Hydrocarbon Prospectivity Research Articles (Page 1)

Tectonic and stratigraphic evolution of the Shushan Basin in northern Western Desert of Egypt played an important role in hydrocarbon accumulation in the Mesozoic. The purpose of this study is to assess the hydrocarbon prospectivity of the deep Middle Jurassic Safa Member by integration of seismic interpretation, structural analysis, core descriptions, and wireline log evaluation over ten wells. Seismic data also indicate extensive E–W and NW–SE normal fault systems that developed horst–graben structures, hence providing crucial structural traps. Petrographic observation indicates that the Safa reservoir consists of vertically stacked, pebbly, cross-bedded sandstones deposited in a fluvial channel environment. Petrophysical evaluation indicates net pay thicknesses varying from 375 to 500 ft, 10–15% effective porosity, 5–20% shale content, and hydrocarbon saturation varying up to 95%, particularly in Qasr-3 and Qasr-4 wells. These results confirm the Safa Member as a fault compartmentalized, overlying Zahra shale-sealed, high-productivity gas–condensate reservoir. The findings also stress the significance of tectono-stratigraphic evolution in governing reservoir development and offer an exploration predictive model for such similar rift-related basins worldwide.

Enhancing hydrocarbon prospect delineation through artificial intelligence driven integration of seismic attributes and inversion in ‘OS’ field, offshore, Niger Delta

Exploration activities in Teapot Dome can be carried out by looking at the geological structure. Determination of geological structure can be done by interpreting seismic data. This study aims to identify hydrocarbon prospect zones in the Teapot Dome field through 3D seismic interpretation of wells 25-1-X-14 and 64-JX-15, and to evaluate the application of sweetness and RMS amplitude attributes in determining the geological structure of the Teapot Dome using 3D seismic reflection data. The data interpretation processing stage starts from performing wavelet extraction, well seismic tie, horizon picking, and time structure map. This research utilizes seismic sweetness and RMS amplitude attributes with amplitude values of 10 to 60ms to map hydrocarbon distribution. The results of this study show that the greatest hydrocarbon distribution occurs at both markers in well 25-1-X-14, with amplitude values of 50 ms and 20 ms, indicated by the presence of sweet spots and bright spots. In well 64-JX-15, sweet spots and bright spots are observed at the top marker with an amplitude value of 20 ms. The application of attributes in determining the geological structure in the Teapot Dome field is found to be an anticline that runs from the northwest to the southeast.

A new Upper Cambrian through Upper Cretaceous tectono-stratigraphic units framework has been developed for the southwestern portion of the Wadi Sirhan Basin in Jordan based on the interpretation and integration of key well results and a regional grid of 2D seismic data. Seismic lines through this area, tied to vertical seismic profiles from four wells, defines stratigraphic boundaries. All stratigraphic boundaries are based on fair-to-good continuous markers, with strong stratigraphic boundary reflectors. Seven tectono-stratigraphic units have been identified within the subregional geoseismic sections: tectono-stratigraphic unit A corresponds to the Lower–Middle Cambrian strata; tectono-stratigraphic unit B corresponds to the Upper Cambrian strata; tectono-stratigraphic unit C corresponds to the Lower–Middle Ordovician strata; tectono-stratigraphic unit D corresponds to the Upper Ordovician strata; tectono-stratigraphic unit E corresponds to the Silurian strata; tectono-stratigraphic unit F corresponds to the Lower Cretaceous strata; and tectono-stratigraphic unit G corresponds to the Upper Cretaceous strata. A geological model has been devised to illustrate the geometry of the tectonic structure and major fault sets where differing trends have been recognised. The Zakimat Al-Hasah Fault is a major E–W-trending fault downthrown to the north that must have been active as a normal fault formed during the Cretaceous, and was rejuvenated in recent time. Other major faults include a NW–SE-trending fault with a northeast downthrow; a NW–SE-trending fault with a southwest downthrow; a WNW–ESE-trending fault with both a south and a north downthrow; and an E–W- to ENE–WSW-trending fault with both a south and north downthrow. The tectono-stratigraphic model provides new constraints on potential structural style controls and illustrates the stratigraphic position of the accumulation features and more clearly demonstrates an explorationist’s interpretation of the origin and migration route of hydrocarbons.

Background: Development of a geological framework to substantiate and quantitatively evaluate the hydrocarbon potential of the Balkhash sedimentary basin cover. Aim: Identification of the key estimation parameters for potentially promising hydrocarbon plays (area, thickness, lithological composition) on a qualitatively new geological lithological and stratigraphic base for determining the hydrocarbon potential of the Balkhash sedimentary basin. Materials and methods: Correlation of lithological and stratigraphic sequences of Mesozoic (Triassic-Cretaceous) and Cenozoic (Paleogene-Neogene) deposits in accordance with the stratigraphic charts of the Phanerozoic of Kazakhstan based on the International Chronostratigraphic Scale from 2016 to 2021. Results: The paper investigates the geological structure, zoning, and platform cover of the Balkhash sedimentary basin (BB). During the study, two tectonic units were identified within the BB structure: the West Balkhash and East Balkhash (Lepsin) depressions. Lithological and stratigraphic charts of the Balkhash sedimentary basin have been created and refined to serve as a basis for appraising its hydrocarbon resources. Additionally, prospective hydrocarbon plays have been identified, and their thicknesses have been measured. Furthermore, the analysis of lithological and stratigraphic data has allowed for the determination of the thicknesses, distribution areas of these discoveries, and the organic carbon content within them. These parameters are critical for calculating predicted hydrocarbon resources. Data regarding the development areas of promising BB hydrocarbon plays were obtained from the results of constructing lithological and paleogeographic maps and sections. Conclusion: Based on the developed lithological and stratigraphic model, charts of the Balkhash basin have been drawn up allowing for appraisal of the hydrocarbon potential. The oil and gas potential of the region is estimated to be very low due to the characteristics of the sedimentary cover structure, tectonic activity, and types of possible traps. However, we have identified prospective gas plays that exhibit certain capacities, areas, and organic matter content.

Faults play a crucial role in subsurface reservoir characterization by influencing fluid migration, compartmentalization, and hydrocarbon trapping. Understanding fault-induced variations in petrophysical properties is essential for optimizing reservoir management and hydrocarbon recovery. This study investigates the structural discontinuities in the subsurface through well log analysis of three wells QUAC-1, QUAC-2, and QUAC-3. It aims to delineate fault zones and assess their impact on lithology, porosity, and fluid distribution. Gamma ray (GR), resistivity, density, neutron porosity, and sonic logs were analyzed across the three wells. Key fault indicators were identified using abrupt log variations, lithological shifts, and crossplot analyses. Fault types were classified based on stratigraphic displacement and structural interpretation. Five fault zones (F1–F5) were identified, with F1 and F3, classified as major faults unlike F2, F4 and F5. GR variations indicated shale smearing along fault planes, while resistivity contrasts revealed compartmentalization effects. Density-neutron crossover effects suggested gas-bearing zones displaced along fault planes, confirming hydrocarbon migration pathways. The findings highlight fault-controlled lithological variations and reservoir compartmentalization, with normal faults predominantly influencing the study area. Reservoir quality is impacted by fault juxtaposition, affecting hydrocarbon accumulation and fluid flow. Structural discontinuities significantly influence reservoir characterization. Identifying and quantifying fault effects is crucial for improving exploration strategies and enhancing hydrocarbon recovery. This study integrates petrophysical log correlations to refine fault classification and assess their impact on reservoir compartmentalization, providing insights into hydrocarbon prospectivity in structurally complex formations.

Hydrocarbon Prospect Identification through Subsurface and Petrophysical Evaluation of the Alam El-Bueib Formation in the Kenz Oil Field, Northwestern Desert, Egypt

ABSTRACTThis study represents the application of magnetic techniques in hydrocarbon prospection within the Outer Western Carpathian petroleum play, specifically focusing on the Eocene–Oligocene rocks of southeastern Poland. Magnetic minerals serve as a sensitive proxy for diagenetic processes, particularly concerning hydrocarbon generation, migration, and biodegradation. We investigated the magnetic characteristics of surface rock samples from Dukla and Silesian Units, which have been altered by hydrocarbons migrating through pore spaces and tectonic fissures. The magnetic mineralogy of 29 specimens was analyzed through thermal demagnetization (Lowrie's test), complemented by hysteresis loop and anhysteretic remanence susceptibility measurements to assess domain states and ultrafine grain size ranges. Scanning electron microscope analysis of mineral composition revealed that traces of bitumen and abundant pyrite were common in almost all samples. Ultrafine maghemite emerged as the predominant magnetic mineral within the host rock, with some samples exhibiting varying amounts of ultrafine magnetite, often associated with iron sulfides. Areas adjacent to calcite veins stained with hydrocarbons displayed enhanced magnetic properties, primarily due to increased magnetite content. Additionally, aggregates of barite were identified as accessory minerals within these veins. Our study indicates that detrital iron oxides underwent partial dissolution, leading to the formation of new authigenic minerals such as paramagnetic pyrite and, likely, ultrafine magnetite. These constituents were subsequently transformed partially or completely into maghemite during the oxidation stage of diagenesis. Importantly, the presence of hydrocarbon appears to facilitate the formation of ultrafine (<100 nm) magnetic particles, with magnetite being particularly characteristic of tectonic migration pathways.

This volume, Sedimentary Successions of the Arctic Region and their Hydrocarbon Prospectivity , developed around maps of the sedimentary successions of the Arctic Region, and contains a brief, but comprehensive compilation of geological and geophysical data characterizing all significant sedimentary successions in the Arctic, which cover 57% of the polar area north of 64° N. Its two main goals are to provide, based on present-day knowledge and data, a characterization of all Arctic sedimentary successions (or sedimentary accumulations) and to supply a snapshot of hydrocarbon-related exploration in the Arctic at the end of the first quarter of this century. To achieve these goals, we represent sedimentary successions as consisting of one or several ‘tectono-sedimentary elements’ (TSEs) based on the main tectonic regimes that formed accommodation space for accumulation of sediments. A TSE characterization template has been developed as an efficient method of organizing and presenting the most important information about the stratigraphy, structure and petroleum geology of a TSE, including the most significant exploration facts. This organizational architecture is the backbone of the volume and is a key feature that distinguishes it from other studies of Arctic sedimentary basins. The online volume includes six large-size foldout maps portraying the mapped TSEs in the Circum-Arctic context, including tectonic grain of the consolidated basement, anomalous gravity and magnetic fields, location of the Arctic sampling sites and seismic profiles.

Reservoir heterogeneity within the Cretaceous Abu Roash and Bahariya formations of the Abu Sennan Field (Western Desert, Egypt) presents a significant challenge to hydrocarbon prospect evaluation. This study applies an integrated approach combining well logs from four wells, core analysis, and 2D seismic data to assess reservoir quality and structural framework. The workflow includes: (1) petrophysical evaluation to quantify shale volume (Vsh), effective porosity (ϕe), and hydrocarbon saturation (Sh) across five reservoir intervals-Abu Roash C (net pay 1-32.5 m, Vsh 29-35%, ϕe 19-29%, Sh 52-67%), Abu Roash D (7-10.5 m, Vsh 2-13%, ϕe 17-23%, Sh 60-90%), Abu Roash E (3.4-48.6 m, Vsh 20-30%, ϕe 18-24%, Sh 62-76%), Abu Roash G (3-12.5m, Vsh 11-18%, ϕe 22-24%, Sh 58-73%), and Bahariya (2.5-52.5 m, Vsh 17-27%, ϕe 15-26%, Sh 46-77%); (2) seismic interpretation identifying a NW-SE-trending horst structure bounded by E-W and NNW-SSE fault systems, which compartmentalize the reservoirs; and (3) 3D static modeling to visualize the distribution of facies, porosity, and saturation. The results highlight the AR-D-01 structural closure within the Abu Roash D member as a high-potential prospect, featuring dissolution-enhanced vuggy porosity (ϕe 17-24%) and elevated hydrocarbon saturation (Sₕ 60-90%) corroborated by depth structure maps and petrophysical property models. Overall, the study demonstrates that fault-controlled diagenesis improves reservoir quality in grainstone facies, offering a reliable framework for targeted hydrocarbon exploration in heterogeneous systems.

Reservoir characterization of Kolmani Field, Northeast Nigeria, using well log data and 3D seismic data for enhanced hydrocarbon prospectivity

The Abu Roash C Member in Egypt's Sitra Field (Abu El-Gharadig Basin, Western Desert) has been comprehensively assessed for its hydrocarbon reservoir potential through an integrated geological and geophysical study. The analysis combined well log data from four wells, core samples, high-resolution borehole images (captured via the Oil Mud Reservoir Imager - OMRI), and 2D post-stack time migration (PSTM) seismic interpretation. Petrophysical evaluation included log quality control, identification of hydrocarbon-bearing intervals, and quantification of key reservoir parameters (1) Shale volume (2) Effective porosity (3) Water saturation. Between wells Sitra-8-13 and Sitra-8-17, a laterally continuous sandstone unit was identified, demonstrating favorable petrophysical characteristics consistent with good reservoir quality with average porosity 11%, shale volume 9% and water saturation 56%. This reservoir is bounded by fine-grained siltstones and shales, interpreted as effective sealing units. Seismic interpretation revealed NW-SE oriented fault systems, indicating potential structural traps conducive to hydrocarbon entrapment. Lithological and petrographic analyses-encompassing core descriptions, lithofacies classification, and porosity measurements-suggest a paleoenvironment of shallow marine to marginal marine setting, likely influenced by tidal and storm processes, which explains the observed lithologic heterogeneity. These integrated findings affirm the Abu Roash C Member as a viable conventional hydrocarbon reservoir and provide critical insights for guiding future exploration and development in the basin.

Litho-structural–depth interpretation of high-resolution aeromagnetic, radiometric, and field data over Akiri area, Central Benue Trough, Nigeria: implications for hydrocarbon prospectivity

Structural interpretation and sequence stratigraphy of Kolmani field, Northeast Nigeria, using 3D seismic data and well log data for enhanced hydrocarbon prospectivity

This study is focused on the Menes oil field, located on the western flank of Shushan Basin in Egypt’s northern Western Desert (NWD). The primary oil-bearing reservoir in this area is the Lower Cretaceous Alam El Bueib (AEB) Formation (Fm), that extends through the Barremian to Aptian stages. This formation is characterized by thick, massive, argillaceous, and calcareous sandstones interbedded with shale and carbonate layers. 2D seismic profiles are interpreted to delineate the structural features of the subsurface. The well to seismic tie via synthetic seismograms and check-shot data are utilized for mapping the formation tops of Alamein dolomite, as well as the AEB units (1, 3 A, 3 C, and 3D), and the Paleozoic strata. Electrical wireline logs from four wells in Menes oil field were analyzed to estimate key petrophysical parameters, including porosity and hydrocarbon saturation for reservoir characterization. Finally 3D structural model was developed to enhance subsurface visualization, enabling a more precise characterization of the AEB reservoirs. This model also aims to reduce exploration risks and improve field development strategies in the study area. These findings provide crucial insights into the subsurface characteristics and hydrocarbon prospects of this formation, offering valuable information that can inform strategic decision-making in both exploration and production activities within Shushan basin. The comprehensive understanding gained from these results serves as a key contribution to optimizing future exploration efforts and enhancing the development of hydrocarbon resources in the near by regions.

The offshore Niger Delta Basin "X" field presents significant opportunities for hydrocarbon prospecting; however, effective reservoir characterization remains challenging. This study addresses this challenge by employing a robust combination of seismic attributes, including amplitude, Root Mean Square (RMS) amplitude, variance edge, phase, frequency, and reflector continuity. Utilizing advanced seismic data processing and visualization techniques, the research aims to accurately map structural features, faults, horizons, and potential hydrocarbon traps within the "X" field. The integrated seismic attribute approach enables precise identification of prospective zones by enhancing fault delineation and improving reservoir characterization. The application of the structural smooth attribute significantly increases seismic resolution, allowing for the clear visualization of fault lines and reservoir boundaries, while the variance edge attribute proves instrumental in delineating fault trends and identifying potential trapping mechanisms. Additionally, the construction of 3D fault models using amplitude attributes enhances the interpretation of subsurface features, offering critical insights for targeted well placement. The results reveal two principal faults that align with the reservoir zones, indicating promising areas for detailed hydrocarbon exploration. The findings demonstrate that deploying a multi-attribute seismic analysis provides a cost-effective and reliable method for improving exploration accuracy, optimizing resource allocation, and supporting decision-making in offshore hydrocarbon development.

Multidimensional geophysical insights into hydrocarbon prospectivity in structurally complex fold-and-thrust belt system

The Vale of Pickering (VoP) in North Yorkshire has played host to several small gas discoveries that have come to the end of their production life. Now that the fields have ceased production, there is an opportunity to repurpose them and their infrastructure for the energy transition. Using an extensive, well-constrained seismic dataset, mapping of the VoP has revealed the presence of a NNE–SSW-striking Carboniferous basin precursor, the (newly defined) Slingsby Trough, containing Visean (syn-rift) organic shales that source the gas reservoirs and Namurian sandstones (post-rift) that form secondary reservoirs. Structural inversion of the half graben because of foreland deformation during the Variscan orogeny led to uplift, folding and peneplanation by the Base Permian Unconformity. The area was subsequently overlain by Upper Permian Zechstein Group carbonates and evaporites deposited on the margins of the Anglo-Polish Basin, creating the main reservoir–seal pair and a local petroleum system. Mesozoic faults striking ESE–WNW transected the area and created three-way, fault-bound footwall closures, forming a hydrocarbon ‘sweet-spot’ in the VoP through the coalescence of traps, a reservoir–seal pair and a mature source rock. This study improves our understanding of the various geological conditions that lead to its hydrocarbon prospectivity, explains why interest was shown in its unconventional resource potential, and provides a basis for evaluating the feasibility of re-imagining these fields as viable onshore storage and geothermal sites to aid the decarbonization of NE England.

3D geo-seismic data enhancement leveraging geophysical attributes for hydrocarbon prospect and geological illumination

Satellite gravity data were interpreted to characterise the basement morphotectonic features and architecture beneath the Benin Basin of Nigeria. The Bouguer anomaly data was processed using the high-pass filter to generate the residual anomaly grid, which formed the basis for other edge enhancement techniques like the first vertical derivative (1VD), and tilt angle derivative (TDR) in order to map linear geological features of interest. The interpreted lineaments showed major trends in the NNE-SSW, ENE-WSW, NNW-SSE, N-S, and E-W directions. 2D forward modeling of the basement architecture revealed structural mini basins located offshore of the study region. The mini basins may have accommodated over 4 km thick sedimentary packages, indicating that they have great potentials for hydrocarbon prospectivity if the right conditions for the existence of all the petroleum systems elements are met. It is recommended that future exploration efforts be concentrated on the identified mini basins to ascertain their potential through well test drilling and prospect generation in the Benin Basin of Nigeria.