Petroleum Geoscience - Volume 29, Issue 2, 2023

In the northern Perth Basin (Western Australia), the Early Triassic Kockatea Shale is the primary petroleum source rock. Possible source rocks in the Northern Carnarvon Basin are more varied and include the Upper Jurassic Dingo Claystone as well as the Early Triassic Locker Shale. Biomarker analyses were conducted on petroleum samples from these basins to understand the nature of the petroleum systems. Many of the analysed petroleum samples contain carotenoids (okenane, chlorobactane and isorenieratane) derived from photosynthetic sulfur bacteria, suggesting that their source rocks were deposited under conditions of photic zone euxinia (PZE) and/or derived from microbialites. In the northern Perth Basin, the major lithofacies contributing to the source rock are dark coloured mudstones deposited under PZE conditions and/or derived from microbialites. In the southern Perth Basin, the potential source rock is either Permian, Jurassic or Cretaceous in age as indicated by the low concentrations or absence of carotenoids and the Triassic biomarker n-C33 alkylcyclohexane. There is also a possibility that the Lower Triassic Locker Shale is the source rock of petroleum in the Tubridgi field on the Peedamullah Shelf of the Northern Carnarvon Basin, based on the similarity of biomarkers to Perth Basin petroleum sourced from the Kockatea Shale. However, the possibility of charge from the Upper Jurassic Dingo Claystone cannot be entirely excluded.

Supplementary material: biomarker dataset is available at https://doi.org/10.6084/m9.figshare.c.6452153

Clay-coated grains play an important role in preserving reservoir quality in high-pressure, high-temperature (HPHT) sandstone reservoirs. Previous studies have shown that the completeness of coverage of clay coats effectively inhibits quartz cementation. However, the main factors controlling the extent of coverage remain controversial. This research sheds light on the influence of different depositional processes and hydrodynamics on clay-coat coverage and reservoir quality evolution. Detailed petrographic analysis of core samples from the Triassic fluvial Skagerrak Formation, Central North Sea, identified that channel facies offer the best reservoir quality; however, this varies as a function of depositional energy, grain size and clay content. Due to their coarser grain size and lower clay content, high-energy channel sandstones have higher permeabilities (100–1150 mD) than low-energy channel sandstones (<100 mD). Porosity is preserved due to grain-coating clays, with clay-coat coverage correlating with grain size, clay-coat volume and quartz cement. Higher coverage (70–98%) occurs in finer-grained, low-energy channel sandstones. In contrast, lower coverage (<50%) occurs in coarser-grained, high-energy channel sandstones. Quartz cement modelling showed a clear correlation between available quartz surface area and quartz cement volume. Although high-energy channel sandstones have better reservoir quality, they present moderate quartz overgrowths due to lesser coat coverage, and are thus prone to allowing further quartz cementation and porosity loss in ultra-deep HPHT settings. Conversely, low-energy channel sandstones containing moderate amounts of clay occurring as clay coats are more likely to preserve porosity in ultra-deep HPHT settings and form viable reservoirs for exploration.

Supplementary material: of data and technique used in this study are available at https://doi.org/10.6084/m9.figshare.c.6438450

The discovery of Wytch Farm field in the Wessex Basin, and Kinsale Head field in the North Celtic Sea Basin in the early 1970s, led to exploration interest offshore in the Western Approaches Trough. Despite this activity, little evidence for prospective hydrocarbon resources has been found. To better understand the failures and analyse remaining hydrocarbon potential in this region, we make use of a large collection of new seismic reflection and well data to map Carboniferous to Neogene stratigraphy. The improved seismic imaging has allowed a better interpretation of the hitherto poorly understood, salt-related structures in the South Melville and the Plymouth Bay basins. The implications of the new interpretations for Carnian (Late Triassic), and Carboniferous stratigraphic and geodynamic evolution are assessed and contextualised with regional salt deposition in the Wessex, Bristol, and South Celtic Sea basins. From a petroleum system perspective, the Lias and Carboniferous source rocks are evaluated and modelled to analyse the maturity and evolution of the petroleum systems. We conclude that the Lias is an ineffective petroleum system due to timing and source maturation risk. However, the Triassic salt and associated subcropping faults have produced several possible pre-salt hydrocarbon traps. The traps may be charged from sporadic Mid-Late Carboniferous coal-bearing post-orogenic basins, a petroleum system previously overlooked.

Thematic collection: This article is part of the New learning from exploration and development in the UKCS Atlantic Margin collection available at: https://www.lyellcollection.org/topic/collections/new-learning-from-exploration-and-development-in-the-ukcs-atlantic-margin

Supplementary material: Appendix showing seismic, well data and petroleum systems boundary conditions. Burial history plots of the petroleum systems modelling scenarios used to generate source rock transformation ratio plots shown in Figures 9 & 10 are available at https://doi.org/10.6084/m9.figshare.c.6486999

In the Pannonian Basin, especially in Croatia, there are a small number of wells for which acquired shear-wave (S-wave) velocities have been obtained. Often, quantitative interpretation relies only on compressional-wave (P-wave) velocity data, and S-wave velocity must be modelled. S-wave velocity estimation in combination with other petrophysical data is essential for detailed reservoir characterization. P- and S-wave velocities enable seismic modelling of different saturation states in a reservoir. This paper demonstrates a workflow for S-wave velocity estimation where S-wave velocity data are absent in the gas field and neighbouring fields with the same lithology, based on the Kuster–Toksöz and Xu–Payne models applied to the Pannonian Basin limestone reservoir. The results are calibrated with the P-wave velocity obtained from borehole data and the vertical seismic profile (VSP) S-wave interval velocity. Although rock physics models are idealized analogues of real rocks, a very good correlation was obtained between the modelled and measured P-wave velocity, as well as between the modelled S-wave velocity and the VSP interval velocity. The study also illustrates the problem of defining the pore aspect ratio in zones of increasing shale content. Due to the limited research on the limestones of the Pannonian Basin, these results enable a better understanding of the seismic parameters of the Pannonian Basin limestones. The results indicate that the proposed workflow gives an adequate estimation of S-wave velocities.

This work addresses the tectonic significance of a NW–SE-trending strike-slip fault zone in the Calabrian Arc of southern Italy, the Rossano–San Nicola Fault Zone (RSFZ). High-quality seismic reflection and 1D forward models of exploration boreholes and pseudo-wells show that the RSFZ experienced multiple Miocene phases of contractional/transpressional tectonics. These were followed by crustal extension during the Pliocene, which occurred in association with the oceanization of the Tyrrhenian Sea, Apennine orogenesis, and collision between the Calabrian Arc and adjacent tectonic plates. Such a setting had a profound influence on the Crotone Basin and its economic potential: (1) tectonic reactivation allowed reservoir units of the Crotone Basin to be charged by gas derived from Triassic/Lower Jurassic source rocks; and (2) source rocks reached their maximum depth and remained in the gas generation window after the emplacement of a large mass-transport complex in the Pliocene. In the surrounding areas, tectonic activity near the RSFZ contributed to source-rock maturation by enhancing local sedimentation rates, particularly during Langhian (Middle Miocene) and Zanclean (early Pliocene) tectonics. This work is important as it demonstrates that the tectonostratigraphic evolution of the Crotone Basin was closely related to the structural evolution of the RSFZ. Crucially, the study area reveals the first example of a gas field fully sealed by a large mass-transport complex. As a corollary, we tie the Late Cenozoic geological history of the Crotone Basin to the geodynamic evolution of the central Mediterranean region, namely the Ionian and Tyrrhenian seas. We identify new prospects in the Crotone Basin, and provide a time frame for gas generation and accumulation in southern Italy.