Catálogo de publicaciones - revistas

<jats:p> 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 <jats:italic>n</jats:italic> -C <jats:sub>33</jats:sub> 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. </jats:p>

<jats:p>In the Pannonian Basin, especially in Croatia, there are a small number of wells with acquired shear velocities. Often, quantitative interpretation must rely only on compressional velocity data, and shear velocity must be modelled. Shear wave velocity estimation in combination with other petrophysical data is essential for detailed reservoir characterization. Compressional and shear wave velocity allow the seismic modelling of different saturation states in a reservoir. This paper demonstrates a workflow for S-wave velocity estimation where shear velocity data is absent in the gas field and neighboring 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 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.</jats:p>

<jats:p>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.</jats:p> <jats:p content-type="supplementary-material"> <jats:bold>Supplementary material</jats:bold> : [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 Figs 9 &amp; 10. [Item 1: Spreadsheet with seismic and well data used in the study, and petroleum system modelling input data. Item 2: Raw decompacted burial history plot, and burial history plots of the 3 Lias petroleum systems scenarios] <jats:ext-link xmlns:xlink="http://www.w3.org/1999/xlink" ext-link-type="uri" specific-use="dataset is-supplemented-by" xlink:href="https://doi.org/10.6084/m9.figshare.c.6486999">https://doi.org/10.6084/m9.figshare.c.6486999</jats:ext-link> </jats:p> <jats:p content-type="thematic-collection"> <jats:bold>Thematic collection:</jats:bold> This article is part of the UKCS Atlantic Margin collection available at: <jats:ext-link xmlns:xlink="http://www.w3.org/1999/xlink" ext-link-type="uri" xlink:href="https://www.lyellcollection.org/topic/collections/new-learning-from-exploration-and-development-in-the-ukcs-atlantic-margin">https://www.lyellcollection.org/topic/collections/new-learning-from-exploration-and-development-in-the-ukcs-atlantic-margin</jats:ext-link> </jats:p>

<jats:p> Determining rock resistivity for saturation estimation in reservoirs is challenging due to the complex nature of pores in the rock. This paper aims to establish a computational relationship between formation factors ( <jats:italic>F</jats:italic> ) and permeability ( <jats:italic>K</jats:italic> ) by combining theoretical and experimental data. Firstly, the relationship between the permeability of the curved capillary model and formation factors, as well as the relationship between the permeability of the complex curved capillary model and formation factors, are deduced. Theoretical analysis proved that the formation factors( <jats:italic>F</jats:italic> ) have a power relationship with permeability( <jats:italic>K</jats:italic> ) and porosity ( <jats:inline-formula> <mml:math xmlns:mml="http://www.w3.org/1998/Math/MathML" overflow="scroll"> <mml:mi>φ</mml:mi> </mml:math> </jats:inline-formula> ), and confirms the existence of additional resistivity ( <jats:italic> R <jats:sub>x</jats:sub> </jats:italic> ). To validate the the theoretical study, we conducted model analysis using open experimental data from thirty-five sandstone cores with different porosity and permeability from the tight gas sandstone in the Western U.S. Basins, which measured resistivity data in saline at 20ppm, 40ppm, and 80ppm, respectively. We confirmed the existences of additional resistivity ( <jats:italic> R <jats:sub>x</jats:sub> </jats:italic> ) by fitting the relationship between the rock resistivity of saturated formation water ( <jats:italic>R</jats:italic> <jats:sub>o</jats:sub> ) and the formation water resistivity ( <jats:italic> R <jats:sub>w</jats:sub> </jats:italic> ). We then fitted the formation resistivity change factor ( <jats:italic> F <jats:sub>d</jats:sub> </jats:italic> ) with permeability ( <jats:italic>K</jats:italic> ), the formation resistivity change factor ( <jats:italic> F <jats:sub>d</jats:sub> </jats:italic> ) with porosity ( <jats:inline-formula> <mml:math xmlns:mml="http://www.w3.org/1998/Math/MathML" overflow="scroll"> <mml:mi>φ</mml:mi> </mml:math> </jats:inline-formula> ), the additional resistivity ( <jats:italic> R <jats:sub>x</jats:sub> </jats:italic> ) with permeability ( <jats:italic>K</jats:italic> ), and the additional resistivity ( <jats:italic> R <jats:sub>x</jats:sub> </jats:italic> ) with porosity ( <jats:inline-formula> <mml:math xmlns:mml="http://www.w3.org/1998/Math/MathML" overflow="scroll"> <mml:mi>φ</mml:mi> </mml:math> </jats:inline-formula> ). Both changeable formation resistivity change factor ( <jats:italic> F <jats:sub>d</jats:sub> </jats:italic> ) and additional resistivity ( <jats:italic> R <jats:sub>x</jats:sub> </jats:italic> ) showed a strong linear relationship with permeability ( <jats:italic>K</jats:italic> ) in logarithmic coordinates. </jats:p> <jats:p> We also verified the existence of a suitable equation using available experimental data by changing formation parameters and permeability. The study shows that the fitting equations may be utilized to determine changeable formation resistivity change factor ( <jats:italic> F <jats:sub>d</jats:sub> </jats:italic> ), additional resistivity ( <jats:italic> R <jats:sub>x</jats:sub> </jats:italic> ), and the rock resistivity of saturated formation water ( <jats:italic>R</jats:italic> <jats:sub>o</jats:sub> ) with varying permeability. The predicted rock resistivity of saturated formation water ( <jats:italic>R</jats:italic> <jats:sub>o</jats:sub> ) strongly correlates with the one measured in the laboratory, providing better precision for future reservoir evaluation in saturation estimations. </jats:p>

<jats:p>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 (&lt;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 (&lt;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.</jats:p> <jats:p content-type="supplementary-material"> <jats:bold>Supplementary material:</jats:bold> of data and technique used in this study are available at <jats:ext-link xmlns:xlink="http://www.w3.org/1999/xlink" ext-link-type="uri" specific-use="dataset is-supplemented-by" xlink:href="https://doi.org/10.6084/m9.figshare.c.6438450">https://doi.org/10.6084/m9.figshare.c.6438450</jats:ext-link> </jats:p>

<jats:p> The article highlights the importance of understanding the permeability of fault zones as fluid migration pathways, with an example from the Vette Fault Zone in the North Sea. The study characterizes the hydraulic properties of the fault zone by mixing host rock lithologies into the fault zone and deriving the fault width from empirical relationships. A parametric study with 1125 model realizations was conducted to understand the sensitivity related to uncertainties in overburden lithologies and fault width correlations. The study found that the fault zone significantly alters the flow-field compared to a model that only considers lithological juxtaposition. The most significant hydraulic communication in the Vette Fault Zone is downwards from the storage reservoir where sand is mixed into the fault zone. The models highlight the potential for downward hydraulic communication along the fault for brine and CO <jats:sub>2</jats:sub> capillary sealing towards the overburden. </jats:p> <jats:p content-type="thematic-collection"> <jats:bold>Thematic collection:</jats:bold> This article is part of the Fault and top seals collection available at: <jats:ext-link xmlns:xlink="http://www.w3.org/1999/xlink" ext-link-type="uri" xlink:href="www.lyellcollection.org/topic/collections/fault-and-top-seals-2022">www.lyellcollection.org/topic/collections/fault-and-top-seals-2022</jats:ext-link> </jats:p>

<jats:p>Carbonaceous shales in the Southern Uplands-Down-Longford Terrane accretionary prism had extremely high potential for hydrocarbon generation in the Lower Palaeozoic. Structural thickening in the prism enhanced the rapid generation of oil. Shale horizons are separated by thick turbidites composed of low-permeability greywackes, so oil under high fluid pressure either pooled along shale bedding surfaces or migrated into fractured greywackes. Pooled oil became solidified to bitumen, which locally formed deposits on a scale of tonnes, mined as coal. The carbon-rich shale also sequestered large amounts of sulphur from seawater, which precipitated as pyrite firstly during early diagenesis, then further during fluid flow through the shale beds. The oil was also sulphur-bearing. Deformation focussed on the shale beds during the evolution of the accretionary prism would have been closely related to the fluid flow which precipitated bitumen and sulphides. The palaeo-fluids were also anomalously rich in methane and hydrogen, similar to fluids venting from modern accretionary prisms.</jats:p> <jats:p content-type="supplementary-material"> <jats:bold>Supplementary material:</jats:bold> <jats:ext-link xmlns:xlink="http://www.w3.org/1999/xlink" ext-link-type="uri" specific-use="dataset is-supplemented-by" xlink:href="https://doi.org/10.6084/m9.figshare.c.6691597">https://doi.org/10.6084/m9.figshare.c.6691597</jats:ext-link> </jats:p>

<jats:p>Forward modeling of sedimentary systems is a method that simulates sedimentation processes over geological time to generate a set of facies distributed in a depositional space. The objective of using forward modeling in this work was to build a three-dimensional facieś model, from which a synthetic seismic simulation was generated, and then to analyze the relation of seismic-stratigraphic interpretations with the knowledge of the a priori generated sedimentological model. This modeling methodology was applied in a pre-salt field of the Santos Basin, Brazilian offshore, focused on the Barra Velha Formation. The modeling parameters used were (i) the initial surface of bathymetric depth; (ii) the lake level variation; (iii) the subsidence map; and (iv) the deposition rates by facies. Average-constant of acoustic impedance values were assigned to each facies and a synthetic seismic was obtained. With the facies and synthetic models available, it was possible to analyze: (i) the distribution of thicknesses and proportion of facies by region; (ii) the vertical stacking pattern and lateral facies variation; (iii) the Wheeler's distance x time diagram; and (iv) the seismic reflector patterns through the seismic facies classification. Through these analyses, it was possible to better understand the possibilities and limitations of seismic stratigraphy as an interpretation auxiliary tool in pre-salt carbonate environments.</jats:p>

<jats:p>Fracture networks play a critical role in fluid flow within reservoirs, and it is therefore important to understand the interactions and influences these networks have. Our study focusses on the Southern Chotts-Jeffara basin which hosts reservoirs within the Triassic, Permian and Ordovician units containing significant hydrocarbon accumulations. Recent developments on the structural understanding of the basin have proven a regional shortening phase occurring between the Permian and Jurassic forming open folds and a distributed fracture network. Analysis of late Palaeozoic and Mesozoic outcrops within the basin identify several sets of fractures (150/80; 212/86) and compressional structural features which support this shortening hypothesis. We integrate fracture data from surface analogues and subsurface analysis of advanced seismic attributes and well data through structural linking to form a 2D hybrid fracture model of the reservoirs in the region. Through analytical aperture modelling and numerical simulation, we find that the fractures orientated 212° in combination with large-scale fractures contribute significantly to the fluid flow orientation and potential reservoir permeability. Our presented fracture workflow and framework provides an insight in network characterisation within naturally fractured reservoirs of Tunisia and how certain structures form fluid pathways influence flow and production.</jats:p> <jats:p content-type="supplementary-material"> <jats:bold>Supplementary material:</jats:bold> <jats:ext-link xmlns:xlink="http://www.w3.org/1999/xlink" ext-link-type="uri" specific-use="dataset is-supplemented-by" xlink:href="https://doi.org/10.6084/m9.figshare.c.6904499">https://doi.org/10.6084/m9.figshare.c.6904499</jats:ext-link> </jats:p>

<jats:p>Pervasive igneous intrusive complexes have been identified in many sedimentary basins which are prospective for petroleum exploration and production. Seismic reflection and well data from these basins has characterised many of these igneous intrusions as forming networks of interconnected sills and dykes, with distinctive morphologies and typically cross-cutting sedimentary host rocks. Intrusions have also been identified in close proximity to many oil &amp; gas fields and exploration targets (e.g. Laggan-Tormore fields, Faroe Shetland Basin). It is therefore important to understand how igneous intrusions interact with sedimentary host rocks, specifically reservoir and source rock intervals, to determine the geological risk for petroleum exploration and production. The risks for petroleum exploration include low porosity and permeability within reservoirs, and overmaturity of source rocks, which are intruded. Additionally, reservoirs may be compartmentalised by low permeability igneous intrusions, inhibiting lateral and vertical migration of fluids. Based on a range of field studies and subsurface data, we demonstrate that sandstone porosity can be reduced by up to 20% (relative to background porosity) and the thermal maturity of organic rich claystones can be increased. The extent of host rock alteration away from igneous intrusions is highly variable and is commonly accompanied by mechanical compaction and fracturing of the host rock within the initial 10 to 20 cm of altered host rock. Reservoir quality and source rock maturity are key elements of the petroleum system and detrimental alteration of these intervals by igneous intrusions increases geological risk and should therefore be incorporated into any risk assessment of an exploration prospect or field development.</jats:p> <jats:p content-type="thematic-collection"> <jats:bold>Thematic collection:</jats:bold> This article is part of the UKCS Atlantic Margin collection available at: <jats:ext-link xmlns:xlink="http://www.w3.org/1999/xlink" ext-link-type="uri" xlink:href="https://www.lyellcollection.org/topic/collections/new-learning-from-exploration-and-development-in-the-ukcs-atlantic-margin">https://www.lyellcollection.org/topic/collections/new-learning-from-exploration-and-development-in-the-ukcs-atlantic-margin</jats:ext-link> </jats:p>