Petroleum Geoscience - Current Issue

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

Interpretation of newly acquired seismic and legacy well data has led to a greater understanding of the Upper Paleozoic–Recent geological evolution of the Mid North Sea High (MNSH), an under-explored region of the North Sea. The position of granite-cored blocks controlled the distribution of Devono-Carboniferous highs and basins before Variscan uplift led to peneplanation and the creation of the Base Permian Unconformity. The MNSH became the dominant feature during the Permian when it formed a west–east-striking ridge between the Southern and Northern Permian basins. Following a period of non-deposition, sedimentation was renewed in the Late Permian–Triassic before Middle Jurassic doming caused uplift to the NE. Subsequent Late Jurassic North Sea rifting transected the MNSH to create the Western Platform between the Central Graben and Moray Firth rift arms. Following Cretaceous post-rift deposition, the area experienced a significant easterly tilt in the Cenozoic that led to the demise of the MNSH as a prominent topographical feature. The tectonic and stratigraphic evolution exerts a strong control over reservoir facies distribution, source-rock deposition and maturation. However, the area is not barren of petroleum potential. Despite the lack of Upper Carboniferous source rocks over large areas, hydrocarbon potential is evident through shows in legacy wells, indicating the Lower Carboniferous as a potential source rock. Cenozoic uplift to the west imparted a regional tilt, the effects of which remains key to unlocking the area's prospectivity since it reconfigured structures and formed remigration pathways from Lower Carboniferous and Jurassic source rocks.

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

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

Discovery of the Breagh gas field in the Southern North Sea (SNS) has demonstrated the potential that the Lower Carboniferous (Visean, 346.7–330.9 Ma) Farne Group reservoirs have to contribute to the UK's future energy mix. New biostratigraphic correlations provide a basis to compare Asbian and Brigantian sedimentary cores from the Breagh Field and age-equivalent sediments exposed on the Northumberland Coast, which has proved critical in gaining an understanding of exploration and development opportunities. Thirteen facies associations characterize the mixed carbonate–siliciclastic system, grouped into: marine, delta front, delta shoreface, lower delta plain and upper delta plain gross depositional environments. The facies associations are interpreted as depositing in a mixed carbonate and siliciclastic fluvio-deltaic environment, and are arranged into coarsening- and cleaning-upward cycles (parasequences) bounded by flooding surfaces. Most cycles are characterized by mouth bars, distributary channels, interdistributary bays and common braided rivers, interpreted as river-dominated deltaic deposits. Some cycles include rare shoreface and tidally-influenced deposits, interpreted as river-dominated and wave- or tide-influenced deltaic deposits. The depositional processes that formed each cycle have important implications for the reservoir net/gross ratio (where this ratio indicates the proportion of sandstone beds in a cycle), thickness and lateral extent. The deltaic deposits were controlled by a combination of tectonic and eustatic (allocyclic) events and delta avulsion (autocyclic) processes, and are likely to reflect a changing tectonic regime, from extension within elongate fault-bounded basins (synrift) to passive regional thermal subsidence (post-rift). Deep incision by the Base Permian Unconformity across the Breagh Field has removed the Westphalian, Namurian and upper Visean, to leave the more prospective thicker clastic reservoirs within closure.

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

Interpretation of a 3D seismic survey located on the western margin of the Northern North Sea Basin demonstrates how the propagation, overlap and linkage of two north–south-striking, en echelon normal fault segments exerted a powerful influence over prospective subtle stratigraphic traps. The relay ramp that formed between the segments appears to have focused sediment dispersal, controlled reservoir distribution and aided post-depositional petroleum migration. Integration of electrical well log data, root-mean-square (RMS)-amplitude analysis and biostratigraphy with seismic interpretation demonstrates that a series of elongate, linear, sand-prone (reservoir) channel complexes characterize the depositional slopes generated by fault growth. The combination of synsedimentary rotation of bedding due to fault propagation and associated footwall uplift led to erosion and truncation of a laterally extensive, older channelized system (Lower Sequence), the downdip parts of which extend beyond the relay ramp. Its subsequent drape by transgressive shales created the subtle stratigraphic trap that now hosts the Cladhan Field, with charge occurring because the sandstones belonging to the Lower Sequence extend as far as the active kitchen in the neighbouring (hanging-wall) depocentre situated downdip and to the east. In contrast, the exploration of a younger, Upper Sequence of sandstones has proven to be disappointing due to their more restricted distribution, lack of access to charge, and occurrence of faults that offset and breach the thin end of the stratigraphic wedge. The implication is that partially breached relay ramps not only provide a preferential site for syn-rift clastic reservoirs to develop but also form important migration pathways through which oil passed from a petroleum kitchen into a trap.

Thematic collection: This article is part of the Under-explored plays and frontier basins of the UK continental shelf collection available at: http://www.lyellcollection.org/cc/under-explored-plays-and-frontier-basins-of-the-uk-continental-shelf

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

Thematic collection: This article is part of the Under-explored plays and frontier basins of the UK continental shelf collection available at: http://www.lyellcollection.org/cc/under-explored-plays-and-frontier-basins-of-the-uk-continental-shelf

Detailed interpretation of a 3D seismic data volume reveals the detrimental effect that post-depositional tectonic deformation has had on buried Lower Carboniferous (Dinantian–Namurian) shales and its consequences for shale gas exploration in the SW part (Fylde area) of the Craven Basin in NW England. The structural styles primarily result from Devono-Carboniferous (syn-sedimentary) extension, post-rift subsidence and Variscan inversion, a renewed phase of Permo-Triassic extension, and Cenozoic uplift and basin exhumation. In contrast to the shallow dips and bedding continuity that characterizes productive shale gas plays in other basins (e.g. in the USA and Argentina), our mapping shows that the area is affected by deformation that results in the Bowland Shale Formation targets being folded and dissected into fault-bound compartments defined by SW–NE striking (Lower Carboniferous and Variscan) reverse faults and SSW–NNE to N–S striking (Permo-Triassic) normal faults. The fault networks and the misalignment between the elongate compartments they contain and the present-day minimum horizontal stress orientation limit the length over which long lateral boreholes can remain in a productive horizon, placing an important constraint on optimal well positioning, reducing the size of the shale gas resource and affecting well productivity. Our subsurface mapping using this high-fidelity dataset provides an accurate picture of the Upper Palaeozoic structure and demonstrates that faulting is denser and more complex than apparent from geological mapping of the surface outcrop. That structural complexity has direct and significant consequences for: the location of well pads; the lateral continuity of target shale gas horizons; the evaluation of the risk of inducing seismicity on seismically resolvable (large displacement) fault planes prior to drilling; and the likelihood of faults with small throws (below seismic resolution) being present.

The Carboniferous Bowland Shale Formation of the UK is a proven hydrocarbon source rock and currently a target for shale gas exploration. Most existing analysis details lithofacies and geochemical assessment of a small number of boreholes. Given a paucity of relevant borehole cores, surface samples provide a valuable contribution to the assessment of this unconventional gas source. This study reviews existing literature on the formation's hydrocarbon geochemistry and provides new lithological descriptions of seven lithofacies, XRD mineralogy and hydrocarbon-specific geochemical data for 32 outcrop localities within the Craven and Edale basins, respectively in the northern and southern parts of the resource area. Low oxygen indices suggest that the majority of samples are relatively unaltered (in terms of hydrocarbon geochemistry), and therefore suitable for the characterization of the shale organic character. Total organic carbon (TOC) ranges from 0.7 to 6.5 wt%, with highest values associated with maximum flooding surfaces. Mean T max values of 447 and 441°C for the Edale and Craven basins, respectively, suggest that nearly all the samples were too immature to have generated appreciable amounts of dry gas. The oil saturation index is consistently below the >100 mg g−1 TOC benchmark, suggesting that they are not prospective for shale oil.

Supplementary material: A table summarizing the location, geological description and age of all of the samples in this paper is available at https://doi.org/10.6084/m9.figshare.c.4444589

Pre-drill pore pressure prediction is essential for safe and efficient drilling, and is a key element in the risk-reducing toolbox when designing a well. On the Norwegian Continental Shelf, pore pressure prediction commonly relies on traditional 1D offset well analysis, whereas velocity data from seismic surveys are often not considered. Our work with seismic interval velocities shows that the velocity field can provide an important basis for pressure prediction and enable the construction of regional 3D pressure cubes. This may increase the confidence in the pore pressure models and aid the pre-drill geohazard screening process. We demonstrate how a 3D velocity field can be converted to a 3D pore pressure cube using reported pressures in offset wells as calibration points. The method is applied to a regional dataset at the Halten Terrace in the Norwegian Sea; an area with a complex pattern of pore pressure anomalies which traditionally has been difficult to predict. The algorithm is searching for a velocity to pore pressure transform that best matches the reported pressures. The 3D velocity field is a proxy of rock velocity and is derived from seismic surveys, and is verified to checkshot velocities and sonic data in the offset wells.

We present a review of the Chang 7 Member oil shale, which occurs in the middle–late Triassic Yanchang Formation of the Ordos Basin in central north China. The oil shale has a thickness of 28 m (average), an area of around 30 000 km2 and a Ladinian age. It is mainly brown-black to black in colour with a laminar structure. It is characterized by average values of 18 wt% TOC (total organic carbon), 8 wt% oil yield, a 8.35 MJ kg−1 calorific value, 400 kg t−1 hydrocarbon productivity and kerogen of type I–II1, showing a medium quality. On average, it comprises 49% clay minerals, 29% quartz, 16% feldspar and some iron oxides, which is close to the average mineral composition of global shale. The total SiO2 and Al2O3 comprise 63.69 wt% of the whole rock, indicating a medium ash type. The Sr/Ba is 0.33, the V/Ni is 7.8, the U/Th is 4.8 and the FeO/Fe2O3 is 0.5, indicating formation in a strongly reducing, freshwater or low-salinity sedimentary environment. Multilayered intermediate-acid tuff is developed in the basin, which may have promoted the formation of the oil shale. The Ordos Basin was formed during the northwards subduction of the Qinling oceanic plate during the Ladinian–Norian in a back-arc basin context. The oil shale of the Ordos Basin has a large potential for hydrocarbon generation.

Supplementary material: Tables of oil-shale geochemical composition, proximate and organic matter analyses from the Chang 7 Member oil shale, the Ordos Basin, Central north China are available at https://doi.org/10.6084/m9.figshare.c.4411703