Well logs and seismic data integration for 3D structural, facies, and petrophysical static modeling approach of the Albian–Cenomanian reservoirs in the Silah field, El Fayoum concession, Egypt

3D Structural and Petrophysical Modelling for Reservoir Characterization of the Poseidon Gas Field, Browse Basin, NW Shelf, Australia

Integrated 3D static modeling approach for evaluating the Cenomanian Bahariya reservoir in Falak Field Shushan Basin northwestern desert Egypt

This study integrates petrophysical analysis, seismic interpretation, and 3D reservoir modeling to evaluate the hydrocarbon potential of the Albian-Cenomanian Bahariya Fm in the Falak Field. Seismic interpretation reveals a structurally compartmentalized field dominated by a NW-SE trending normal fault system, compartmentalizing the field into distinct up-thrown and down-thrown blocks. Time-to-depth conversion, validated by synthetic seismogram, check shot data that is used to build a velocity model, facilitated the construction of structural contour maps, identifying two primary three-way dip closure prospects. The Bahariya Fm exhibits significant thickness variation (568 ft to 861 ft), with net pay zones ranging from 47 ft to 197.5 ft. The average effective porosity is between 16.3% and 22.7%, while the average oil saturation is between 44.2% and 51.4%. Petrophysical evaluation based on well logs, cross-plots, well-to-well correlation and facies modeling (55.48% sandstone) indicates that sandstone represents the dominant modelled facies, followed by siltstone, shale, and minor carbonate/limestone facies. The sandstone-rich intervals are mainly associated with the lower Bahariya units and represent the most favorable reservoir zones. A 3D geocellular model, incorporating interpreted horizons, faults, facies distributions, and petrophysical properties (populated via Sequential Gaussian Simulation), visualizes the reservoir architecture, confirms superior reservoir quality (higher Øeff, lower Sw/Vsh) within the central, northwestern, and southeastern areas, particularly in the lower fluvial sandstone units. These results prioritize the northern and southeastern structural closures for future development drilling targeting the Bahariya Fm due to optimal reservoir properties and hydrocarbon pore volumes. Model uncertainty is mainly related to sparse and uneven well control, facies distribution away from wells, log upscaling, and variogram-based property modelling. Volumetric calculations estimate the total OIIP/STOIIP of the Bahariya reservoir at approximately 160 MMSTB, with Bahariya-I contributing about 46 MMSTB and Bahariya-III contributing about 114 MMSTB. The workflow is extendable to analogue subsurface clastic reservoirs in the Northwestern Desert and North Africa.

Integrated Petrophysical Characterization and 3D Static Modeling of the Early Cretaceous Zubair Reservoir: Implications for Hydrocarbon Asset Evaluation in Luhais Oilfield, Southern Iraq

This study presents an in-depth reservoir properties of the Zubair Formation in the Luhais Oil Field in southern Iraq. Geologically speaking, the formation is situated in the Thamama Group, which is part of the Early Cretaceous Eighth Megasequence (AP8). By integrating wireline log data with 3D structural and petrophysical modeling, the study evaluates the reservoir's spatial heterogeneity and storage capacity. Sandstone intervals with adjacent shale successions comprise most of the Zubair Formation, which has been split into three members and four distinct reservoir units. The upper sand member is the primary interval that contains hydrocarbons, according to the analysis results. Based on petrophysical analyses, the sandstone-dominated Units A and C have good reservoir quality, with moderate-to-high permeability levels between 76 and 328 mD and porosity values between 15% and 25%. Also, these units show quite low water saturation (0.22–0.37), suggesting a high potential for hydrocarbon accumulation. On the other hand, due to their high water saturation and low permeability, Units B and D which have a high shale content act as non-reservoir intervals; these intervals are thought to serve as both hydraulic barriers and potential source rock facies. The most productive zones are contained within the upper sand member, as confirmed by the developed 3D geological and petrophysical models that successfully define the geographic distribution of these characteristics.  

INTEGRATED STRATIGRAPHIC AND PETROPHYSICAL ASSESSMENT OF THE MADUKY FIELD, NIGER DELTA, NIGERIA: IMPLICATIONS FOR RESERVOIR ARCHITECTURE AND HYDROCARBON PROSPECTIVITY

The Maduky Field, situated within the Coastal Swamp depobelt of the Niger Delta Basin, represents a structurally complex and geologically heterogeneous marginal field with untapped hydrocarbon potential. This study integrates 3D seismic interpretation, well log correlation, sequence stratigraphy, and petrophysical analysis to characterize its reservoir architecture and evaluate hydrocarbon volumes. Structural mapping reveals prominent listric growth faults and rollover anticlines that define three main field compartments, each with distinct depositional and trapping characteristics. Sequence stratigraphic analysis, guided by five regionally correlated Maximum Flooding Surfaces (MFSs), delineates Genetic Sequences and system tracts (HST, TST, LST), each with unique parasequence stacking patterns and reservoir geometries. The highstand and lowstand system tracts host the most prolific reservoirs, characterized by clean, coarsening-upward sand bodies with high net-to-gross ratios and favorable porosity-permeability relationships. Petrophysical evaluation across five wells indicates effective porosity values of 20–34%, permeability ranging from 2.50 to 18 mD, and low water saturation (8–35%), confirming reservoir quality suitable for commercial exploitation. Crossplots further demonstrate the controls of porosity and depositional environment on fluid distribution and reservoir performance. The study identifies key hydrocarbon-bearing units sealed by marine shales associated with MFSs and quantifies Stock Tank Oil Initially In Place (STOIIP) across fault blocks, highlighting potential development zones. These insights support the redevelopment of Maduky Field and provide a scalable model for optimizing marginal field performance in mature deltaic basins.

Geometrization of East Siberia complex carbonate reservoirs with integration of well-testing and seismic surveys

Complex carbonate reservoirs of Eastern Siberia are highly heterogeneous and difficult to predict seismically because of intrusive bodies, thin-bedded strata, and salinization zones. This study aims to evaluate the effectiveness of an integrated reservoir geometrization approach for refining the boundaries of productive zones, improving production drilling success, and reducing geological risks using an oil and gas condensate field in the Irkutsk Region as a case study. The leading method is a retrospective analysis by integrating long-term well testing, interference testing, numerical 2D flow modeling in Kappa Ecrin Saphir, seismic attribute maps (acoustic impedance and Vp/Vs ratio), and seismic facies analysis. The results show that the productive reservoir is only partly associated with basement highs and does not fully conform to their boundaries. By combining dynamic reservoir data with seismic information, the authors define the lateral extent of vuggy porosity zones more accurately. Initial rates, reservoir pressure measurements, and pulse interference tests confirm authors' results. This approach can enhance drilling success from 78,4 % to 86,4 % and provides an effective tool for optimizing well placement and development programs.

Characterization of the Menggala Formation Sandstone Reservoir Using Multi-Attribute Seismic in the “X” Field, Central Sumatra Basin

Field X in the Central Sumatra Basin presents unique characteristics due to suboptimal data quality for seismic inversion analysis. However, a comprehensive reservoir characterization is still required. Therefore, alternative strategies are needed to optimize the available data, one of which is multi-attribute seismic analysis. This study aims to characterize the reservoir in the Menggala Formation, Central Sumatra Basin, using multi-attribute seismic analysis. The petrophysical parameters used include density porosity (DPHI), water saturation (Sw), and shale volume (Vsh) as primary indicators for assessing reservoir quality. The dataset consists of post-stack 3D seismic data and well log data from four calibration wells, including gamma ray, density, neutron, and resistivity logs. The research workflow began with petrophysical analysis to derive DPHI, Sw, and Vsh values from the well log data, followed by seismic attribute extraction within the target reservoir intervals. Multi-attribute linear regression was then applied to establish a quantitative relationship between seismic attributes and well log data, enabling the lateral prediction of petrophysical parameter distributions across the study area. Model validation was conducted by comparing the predicted values against well log data, yielding correlation coefficients of r= 0.63 (Vsh), r= 0.85 (DPHI), indicating sufficiently reliable and acceptable prediction results. Based on the modeled property distributions, potential reservoir zones are characterized by low Vsh, high DPHI, reflecting the presence of clean sandstone with good hydrocarbon potential. These findings serve as a valuable reference for identifying prospect zones and supporting future development planning within the study area.