3D Static Modeling and Petrographic Aspects of the Albian/Cenomanian Reservoir, Komombo Basin, Upper Egypt

Ali, Mohamed; Abdelhady, Ahmed Awad; Abdelmaksoud, Ahmed; Darwish, M.; Essa, Mahmoud A.

doi:10.1007/s11053-019-09521-5

Cited by 36 publications

(8 citation statements)

References 29 publications

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“…Seismic reflection data allow the imaging of subsurface structures down to 7 s two‐way time (TWT). The seismic interpretation process includes the recognition and picking of the principal seismo‐stratigraphic features and faults (carried out using the Schlumberger Petrel TM package) in order to define boundaries of the main seismo‐stratigraphic units in the study area, and in particular, in the vicinity of the structural high (Ali, 2020; Ali et al., 2018; Ali, Abdelhady, et al., 2020; Ali, Abdelmaksoud, et al., 2020). Accordingly, six crosslines, three inlines, and three composite lines were interpreted to study the break out of the studied feature (Figures 2b, 3, 4, and 6).…”

Section: Data Sets and Methodologymentioning

confidence: 99%

Geophysical Evidence for Magmatism Southwest of the Brothers Islands, Northern Red Sea (Offshore Quseir, Egypt)

et al. 2022

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The Red Sea formed due to the separation of Arabia from Nubia during the Late Oligocene-Early Miocene, involving a counter-clockwise rotation of the Arabian plate. Although the southern and central sectors of the Red Sea reached the oceanic stage and display a prominent NW-SE oriented axial ridge, the nature of the crust in its northward termination is still controversial (e.g., Augustin et al., 2021). Onshore observations in the present-day margins of the northern Red Sea (NRS) indicate a "classic" rifted margin dynamic dominated by normal fault and half-graben geometries and provide constraints on the timing and evolution of rifting (Figure 1a; Bosworth & Burke, 2005;Cochran, 1983Cochran, , 2005. Omar and Steckler (1995) concluded that the early stage of rifting was accompanied by two uplift and erosion phases of the shoulders. The first stage started ∼34 Ma in the Early Oligocene, while the second uplift and erosion phase occurred during the latest Oligocene to Early Miocene. However, geological and thermochronometric evidence from the Quseir area on the Red Sea coast indicates that only the second uplift and erosion phase at 23 Ma exists (

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Section: Data Sets and Methodologymentioning

confidence: 99%

Geophysical Evidence for Magmatism Southwest of the Brothers Islands, Northern Red Sea (Offshore Quseir, Egypt)

et al. 2022

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“…The local tectonics of the Kadanwari eld in MIB resulted in various structural deformations that led to many uncertainties in understanding the 3D reservoir structural framework (Saif-Ur-Rehman et al, 2020). The understanding of such deformations can be better comprehended by 3D SM using relevant algorithm models, e.g., volume-based modeling in the Petrel TM (2017) modeling software, which is based on the interpreted seismic data integrated with borehole information (Qadri et al, 2019;Ali et al, 2020;Khan and Abdelmaksoud, 2020;Qadri et al, 2020;Ali et al, 2021;Islam et al, 2021;Radwan et al, 2021;Thota et al, 2021). Traditional modeling methods generally require oversimpli cation of geological settings; however, grid generated volume-based modeling captures realistic reservoir architecture (Thota et al, 2021).…”

Section: D Structural Modeling (3d Sm)mentioning

confidence: 99%

“…With the continuous development of reservoir geological modeling technology, the volume-based modeling, objective function, variation function, multipoint geostatistics, static geological modeling with knowledge-driven methodology, and other mathematical methods have been widely applied in reservoir modeling, which signi cantly promoted the development and technology of 3D reservoir geological modeling (Jung et al, 2010;Adelu et al, 2019;Li et al, 2019;Ayodele et al, 2021;Okoli et al, 2021). However, volume-based modeling is a step-change reservoir modeling technique that creates horizons based on depositional sequence instead of considering horizons as discrete surfaces (Ali et al, 2020;Islam et al, 2021;Thota et al, 2021). This technique directly models volume using a discretized and heterogeneous tetrahedral mesh encompassing the fault framework.…”

Section: Introductionmentioning

confidence: 99%

Three-dimensional Structural Modeling (3D SM) and Joint Geophysical Characterization (JGC) of Hydrocarbon Reservoir: A Case Study of the Kadanwari field in Middle Indus Basin (MIB), Southeastern Pakistan

Khan

Hussain

et al. 2022

Preprint

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Complex structural geology generally leads to significant consequences for hydrocarbon reservoir exploration that needs a comprehensive methodology for complete comprehension. Despite a large number of existing wells in the Kadanwari field, Middle Indus Basin (MIB), southeastern Pakistan, the depositional environment of the Early Cretaceous stratigraphic sequence is still poorly understood, which has implications for regional geology as well as economic significance. To improve the understanding of depositional environment of complex heterogeneous reservoirs with associated 3D stratigraphic architecture, spatial distribution of facies and properties, and hydrocarbon prospects, a new methodology of three-dimensional structural modeling (3D SM) and joint geophysical characterization (JGC) is introduced in this research. JGC makes use of seismic interpretation-aided 3D SM, 3D seismic attributes analysis coupled with petrophysical modeling using 3D seismic reflection, and borehole data. Subsequently, the 3D SM reveals that the Kadanwari field experienced multiple stages of complex deformation dominated by NW to SW normal fault system, high relief horsts, half-graben, and graben structures. 3D SM and 3D fault system models (FSMs) further depict that the middle part of the sequence experienced more deformation compared to the surroundings of major faults with predominant oriented in S30°-45°E and N25°-35°W, azimuth as 148°–170° and 318°–345°, minimum (28°), mean (62°), and maximum (90°) dip angles. The applied variance edge attribute better portrays the inconsistency of the seismic data associated with faulting and estimated high reflection sediments presumed to be potential hydrocarbon traps. The high amplitude and loss of frequency anomalies of sweetness and root mean square (RMS) amplitude attributes represent cleaner and payable sand-rich shoreward facies revealing gas saturated sand, while relatively low amplitude and high-frequency anomalies indicate sandy shale, shale, and pro-delta facies, unfavorable zones for gas potential. The quantitative petrophysical modeling result shows that E sand interval has good effective porosity (∅ eff ) and hydrocarbon saturation (S hc ) compared to G sand interval. The derived average petrophysical properties, such as volume of shale (V shale ), average porosity (∅ avg ), ∅ eff , water saturation (S W ), and S hc of the E sand interval are 30.5%, 17.4%, 12.2%, 33.2%, 70.01%, respectively. The newly introduced 3D SM and JGC workflow is an effective tool for highlighting potential areas of high quality reservoir development.

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“…The displacement values of most of these faults range between 40 and 200 ft in the SE and NW directions, forming many horst, graben and half-graben structures. Some of these faults have large displacement values, ranging from 100 to 800 ft (Ali et al, 2020b). Figure 9 represents the 3D structural model of the Quseir Fm, showing horizons that are dissected by many normal faults with NW-SE and ENE-WSW directions.…”

Section: D Fault Horizon and Facies Models Of The Quseir Formationmentioning

confidence: 99%

Three‐Dimensional Structural Modelling and Source Rock Evaluation of the Quseir Formation in the Komombo Basin, Egypt

Ali

2020

Acta Geologica Sinica (Eng)

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The Quseir Formation consists mainly of dark gray mudstones with a high organic matter content and excellent hydrocarbon-generating potential. The main objectives of this study are to highlight the dominant structural elements in the Komombo Basin, Egypt, and evaluate the geochemical characteristics of the Quseir Formation. Depth maps and a 3D structural model indicate two normal fault trends NW-SE and ENE-WSW. The NW-SE trend is the dominant one that created the primary half-graben system. The depth to the top of the Quseir Formation gradually decreases from the eastern and central parts towards the corners of the basin. The thickness of the Quseir Formation ranges from about 300 to 1000 ft. The 3D facies model shows that the shale has a large probability distribution in the study area, compared with the sandstone and siltstone. The source rock potential varies between good in the western part to very good in the eastern part of the basin. The organic-rich interval is dominated by gas-prone kerogen type III based on TOC and Rock-Eval. The pyrolysis data vitrinite reflectance (%R o) (0.5-0.74%) and T max values (406-454C°) suggest a maturity level that ranges from immature to early maturity stage for hydrocarbon generation.

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3D Static Modeling and Petrographic Aspects of the Albian/Cenomanian Reservoir, Komombo Basin, Upper Egypt

Cited by 36 publications

References 29 publications

Geophysical Evidence for Magmatism Southwest of the Brothers Islands, Northern Red Sea (Offshore Quseir, Egypt)

Geophysical Evidence for Magmatism Southwest of the Brothers Islands, Northern Red Sea (Offshore Quseir, Egypt)

Three-dimensional Structural Modeling (3D SM) and Joint Geophysical Characterization (JGC) of Hydrocarbon Reservoir: A Case Study of the Kadanwari field in Middle Indus Basin (MIB), Southeastern Pakistan

Three‐Dimensional Structural Modelling and Source Rock Evaluation of the Quseir Formation in the Komombo Basin, Egypt

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