Abu Roash Research Articles

Formation evaluation utilizing a new petrophysical automation tool and subsurface mapping of the Upper Cretaceous carbonate reservoirs, the southern periphery of the Abu-Gharadig basin, Western Desert, Egypt

The southern periphery of the Abu-Gharadig basin in the Northern Egyptian Western Desert is characterized by some subsurface geological challenges related to the carbonate reservoir's quality, which requires precise petrophysical evaluation and seismic structural interpretation. Therefore, we conducted a subsurface mapping and formation evaluation for the Upper Cretaceous carbonate reservoirs in the Southwest Abu Sennan (SWS) area utilizing seismic reflection profiles and borehole geophysical data. Seismic mapping of the Upper Cretaceous carbonate reservoirs (Abu Roash (AR)/B,/D, and/F) revealed 3-way folds with NE-SW trends divided by NW-SE normal fault trends presenting significant chances for exploration. These closures were filled by hydrocarbons generated from the Jurassic source rocks. Formation evaluation was performed using the new petrophysical tool “Gaialog” which was coded using Python. Petrophysical parameters for the recognized net pay intervals of AR/B, AR/D, and AR/F carbonate reservoirs showed that the effective porosity (φeff: Phie) and the hydrocarbon saturation (Sh) increases towards the East to Southeast direction while the water saturation (Sw) increases to the Northwest of the study area. The highest net pay and the effective porosity were found in the Eastern part of the study area. The study procedures can be applied in neighboring areas to evaluate and understand similar reservoirs.

Delineating tidal channel feature using integrated post-stack seismic inversion and spectral decomposition applications of the Upper Cretaceous reservoir Abu Roash C: A case study from Abu-Sennan oil field, Western Desert, Egypt

Delineating tidal channels that bear hydrocarbons in fluvial systems is crucial to minimize drilling risks, and raise the hydrocarbon potential. Therefore, we performed an integrated workflow that combines/compares the outcomes of a pair of post-stack inversion techniques (model-based inversion and colored inversion) and the spectral decomposition attribute to delineate (vertically and horizontally) the hydrocarbon-bearing tidal channel contained in the Upper Cretaceous Abu Roash (AR)/C reservoir in the South West Abu-Sennan (SWS) area in Abu-Gharadig basin in the Northern Egyptian Western Desert (NEWD). We used a dataset consisting of twenty seismic reflection profiles and borehole geophysical data of four wells. Data conditioning was performed in detail for the whole dataset that was used in this study. The application of the absolute impedance (model-based inversion) produced better results relative to the band-limited acoustic impendence (colored inversion). The model-based inverted sections gave an improved subsurface image of seismic data and delineated the reservoir properly. The low-frequency range detected through the use of seismic inversion techniques and the spectral decomposition attribute analysis showed a good fit with the low impedance values corresponding to hydrocarbons. The study results showed a correlation of roughly 0.99 exists between the generated synthetic impedance, original seismic, and the borehole geophysical data characterizing the tidal channel confined within the AR/C reservoir. The match between the post-stack inversion techniques and the spectral decomposition analysis results is considered a visual validation of the delineated tidal channel. The performed workflow can be applied and impact the understanding of comparable reservoirs with similar settings in near areas.

Geologic Causatives and Seismic Attributes Heterogeneities for Structural and Stratigraphic Interplays, Sitra Area, North Western Desert, Egypt

Sand-lithofacies distributions are a vital component of reservoir characterisation and the generation of successful reservoir models, particularly in thin reservoirs thickness. The integration between seismic attributes and conceptual geologic models is important to identify the sand distributions and reservoir geometries. The aim of this work is illustrating the uses of seismic data in revealing the structural and stratigraphic elements of two main reservoir units. It is important to identify and list the attributes, which can be involved in analysing the reservoirs and their degree of involvement in the characterisation of the hydrocarbon accumulation zones. The study was carried out for the reservoirs: Abu Roash C and Abu Roach E in Sitra oil and gas concession, which is located in the northern part of the Egyptian Western Desert. Four seismic attributes are used: 1- Coherence (Variance) 2- 3D Curvature attributes were used for resolving mainly the structural features and also the stratigraphic features 3- Instantaneous phase 4- Instantaneous frequency attributes were used mainly for resolving the stratigraphic features. Through the integration of selected seismic attributes with post-stack seismic data, reservoir distributions and architectures are accurately delineated for the Upper Cretaceous reservoir (Abu Roash ‘C’ and ‘E’). Five wells were used to match the results of the seismic attributes and establish the regional trends of reservoir parameters. The integration of wells data, conventional seismic interpretation and extracted the relevant seismic attributes help in reaching a robust geologic model for the reservoirs of interest. Stratigraphic and structural interpretation objectives based on extracting the seismic attributes for reservoir characterisation become more dominant, as they go deeper in seismic data, to derive more subsurface geologic data than traditional interpretation. 3D structure model of the concern area was established by interpreting the available seismic data as both reservoirs implicated by two fault trends: NW-SE and ENE-WSW. By the end a 3D geological model was defined based on the results of the conventional interpretation of the seismic and seismic attributes to reflect all structural and stratigraphic elements of the two reservoir units.

The Albian – Cenomanian boundary on the southern Tethyan margin: Abu Gharadig Basin, Northern Western Desert, Egypt

Lithostratigraphy and biostratigraphy sometimes provide contradictory interpretations, especially when trying to establish a chrono-lithological boundary between two reservoir formations from different paleoenvironments. One of these contradictions is the definition of the boundary between the Kharita and Bahariya formations and the Albian and Cenomanian Stages in the Abu Gharadig Basin of the Western Desert, Egypt. an integrated approach has been applied to this problem using borehole image logs, palynology, and conventional wireline logs. authors also calibrate the stratigraphic sections with global chronostratigraphic charts, using nannoplankton, planktonic foraminifera, and dinoflagellates to construct a better understanding of this basin. The abundances of pollen, spores, and dinoflagellates in the interpreted reservoir intervals suggest that hydrocarbons trapped in the Albian-Cenomanian reservoirs are composed of type II/III kerogen. The interpreted intervals are subdivided into seven depositional cycles: one in the Kharita Formation, five in the Bahariya Formation, and one in the Abu Roash Formation. The interpreted environments are, from bottom to top: I) fluvio-deltaic distributary channels, II) and III) intertidal to subtidal deposits, IV) offshore bar deposits, V) intertidal to subtidal deposits, VI) shoreface deposits, and VII) shallow marine carbonate deposits. Diagnostic palynomorphs reflect climatic change from arid to humid conditions and also enable changes in salinity to be determined.Much of the published work in the southern Tethyan margin, particularly in the Western Desert, is either related to stratigraphy, palynology, or reservoir evaluation with a focus on a narrow field. Tectonostratigraphic studies and analyses of petroleum system elements have often been very regional in nature. The work presented here is of an intermediate scale linking regional frameworks with local details to provide comprehensive information about the Albian-Cenomanian succession in the Northern Western Desert. The focus has been the Abu Gharadig basin but this integrated approach has implications for other basins in North Africa. A specific example is the similarity of Western Desert and Libyan Sirt basin Albian-Cenomanian key palynomorphs which would facilitate a similar integrated chrono-lithologic intepretation.

Petrophysical characterization of the heterogeneous shale-rich oil reservoirs: a case study of the Cenomanian Clastics, Abu Sennan Concession, North Western Desert of Egypt

Shale-rich reservoirs present a long-standing challenge for reservoir geologists because the clay minerals often induce a large-scale heterogeneity in the reservoir pore system. This work aims to understand the impact of clay distribution and mineralogy which would enhance the predictability of the best reservoir facies. We integrate seismic, well-log datasets to investigate the petrophysical characteristics of the clay-rich Cenomanian Clastics in the GPY oil field, north Western Desert of Egypt. These Clastics comprise the sandstone intervals which are the most prolific hydrocarbon reservoirs. Seismic data were used to interpret the main structural patterns as well as the different seismic facies. The well log data were utilized to interpret the lithologic variations and the type of clays in the reservoir as well as the different petrophysical parameters. Based on variations in their lithological and petrophysical characteristics, the Bahariya sandstones were sub-divided into three different rock units: Bahariya-3 (B-3), Bahariya-2 (B-2), and Bahariya-1 (B-1), separated by thick laminated clay intervals. AR/G Member is dominated by clays with relatively lower reservoir quality. Spectral gamma ray log values reveal that smectite is the dominant clay mineral in all the studied intervals. Laminated clays are dominant in B-1 and B-2 units, whereas, B-3 unit and Abu Roash G Member are enriched in structural clays. The quartzose sand content decreases from B-3 to AR/G and clay content increases from B-3 to AR/G. Therefore, the best reservoir facies and fluid flow conduits with best pore system characteristics are hosted in B-3 and the smectite clay streaks act as a good seal for hydrocarbons in the quartzose sandstone pay zone.

Geophysical appraisal of fractured carbonate reservoirs: a case study of Abu Roash D Member, Abu Gharadig Field, Western Desert, Egypt

Geophysical appraisal of fractured carbonate reservoirs: a case study of Abu Roash D Member, Abu Gharadig Field, Western Desert, Egypt

3D Geological Modeling for Characterizing the Bahariya Formation and Abu Roash G Dolomite Unit, Horus Field, North Western Desert, Egypt

The Horus field is considered one of the most important hydrocarbon producers within the Alamein basin, Western Desert of Egypt. This area was affected by different tectonic movements throughout geological history. The re-evaluation and characterization of the Horus area, especially its main reservoirs of Lower Bahariya, middle Bahariya, upper Bahariya, and AR/G Dolomite units, because of its low production of oil tend (only 1100 BBD). Despite this, the Alamein basin is large and very rich in hydrocarbon. This study depends on the interpretation of thirty 2D seismic lines in addition to open-hole logs in the form of Resistivity, SP, GR, Density, Neutron, and Sonic logs for the five studied wells in order to delineate the subsurface structure and reservoir petrophysical characteristics of the Horus field. The data is tried to the formation tops and seismic lines by using synthetic seismograms. The main surfaces were mapped to proceed with the further static modeling. The work flow of the 3D geological modeling in the Horus area for characterization of the Bahariya Formation and AR/G Dolomite Unit. The processes that were carried out during the construction of the geological structure in the study area respectively, fault modeling, pillar gridding, skeleton grid, horizon modeling, zonation, and layering, and then distributed the facies and petrophysical parameters (Vsh, Sw and Φe) in this model. The main objective of this study is to delineate the seismic phenomena for structural, petrophysical, and facies modelling of the Bahariya Formation (Lower, Middle, and Upper) and AR/G Dolomite unit. The depth structure contour map on top of the Bahariya formation and the AR/G Dolomite unit indicated that the Horus area affected by NW-SE and WNW-ESE faults related to the lower Cretaceous. The study discussed the possibility of new structural traps that benefit in increasing the production of the area. All the results were consistent and confirmed that the Bahariya Formation and AR/G Dolomite are excellent reservoirs. Integrating multidisciplinary methods of seismic interpretation, static modeling, property modeling and well log analysis to design 3D structural and property models, helped predict new exploratory promising areas and structural traps to increase in production and the reserves in the study area, also decreasing the uncertainty of hydrocarbon exploration.

Geophysical assessment for the oil potentiality of the Abu Roash “G” reservoir in West Beni Suef Basin, Western Desert, Egypt

The current study evaluates the hydrocarbon potentiality of the sandstone intervals of the Abu Roash “G” Member in Beni Suef Basin, Egypt. This evaluation has been performed through seismic interpretation for thirty seismic profiles and petrophysical appraisal for Fayoum-2X well (Fayoum oil field) and Yusif-4X well (Yusif oil field). The seismic interpretation presented the prevalence of the Lower Cretaceous NW-SE normal faults followed and linked with a major Late Cretaceous ENE strike-slip fault affected the Beni Suef Basin. This strike-slip fault is accompanied by a significant flower structure and releasing bend in the middle part of the studied area. The entrapment styles in both Fayoum and Yusif oil fields are considered by the existence of NW-SE trending horst closures bounded by the NW-SE faults. The petrophysical analysis exhibits good reservoir quality for the sandstones of Abu Roash “G” Member in the examined fields with low shale volume (5–20%); high effective porosity (15–25%), relatively low water saturation (35–55%) and pay thickness varies between 14 ft and 16 ft. Although the Abu Roash “G” Member exhibits lateral facies changes across the Beni Suef Basin, this study highlights the hydrocarbon potentiality of its entire sandstones for further exploration and development purposes in both Fayoum and Yusif oil fields. Core-based petrophysical analysis and detailed sedimentological analyses for the reservoir zones within Abu Roash “G” Member at Beni Suef Basin are highly recommended to emphasize the effect of the lateral facies change on the reservoir properties along the whole basin which will affect the development plans. The integration of multiscale datasets which includes seismic, different types of well logs, core is giving a precise picture about the reservoir units. Altogether are figuring out the detailed composition of reservoir sedimentology and quality by using the core information, investigate the hydrocarbon potentiality using the well logging evaluation, deducing their trapping mechanism, and controlling structures using the seismic datasets and the spatial distribution is define based on the correlation between different wells, depositional and structural conditions.

Delineating the main structural outlines and the petrophysical properties of the Albian-upper Cretaceous Reservoirs using seismic and well log data, Shushan Basin, north Western Desert, Egypt

This study concerns with delineating and analyzing the subsurface structural setting of Khalda Oil Field at Shushan Basin as a key factor for evaluating the petrophysical properties and the deliverability of the Bahariya Formation. Shushan Basin is considered one of the most prospective basins in the Western Desert. The oil is trapped within a gentle seismically defined anticline that contains a series of coastal sandstone reservoirs interbedded with a neritic and tidal flat mudstone and a few carbonate interbeds of the Albian-Cenomanian Bahariya Formation forming multiple oil-bearing sandstone reservoirs. A set of borehole logging and seismic data were available, tied, processed, and mapped to delineate the predominant structures in the study area. Results show the implication of the NW–SE, NE–SW, and E–W gravity faulting on the Bahariya and the overlying Abu Roash formations. This set of gravity faults is attributed to the Mesozoic tensional stresses. The depth structure contour maps on the upper surfaces of the Lower and Upper Bahariya members reveal the presence of some NE–SW gravity faults that dissected the Khalda Field into some slightly tilted blocks, shallowing in depth to the south as deepening to the north. Besides, the study area has been affected later in the Jurassic by E–W gravity faults during the Atlantic Ocean opening. This faulting trend was changed later into the NE–SW direction as a result of the movement of North Africa against Laurasia. The petrophysical analysis indicated that the Lower Bahariya sandstone reservoir has a good reservoir quality (16 ≤ ∅ ≤ 25%, 53 ≤ Sw ≤ 59%, 6.0 ≤ Vsh ≤ 32.2%, and good net-pay thickness 18.0–38.0 ft). It is revealed that the drilled wells penetrating the crest of the anticline are prospective while that located in the anticline flanks are water-bearing recommending exploration away from the anticline flanks. By applying this workflow, it is possible to explore for the similar subsurface hydrocarbons-bearing sequences in the Western Desert and North Africa in future exploitation plans.

A new approach automatic separation of the Bouguer gravity anomaly, using a new concept for 2D-semi-inversion of the sphere-shaped model

ABSTRACT The present research represents a new, fast and easy-to-apply semi-inversion technique for the direct separation of the Bouguer gravity anomaly to its corresponding depths or thicknesses of the prior known rock formations from a borehole (as a control point). As well as the possibility of tracing these formations on the profile points to the Bouguer gravity map according to their density contrasts with basement rock. The proposed method is based on the fact that the sum of the gravitational effect at a point on the Earth’s surface is equal to the sum of the subsurface gravity effects arising from the points of masses of the causal bodies along the vertical line between the Earth’s surface and the basement rocks. In this method, two sedimentary basin models were built based on the distribution of densities from a prior known borehole. Assuming that the depths of the pointed tops of these rock formations can be replaced by the centres of sphere bodies (or point masses) as causative sources of gravitational effect and by the use of a simple algorithm, it was possible to calculate the depths of the rock formations and trace them on the profile, using a new concept called the zero-offset gravity measurement. In this concept, the measuring gravity is vertically above the centre of the sphere-shaped body as it represents the causative source, and its depths are equal to the radius of the sphere body. The present method was assessed on hypothetical models and synthetic data and applied to two real data in field cases which vary in geological and lithological aspects. The first assessed location is Abu Roash Dome Area, southwest Cairo, Egypt, and the second location is the Mors Salt Dome, North Jutland, Denmark.

Exploration of new hydrocarbon leads in the eastern flank of Abu Gharadig Basin, North Western Desert, Egypt

The present study aims to understand better the structural elements controlling the hydrocarbon potentiality and productivity for the upper Cretaceous reservoirs in the Eastern flank of the Abu Gharadig Basin in the Western Desert of Egypt. The major sandstone reservoirs in this area are found within Abu Roash “G” Member and Upper Bahariya Formation, characterized by lateral facies changes with major structure uncertainty and unleashed hydrocarbon potential. Therefore, we aimed to identify the lateral distribution of the studied reservoirs regionally in Abrar, Ferdaus, Ganna, Rawda, Sidra, and Rayan fields at the North Bahariya Concession and Aqsa and Yamma-SE fields at the East Bahariya Concession through integrated geological and geophysical studies for further exploration activities in this area. As a result, we produced regional depth contour maps covering most of the producing fields with the lateral distribution of hydrocarbon occurrences through the area. Moreover, the petrophysical parameter maps for the Middle and Lower Abu Roash “G” reservoirs, such as net pay thickness, shale volume, effective porosity, and hydrocarbon saturation are prepared to understand the hydrocarbon potentiality. This, in turn, allowed us to determine nine promising structural traps for future exploration with high certainty.

Hydraulic fracturing as unconventional production potential for the organic-rich carbonate reservoir rocks in the Abu El Gharadig Field, north western Desert (Egypt): Evidence from combined organic geochemical, petrophysical and bulk kinetics modeling results

This paper systematically analyzes the organic geochemical, petrophysical, and petrographical properties combined with bulk kinetics modeling of the Abu Roash (F) organic-rich carbonate rocks in the Abu El Gharadig Field. The Abu Roash (F) carbonate-rich samples exhibit high organic content with total organic matter (TOC) values up to 3.04 wt%, and mainly Type II kerogen, with a slight gradient to Type II/III and III kerogens, reaching good to very good oil generation potential. This finding of hydrogen-rich kerogen and oil generation potential was also demonstrated by the abundance of fluorescent alginite, amorphous organic matter (AOM), and bituminite organic matter (OM) as established via ultra violet (UV) light microscopy. The maturity indicators demonstrate that most of the examined Abu Roash (F) carbonate-rich samples from the studied wells, with a deep burial depth of more than 3000 m, are thermally mature, thus defining an early mature to moderate-mature stage. The kinetic models suggest that the Abu Roash (F) carbonate-rich rocks in the deepest burial depth, with calculated vitrinite reflectance (%VRo) values in the range of 0.72–0.83 %, have reached kerogen transformation ratio (TR) in the range of 10–55 %, indicating a high probability of oil production. This finding is confirmed by the presence of the oil crossover in these rocks with an oil saturation index (OSI) of more than 100 mg HC/ g rock. The Abu Roash (F) organic-rich carbonates are intractable rocks as implied by low porosities (up to 2.33 %) and poor permeability in the range of 0.0017–0.0039 mD. The pores in these rocks have a wide range in size, including interparticle, fracture, and organic matter (OM) pores, as recognized in the thin section and scanning electron microscopy (SEM). The development of these pore types and their quality is mainly controlled by high mineralogical brittleness (i.e., carbonates) together with the high OM inputs. Based on the above characteristics, the Abu Roash (F) carbonate-rich rocks in the Abu El Gharadig Field are a candidate for unconventional tight oil reservoir potential, which typically require a form of hydraulic fracturing for possible oil production at deeper burial depths.

Oil biomarker signature and hydrocarbon prospectivity of Paleozoic versus Mesozoic source rocks in the Faghur–Sallum basins, Egypt's Western Desert

Exploration campaigns focusing on Paleozoic plays in the Egyptian north Western Desert Sallum and Faghur basins have been limited to date, and little has been done to investigate their hydrocarbon generation potential. A total of 284 shale, calcareous shale, coaly shale and siltstone side-wall core and cuttings samples, covering the rock succession that ranges from the Silurian Kohla Formation to the Turonian Abu Roash Formation were analyzed for source rock potential. In addition, eight reservoired Paleozoic–Mesozoic oil samples were geochemically analyzed. This paper systematically investigates (1) organic enrichment, hydrocarbon generation potential, and thermal maturity of Mesozoic as well as possible Paleozoic source rocks, and (2) composition and biomarker characteristics of crude oil samples in the study area from the far north Western Desert basins of Egypt.The Silurian Kohla and Basur and the Carboniferous Desouqy and Dhiffah siltstone and shale rock samples show overall poor and fair to good source rock potential for the Lower and Upper Cretaceous rock units, respectively. In contrast, high TOC (up to 4.83 wt%) and Rock-Eval S2 (up to 6.57 mg HC/g rock) for the Devonian Zeitoun Formation samples indicates fair to very good source potential. The Middle Jurassic Khatatba Formation samples, compared with the Devonian Zeitoun Formation or other rock units in the stratigraphic column of the study area, have the highest TOC (30.1 wt%) and the highest S2 (26.9 mg HC/g rock), indicating fair to excellent source rock potential. These high values of the Khatatba Formation are locally related to organic-rich coaly shales and calcareous shale intervals. The Rock-Eval results indicate an overall dominance of Type-III kerogen with strongly varying OI values. This highly gas-prone character for most samples was confirmed petrographically by abundant vitrinite phytoclasts and recycled organic matter. Coals and coaly shale facies from the Alam El Bueib and Khatatba formations that contain liptinitic materials may represent Type-III kerogens that are capable of generating gas with minor oil. Based on Rock-Eval Tmax and HI results, the Zeitoun and Khatatba samples range from early to peak oil window. This is consistent with the Ro measurements of the Paleozoic Zeitoun samples (0.65–1.02%) and the Middle Jurassic Khatatba samples (0.59–1.01%).The Faghur oils are light (35°–46° API gravity), belong to a single genetic family and are non-biodegraded based on wide-ranging n-alkanes. Abundant tricyclic diterpanes, C24 tetracyclic terpane, C27 Ts trisnorneohopane, diahopane, cyclohexanes, C29 steranes and rearranged steranes and low to very low gammacerane and extended hopanes are common molecular signatures of the analyzed light oil and condensate samples. These findings indicate a relatively oxic fluvio-deltaic environment for the corresponding clay-rich coaly shale and calcareous shale source rocks that contain predominantly higher land-plants with negligible algal/bacterial organic materials. Based on saturated- and aromatic-maturity parameters, the analyzed oils were inherited from peak–late mature source rock.

Petroleum generation modelling of the Middle‐Late Cretaceous sediments in the Abu Gharadig Field, Northwestern Desert, Egypt

The present work introduces an integral study concerning the Middle‐Late Cretaceous source rocks in Abu Gharadig (AG) Field utilizing source rock evaluation techniques and hydrocarbon generation modelling. The used methods include TOC%, Rock‐Eval pyrolysis, vitrinite reflectance (Ro%), and 1D basin modelling data. Our results show that most of the studied marine Middle‐Late Cretaceous intervals in AG Field are considerable as source rocks, excluding the Abu Roash A‐D members. The Kharita, Bahariya, and Abu Roash E & G intervals have mainly gas‐prone kerogen. The Abu Roash F and Khoman B members contain mixed kerogen type II/III with oil/gas‐prone generative potential. Khoman A member has marine type II kerogen with mainly oil‐ and minor gas‐prone generative potential. Among the Middle‐Late Cretaceous rock units, the Khoman Formation is either immature or early mature, whereas others are mature enough to generate hydrocarbons. The burial history models typify a high subsidence rate during the deposition of Kharita, Bahariya, and Abu Roash formations in response to the Tethyan rifting phase. The timing of the peak of oil generation window for the Abu Roash G interval is ranged as Late Oligocene‐Early Pliocene time. Moreover, the timing of the peak of oil generation for the Abu Roash F interval is ranged as Early Miocene‐Latest Miocene. Based on transformation ratios (TR), the Abu Roash F member demonstrates a limited hydrocarbon expulsion (25% > TR <50), whereas both Abu Roash G and Khoman B members can generate in‐situ hydrocarbon (TR ≤10%). Compiling data along the AG basin from previous works infers that there are spatial and temporal discrepancies in organics composition and thermal maturity of the Middle‐Late Cretaceous intervals. Changes in paleoclimate, eustatic, and basin tectonics can be considered as the primary drivers that triggered such spatiotemporal variation. Integrated approaches are needed to constrain the multi‐geospheric interactions of major Cretaceous anoxic events in the Northwestern Desert of Egypt, and to explore the driving forces on these organics‐accumulating events.

Petrophysical Evaluation and Hydrocarbon Potentialities of the Abu Roash C Member of the Abu Roash Formation, Badr El Din-3 and Badr El Din-15 Oil Fields, Abu Gharadig Basin, Northern Western Desert, Egypt

Petrophysical Evaluation and Hydrocarbon Potentialities of the Abu Roash C Member of the Abu Roash Formation, Badr El Din-3 and Badr El Din-15 Oil Fields, Abu Gharadig Basin, Northern Western Desert, Egypt

Reply to the discussion of Moustafa (2021) on Sayed et al. (2020) (Marine and Petroleum Geology, 17, 2020-104401)

Moustafa (2021) addressed four main comments in his discussion “On the structures of Abu Roash area and inverted basins of northern Egypt - Comments on “Surface expression of the Syrian Arc Kattaniya inverted basin in the Abu Roash area, northeast Western Desert, Egypt: Structural style and tectonic history” by Sayed et al. (2020)”. Two of these comments criticized the new structural mapping of Abu Roash outcrops and the proposed model for El Ghigiga-El-Hassana Folds based on the early geologic mapping of the Abu Roash area by Moustafa (1988). His other comments were concerning the NE-orientation and end of tectonic inversion of the extensional Jurassic -Lower Cretaceous basins in North Egypt including the Kattaniya basin. Except for two constructive memos on drafting errors in the regional geologic map of Abu Roash, the registered comments were inaccurate and can be refuted with the results of the comprehensive regional and integrated subsurface geologic mapping on the North Western Desert basins, the previous works of Moustafa and his collaborators and the figures included in his discussion as we will present in this reply. It was documented that the inversion time, intensity, and type (orthogonal versus oblique or compressional versus transpressional/transtensional) differ from one basin to another in the northern part of Egypt. The geologic structures of Abu Roash helped to define a transpressional (oblique) inversion tectonic model that started at the Santonian and ended by the Latest Senonian. This tectonic model represents the northeastern segment of the Kattaniya basin and does not generalize to the whole basin or other basins in North Egypt.

Taphonomy and its significant role in palaeoenvironmental reconstruction of the upper Turonian actaeonellid gastropod concentrations of Abu Roash, Western Desert, Egypt

Taphonomy and its significant role in palaeoenvironmental reconstruction of the upper Turonian actaeonellid gastropod concentrations of Abu Roash, Western Desert, Egypt

Effects of petrographic and diagenetic characteristics on reservoir quality of Late Cretaceous Abu Roash “G” Member, Abu Sennan area, Western Desert, Egypt

Effects of petrographic and diagenetic characteristics on reservoir quality of Late Cretaceous Abu Roash “G” Member, Abu Sennan area, Western Desert, Egypt

Source rock evaluation and petroleum system modeling of the East Beni Suef Basin, north Eastern Desert, Egypt

This study deals with the East Beni Suef Basin (Eastern Desert, Egypt) and aims to evaluate the source-generative potential, reconstruct the burial and thermal history, examine the most influential parameters on thermal maturity modeling, and improve on the models already published for the West Beni Suef to ultimately formulate a complete picture of the whole basin evolution. Source rock evaluation was carried out based on TOC, Rock-Eval pyrolysis, and visual kerogen petrography analyses. Three kerogen types (II, II/III, and III) are distinguished in the East Beni Suef Basin, where the Abu Roash “F” Member acts as the main source rock with good to excellent source potential, oil-prone mainly type II kerogen, and immature to marginal maturity levels. The burial history shows four depositional and erosional phases linked with the tectonic evolution of the basin. A hiatus (due to erosion or non-deposition) has occurred during the Late Eocene-Oligocene in the East Beni Suef Basin, while the West Beni Suef Basin has continued subsiding. Sedimentation began later (Middle to Late Albian) with lower rates in the East Beni Suef Basin compared with the West Beni Suef Basin (Early Albian). The Abu Roash “F” source rock exists in the early oil window with a present-day transformation ratio of about 19% and 21% in the East and West Beni Suef Basin, respectively, while the Lower Kharita source rock, which is only recorded in the West Beni Suef Basin, has reached the late oil window with a present-day transformation ratio of about 70%. The magnitude of erosion and heat flow have proportional and mutual effects on thermal maturity. We present three possible scenarios of basin modeling in the East Beni Suef Basin concerning the erosion from the Apollonia and Dabaa formations. Results of this work can serve as a basis for subsequent 2D and/or 3D basin modeling, which are highly recommended to further investigate the petroleum system evolution of the Beni Suef Basin.

Petrophysical Studies on Upper Bahariya and Abu Roash “G” ‎Reservoirs Using Well Logs in Karama Field, North Western ‎Desert, Egypt

Petrophysical Studies on Upper Bahariya and Abu Roash “G” ‎Reservoirs Using Well Logs in Karama Field, North Western ‎Desert, Egypt