The lacustrine carbonates of the Barra Velha Formation are a prolific hydrocarbon reservoir in the Santos Basin, Brazil. In many fields, they comprise decimetre- to metre-scale cycles composed of laminated calcimudstones, spherulite and shrub-dominated facies. However, locally these cycles are replaced by decametre packages of re-worked shrub grainstone/rudstone/breccia and in-situ shrub framestone with significant (>30°) depositional dips. The latter could be interpreted in several ways (e.g. fault block highs, carbonate mounds) but the integration of seismic, borehole image (BHI) log and whole core datasets converge on a model of aggrading carbonate mounds that developed in or marginal to a lake setting. The core datasets in this study demonstrate a distinctive depositional fabric within the carbonate mounds. From a production geology standpoint, the crucial difference between mound-dominated and cyclothem-dominated successions is their permeability architecture. Cyclothem-dominated intervals show prominent and laterally continuous, decimetre-scale vertical matrix permeability variations. Mound-dominated intervals lack fine-scale palaeo-horizontal layering and exhibit a greater prevalence of irregular, cm-scale conduits and higher vertical permeability. This difference can only be reliably characterised via the integration of whole core samples with other datasets and has a significant quantified impact on sweep and production performance.

The offshore Temsah Gas Field, located about 65 km NNW of Port Said in the northeastern Nile Delta Basin, is structurally complex, with NE-SW and NW-SE normal faults that control reservoir compartmentalization and hydrocarbon entrapment. The Sidi Salem Formation, the primary reservoir, comprises interbedded sandstone and shale facies with significant hydrocarbon potential. This study integrates high-resolution post-stack time-migrated 2D seismic data and well log analysis from four wells and twenty-nine 2D seismic lines to delineate reservoir structures, evaluates the hydrocarbon potential of the Sidi Salem Formation, and builds a 3D geological model to enhance field productivity, while also clarifying fault geometries, quantifying key petrophysical parameters, and pinpointing new exploration prospects. Seismic interpretation reveals a prominent horst block with a three-way dip closure and several fault-bounded traps. Petrophysical analysis indicates net reservoir thickness of 22-120 m, effective porosity of 19-34%, shale content of 8-27%, and hydrocarbon saturation of 70-79%. Integration of seismic and petrophysical data delineates sandstone-rich zones with enhanced reservoir quality, mainly within the upthrown fault blocks. The resulting 3D model supports volumetric estimation, identifying a new fault-bounded prospect with an estimated GIIP of ~5.33 TCF. This integrated workflow reduces structural uncertainty, refines reservoir characterization, and offers a reproducible approach for exploration in fault-controlled deltaic reservoirs.

Geological formation A formation, or rock formation, is the fundamental unit of lithostratigraphy. A formation consists of a certain number of rock strata. They have similar lithology (rocks), sedimentary facies (appearance) or other properties. Formations are not defined on the thickness of the rock strata, and the thickness of different formations can therefore vary widely. The concept of formally defined layers or strata is central to stratigraphy. A formation can be divided into 'members' and are themselves packed together in 'groups'. Formations were initially described as time markers, based on relative dating and the law of superposition. The divisions of the history of the Earth were the formations described and put in chronological order by the geologists and stratigraphers of the 18th and 19th centuries. Rock formations are formed by sedimentary deposition in environments which may persist for hundreds of millions of years. For example, the Hammersley Basin in Pilbara, Western Australia, is a Proterozoic sedimentary basin where up to 1200 million years of sedimentation is preserved intact.

The Tertiary Uinta and Duchesne River Formations exhibit spectacular outcrop exposures in the Uinta Basin, northeastern Utah. This paper documents four different geological topics/subjects resulting from field and laboratory studies: 1) fluvial-lacustrine sequence stratigraphy, 2) source-to-sink fluvial system, 3) ichnology and paleoenvironment implications, and 4) sandstone reservoir models and characterization. Chapter 1 highlights a sequence stratigraphic framework and basin-scale facies architecture of the Duchesne River Formation. An upward-fining sequence of the lower three members was heavily influenced by uplift in the Uinta Mountains. Its internal fluvial-lacustrine deposits show marked contrasts between the western and eastern part of the basin due to irregular allogenic controls of tectonic subsidence and water discharge (climate and source terrain input controls). Chapter 2 highlights a source-to-sink fluvial system of the basal member of the Duchesne River Formation, which preserves a high net-sand-to-gross-thickness ratio (NTG) system in the western sink (basin) and a low NTG system in the eastern sink. Petrographic data and drainage patterns indicate a high discharge from multiple source terrains with a long sediment transport along the E-W basin axis in the western part of the basin. These factors were important for development of large-volume and high-quality (porous) fluvial sandstone reservoirs in the sink. Chapter 3 focuses on distinct trace fossil assembl

So far from this being the case, it might not be difficult to show that the minor thickness of rock really denotes by far the longer geological interval. If, for instance, it could be proved that the upper part of both the sections lies on one and the same geological platform, but that the lower unconformable series in the one locality belongs to a far lower and older system of rocks than the base of the thick conformable series in the other, then it would be clear that the gap marked by the unconformability really indicates a longer period than the massive succession of deposits. 7. Fossil evidence furnishes the chief means of comparing the relative value of formations and groups of rock. A “break in the succession of organic remains,” as already explained, marks an interval of time often unrepresented by strata at the place where the break is found. The relative importance of these breaks, and therefore, probably, the comparative intervals of time which they mark, may be estimated by the difference of the facies or general character of the fossils on each side.

Abstract The Upper Shuaiba Clinoforms in northern Oman represent a geologically complex environment characterized by complex carbonate clinoform structures and lateral facies variations. These formations, deposited during the late Aptian regressive cycle, feature prograding carbonate sediments that extend towards the Bab Basin. The stratigraphic architecture of the Upper Shuaiba reservoir is dominated by thin profile clinoforms, typically 1 to 6 meters thick, separated by argillaceous units. This unique depositional pattern intensely influences reservoir properties and hydrocarbon productivity across the region. Geological studies underscore the significance of understanding lateral facies staggering within the Upper Shuaiba formation for assessing reservoir quality. Research highlights the diversity of rock types, categorized into five major groups (RT-A to RT-E), each with distinct reservoir characteristics. RT-A, RT-B, and RT-C are primary oil-bearing units, whereas RT-D and RT-E exhibit limited hydrocarbon mobility. The Upper Shuaiba B (USB) clinoform, comprising units B1 and B2, represents this variability, with B1 noted for superior reservoir properties compared to the denser B2 unit. Well placement within the Upper Shuaiba clinoform presents significant challenges due to the thin and variable reservoir thickness. Initial attempts using conventional methods often resulted in suboptimal positioning and variable reservoir performance, highlighting the need for advanced ge

Shale is at the forefront of oil and gas geological research and a hotspot for exploration; however, research has mainly focused on marine and lacustrine shale systems, while studies on shale within transitional coal-measure strata are relatively limited. The Carboniferous-Permian coal-measure strata in the Bohai Bay Basin are well-developed, characterized by widely distributed, regionally stable, and thick shale layers. These strata represent excellent source rocks and reservoirs, indicating significant potential for oil and gas exploration and development. This study investigated the coal-measure shale of the Carboniferous-Permian Taiyuan and Shanxi Formations in the Huanghua Depression of the Bohai Bay Basin. Using data from core analysis, thin sections, well logging, organic carbon content, Rock-Eval pyrolysis, and vitrinite reflectance (R0), this study examined the depositional environment types of coal-measure shale, the vertical evolution of the depositional environments, and the organic geochemical properties of the shale from different depositional environments. This research aims to provide a theoretical basis for oil and gas exploration in the Carboniferous-Permian coal-measure strata of the Bohai Bay Basin. The Carboniferous-Permian coal-measure strata in the Huanghua Depression were divided into the Taiyuan Formation and the Shanxi Formation. The Taiyuan Formation was mainly characterized by barrier coastal facies, while the Shanxi Formation was dominated by delt

2. Silurian.—Upper Silurian, having a strong relation to the Wenlock group of Britain, but with an American facies, and Lower Silurian, with a succession much the same as in British North America, are found on the shores of Smith Sound, and Nathorst has discovered them in King Oscar Fjord, but not as yet so far south as the Danish possessions. 3. Devonian rocks are believed to occur in Igaliko and Tunnudiorbik Fjords, in S.W. Greenland, but as they are unfossiliferous sandstone, rapidly disintegrating, this cannot be known. It is, however, likely that this formation occurs in Greenland, for in Dana Bay, Captain Feilden found a species of Spirifera and Productus mesolobus or costatus, though it is possible that these fossils represent the “Ursa stage” (Heer) of the Lower Carboniferous. A few Devonian forms have also been recorded from the Parry Archipelago, and Nathorst has shown the existence of Old Red Sandstone facies of Devonian in Traill Island, Geographical Society Island, Ymer Island and Gauss Peninsula. 4.

Thinly bedded reservoirs are hard to characterize due to heterogeneity and subtle lithological changes that hinder the identification of productive zones. To overcome these challenges, this study integrates seismic data, well logs, core samples and sedimentology to achieve precise reservoir characterization. Structural interpretation revealed a complex graben system bounded by major listric normal faults trending predominantly NW–SE and WNW–ESE. These faults dip to the NE and SW, creating a series of horsts and graben that control sediment deposition and compartmentalizing the reservoir. The analysis identified four distinct lithofacies associations within the Abu Roash ‘G’ (ARG) reservoir, which are key to understanding the reservoir's heterogeneity and potential for hydrocarbon accumulation: bioturbated mudstones, lenticular-bedded siltstone, flaser-bedded sandstone and massive sandstone. The sandstones, deposited in tidal mixed flat or channel environments, represent the primary hydrocarbon-bearing units, while the siltstone and mudstone facies reflect a tidal-dominated shoreline environment. Petrophysical evaluation identified key reservoir zones in oilfields such as Gharibon and Sohba, with oil-bearing intervals ranging from 2 to 9 ft. Despite their thin nature, these zones exhibit excellent reservoir properties, including low shale volume (<15%), high porosity (15–22%) and high hydrocarbon saturation (40–70%). The reservoir is classified into four types (1–4). Types 1 a

.AbstractThe Permian–Triassic carbonates of the Kangan–Dalan formations in the central Persian Gulf represent one of the largest gas reservoirs in Iran and worldwide. Integrated petrophysical–core zonation, supported by multivariate cluster analysis, was applied to reduce reservoir heterogeneity and improve the understanding of reservoir properties. The results were compared with petrophysical logs, scanning electron microscopy, and pore-throat size distribution. Diagenetic processes were found to play a key role in reservoir quality. Fabric-destructive dolomitization in the upper K2 and lower K4 units generated micro-scale pathways connecting primary pores. Dissolution in the lower K2 and upper K4 units further enhanced pore connectivity, resulting in high permeability within these zones. In contrast, selective dolomitization and dissolution in K1 and K3 did not produce effective flow pathways. These processes led to the development of distinct reservoir zones, including high-porosity/low-permeability (Zone 2), high-permeability/low-porosity (Zone 3), and non-reservoir zones (Zones 4 and 5). Additionally, a thin interval with both high porosity and permeability (Zone 1) occurs as a transitional layer within the lower K4. Although diagenesis is the dominant control, primary depositional facies also influenced reservoir characteristics. All zones were successfully identified by the proposed algorithm.Keywords: Diagenesis, Petrophysical Zonation, Clustering, Permian–Triassic, D

Advanced 3D lithology prediction is vital for reducing uncertainty in reservoir characterization and exploration planning. Traditional post-stack inversion yielded only acoustic impedance volumes, limiting facies discrimination. However, pre-stack simultaneous inversion enables direct estimation of elastic property volumes, particularly P-impedance, shear impedance and Vp/Vs, linking seismic inversion to rock physics evaluation. In this study, the applied workflow integrates seismic inversion products and borehole information within a structured, multi-stage lithology classification framework. Initially, 3D seismic inversion volumes and available well logs were subjected to comprehensive quality control and jointly interpreted to establish a consistent geological framework. This geological interpretation guided subsequent petrophysical analysis of the well logs, from which key reservoir properties were derived. Based on these petrophysical results, rock physics crossplots were conducted to define and discriminate the lithology classes generating a litho-facies log for each well and characterize their elastic responses. The classified well-based data were then, used to generate probability density functions (PDFs) for each lithology class, forming the statistical foundation of the lithology classification model. The dataset used to train an ML algorithm (trained model) was subsequently applied to the 3D seismic inversion volumes to predict lithological distributions away from the wells. Finally, the resulting lithology classification volumes were visualized, interpreted, and quality-controlled to delineate reservoir outlines and assess their spatial continuity and geological credibility. This workflow applied to the Abu Madi Formation in the west onshore Nile Delta, with a focus on the Desouq Gas Field. The probabilistic classification revealed compartmentalized gas-sand channels, refined hydrocarbon facies outlines in the northwest sector, and identified eight previously unrecognized gas-charged zones in the southwest sector. Validation using classification metrics and confusion-matrix analysis confirmed the robustness of the workflow, while integration with elastic property crossplots clarified ambiguities caused by thin anhydrite layers that commonly generate misleading amplitude responses which reduced misclassification risks. The resulting 3D lithology volumes (gas sand, wet sand, shale, and tight anhydrite formation) provide enhanced insights into subsurface heterogeneity and hydrocarbon potential, demonstrating the added value of integrating seismic inversion, machine learning, and rock physics analysis.