Investigation of petroleum inclusions in carbonate samples from the Senilix well in the Barents Sea reveals petroleum entrapment in Paleozoic carbonates at reservoir temperatures from as low as 87.3°C to more than 130°C. Using corrected bottom hole temperatures, this corresponds to depths of 2800–4100 m, compared to the present-day depth of these samples of only 1965.9–2020.5 m. The oil in the Gohta and Alta discoveries is concluded to be of either Lower Triassic or Paleozoic origin based on the isomer distribution of triaromatic dimethylcholesteroids (TA-DMC). A potential source-rock candidate is the Ørret Formation, which is the time-equivalent to the Ravnefjeld Formation in Greenland. These oils are of a different origin compared to oils in the nearby Skrugard (renamed to Johan Castberg) discovery which contain oil sourced from the Upper Jurassic Hekkingen Formation. Evidence is presented to suggest that the Gohta and Alta oils represent blends of petroleum expelled at maturities ranging from about 1.0% calculated vitrinite reflectance (Rc) to more than 1.3%Rc, and this corroborates the inferences made from the petroleum inclusions. This emerging play is significant to exploration in the karst developed on the Barents Shelf and the Bjarmeland Platform during the Permo-Carboniferous. Karst reservoirs have been linked to eustatic sea-level changes, and analogous karst reservoirs may be present elsewhere in the Circum-Arctic: for example, in the Sverdrup Basin.

This paper provides an overview of a series of papers to be published within two issues of Petroleum Geoscience in 2018 expressing the theme ‘tectonics and petroleum systems of East Africa’. These papers partly result from the Geological Society of London’s Petroleum Group conference in April 2016 on ‘East Africa; From Research to Reserves’. The theme of this conference highlighted the advances that have been made since a previous East Africa conference as a result of the recent major exploration efforts. This issue (February 2018) concentrates on the regional tectonics and include overviews of our current understanding of Permian to Mesozoic rifting (Macgregor), Tertiary rifting (Purcell), the plate tectonic model (Reeves), and of the development of the East African margin (Davison & Steel). The August 2018 issue is planned to include more basin and regional specific papers on the Kenyan rift system, offshore Somalia, offshore Tanzania and offshore Mozambique.

Over the past ten years we have numerically modelled the properties of the magmatism generated at four of the key areas where the ‘mantle plume–volcanic margin hypothesis’ is expected to be valid: the North Atlantic, South Atlantic, India–Seychelles and Afar. Our model incorporates many of the original assumptions in the classic White and McKenzie model, with pure shear of the lithospheric mantle, passive upwelling and decompressional melting. Our model is however two- rather than one-dimensional, can capture the rift history (extension rate changes and axis jumps) and tracks mantle depletion during melting. In all four of our study areas we require the sub-lithospheric mantle to be 100 – 200°C hotter than ‘normal’, non-volcanic margins to explain the characteristics of the magmatism. In the three passive margin cases we find this excess temperature is limited to a 50 – 100 km thick layer. We require this layer temperature to drop along-strike away from the proposed sites of plume impact at the base of the lithosphere. However, we also find that lithospheric thickness and rift history are as important as temperature for controlling the magmatism. Our work therefore lends support to the hypothesis that the excess magmatism at volcanic margins is due to a thermal anomaly in the asthenosphere, albeit with consideration of extra parameters. Supplementary material: Numerical model description is available at https://doi.org/10.6084/m9.figshare.c.3924505

Faults, fracture systems, weathering profiles and cover sediments of granitic basement in the rift shoulder of the Gulf of Suez Rift (Sinai, Egypt) are useful conceptual analogues for basement–cover reservoir fields. Outcrops demonstrate that fracture intensity peaks adjacent to major faults, and declines in damage zones that stretch to the background fracturing level over distances of 150 m. In the rift shoulder, smaller faults have damage zones that are 30 – 40 m wide with 1 – 5 m-wide fracture corridors. Faults show chemical alteration extending hundreds of metres into basement, with characteristics similar to saprolite in schists, mafic rocks and granitoids. Cover sandstones fill and drape top-basement relief, as recorded by metre-thick basal fluvial coarse sandstones, hosting kaolinite both as diagenetic pore fill and clastic grains. Overlying floodplain to marginal-marine deposits consist of mature quartz arenites. Strategies for production of hydrocarbons or groundwater from basement–cover reservoir couplets should consider a layered system with: (i) deep tight basement of minimal porosity ( c. 1%) hosting producible fractures and faults in a plumbed system with potential thief zones; (ii) top-basement weathering profiles capping granitoids representing a volumetrically considerable reservoir; and (iii) draping cover sandstones showing good reservoir properties, and representing the most homogenous unit. Diagenetic modifications of saprolite, fault rocks and fractures potentially baffle recharge between layers.

The rediscovery of the regional approach and of play-based evaluation has played a key role in the success of conventional exploration in new plays and frontier basins over the past two decades. In this paper, we compare the results of a vintage (1995) play assessment of onshore Colombia (Upper Magdalena Basin) with the actual results of exploration over the following 20 years, reconstructing the vintage risk assessment and recomputing yet-to-find (YTF) using different methodologies. The overall perception of chance displayed on the vintage play maps proved to be largely correct, with most of the discoveries made over the following 20 years being within the forecasted ‘sweet spots’ and the higher risk areas being confirmed by the subsequent, less successful exploration drilling. In contrast, the YTF calculated in the vintage evaluation was overestimated. Such an overestimation of YTF seems a persistent problem in the exploration and production (E&P) industry. Recreating and analysing the vintage assessment in light of subsequent exploration results highlighted that field size distribution (FSD), the number of future accumulations and the prospect-specific risk evaluation were the main variables responsible for the overestimation of the YTF. Clearly, calculating reliable YTF is only possible with sound geological, exploration and statistical knowledge of the analysed play.

Accurate palaeoenvironmental analysis is at the heart of producing reliable interpretations and depositional models. This study demonstrates a multivariate statistical approach to facies analysis based on relationships between grain size and quantitative palynology. Our methodology has the advantage that it can be used on small amounts of sample, such as core or well cuttings, as the basis for facies analysis. Proof of concept studies involving the collection of grain-size and palynological datasets from well-exposed outcrops of the Middle Jurassic, Lajas Formation of the Neuquén Basin, Argentina, demonstrate that canonical correspondence analysis can be used to consistently recognize facies and aid in the determination of depositional environments. This study demonstrates the link between depositional facies, grain-size distribution, palynomorph hydrodynamics and assemblage taphonomy of palynomorphs. This knowledge can be transferred into a semi-automated statistical facies prediction technique for the subsurface in complex depositional settings, particularly when calibrated against conventional sedimentary facies analysis. Supplementary material: The full set of grain-size data and statistical scores are available at: https://doi.org/10.6084/m9.figshare.c.3745481.v1

The SH-1 wildcat well, firstly encountering oil, proved the existence of a working petroleum system in the Tenere Basin, but the origin of oil and its generation history is not fully understood. In this regard, one crude oil and nine Upper Cretaceous source rock samples from the SH-1 wildcat well in the Tenere Basin were characterized by a variety of biomarker parameters and stable carbon isotopic composition. The oil from the Tenere Basin displays a low pristine/phytane (Pr/Ph) ratio, low C 29 /C 30 and C 35 /C 34 hopane ratios, low C 22 /C 21 and high C 24 /C 23 tricyclic terpane ratios, and high gammacerane index (gammacerane/C 30 hopane), suggesting shale source rocks deposited under an anoxic and relatively high-salinity environment. Relatively high C 29 sterane concentrations, a low value of the regular steranes/17 α (H)-hopanes ratio and a canonical variable from stable carbon isotopic composition larger than 0.47 indicate that the oil is mainly derived from terrestrial higher plants. Both aromatic maturity parameters and sterane isomerization parameters suggest that the oil was generated from an early mature source rock. Correlation between oils from the Tenere Basin and those from the Termit Basin confirms that these oils belong to the same genetic family. The oil–source rock correlation suggests that the oil from the Tenere Basin originated from the Upper Cretaceous marine source rocks, and the Yogou Formation can be considered as effective source potential.

Relay ramps can act as conduits for fluid flow in producing hydrocarbon reservoirs, but the two bounding faults are often at the limit of seismic resolution. To study the impact of relay ramps and their fluid composition on seismic data, we present an integrated workflow combining flow simulation in a geomodel of an outcrop relay ramp, forward seismic modelling and seismic-attribute-based volume extraction. In the chosen outcrop of the Arches National Park (Utah, USA), the petrophysical properties are conditioned by deformation bands present in the sandstone, and are used to run a simple water injector–oil producer fluid-flow simulation. Pre-stack depth-migration seismic images are obtained at t = 0, t 1 = 10 and t 2 = 20 years of the flow simulation. The seismic image porosity changes at t = 0 when the model is oil-saturated, whereas the water–oil contacts have stronger amplitude contrasts at later stages. With an adapted attribute-based workflow, we are able to extract geobodies corresponding to the faults and the relay ramp from the three seismic cubes. By varying workflow parameters, we also show reservoir and acquisition conditions that can affect the resolution of the relay ramp on the seismic image either positively or negatively.

This paper presents case studies of producing fields where faults heavily influence fluid-flow behaviour. In a first case, faults show no evidence of barrier behaviour prior to production but, nevertheless, demonstrate strongly compartmentalized field behaviour once production starts. Analytical modelling suggests that short-term pressure differences between faulted panels can be predictable owing to the permeability contrast between fault zone and reservoir: fault permeability, however, is not low enough to prevent dissipation on the geological timescale. Faults in a second case acted as baffles during production, supporting significant pressure differences, with salinity data suggesting that, as a network, they channelled sweep through relays and around fault tips. The third case examines a fault acting as a vertical drain, causing early water breakthrough through proven intermediate seals and depleting non-produced aquifers above. The fault permeability required to explain these depletion rates is estimated from an analytical model. Estimates of 0.02 – 0.2 mD compare well with predictions from a new algorithm calibrated using measurements on natural fault rocks from seismic-scale faults. Experience from case studies such as these can improve the way in which we use limited data from exploration wells when considering fault behaviour in development scenarios and in conditioning reservoir models for production forecasting.

Our study shows that time-lapse changes in the amplitude of the seismic reflection at an oil–water contact (OWC) and/or produced OWC can be used to estimate directly the displacement efficiency of water displacing oil, E D , without the need of a rock and fluid physics model. From this value, it is possible to determine the remaining oil saturation if required. A preliminary application is performed using several published literature examples, which are reinterpreted to assess the average E D and ensure that the theory is consistent with expectations. Next, a North Sea field model with a known E D is used to create fluid-flow predictions and the corresponding synthetic time-lapse seismic data. Application to these data again confirms the basic principles of the method and defines the accuracy when applied to 4D seismic data. Finally, an observed 4D seismic dataset from a producing field in the North Sea is analysed. The results suggest a displacement efficiency of between 21 and 65% with an accuracy of 3% due to data non-repeatability (with a NRMS of between 11 and 13%). Given an average irreducible water saturation of 0.32, this calculates the remaining oil saturations at between 24 and 53% for this field. A prerequisite for use of the proposed OWC approach is that a discrete contact be interpreted on either the 3D or 4D seismic datasets. Therefore, successful application of this technique requires moderate- to high-quality seismic data and a fairly thick reservoir sequence without significant structural complexity.