ pertaining to source and reservoir. Preliminary reviews of the data suggest that there are clear trends such as an increased geothermal gradient in the Mesozoic basins (south of Malta) in contrast to the lower gradient on the Malta Plateau. Full details will be presented at the Workshop.

The Maltese Islands have a long hydrocarbon exploration history, but with limited success, so far. However, as the southern part of the Ragusa plateau (Hyblean foreland) has major oil fields offshore Southern Sicily it should be considered as prospective region. In terms of prospectivity, the area in the south is surrounded by proven petroleum systems and shows; and from an exploration point of view, with important analogies to the well-known offshore Tunisia and northern Libyan petroleum provinces. In the north, the area is next to offshore southern Sicily with well-known large oil fields on the Ragusa plateau. Offshore Malta is covered by several seismic vintages of 2D data (WG and TGS). Interpretation of 2D, both structural and stratigraphic, delineates a better understanding of the individual petroleum systems within the area. The objective of the study is to summarize the results of the interpretation completed by WG and TGS tying areas covered by both parties’ seismic, extrapolate the findings across the plays and leads identified on seismic offshore Malta and update our insight with new petroleum system analyses, to assess the geological evolution of the area, and give our perspective on the exploration potential of this under-explored area.

The Otway Basin is a broadly northwest–southeast trending basin and forms part of a rift system that developed along Australia’s southern margin. It represents an established hydrocarbon province with mostly onshore and shallow-water offshore discoveries. However, the outboard deep-water Otway Basin, with water depths up to 6300m, is comparatively underexplored and can be considered a frontier area. Following the completion of a basin-wide seismic depth-imaging program (Part 1) and insights from the revised seismic interpretation (Part 2), we have developed a comprehensive petroleum system modelling (PSM) study by integrating these data and findings (Part 3). Together, the studies have resulted in an improved understanding of the hydrocarbon prospectivity of the deep-water areas of the basin. Given the sparsity of data outboard, almost all legacy PSM studies have been focused either on the onshore or shallow-water areas of the basin and primarily on their thick Lower Cretaceous depocentres. The limitations of legacy seismic datasets resulted in a high degree of uncertainty in the derivative interpretations used as input into PSM studies. In addition, the paucity and poor quality of data in the deep-water area reduced confidence in the understanding of the basin evolution and spatial distribution of depositional environments through time. The newly acquired 2D seismic survey and reprocessed legacy data, with calibration via several wells across the basin, have improved confidence in our understanding of the tectonostratigraphic evolution of the basin (Part 2). The study presented herein integrates products from the work in Part 2 into a petroleum system model with the primary objective being to better understand the petroleum systems across the deep-water Otway Basin.

The inboard areas of the Otway Basin, particularly the Shipwreck Trough, are well explored and a petroleum-producing province. However, outboard in water depths greater than 500m, the basin is underexplored with distant well control and sparse 2D reflection seismic data coverage. The presence of a successful petroleum province onshore and in shallow waters raises the question as to whether these plays may extend further outboard into the deep-water areas. In the deep-water area, structural complexity and poor imaging of events in the legacy seismic data have resulted in interpretation uncertainty and consequentially a high-risk profile for explorers. The 2020 Otway Basin seismic program acquired over 7000-line km of 2D reflection seismic data across the deep-water Otway Basin. In addition, over 10000km of legacy 2D seismic data were reprocessed to improve the tie between the inboard wells and the new seismic grid. This new dataset provides the first clear insight into the structural and stratigraphic framework of this frontier area, including better imaging of the sedimentary section and the lower crust, increased structural resolution and improved calibration of the outboard seismic reflectors via ties to the inboard wells. Interpretation of the new data has led to an improved assessment of the structural elements and the extension of regional supersequences into the deep-water areas. These refinements have been used as input into petroleum systems modelling work and will provide a foundation for future work to understand petroleum prospectivity, including the distribution of source, reservoir and seal facies.

In the Freeman Field, located about 120 km (75 miles) offshore southwestern Niger Delta at about 1300 m (4260 ft) water depth, 3D seismic attributes-based analyses and stratigraphic based geometric models enhance and constrain the characterization of the stratigraphic framework and depositional setting of Miocene-Pliocene Agbada Formation reservoirs in the deep offshore Niger Delta Basin for improved oil and gas exploration and exploitation. An integrated approach was employed involving 3D seismic interpretation, prospectivity mapping, subsurface modelling, as well as spectral decomposition and amplitude attributes analyses. Attribute-assisted seismic interpretation and mapping results reveal a massive northwest-southeast trending shale-cored detachment anticline containing numerous associated normal faults. Strata in the Freeman Field are interpreted to have been deformed by extension in the crestal region of a compressional fault-related fold and secondarily by inflation of the anticline by flow of the ductile, undercompacted, and overpressured Akata Shale. The Mid-Miocene to Pliocene Agbada Formation reservoirs occur as part of a channelized fan system, mostly deposited as turbidites in an unconfined distributary environment on a massive northwest-southeast trending shale-cored detachment anticline containing numerous associated normal faults, except a reservoir sand that occurs as channel fill in a confined depositional environment within a submarine canyon that came across and eroded a previously deposited distributary fan complex, suggesting likely presence of prospective areas for hydrocarbon exploration southwest of the Freeman Field.

Unconventional hydrocarbon exploration in the UK is in its infancy and Third Energy9s activities represent a major step towards unlocking the potential contained within the Carboniferous section beneath North Yorkshire. In the United States, production from unconventional petroleum systems has transformed the country9s domestic energy markets. If the UK can replicate this success, it would go some way to offsetting the decline of North Sea production and thereby reduce dependence on foreign imports. At the end of 2015, no other company had undertaken any unconventional exploration in North Yorkshire and great uncertainty remained over the region9s prospectivity. To rectify this dearth of information, Third Energy carried out a detailed examination of vintage data from the area and also drilled a new well to acquire a modern, unconventionally focused dataset, including approximately 800 ft of core and 4000 ft of wireline log data. Analysis of the mineralogy, maturity, kerogen type, total organic content, brittleness, porosity and permeability of the Carboniferous Bowland sequence has enabled several intervals to be high graded. Given these results, Third Energy now plan to hydraulically fracture these intervals with the intent of producing the UK9s first unconventionally sourced electricity at its Knapton Generating Station.