Geophysical studies around abu gharadig basin, North Western desert, Egypt

Abdelhamed, Belal Mohamed; Araffa, Sultan Awad Sultan; Abdelhafeez, Tharwat

doi:10.1080/08123985.2022.2123736

Cited by 1 publication

(1 citation statement)

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“…Two boundary conditions need to be satisfied in order to build a 1D‐basin model: the paleo‐heat flow at the bottom and the temperature at the sediment–water interface (TSWI) at the top of the model (Hantschel & Kauerauf, 2009; Figure 16). The estimated Cretaceous paleowater depth is attempted based on foraminiferal and palynological studies (Abd El Kireem et al, 1996; Ahmed, 2008). The TSWI is dependent on paleolatitude and water depth (Wygrala, 1989), with the help of the well‐known crustal evolution models and plate tectonic framework, the values of base heat flow are determined for each geologic event (Allen & Allen, 1990, 2005).…”

Section: Resultsmentioning

confidence: 99%

Geochemical evaluation and basin modelling of the Cretaceous succession in the Azhar Oil field, West Beni Suef Basin, Egypt

Farouk,

Saada,

Fagelnour

et al. 2024

Geological Journal

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Geochemical analysis was performed on the Cretaceous sequence of the Azhar‐A‐2 well in the West Beni Suef Basin (WBSB), Western Desert, Egypt, utilizing data on total organic carbon (TOC), kerogen composition, vitrinite reflectance (Ro%) and Rock‐Eval pyrolysis. In addition, a 1D basin model was built to investigate the burial and temperature history of the study area. The most important Cretaceous source rocks are predominantly reported within the Albian Kharita Formation and Late Cenomanian‐Santonian Abu Roash (AR) Formation. Based on visual kerogen tests and Rock‐Eval pyrolysis, AR Formation (A, E, F, and G) are mixed oil‐ and gas‐prone source rocks with kerogens ranging from type II to type III, where A/R ‘A and F’ Members show dominant oil‐prone kerogen with the highest generative potential, while A/R ‘E and G’ Members are more gas‐prone kerogen. Most samples of the lower Kh Formation were interpreted as gas‐prone kerogen type III with low generative potential. On the other hand, the high amount of liptinite in the visual kerogen macerals is a strong indicator that the lower Petroleum Formation is an oil‐prone rather than gas‐prone source rock. The thermal maturity of the studied members increases consistently with depth, ranging from immature at the top of the AR Formation to the main/peak oil window at the base of the Lower Kharita Formation, which served as an active source rock for the hydrocarbons generated in the WBSB. The high value of the heat flow in the Beni Suef Basin (57 and 60 mW/m2) is a good indicator for the shallowing of the active source rock depth limit depth. From the study of the basin modeling, the main mature zone reached between 9811 and 11,090 ft in the middle of the Late Cretaceous (84.3–82.5 Ma) is through the L. Kharita Formation with three phases of hydrocarbon generation according to transformation ratio, where the second phase is the main stage in which TR is 5%–50%, showing the beginning of oil expulsion (Ro: 0.73%–0.78%, possibly 0.81%).

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