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.


Introduction
Clay minerals' distribution in reservoir rocks presents key challenges to exploration geologists because of their detrimental effect on the reservoir quality (e.g., Loucks et al. 1984;Ehrenberg 1990;Walderhaug et al. 2012;El Adl et al. 2021). However, recent studies highlighted the beneficial impact of specific clay mineral phases on the reservoir quality such as chlorite coating in deeply buried reservoirs through preventing further diagenetic attributes such as quartz from destructing the primary porosity (e.g., Pittman 1992;Leila et al. 2018;Leila 2019). Therefore, the occurrence of clays and shale beds in the reservoir would complicate the determination and evaluation of petrophysical parameters. Accordingly, analyzing the type, content, and distribution mode of clay minerals in the reservoir is elemental for reservoir evaluation and management (Ghassem 2018;Spooner 2018). In Clastics reservoirs, clays occur in three distribution types comprising dispersed, laminated, and structural. Each type varies in its impact on the reservoir quality (Wei et al. 2014;Ghassem and Roozmeh 2017).
The Cenomanian Clastics including the Bahariya and Abu Roash G sediments present the most prolific reservoirs in the north Western Desert (EGPC 1992;Dolson et al. 2001;Kassab et al. 2019;Yasser et al. 2021). These sediments Responsible Editor: François Roure

Geologic setting
The north Western Desert of Egypt constitutes several petroliferous rift basins that were developed during the Mesozoic breakup of the Gondwana landmass and the birth of the southern Neo-Tethys (Garfunkel 1998(Garfunkel , 2004Guiraud et al. 2005;Tassy et al. 2015;Leila et al. 2022a). These basins are mostly aligned in a series of E-W, NE-SW, and ENE-WSW oriented half grabens ( Fig. 1; Guiraud et al. 2005;Moustafa 2008;Bevan and Moustafa 2012). Besides the studied Abu Gharadig (AG) basin, they include Natrun, Shushan, and Matruh as well as Faghur-Siwa basins. The AG represents an intracratonic E-W-trending basin in the central northern part of the Western Desert (Fig. 1). The basin was actively subsiding since the Paleozoic with a down warping initiated in Carboniferous and continued until Early Cretaceous (Kitchka et al. 2015;El Gazzar et al. 2016;Sarhan 2017;El Mahdy et al. 2019). Similar to all the northern basins of the Western Desert, Abu Gharadig is a part of the extensive Tethys passive margin that evolved during the Late Triassic-Jurassic crustal break-up of the Gondwana landmass (Guiraud 1998;Bosworth et al. 1999;Stampfli et al. 2001;Garfunkel 2004). Rift-related subsidence during the Jurassic permitted the accumulation of this syn-rift siliciclastics and mixed siliciclastics carbonate facies in all the north Western Desert basins (Ras Qattara, Khtataba and Masajid) (Fig. 2). The subsurface data from all the Western Desert rift basins suggest prevailing NW-SE extension tectonics during the initial opening phase (Longacre et al. 2007;Bevan and Moustafa 2012;. This is confirmed on seismic profiles by a dominant pattern of NE-SW extensional faults (Fig. 3a, b). By the beginning of the Early Cretaceous, a clockwise rotation of the extension direction prevailed toward the NE-SW, thus resulting in a generation of complex fault patterns with continuous subsidence and deposition of Clastics-dominated Cretaceous sediments in Abu Gharadig Basin (Dolson et al. 2001;Bosworth et al. 2008;Ibrahim et al. 2009;Mousa et al. 2011).
The Jurassic-Cretaceous extensional phase was followed by a compressional episode during the Late Cretaceous and continued until the end of the Eocene due to the convergence between Africa and Eurasia (Guiraud and Bosworth 1997;Dolson et al. 2001;Guiraud et al. 2005;Bosworth et al. 2008;Bevan and Moustafa 2012). This convergence plate movement resulted in the structural inversions of the north Western Desert rift basins including Abu Gharadig and therefore inverted structural patterns extended as a foldbelt across the whole north Western Desert (e.g. Moustafa and Khalil 1990;Guiraud and Bosworth 1997). The studied seismic profiles document these inverted structural patterns which form excellent hydrocarbon traps (Fig. 3a, b). The Upper Cretaceous sedimentary successions consist mainly of mixed siliciclastics carbonate facies marked by fluvial to shallow-marine Kharita sediments at the base grading upward into shallow marine Clastics of the Bahariya Formation. These Clastics are overlaid by transgressive carbonate of the Abu Roash Formation (Abu Roash "G" Member). The Bahariya Formation and AR/G Member petrophysically have been studied by numerous authors such as Temraz et al. (2009)

Seismic data
The available seismic data include 2D seismic profiles covering an area of approximately 70 km 2 in the GPY field. Interpretation of seismic profiles included (b) (a) Fig. 1 A map illustrating the location of the GPY oil field wells in Abu Gharadig Basin, north Western Desert, Egypt (a) as well as the investigated 2D seismic lines (b) picking the main seismic-stratigraphic horizons (Bahariya, AR/G) and identification of the cross-cutting faults based on the discontinuities in seismic reflections (Abdel-Fattah et al. 2018;Henaish et al. 2022).
Moreover, structural contour maps of the top studied horizons were constructed on the picked surfaces. Different seismic facies within the studied horizons were interpreted based on their variation in some  (Schlumberger 1995;Wescott et al. 2011) specific seismic characteristics (e.g., seismic reflectivity, continuity, and amplitude) following the standard seismic stratigraphic procedure of Mitchum et al. (1977). Seismic data analysis allowed the identification of the structural patterns that affect the different stratigraphic horizons. Variation in seismic characteristics (amplitude, reflectivity) was compared with well-data after performing seismic well-tie and permitted understanding variation in seismic facies with sedimentary patterns. b a Fig. 3 Interpreted seismic profiles along strike (a) and dip (b) illustrating the dominant extensional structural patterns in the study region (Henaish et al. 2022)

Wireline logging interpretation
Complete wireline log suites from four wells (GPY-2, GPY-3, GPY-9, and GPY-11) were utilized in this study. The available well logs comprise natural and spectral gamma ray "GR," "SGR," caliper "CAL," spontaneous potential "SP," compensated sonic "DT," formation density compensated logs "RHOB," and photoelectric factor effect (PEF). Additionally, neutron "CNL," deep Laterolog "LLD," shallow Laterolog "LLS," and micro spherical logs "MSFL" were also available for the studied wells. Prior to performing the calculations, adjustments were performed to reduce the influence of several factors on the well-log data, including lithology, mud weight, borehole temperature, and formation temperature. The petrophysical properties of the geological intervals of the Bahariya Formation and AR/G Member that may include highly promising hydrocarbon zones have been identified using the adjusted data. The well log analysis followed by potential reservoir petrophysical evaluation has been performed in a successive and interrelated sequence as follows: determination of formation temperature, determination of mud filtrate resistivity, and determination of shale volume (Vsh) (gamma-ray and neutron-density methods). Finally, the Calculation of the total (∅t) and effective (∅e) porosity depended on the using of neutron-density method (Fig. 4).
The available well logs were analyzed using Schlumberger Techlog 2015 software and the outputs were interpreted and presented in vertical lithosaturation crossplot and isoparametric distribution maps. Different matrix cross plots were applied to differentiate between the main reservoir rock-forming lithologies and minerals such as sandstone, shales, and carbonate lithologies. In complex lithology, the (M-N) cross-plot or three-dimensional (3-D) cross-plot is often called litho-porosity cross-plots. The M and N parameters are derived using the readings of the neutron, sonic, and density logs together (Bruke et al. 1969;Schlumberger 1974). M and N are deduced as follows: where: Δtfl is the transit time of the saturation fluid, ρb density log reading, and ρfl fluid density; (ΦNfl) is the hydrogen index of the fluid and (ΦN) the neutron log reading. For saline mud Δtfl = 184 µ sec/ft, ρfl = 1.1 gm/cc, and ΦNfl = 100%.
Thin-bed analysis (TBA) is a suitable way to prove how various combinations of logs would respond to porosity, lithology, and shale type and content. Shale mineralogy and distribution were interpreted using a spectral gamma ray log. Thomas-Stieber analysis was utilized for the evaluation of A flow chart illustrates the sequence of different analytical approaches that were followed in this study for wireline logging data interpretation thin-bedded shaly-sand reservoirs, whose bed thicknesses are too thin to be resolved by traditional tools (Thomas and Stieber 1975). The parameters are derived using the total shale volume (Vsh) and total porosity (∅t) of the shale determined using the gamma-ray and density logs. The shale and sand endpoints should be picked in different cross-plots. Thomas-Stieber method needs the total shale porosity and porosity of clean sand (∅ss = ∅max). According to the method, the volume of laminar shale can be calculated by this formula: Calculation of the volume of dispersed and structural shale can be obtained from these formulas (Thomas and Stieber 1975): Calculation of the total porosity (∅t) and effective porosity (∅e):

Seismic facies analysis
On seismic, the Bahariya Formation is characterized by vertically variable amplitude and frequency reflections. It comprises semi-parallel and discontinuous reflections. The Bahariya seismic reflections are partly chaotic and their amplitude decreases upward reflecting an upward variation in sedimentary facies and/or fluid content (Fig. 3a, b). On the other hand, AR/G seismic facies constitutes well-bedded, continuous, parallel, high amplitude, and reflectivity reflections. The AR/G seismic facies are vertically and laterally uniform in the study area reflecting its deposition during the same phase of sedimentation without significant variation either in lithology or fluid content (e.g., Mitchum et al. 1977;Leila 2019Leila , 2022b. The depth structure contour map on the top of the Bahariya Formation shows an irregular distribution pattern with local structural highs in the central and western part of the study region (Fig. 5a). The structural highs are bounded by faults from all directions forming a perfect four dip-way closure structure (Henaish et al. 2022).
A similar pattern was also observed in the depth structure contour map on the top of the AR/G where the four dipway closure structures also exist in the central and western part of the study area (Fig. 5b). This structure was formed contemporaneously with the late Cretaceous-Paleogene inversion phase due to the convergence between Africa and Eurasia (e.g., Mustafa and Khalil 1990;Guiraud and Bosworth 1997). This tectonic phase was likely responsible for the hydrocarbon trap formation in Abu Gharadig Basin.

Lithosaturation characteristics of Bahariya and AR/G sediments
The plotting of the caliper log with the bit size reveals that there is a huge washout in the four wells of the study area, which has a significant impact on the reading of the logs, particularly the neutron and density logs. We attempted to mitigate the impact of washout with applying all necessary correction on all the raw data before the final analysis. Based on vertical variation in lithological and petrophysical properties, the Bahariya Formation is identified into three different units. The lower Bahariya unit (B-3) is at the bottom, followed by the middle Bahariya unit (B-2), and the upper unit Bahariya unit (B-1) (Figs. 6, 7, 8, and 9). The B-3 unit consists mainly of sandstone and siltstone. The presence of carbonate minerals (limestone and dolomite) likely reflects their occurrence as pore-filling cement (e.g., Yasser et al. 2021). The occurrence of siderite, hematite, clay content, glauconite, and pyrite is indicated by low resistivity and high gamma-ray log readings (Mohamed et al. 2016). B-3 is characterized by an elevated shale volume due to the presence of siltstone. The highest effective porosity (∅e) and hydrocarbon saturation (S h ) values of 17% and 69% for B-3 in the GPY-2 well are reported between 2321 and 2324 m (Fig. 6). B-3 unit is comparatively sand-rich in GPY-3 with the highest ∅e and S h values of 43% and 83%, respectively (Fig. 7). Therefore, the highest net pay thickness is reported in GPY-3 well. On the other hand, B-3 unit is dominated by siltstone with thin sandstone interbeds in GPY-9 and GPY-11 wells and therefore display comparatively lower ∅e and S h values (Figs. 8 and 9). The B-2 unit is dominated by sandstone and siltstone with thin shale interbeds. In GPY-2 well, the highest ∅e and S h values are respectively 23% and 93% where hydrocarbon-bearing pay zones are observed in this unit between 2265-2277 m and 2295-2300. In GPY-3 well, the ∅e and S h values are comparatively lower (17%, and 64%, respectively) where the facies are more clay-rich. Moreover, in the GPY-9 well, the highest ∅e and S h values are 21% and 54%, respectively, where a 1-m thick streak of hydrocarbon pay zone is reported at 2309-2310 m. Similarly, GPY-11 well constitutes only a 1.5-m thick pay zone (2294-2295.5 m) in B-2 unit with average ∅e and S h values of 31% and 64%. The B-1 unit is composed primarily of carbonate (limestone and dolomite), shale, and sandstone. In the GPY-2 well, the greatest ∅e and Sh values of 37% and 65% are observed between 2226 and 2231.5 m which is the main pay zone in the B-1 unit. In GPY-3, the maximum ∅e and S h values are 17% and 64% in the 4-m thick pay zone identified between 2063 and 2067.5 m. The lowest value of S h is reported for B-1 unit in GPY-9 and GPY-11 wells where no pay zones were observed in B-1 unit in these wells.
AR/G Member consists mainly of shale, limestone, dolomite, and sandstone with a very low content of siltstone. AR/G Member has the maximum ∅e and Sh values of 37% and 60% in the GPY-2. Hydrocarbon-bearing pay zones within AR/G Member are only reported in the GPY-2 well. In the other wells, AR/G Member is dominated by calcareous shale beds with very low ∅e values < 10%. Therefore, reservoir intervals are completely absent in AR/G Member in most of the studied wells.

Petrophysical parameters distribution
The different petrophysical parameters deduced from wireline logging interpretation for the Bahariya Formation units (B-3, B-2, B-1) as well as AR/G Member were mapped to define lateral changes and distribution of the best reservoir facies ( Table 1). The mapped petrophysical parameters comprise shale volume (V sh ), effective porosity (∅ e ), movable hydrocarbon saturation (S hm ), and the net-pay thickness.
For the B-3 unit, the V sh increases northward with a maximum value of 25% in the GPY-9 well and decreases in the southwest direction with a minimum content of 12% in the GPY-3 well (Fig. 10a). The ∅e increases in the southwest direction with the highest effective porosity value of 27% in the GPY-9 well. It gradually decreases northeast with the lowest value of 13% in GPY-11 (Fig. 10a). The sediments of the B-3 unit are fully saturated with water in the eastern parts of the study area where the lowest content of movable hydrocarbon was reported (Fig. 10a). On the other hand, the movable hydrocarbon content increases in the northeastern and southwestern parts of the study region consistent with the occurrence of hydrocarbon pay zones in GPY-2 and GPY-3 wells. Figure 10b illustrates that the V sh of the B-2 unit increases in the northwest directions, recording a maximum value of 31% through the GPY-9 well. It decreases in the southwest direction, reflecting a minimum shale content of 5% in the GPY-3 well. The ∅ e recorded an overall increase in the south and east directions with the highest percentage of 32% in the GPY-11 well. It gains the lowest connected pore percent of 20% in GPY-2 (Fig. 10b). The S hm recorded a maximum saturation of 41% through the GPY-2 well in the northeastern parts. This saturation decreases toward the northwestern direction recording an average value of 18% in the GPY-9 well (Fig. 10b). Finally, the thickness of the net pays intervals of nearly 24 m was recorded in the GPY-2 well and decreases to reach 0.3 m at the GPY-9 well ( Table 1).
The V sh of the B-1 unit increased in the northeast and southwest directions, recording a maximum volume of 27% through the GPY-3 well. It decreases in the northwest direction, reflecting a minimum shale volume of 3% in the GPY-9 well (Fig. 10c). The ∅ e displays a general increase in the central part of the study region where the highest values of 32% are reported in GPY-9 and GPY-11wells. It gradually decreases in the southwest direction with the lowest connected pore percent of 17% in GPY-3 (Fig. 10c). The S hm recorded a maximum saturation of 37% through the GPY-2 well in the northeastern direction. This saturation decreases toward the northwestern direction recording 12% in the GPY-9 well (Fig. 10c). A maximum net pays interval of nearly 7.8 m was recorded in the GPY-2 well and it decreased to reach 0.5 m at the GPY-9 well (Table 1). The V sh of AR/G Member increased in the east direction, recording a maximum value of 36% through the GPY-11 well. It decreases in the north, southwest, and west directions, reflecting a minimum shale content of 31% in the GPY-2 well (Fig. 10d). The ∅e recorded a general increase in the northeast direction with the highest effective porosity of 31% in the GPY-2 well. It regularly decreases in the southwest direction with the lowest connected pore percent of 7% in GPY-3 (Fig. 10d). The S hm recorded a maximum saturation of 32% through GPY-2 well in the northeastern parts. This saturation decreases toward the northwestern direction recording an average value of 10% in the GPY-9 well (Fig. 10d). The maximum net pay intervals of nearly 5.3 m were recorded in the GPY-2 well and decrease to reach zero at GPY-9 and GPY-11 wells (Table 1). According to the distribution patterns of Cenomanian petrophysical characteristics, the GPY field's B-3 unit has a highly promising southwestern hydrocarbon potentiality, whereas the B-2, B-1 units, and AR/G Member all have northeastern high potentialities.

Reservoir lateral connectivity
Tracking both lateral and vertical variation in the architecture and distribution of reservoir sand bodies is crucial for hydrocarbon exploration and development strategies.
These variations are often dependent on the depositional setting which control the sedimentary stacking patterns (Posamentier and Allen 1999;Nabawy and El Sharawy 2015;Leila et al. 2022b). Stratigraphic architecture, sandbody geometry, and proportion of clay and fine materials are important factors to have an impact on reservoir facies connectivity (Tearpock and Bischke 1991;Bridge and Mackey 1993;Li et al. 2004;Colombera et al. 2016). The NE-SW stratigraphic cross-section passing through the studied wells shows wide variations in the thicknesses and lithological characteristics of the studied rock units (Fig. 11). For example, Bahariya unit 3 thickness in the southwest direction in GPY-3 well, however, the highest content of Bahariya unit 3 sand is observed in the northeastern part of the field where the thickness of Bahariya unit 3 (B-3) decreases. Despite the great thickness of Bahariya unit 3 in the GPY-3 well, the sand beds are thin, disconnected, and heterogeneous. The thickness of Bahariya unit 3 sandstone bodies is structurally rather than depositionally controlled. The inversion of the fault slipping during Late Cretaceous-Middle Eocene affected the NE-SW normal faults, which suffered positive structural inversion forming a symmetrical anticline with variated thickness distribution in the four Cenomanian units with the thicker interval on the hanging wall of these faults that extended throughout the study area of GPY oil field. The where the beginning of limestone deposition. The B-1 unit and AR/G Member are represented by deep marine environments. These fluctuating sediments affected greatly the petrophysical properties of the four Cenomanian horizons, especially the shale quantity, distribution as well as the porosity, permeability, and hydrocarbon potentiality.

Reservoir matrix analysis
The neutron-density cross-plot of the B-3 unit reflects in dominant sandstone composition with limestone and shale interbeds (Fig. 12). The sandstone porosity ranges from 20 to 25%. Limestone likely occurs as calcareous cement and bed intercalations in the sandstones (Abdel Maksoud et al. 2019;Yasser et al. 2021;Leila et al. 2022a, b). The matrix composition of Bahariya unit-2 (B-2) indicates a comparatively lower sand content than that in B-3. B-3 matrix is rather dominated by dolomite and limestone with sub-ordinate contents of siltstone and shale (Fig. 12). Bahariya-1 unit (B-1) matrix consists mainly of limestone with porosity values of approximately 15%. Similar to B-1, the matrix composition of AR/G is dominated by limestone and shale with rare sandstone and siltstone contents (Fig. 12). Matrix analysis of the Cenomanian sedimentary facies in GPY Field reveals an upward increase in the shale and carbonate content and a decrease in the sand content confirming a transgressive depositional phase that prevailed in the study region during Late Cenomanian. This transgressive phase was likely accompanied by a prominent change in the depositional facies from fluvial-dominated (B-3) at the base to shallow and deep-marine deposition at the top (B-3 and AR/G) (Leila et al. 2022b). M-N cross-plot allows the identification of the dominant mineralogical composition of the studied Cenomanian rock units. The plot shows that B-3 unit sediments are  Fig. 15 Gamma ray-density and neutron-density cross plots of the sandstone of a B-3 unit, b B-2 unit, c B-1 unit, and d Abu Roash G member in GPY oil vicinity in Abu Sennan Concession, Western Desert, Egypt preliminary and consist of quartz and calcite with subordinate content of clay minerals (Fig. 13). B-3 sediments also contain significant volumes of secondary pores evidenced by shifting of the B-3 points upwards. Secondary porosity in B-3 sandstones suggests a prominent dissolution of the calcite cement and/or the calcareous clasts (e.g., Radwan et al. 2022). B-2 sediments contain less content of quartz and their mineralogical composition is dominated by calcite and clay minerals. Secondary porosity is less common in B-2 compared with B-3 typifying a mild extent of dissolution and the carbonate materials mostly occur as concretions in the sand and thin-bed intercalations. Shale is the main lithology in the B-1 unit and its sediments mainly consist of clay minerals and carbonate. Similarly, AR/G facies are dominated by calcite, dolomite, and clay minerals, and the effect of secondary porosity is observed in some wells. Secondary porosity is mostly attributed to the dissolution of carbonate components.
The photoelectric factor (PEF) versus bulk density (RHOB) cross plot confirms the dominant quartzose sandstone composition of the B-3 unit and the mixed siliciclastics-carbonate composition of the other units (Fig. 14a). Such upward transitions from Clastics-dominated sedimentation in B-3 into mixed siliciclastics-carbonate upward confirm a major change in the depositional environment during the Cenomanian with increasing the marine influence during Late Cenomanian (e.g. , Hantar 1990;Helba and Bakry 1996;Alsharhan and Abd El-Gawad 2008;Leila et al. 2022b).

Clay mineral identification
The occurrence of clay minerals in the reservoir is often crucial for reservoir management as they induce a major influence on the reservoir storage and flow capacities (e.g., Walderhaug et al. 2012;Leila and Mohamed 2020;El Adl et al. 2021). Moreover, physical and chemical characteristics as well as the performance of conventional sandstone, carbonate, and unconventional shale are significantly influenced by the presence of clay minerals (e.g., Schon 2011;Jiang 2012;Chou et al. 2014). Migration of fines and swelling of specific clay mineral phases are the primary reasons for formation damage measured as permeability impairment (Civan 2000(Civan , 2007Galal et al. 2016). Moreover, formation damage is a catastrophic operational and financial issue during the many stages of oil and gas recovery from reservoirs, including drilling, production, hydraulic fracturing, and workover operations. According to Amaefule et al. (1993), formation is particularly prone to occur in poorly lithified and densely packed formations that contain significant amounts of authigenic, pore-filling clays that are susceptible to aqueous solutions, such as kaolinite, illite, smectite, chlorite, and mixes-layer clay minerals. Accordingly, accurate identification of the dominant clay phase as well as prediction of their distribution patterns is crucial for optimal reservoir management. The PEF versus Th/K cross-plot reflects the clay composition in the studied sediments (Schlumberger 1985;Schon 2011). Most of the studied sediments have Th/K values less than 10 typifying that montmorillonite is the most dominant clay phase in the studied Cenomanian sediments (Fig. 14b). Potassium (K) and thorium (Th) contents confirm that clay minerals in the studied sediments are mainly represented by montmorillonite and mixed layer clays with subordinate contents of kaolinite and illite. The mixed clay phases mainly consist of mixed illite/smectite (Fig. 14c, d).
Thin bed analysis (TBA) was utilized to identify different forms of shale associated with sandstone reservoirs of the Bahariya Formation and Abu Roash G Member (Farrag et al. 2021). The Thomas-Stieber model was initially created to resolve the problem of laminated shaly sand sequences in the older South Louisiana fields. Shale exists in three different forms in the sand: dispersed, laminated, and structural (Ali et al. 2016;Schlumberger 2011;Willis et al. 2017). The gamma-ray and density porosity log values were plotted to determine the sand fraction, the sand porosity, and the shale distribution. Figure 15a typifies that the sandstone of the B-3 unit is marked by laminated shale and rare dispersed shale. Nevertheless, the B-2 and the B-1 units are marked by laminate shale only (Fig. 15b, c). On the other hand, A/R G is marked by laminated shale and rare structural shale (Fig. 15d).

Conclusions
The Cenomanian sediments host the most prolific reservoir targets in the north Western Desert. In the studied GPY oil field, the Cenomanian rock units were subdivided into four main units with variable lithologic and petrophysical characteristics. These units comprise Bahariya units (B-3, B-2, B-1) as well as the AR/G member. B-3 unit consists mainly of sandstone, siltstone, and little shale streaks with the presence of carbonate as cement and bed intercalation. The sand content decreases upward from B-3 to B-1 with an upward increase in the silt, shale, and carbonate content. AR/G consists preliminary of carbonate with little content of quartz and silicate minerals.
The depositional facies change upward from Clastics facies in B-3 to mixed siliciclastics carbonate B-1, B-2, and carbonate in AR/G. B-3 has the best reservoir characteristics and hosts the best reservoir conduits and the highest contents of hydrocarbon saturation. The reservoir conduits are preferentially distributed in the southern part of the study region where the B-3 units have the highest values of porosity and lowest content of shale volume. The shale mineralogy consists mainly of smectite and mixed-layer illite/ smectite and therefore induces a detrimental impact on the reservoir quality. Consequently, the facies of the lowest content of clays have the best reservoir quality. Therefore, the reservoir quality of the Cenomanian rock units decreases upward from B-3 to AR/G. Furthermore, the occurrence of shale streaks would be an effective seal for the hydrocarbon because of its dominant smectite content resulting in a very effective seal capacity.