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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/

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 analysis of structural discontinuities in the Tunas Formation helps characterize this unit as a potential naturally fractured reservoir. The principal discontinuities are 1) fractures parallel to the bedding planes, 2) fractures coplanar to the axial planar cleavage, 3) dilatant fractures filled by quartz, and 4) subvertical shear fractures. Over a thousand measurements on microtectonic structures help infer a stress field whose maximum principal stress (σ1) has a SW-NE orientation. Based on this structural analysis, optimal orientations for exploration and/or production wells in the Claromeco Basin should be a 130° azimuth. Fracture spacing range between 30 and 100 cm in outcrops of the Tunas sandstones along the Ventana foldbelt (VFB). A similar fractured network is postulated for the subsurface of the basin. Organic-rich levels, ranging from coals to carbonaceous shales, occur in the Tunas Formation in the subsurface of the Claromeco Basin and are a potential shale gas resource play. These beds tend to cap successions of interbedded shales and sandstones. The coals range from semi anthracitic to low volatile bituminous. Vitrinite and fusinite prevail as organic matter types, ranging between 1.3 and 2.4 vitrinite reflectance (Ro). The occurrence within condensate-wet gas to dry gas windows reflect subsurface processes such as strong diagenesis and anchimetamorphism. The coal-rich levels in the Tunas Formation can be correlated with other Lower Permian organic-rich units in the Parana Basin in Uruguay (Tres Islas Formation) and Brazil (Rio Bonito Formation). All are analogous to the lower Upper Permian Vryheid coals of the eastern Karoo Basin in South Africa with shale gas and coal bed methane (CBM) prospectivity.

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.

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.

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.

The Ceduna Sub-basin in the offshore Bight Basin of southern Australia is under-explored with no significant hydrocarbon discoveries. Validation of potential petroleum systems is limited to geochemical data from minor shows. Fluid inclusion (FI) analysis was used to investigate the possibility of hydrocarbon migration throughout the penetrated sedimentary sections. Low abundances of FIs were identified in sandstones from several intervals in the Gnarlyknots-1A and Greenly-1 wells, indicative of oils trapped along migration pathways. The trace quantities of oils contained within FIs were successfully analysed by the molecular composition of oil inclusions (MCI) technique. The Gnarlyknots-1A FI oil provides the first geochemical characterisation of oil generated in the central Ceduna Sub-basin. It originated from source rocks that contain both terrestrial and algal organic matter deposited in a sub-oxic environment. The biomarker signature of the Greenly-1 FI oil reflects its derivation from a fluvial-deltaic, clay-rich source rock containing predominantly terrestrial higher plant detritus deposited under oxic conditions. These results reveal that several Lower to Upper Cretaceous source rock intervals in the Tiger, Blue Whale and White Pointer supersequences have potentially generated hydrocarbons, a finding which significantly enhances the petroleum prospectivity of the Bight Basin.

In recent years, the Brazilian Equatorial Margin has drawn attention due to its similarity to areas with new hydrocarbon discoveries in the African conjugated margin, and in French Guiana. However, studies on the tectonic regimes associated with transform margins and their evolution, structures, and petroleum potential are still lacking due to the geological complexity of this region. To address this knowledge gap, research has been done to better understand the geological structures, as well as to identify potential hydrocarbon accumulations in the deepwater Ceara Basin. To achieve this, we performed an integrated interpretation of a large 2D seismic data, new exploratory borehole data, as well as older well data with revised biostratigraphy. This data analysis refines the basin architecture and the Cretaceous-Paleocene tectonic evolution, including implications for hydrocarbon prospectivity in the Ceara Basin deepwater. 2D seismic interpretation was performed using modern concepts of continental break-up. To accomplish this, the transition of continental-oceanic crust was taken into account for restoration of the sediments of the rift stage in the basin. The analysis also identifies potential hydrocarbon accumulations in turbiditic reservoirs and presents new insights about the dimensions of the underlying rift features situated in the continental slope. The results reveal a high potential for drift sequences in deepwater where the Late Albian-Early Cenomanian-Turonian sediments reach thicknesses of approximately 3048–4894 m. Moreover, this research shows evidence of Cretaceous to Paleocene magmatism, indicated by the well-imaged volcanoes and associated sills in the seismic data. This analysis indicates that the Mundau sub-basin can be classified as a volcanic passive margin that was developed during the oblique dextral separation between South America and Africa. The variety of stratigraphic and structural features developed through the Cretaceous history of the Mundau sub-basin offers a variety of potential hydrocarbon traps and plays in a number of rift and post-rift sequences.

Although Lower Silurian black shales within and around the Sichuan Basin have received renewed attention during the past few years because of their potential prospectivity for shale gas, studies associated with shale gas reservoir evaluation are still rare. In this study, eight black shale core samples were collected from a well drilled recently in the Chuandong Thrust Fold Belt, southwestern China, and their geochemistry and pore structures were investigated using low pressure N2 adsorption analysis and field emission scanning electron microscopy (FE-SEM) observations. The results show that the black shales have total organic carbon (TOC) values ranging from 1.01% to 3.98% and their equivalent vitrinite reflectance values are in the range of 2.84%–3.05%. Both mineral matrix and organic matter pores are well developed with pore sizes ranging from several to several hundred nanometers. The total porosity for the eight samples ranges from 2.60% to 4.74% and the percentages of organic matter pores are estimated to be in the range of 31%–62%. The total surface area ranges from 5.06 m2/g to 19.32 m2/g and the micropore (

A shallow borehole was drilled in lower Silurian (Rhuddanian–lower Aeronian) Tanezzuft Formation siliciclastic sediments at the eastern margin of the Murzuq Basin. Shale samples were retrieved from the borehole to study their source rock potential and trace element geochemical composition. Thirty shale samples analysed from borehole CDEG-2a reveal three geochemically distinct intervals. Shales from the top (23–38 m) interval are weathered and have negligible organic content. Shales from the middle (38–42 m) interval have moderate to good organic richness (0.6–1.7 wt.% TOC) with Hydrogen Index (HI) values up to 443 mg S2/g TOC. Shales from the bottom (42–51 m) interval have poor to moderate organic richness (0.07–0.8 wt.% TOC) with HI values up to 277 mg S2/g TOC. All samples have limited source rock potential and are immature to early mature for hydrocarbon generation. It is unlikely that they have ever been buried deeper than ∼2 km. Low TOC values ( Inorganic geochemical redox proxies (Ce-anomaly, authigenic U, Th/U, V/Cr, Ni/Co, and V/Sc) indicate that the lower Silurian Tanezzuft Formation shales from borehole CDEG-2a were deposited under oxic bottom waters, explaining their relatively low TOC values. Deposition took place in a shallow marine environment, in a proximal position with regard to an early Silurian palaeo-shoreline. This combined Rock-Eval pyrolysis and whole-rock geochemical study provides new insights into the Silurian source rock distribution and hydrocarbon prospectivity in central North Africa.

The post-basalt strata in the Faroese area have been investigated based on interpretation of 2D and 3D reflection seismic data. The post-basalt package is divided into 5 units which have led to the constructions of 6 structural maps and 5 thickness maps. Within the 5 units 12 prograding sediment bodies have been identified. Based on the interpretation it is possible to obtain an overview during time of the location of depocentres and direction of prograding units. Within Eocene time the depocentre was placed in the central part of the basin and the sediment influx was mostly from south and southwest. During Oligocene–Pliocene time the sediment influx was from north and northwest and the depocentre had moved in a westward direction closer to the Faroe Platform area. Emplacement of the Cenozoic sediments in the Faroese sector of the Faroe-Shetland Basin is controlled by thermal subsidence of the basin, and local uplift of sediment source areas. Reactivation of older, Paleozoic and Mesozoic, structural elements seem to control the sediment path way and restrict the depositional areas. Various structural elements being re-activated at different times caused considerable structural complexity. Understanding the older, structural elements and their control on sedimentation is a potential tool for understanding deviations from “normal” thermal subsidence and for predicting the prospectivity in the post-basalt succession in the Faroe-Shetland Basin.

Reconnaissance seismic reflection data indicate that Canada Basin is a >700,000 sq. km. remnant of the Amerasia Basin of the Arctic Ocean that lies south of the Alpha-Mendeleev Large Igneous Province, which was constructed across the northern part of the Amerasia Basin between about 127 and 89–83.5 Ma. Canada Basin was filled by Early Jurassic to Holocene detritus from the Beaufort–Mackenzie Deltaic System, which drains the northern third of interior North America, with sizable contributions from Alaska and Northwest Canada. The basin contains roughly 5 or 6 million cubic km of sediment. Three fourths or more of this volume generates low amplitude seismic reflections, interpreted to represent hemipelagic deposits, which contain lenses to extensive interbeds of moderate amplitude reflections interpreted to represent unconfined turbidite and amalgamated channel deposits. Extrapolation from Arctic Alaska and Northwest Canada suggests that three fourths of the section in Canada Basin is correlative with stratigraphic sequences in these areas that contain intervals of hydrocarbon source rocks. In addition, worldwide heat flow averages suggest that about two thirds of Canada Basin lies in the oil or gas windows. Structural, stratigraphic and combined structural and stratigraphic features of local to regional occurrence offer exploration targets in Canada Basin, and at least one of these contains bright spots. However, deep water (to almost 4000 m), remoteness from harbors and markets, and thick accumulations of seasonal to permanent sea ice (until its possible removal by global warming later this century) will require the discovery of very large deposits for commercial success in most parts of Canada Basin.

The interior basins of Turkey remain effectively unexplored and their petroleum systems are poorly understood. This paper presents a comparative summary of the geological evolution, petroleum potential and prospectivity of the Central (Tuz Golu, Sivas and Cankiri) and East Anatolian (Mus-Hinis, Pasinler-Horasan and Tercan-Askale) basins using geological, seismic, geochemical and petrophysical data, and a series of quantitative basin models. The studied basins are ranked on the basis of source effectiveness, reservoir quality, seal efficiency, and the timing of hydrocarbon expulsion and migration relative to trap formation. A qualitative risk assessment, based on the elements of the petroleum system, is used to evaluate the likelihood of hydrocarbon discovery in each of the basins. This study shows that the chance of hydrocarbon discovery in the East Anatolian basins is unlikely-very unlikely and Tuz Golu, Sivas and Cankiri basins are equally likely/unlikely-unlikely, likely and unlikely, respectively. Heavy oil and minor gas associated with two mature petroleum systems were discovered in the Tuz Golu basin. Various trap forming mechanisms such as salt tectonics and Middle Eocene compression, accompanied by the effective sealing capacity of the Eocene evaporites favor the hydrocarbon exploration potential of the Tuz Golu basin. The highest exploration risk in the Tuz Golu basin arises from the poor quality sandstone reservoirs. The biggest risk factor in the Eastern Anatolian basins is insufficient thermal maturity, despite the presence of good quality source rocks. The Sivas basin is one of the most promising interior basins of Turkey due to the presence of multiple mature petroleum systems and high quality reservoirs. There is a high chance of accumulation of multi-phase hydrocarbons in the Eocene and Miocene traps. The major problem in the Sivas basin is the lack of an efficient seal rock. The Cankiri basin contains all of the necessary elements of an ideal petroleum system except the presence of an organic-rich source rock. Thus, the chance of hydrocarbon discovery in the Cankiri basin is low.

Several exploration wells have intersected a Cenozoic coal-bearing, fluvial-deltaic mudstone and sandstone succession in the northeastern Vietnamese part of the Malay Basin, and have successfully tested seismically identified direct hydrocarbon indicators (DHIs). The oil and gas/condensate discovery well 46-CN-1x encountered a ∼55 m thick section of lacustrine mudstones having considerable potential as an oil source. Vitrinite reflectance (VR) measurements from these alginite-bearing rocks introduce several problems in thermal maturity evaluation, including associated VR suppression and delineation of cavings and bitumens. Reliable thermal maturity gradients, however, may be established using a combination of conventional VR measurements and ‘equivalent VR’ (EqVR) values derived from the fluorescence alteration of multiple macerals (FAMM) technique. These measurements, performed on dispersed organic matter (DOM) in cuttings from 46-CN-1x, allow separation of low-reflecting bitumens and vitrinite in cavings from indigenous vitrinite and the FAMM results indicate VR suppression of 0.14% in an alginite-bearing mudstone with a high Hydrogen Index value. On the basis of available ‘raw’ VR data, a highly irregular maturity trend is determined, with the deepest sample (2675–2680 m) having a VR of ∼0.4%Ro. The EqVR value, however, for the deepest sample is 0.70%. The maturity trend determined from the FAMM data (and VR data, omitting samples having suppressed VR) indicates that the top of the oil window (VR of 0.75%Ro) is located at about 2800 m depth. Modelling the geothermal gradient using the EASY%Ro algorithm yields ∼40 °C/km for both of the two maturity profiles; this is in the low end of the range for the Malay Basin. Modelled temperature histories indicate onset of hydrocarbon generation for the uppermost Oligocene source rocks between 2 Ma and present-day, which post-dates trap formation. Seismic facies patterns suggest that lacustrine oil-prone units are in the oil window in the same graben complex a few km NW of the investigated well, and these rocks are likely to be the source of the hydrocarbons found in the well. A more widespread occurrence of hydrocarbons sourced from this kitchen is indicated by other discoveries and mapping of DHIs in the area.

Interpretation of well-calibrated three-dimensional seismic volumes, sedimentological analysis and electrical well-log correlations from the Ninian and Alwyn North fields challenge the long-held view that Mid-Late Jurassic extensional faults in the East Shetland Basin represent a simple reactivation of older (Triassic) fault systems. Restoration for the effects of the younger, predominantly eastward-dipping, Mid-Late Jurassic structures clearly demonstrates that Triassic precursors had a steep, westerly dip. In contrast to the eastern flank of the Viking Graben (e.g. Troll and Oseberg areas), where the west-dipping Triassic structures are reutilised in the Mid-Late Jurassic, those of the East Shetland Basin have largely been dissected and rotated during the later event. Those west-dipping faults that did see later movement appear to have simply acted as minor antithetic structures to the throughgoing east-dipping ones. The Triassic normal fault patterns actively controlled sediment thicknesses and facies distribution within the Lunde and Teist Formations in the basin. Use of seismic stratigraphic surfaces, calibrated by biostratigraphy and chemostratigraphic markers, provides strong evidence that the Triassic depocentres are spatially offset from their Mid-Late Jurassic counterparts. The combination of structural, stratigraphic and sedimentary effects reveal the existence of an emergent deeper Triassic play opportunity in footwall locations to the Mid-Late Jurassic normal faults, which has the potential to extend the life of what is otherwise mature acreage.

The seabed of the St. Lawrence Estuary is characterized by many fluid releasing features. On multibeam bathymetric images these features correspond to crater-like depression (pockmarks) predominantly found on the northwestern shoulder of the ∼300 m deep Laurentian Channel, as well as on the channel floor. Aligned pockmarks, which define segments up to 12 km long, are frequent in the Laurentian Channel, whereas they are preferentially associated with submarine landslides on the northwestern shoulder of the channel. On high-resolution seismic profiles, pockmarks found in the Laurentian Channel are characterized by seismic chimneys that may be traced down to the autochthonous Paleozoic rocks (St. Lawrence platform), suggesting a thermogenic origin for the gas. On the northwest shoulder of the Laurentian Channel, the seismic signature of pockmarks does not extend downward to the reflector that corresponds to bedrock (St. Lawrence platform and/or Grenvillian province) suggesting, together with high sedimentation rate, a biogenic origin for the gas. These results are discussed in the light of the data collected in the onshore parts of the St. Lawrence platform and suggest the presence of a mature hydrocarbon source. The conclusions are supportive arguments for the hydrocarbon prospectivity of both the onshore and offshore segments of the Paleozoic autochthonous domain (St. Lawrence platform).

Only seven exploration wells have been drilled in Lebanon to date, failing to encounter oil or gas in commercial quantities and to penetrate into unexposed pre-Jurassic reservoirs. This paper shows that the sedimentological and diagenetic characteristics of the major Lebanese Jurassic carbonate rock unit (the Kesrouane Formation; thickness >1000 m) negate Jurassic hydrocarbon prospectivity in northern Mount Lebanon. The Jurassic platform in this region was subjected to a first emergence and invasion by meteoric waters in the Late Jurassic, causing a pervasive cementation. A second phase of uplift and meteoric flushing occurred in the Cenozoic. Thus, only the areas located far from the Jurassic and post-Cretaceous phreatic realms (e.g. offshore Tripoli, NW Lebanon) may have been less affected by meteoric diagenesis and still provide promising prospects. A 1993 seismic survey, offshore Tripoli, confirmed the presence of Late Triassic evaporites in northern Lebanon. This also adds confidence to the results of the Nahr Ibrahim electrical survey, which earlier suggested the presence of these evaporites in the subsurface of central Lebanon. The pre-Jurassic sequence, hence, is sealed and protected from the meteoric invasion observed in the overlying Jurassic rocks. Accordingly, the Qartaba horst structure (central-northern Lebanon) would be equally, if not more, attractive for a pre-Jurassic play.

Pre-Permian sedimentary basins in the southeastern North Sea have been previously interpreted from potential field data but only poorly imaged on seismic sections due to the presence of salt layers and a thick Mesozoic and Cenozoic cover. Furthermore, potentially low prospectivity for hydrocarbon resources has resulted in sparse penetration of Pre-Permian sediments in the southeastern North Sea. We present images of large Palaeozoic basins obtained through reprocessing and pre-stack depth migration of seismic data from the MONA LISA project. The depth images show in detail the structure of pre-Permian basins beneath the Danish basin and the Ringkobing-Fyn High, providing new insights into Upper Palaeozoic basin formation in the North Sea.

A study of the prospectivity around the Veslefrikk oil field in Block 30/3 of the Norwegian North Sea included an evaluation of petroleum migration and trapped gas to oil ratios. The study followed a procedure which involved the assessment of source rock distribution and quality, source rock maturity, petroleum generation and expulsion, and secondary migration. Inside a semi-regional framework two prospects are discussed: (1) B-prospect, a down faulted hanging-wall trap to the west of the Veslefrikk Horst where the existing discoveries of Veslefrikk, Oseberg East, and Zeta exist; and (2) C-prospect, a tilted fault block foot wall trap to the south of the Huldra discovery. 1D thermal modelling coupled to map based petroleum migration analysis and 2D multi-layer migration modelling were used in this multi-source, multi-carrier setting to evaluate the petroleum system. With the integration of available well and seismic data basin modelling techniques can deliver more confident assessments, especially where multiple geological models may exist. In this study area, data, such as temperatures and source rock properties, were used to constrain the model input options, thereby reducing parameter uncertainty. Other data, such as geochemical fluid to source correlation and observed petroleum distribution and composition, served as a validity check for the simulated results from different geological models. The use of these data in this case history are discussed and illustrated.

The Shabwa Basin is the northeastern extension of the Marib-Al Jawf-Shabwa system of Mesozoic grabens, located onshore in the Republic of Yemen. An evaporitic sequence with an estimated maximum depositional thickness of 300 metres was deposited during the Tithonian. It is designated the Sabatayn Formation and exerts significant control on most of the play elements in the principal hydrocarbon play systems anticipated in the northeastern part of the basin. Migration of hydrocarbons from pre-salt source rocks into intra-and post-salt reservoirs is restricted by the evaporites. Localised heat flow perturbations introduced by the salt, increase the maturity of post-salt source rocks. Post and intra-salt reservoirs are structured by listric faulting on a salt detachment, salt pillowing due to post-depositional loading, by local salt dissolution and by late folding due to gravity sliding of the post-salt section on a salt detachment. Early dissolution and reprecipitation of salt is responsible for occlusion of porosity in intra-salt clastic reservoirs.

Shallow boreholes drilled in the West Lewis and West Flannan Basins (outer Hebrides Shelf) have proved rocks of probable latest Bajocian-Bathonian to Barremian age, where previously a mainly Permo-Triassic infill has been assumed. The full geological succession of the basins remains unproved. Although the Permo-Triassic history of the basins may be similar, the rocks encountered suggest that the basins may have dissimilar geological histories during the Jurassic and Early Cretaceous. Lithologies are mainly fine grained, poorly sorted sandstones or organic-rich mudstones. Some correlation can be made with the Isle of Skye and the West Shetland area. The sandstones are poor hydrocarbon reservoirs but the Middle Jurassic and Ryazanian mudstones, although immature where drilled, have excellent oil source rock potential and may have generated large amounts of hydrocarbons if they are present at depth in the adjacent northern Rockall Trough.

A new interpretation of a comprehensive seismic database, consisting of over 5000 km of seismic lines, contradicts the notion that strike-slip motion on the Great Glen Fault (GGF) was the dominant control on Mesozoic basin development in the Inner Moray Firth, UK. It is suggested that the GGF, which may have been active during Palaeozoic times, lay dormant during the Mesozoic and that normal fault systems (such as the Helmsdale-Wick system), formed during two extensional events (pre-Jurassic and Late Jurassic), were the dominant controls on Mesozoic basin evolution. The present expression of the GGF as a discrete, sub-vertical through-going fault attests to its subsequent activity as a divergent wrench structure as part of limited oblique-slip motion after the Early Cretaceous. It seems most likely that such movements occurred in the Tertiary and may have been contemporaneous with regional uplift of the Scottish Highlands during Palaeocene-Eocene (Thulean) events, in response to north-east Atlantic rifting or subsequent Oligo-Miocene (Alpine) tectonism. The new model aids the understanding of the area's general hydrocarbon prospectivity. It can now be demonstrated that the most likely kitchen area for oil resident in the Beatrice Field was centred in the Sutherland Terrace area to the north-west when it formed the site of an active half-graben. Maturation in, and direct up-dip migration from, that area probably took place at the time of maximum burial during the Late Jurassic and Cretaceous, below the half-graben depocentre adjacent to the Helmsdale Fault. Subsequent regional uplift and dissection of the Sutherland Terrace may have served to take the kitchen area out of the maturation window and led to reactivation of several pre-existing structures. Breach and remigration of hydrocarbons is likely to have occurred as a result of the later motions.