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

Integrated Seismic and Petrophysical Evaluation of Reservoir F, DABS Field, Niger Delta Basin

This study presents a comprehensive reservoir characterization of Sand F in the "DABS" Field, located within the coastal swamp depositional belt of the Niger Delta Basin. The primary objective was to evaluate hydrocarbon potential and delineate prospective drilling locations using integrated seismic interpretation and petrophysical analysis. The available data for this study are 3D seismic, well logs (DABS-01 to DABS-06), and checkshot data from DABS-04. The methodology used includes fault interpretation, well log correlation, time-to-depth conversion, map generation, identification of reservoirs/prospects, and volumetrics. Seismic interpretation of 21 inline sections revealed a structurally complex area dominated by listric normal faulting typical of the Niger Delta extensional regime. Seven hydrocarbon-bearing sand bodies (A-G) were delineated, with Sand F selected as the primary reservoir target based on its lateral continuity and hydrocarbon presence in wells DABS-01, DABS-04, and DABS-03. A fault-dependent structural trap with a bottom water drive mechanism characterizes the reservoir. We established the oil-water contact at a depth of −10,565 ft subsea. Volumetric analysis using depth-volume relationships estimated a gross rock volume of 35,276 acre-feet. We estimated the Stock Tank Original Oil In Place at 25.3 MMSTB and Estimated Ultimate Recovery (EUR) at 10.2 MMSTB. In addition, we identified one high-potential prospect: a northeast prospect targeting depths of −8,880 to −8,950 ft and a southeast lead at −10,560 ft. These locations were optimized based on their structural positions relative to the mapped faults and the established oil-water contact (OWC). This integrated approach demonstrates the effectiveness of combining seismic interpretation with petrophysical analysis for reservoir characterization in structurally complex Niger Delta settings, providing a robust framework for field development planning.

INTEGRATED GEOSCIENCE, AND GEOSPATIAL ANALYSIS FOR HYDROCARBON EXPLORATION IN THE KHEWARI BLOCK, SINDH, PAKISTAN

The Khewari Block, located in the structurally complex Lower Indus Basin of Sindh, Pakistan, occupies a tectonically favorable yet insufficiently explored sector of a Mesozoic–Cenozoic rifted basin known for its hydrocarbon prospectivity. This study employs an integrated geophysical geospatial workflow to confine subsurface architecture and assess reservoir potential. Extensive interpretation of 2D seismic profiles identifies a system of NE-SW oriented normal faults, horsts, grabens, and local compressional structures, producing a wide range of trap geometries, including fault-bounded closures, rollover anticlines, and tilted fault blocks. Time and depth structure mapping refines horizon geometries and identifies structurally isolated blocks with enhanced trapping potential. Bouguer and residual gravity anomaly maps further resolve density differences associated with uplifted carbonate platforms and sediment filled troughs, confirming segmentation of the structure based on seismic data. Surface dataset complements, such as DEM-based elevation, slope models, and land-use classification, offer further limitations on terrain accessibility, drainage systems, and operational capabilities. The integration of surface and subsurface datasets reduces the uncertainty in the interpretation process, improves the delineation of traps, and contributes to the most effective well-placement planning. The multidisciplinary approach illustrates the effectiveness of integrating seismic reflection, gravity modelling, and surface-based GIS analysis to create a coherent structural framework of frontier basins. The workflow is transferable to other data-limited regions and provides a robust foundation for evidence-based hydrocarbon exploration and decision making.

Integrated Analysis of Sequence Stratigraphy, Seismic Interpretation and Petrophysical Data for Cenomanian Reservoirs (Horus Field, Alamein Basin, Egypt): Implications for Siliciclastic/Carbonate Reservoir Distribution and Quality

This study integrates seismic interpretation, sequence‐stratigraphic analysis and petrophysical evaluation to characterise the Cenomanian hydrocarbon potential within the Bahariya Formation and Abu Roash ‘G’ Member at Horus Field, Alamein Basin. Seismic interpretation revealed ENE–WSW and ESE–WNW trending extensional normal faults, forming structural highs (horsts, tilted blocks) that act as primary hydrocarbon traps. The Abu Roash Formation exhibited the highest seismic reflector continuity, aiding robust structural mapping, while the underlying Bahariya, Kharita and Alam El Bueib formations showed increasing discontinuity downwards. Instantaneous Amplitude and Energy attributes were applied to quantitatively show deeper‐layers amplitude decay, reflector continuity and reveal subtle stratigraphic geometries obscured in conventional seismic data. Sequence stratigraphic analysis delineated two depositional sequences. BAHR‐SQ‐1 (Bahariya Fm), a siliciclastic‐dominated sequence (535–640 ft), comprises Lowstand (LST‐1: fluvial‐deltaic to shallow marine sandstones), Transgressive (TST‐1: mixed siliciclastics/carbonates) and Highstand (HST‐1: progradational sandstones) Systems Tracts. ARG‐SQ‐2 (Abu Roash ‘G’ Member; 525–675 ft), a carbonate/siliciclastic sequence, comprises a Transgressive Systems Tract (TST‐2: deep‐shelf dolomites) and a Highstand Systems Tract (HST‐2: progradational mixed facies). Petrophysical assessment identified both sequences as hydrocarbon‐bearing reservoirs but with distinct characteristics. The Upper Bahariya (HST‐1) offers volumetric potential (thickness 220–233 ft., porosity 29%–35%) but exhibits variable, generally poorer quality (lower net‐to‐gross: 2%–12%, higher shale volume: 15%–25%, higher water saturation: 32%–33%, limited pay: 4–29 ft). In contrast, the Abu Roash ‘G’ Dolomite (primarily TST‐2) demonstrates superior and consistent reservoir quality across wells (thickness 60–81 ft., net‐to‐gross: 15%–32%, lower shale volume: 5%–9%, porosity 21%–24%, lower water saturation: 28%–41%, hydrocarbon saturation 59%–73%, pay 12–23 ft). The cleaner lithology and favourable petrophysics make the Abu Roash ‘G’ the key contributor to hydrocarbon potential, despite its lesser thickness compared to the Bahariya. These results underscore the critical control of sequence stratigraphic architecture and depositional facies on reservoir distribution and quality, providing essential insights for future exploration targeting in analogous settings.

Diagenesis and Petrographic Characterization of Surma Group Sandstone in the South-Eastern Part of Bangladesh: Implications for Reservoir Quality Assessment

The Neogene Surma Group sandstones exposed in the Sitapahar (Kaptai) and Sitakund structures of the Eastern Fold Belt, Bengal Basin, constitute important hydrocarbon-potential reservoirs whose quality is strongly influenced by depositional architecture and diagenetic evolution. This study integrates outcrop sedimentology, petrography, Field-Emission Scanning Electron Microscopy (FE-SEM), and Energy-Dispersive Spectroscopy (EDS) to evaluate lithofacies distribution, diagenetic alterations, and reservoir quality controls within these sandstones. Detailed facies analysis identified depositional associations related to delta front-shoreface, delta plain, tidal flat, prodeltaic, tidal-influenced channel-fill, and channel-bypass systems, indicating deposition within a tide-dominated deltaic-shallow-marine environment. Petrographic analyses reveal predominantly medium- to fine-grained, moderately to well-sorted sublitharenites composed mainly of quartz with subordinate lithic fragments and feldspars, reflecting moderate compositional maturity. Thin-section porosity ranges from 5–23%, with generally low matrix content (<4%). Diagenetic processes, including mechanical compaction, pressure solution, quartz overgrowth, calcite cementation, chlorite coating, and clay mineral authigenesis, significantly modified the primary pore framework and reduced reservoir quality. Conversely, dissolution of feldspar, lithic fragments, and carbonate cements generated secondary porosity and enhanced pore connectivity. FE-SEM observations confirm the presence of interconnected intergranular and intragranular pore systems, although pore-throat reduction by chlorite and illite-smectite coatings locally restricted permeability. Comparative analyses indicate better reservoir quality in the Sitapahar sandstones than in the Sitakund deposits, due to differences in depositional texture and diagenetic intensity. Overall, the Surma Group sandstones exhibit promising reservoir characteristics with significant implications for hydrocarbon exploration in the Eastern Fold Belt of Bangladesh.  The Dhaka University Journal of Earth and Environmental Sciences, Vol. 15(1), 2026, P 79-105

Stratigraphic Trap Configurations, Seismic Sequence and Facies Analyses of the ‘Ekwai’ Field: Implications for Hydrocarbon Exploration In The Niger Delta

Stratigraphic traps have become increasingly important exploration targets in the mature Niger Delta Basin because of the progressive depletion of conventional structural traps. This study utilized threedimensional (3-D) seismic data, wireline logs, checkshot surveys, and well deviation data from three wells (KC1, KC2, and KC3) to characterize the stratigraphic trapping configuration, sequence stratigraphy, and seismic facies of the Ekwai Field in the eastern Niger Delta. The adopted workflow involved well-to-seismic correlation, structuralinterpretation, sequence stratigraphic analysis, seismic facies classification, and depositional environment interpretation. The results revealed stratigraphic traps associated with lateral facies changes, depositional pinchouts, and five distinct channel-fill architectures (Types I–V). Among these, Channel Types II, III, and IV exhibit favourable seismic attributes, coarse-grained depositional characteristics, and high hydrocarbon prospectivity, whereas Types I and V are understood to be shale-dominated and less prospective. Sequence stratigraphic analysis established five sequence boundaries (SB1– SB5) and four maximum flooding surfaces (MFS1–MFS4), which were correlated across Wells KC1, KC2, and KC3 to define the depositional sequences and associated systems tracts. Seismic facies analysis identified distinct facies assemblages based on reflection configuration, continuity, amplitude, and frequency, enabling the interpretation of lithological variations, depositional energy, and sedimentary environments throughout the field. The integrated interpretation demonstrates that hydrocarbon accumulation within the Ekwai Field is controlled by the interaction of depositional architecture, sequence stratigraphy, and stratigraphic trapping mechanisms. The developed geological model enhances reservoir characterization, reduces exploration uncertainty, and provides a robust framework for hydrocarbon prospect evaluation and future field development within the eastern Niger Delta. The 3-D seismic data conducted in the Ekwai field of the eastern Niger Delta focused on understanding the stratigraphic framework. The main objectives were to identify trapping configurations of stratigraphic traps, and pinpoint channels with potential for hydrocarbon accumulation and analyse facies. The research utilized wireline logs, checkshot, and well deviation data from three wells. The methods included stratigraphic, seismic sequence and seismic facies analyses. Stratigraphic analysis uncovered traps resulting from facies changes, stratigraphic pinch-outs, and five channel fills categorized as types I, II, III, IV, and V. among these, channel types II, III, and IV exhibited promising hydrocarbon potential. In Sequence stratigraphy, four stratigraphic sequence boundaries (SBI, SB2, SB3, SB4 and SB5) and four intrasequence Maximum Flooding Surfaces (MFS1, MFS2, MFS3, and MFS4) were identified. SB1 and SB2 were correlated across KC1, KC2 and KC3 Wells. Facies analysis help to distinctively differentiate various facies units and internal reflective configurations, revealing the deposition environment. 

Sequence stratigraphic controls on reservoir quality: Insights from the Middle Miocene Birsa Formation, Gulf of Hammamet, Southern Mediterranean