Sedimentary facies analysis, seismic interpretation, and reservoir rock typing of the syn-rift Middle Jurassic reservoirs in Meleiha concession, north Western Desert, Egypt

The Middle Jurassic syn-rift sediments of the Khatatba Formation contain not only the principle source rock organofacies in the north Western Desert (NWD), but also several potential sandstone reservoir targets. However, controls on the reservoir quality of the Khatatba facies and spatiotemporal evolution of the reservoir rock types (RRTs) are still blurred. This study integrates seismic, wireline logs, and conventional core data from some wells in the Meleiha development lease in the NWD to investigate the petrophysical characteristics of the Khatatba reservoir facies, and determine the different RRTs. On seismic, Khatatba Formation consists of high reflectivity, continuous reflections displaying an upward decrease in seismic amplitude corresponding to a fining-upward clastic succession of fluvial–tidal facies. These facies display a large-scale pore system heterogeneity, thereby comprising three different RRTs. RRTI and RRTII rocks have a well-connected pore network dominated by capillary and super-capillary pores (> 10 µm), whereas sub-capillary pores (< 10 µm) are more common in RRTIII sediments. RRTI rocks consist of quartzose sandstones with a clean pore network (cement < 20%). The open pore system of RRTI allows a displacement of more than 80% of the pore water at entry pressure levels < 500 psi. Carbonate and clay components are more common in RRTIII rocks (average = 5.6% and 13%, respectively). These components adversely impact the pore system connectivity of RRTIII sediments. Fluvial channel sandstones host the principal fluid flow conduits where RRTI sandstones account for more than 95% of the reservoir flow capacity. The present study provides the first reservoir rock typing for the Khatatba clastic reservoir facies and highlights the link between depositional, compositional attributes and the spatial distribution of the different RRTs.


Introduction
Reservoir rock typing (RRT) represents an essential approach for an optimized reservoir management. RRT approach encompasses a subdivision of reservoir facies into geologically distinctive units with predictable storage and flow capacities (Gunter et al. 1997;Guo et al. 2007;Masalmeh et al. 2012;El Adl et al. 2021;Leila 2019;Leila et al. 2022a, b;Radwan et al. 2021Radwan et al. , 2022a. Therefore, a proper RRT should involve a full consideration for the initial depositional and diagenetic attributes, as well as their influence on the dynamic reservoir properties (Jooybari et al. 2010;Skalinski and Kenter 2014). Thus, depending solely on the conventional petrophysical measurements for RRT is unreliable. The initial step for accurate RRT should comprise a subdivision of the reservoir faces into distinctive units with specific geologically controlled petrophysical properties (static rock typing). This step is followed by a detailed analysis for the pore system characteristics and their impact on the fluid flow behavior within the reservoir facies (dynamic rock typing) (Skalinski and Kenter 2014;El Adl et al. 2021;Leila et al. 2023a, b;Elmahdy et al. 2023).
Initial depositional attributes often control the textural properties of the reservoir rocks (grain size and sorting) and thereby impact their original pore structure and geometry (e.g. Pittman 1992;Coskun et al. 1993). Additionally, the diagenetic processes (e.g. compaction, dissolution and cementation) commonly influence the pore connectivity, pore throat geometry, and therefore control both static and dynamic properties of the reservoir rocks (Houseknecht 1987;Pittman and Larese 1991;Coskun et al. 1993;Kim et al. 2007;Leila and Moscariello 2019). Accordingly, a detailed analysis of the reservoir sedimentary facies, their fabric, composition as well as deciphering the link between depositional and diagenetic attributes is essential to understand the pore system evolution, and hence predict the static and dynamic properties of the reservoir rock types (RRTs).
Western Desert province hosting approximately 26.6% of the entire proven Egyptian hydrocarbon reserves is considered one of the most petroliferous hydrocarbon regions in North Africa (AlSharhan and Abd El-Gawad 2008;Yasser et al. 2021;Hassan et al. 2022). Western Desert accounts for a 54.8%, 44.1% and 17.5% of the Egyptian oil, condensate, and gas daily production, respectively (Hassan et al. 2022). These reserves mostly occur in the rift basins of the north Western Desert (NWD) (e.g. Shushan, Abu El-Ghradig; Fig. 1). These basins host several active petroleum systems in their syn-and post-rift sedimentary successions (AlSharhan and Abd El-Gawad 2008; El Diasty 2015; Abdelwahhab et al. 2022;Leila et al. 2022a, c;El Matboly et al. 2022;Saleh et al. 2023).
The present study focuses on boreholes from the Meleiha development lease, which lies in the southeastern part of Shushan Basin (Fig. 1). Recent oil, condensate, and discoveries in Shushan Basin (e.g. Jasmin, Emry fields) confirm the hydrocarbon prospectivity of the basin. Syn-rift organicrich sediments of the Middle Jurassic Khatatba Formation represent the principle source for most oil and gas discoveries in Shushan Basin (Shalaby et al. 2011;Hassan et al. 2022;Leila et al. 2022a). The Khatatba organofacies charges multiple reservoir intervals within both syn-and post-rift successions (Dolson et al. 2001;AlSharhan and Abd El-Gawad 2008). Most studies about the NWD reservoirs were mainly focused on the post-rift Bahariya and late syn-rift Alam El Bueib formations (Kassab et al. 2019;Yasser et al. 2021;El Matboly et al. 2022). Leila et al (2022a) reported a wide variability in sedimentary facies within the Khatatba Formation where the potential sandstone reservoir intervals are associated with the progradational and aggradational sedimentary successions. However, a detailed rock typing for the Khatatba clastics facies based on a comprehensive understanding for the spatiotemporal evolution of their pore system characteristics is still lacking. Therefore, this study applies an integrated petrophysical and sedimentological approach as a proxy to investigate the geologically controlled static and dynamic characteristics of the syn-rift clastics of the Khatatba Formation in the study region.

Geologic setting
NWD comprises a number of coastal basins stretching along the Mediterranean passive margin (Fig. 1). These basins were developed during the Early Mesozoic rifting of Gondwana landmass and opening of the Neotethys Ocean (Garfunkel 2004;Bosworth and Tari 2020;Torfstein and Steinberg 2020). The pre-rift sedimentary succession constitutes a Paleozoic clastic facies resting unconformably above the pre-Cambrian basement (Fig. 2;Schlumberger 1995;Zein El-Din et al. 2001). Rifting initially took place during the Triassic and reached the peak by the Middle Jurassic (Dolson et al. 2001;Guiraud et al. 2005;Bosworth and Tari 2020). NWD basins were developed in a series of E-W, ENE-WSW, and NE-SW trending intracratonic half grabens with a dominant extensional fault patterns oriented NE-SW (Fig. 3). During Early Cretaceous, a major shift in the direction of the extension toward NE-SW took place, resulting in the development of complex fault patterns oriented NE-SW, NW-SE, and E-W (Dolson et al. 2001;Bosworth et al. 2008;Leila et al. 2022a).
The basin-fill stratigraphy of the NWD basins is similar and comprises three main tectono-stratigraphic units bounded by unconformity surfaces (Schlumberger 1995;Zein El-Din et al. 2001). The first unit comprises the Paleozoic clastic sequence of the continental and shallow marine Nubian sandstones and shales. The earliest Jurassic sediments consist of non-marine clastics of the Ras Qattara Formation that rest unconformably above the pre-rift Paleozoic facies (Fig. 2). Rift-related subsidence during Middle Jurassic triggered the accumulation of successive transgressive and regressive facies of the Khatatba Formation.
Khatatba Formation consists of deltaic and shallow marine sandstones, shales with interbedded coal seams (Keeley and Wallis 1991;Ayyad and Darwish 1996). Development of local depocenters near the major faults triggered the deposition of the Khatatba organic-rich facies, which act as the main source rock in the entire north Western Desert (Dolson et al. 2001;El Diasty 2015;Abdelwahhab et al. 2022;El Matbouly et al. 2022;Leila et al. 2022a). Episodic variation in fault offsets during the deposition of the Khatatba Formation caused a wide lateral and vertical facies variability, and accumulation of a complex pile of successive prograding and retrograding facies (Leila et al. 2022a). Successive episodes of thermal subsidence and stretching prevailed during the Late Jurassic allowed the deposition of shallow-water carbonates (Masajid Formation) conformably above the Khatatba clastics. Masajid carbonates are capped by the Cimmerian unconformity. The latter documents a widespread inversion phase coupled with tilting, partial erosion, and karstification of the Jurassic succession (Keeley et al. 1990;Keeley and Wallis 1991). This unconformity is paved by shallow marine mixed siliciclastic-carbonate facies of the Lower Cretaceous Alam El Bueib (AEB) Formation.
The post-rift unit includes the Upper Cretaceous continental and coastal marine clastics (Bahariya Formation), and the transgressive marine shales, carbonates (Abu Roash Formation). This transgressive sedimentation was terminated by the Late Cretaceous compression induced by the convergent movement between African and Eurasian plates, which lasted until the Late Eocene (Guiraud and Bosworth 1997;Bosworth et al. 2008). This was accompanied by a phase of tectonic inversion which developed several inverted structural patterns extending as fold belts across the whole NWD. Therefore, the Late Cretaceous Fig. 1 Location map of the study area in southern part of Shushan Basin, north Western Desert, Egypt (modified after Bayoumi 1996) 1 3 Abu Roash Formation is unconformably followed by thin sedimentary successions of mixed marine and non-marine Paleogene-Neogene facies (EGPC 1994;Dolson et al. 2001;Zein El-din et al. 2001).

Data and methods
The present study is based on a diverse subsurface dataset including 2D seismic, borehole logs, and conventional cores Generalized lithostratigraphic column of the study region illustrating the tectono-stratigraphic evolution of the Shushan basin-fill sedimentary succession (Schlumberger 1995;Wescott et al. 2011) from the Eastern part of Meleiha Concession, Shushan Basin in the NWD (Fig. 1). The seismic data comprises a grid of twenty 2D seismic profiles covering an area of approximately 67.16 km 2 . Seismic profiles were interpreted in order to define the main structural patterns in the study region. The procedure of seismic data interpretation starts with tying seismic to well data (Fig. 4). The stratigraphic horizons were then picked and mapped. The interpretation of top Khatatba was picked below the Masajid carbonate horizon which is characterized by its high reflectivity and strong positive Interpreted 2D seismic profile passing through the studied wells illustrating the main structural patterns affecting the study region (profile location A-B is illustrated in Fig. 1)   Fig. 4 Synthetic seismogram illustrating tying of seismic to well data by computing the reflectivity coefficient from density and sonic logs. The seismogram shows a good correlation between the studied stratigraphic horizons and well data amplitude (peak) (Fig. 4). A complete suite of wireline logs for the studied wells were utilized to define the hydrocarbon bearing pay zones within the studied Khatatba succession.

Sedimentary facies analysis
Analysis of sedimentary facies is based on a detailed sedimentological description of the available 63-ft-thick conventional core interval retrieved from the Middle Jurassic Khatatba sedimentary succession in Jasmin_002 well (12,262-12,325 ft). The analysis involved a sedimentological core description based on identification of the lithological characteristics and sedimentary structures. The different lithofacies were then grouped in sedimentary facies associations accumulated within specific depositional environments.

Petrography and microfacies analysis
A total of 26 thin sections were prepared from the conventional and side wall core plugs retrieved from the Khatatba clastic interval in Jasmin_002 and Jasmin_001X wells, respectively. The thin sections were prepared in Corex laboratories, Egypt. Prior to microscopic examination, the thin sections were stained with blue dye, potassium ferricyanide, Alizarin Red-S, and sodium cobalt nitrate for the identification of porosity, carbonate, and feldspars mineral phases, respectively (Houghton 1980). The thin sections were then studied under the plane polarized microscope to determine their modal composition as well as the relative abundance of each component using the standard point counting scheme of Dickinson (1970). Scanning electron microscopy (SEM) was performed on the gold-coated polished thin sections to identify the pore structure as well as the morphology and distribution of different pore-occluding cements. Microfacies analysis was performed based on the modal composition of each thin section as well as the relative abundance of different detrital and authigenic mineral phases (e.g. Blatt and Tracy 1996).

Wireline logging interpretation
The available wireline logs including radioactivity logs (gamma ray GR), acoustic logs (sonic DT), electrical resistivity logs (LLS, LLD) as well as neutron (NPHI), density (RHOB), and photo-electric factor (PEF) logs from Jasmin_002 well were utilized in this study. The wireline logs were analyzed and processed using Techlog software (TL.2015.3). Shale content in the Khatatba sandstones was computed using a single-log method (gamma ray), whereas the density-neutron combination was applied to calculate porosity values (Yasser et al. 2021;Abdelmaksoud and Radwan 2022;Radwan et al. 2022a, b;Radwan and Nabawy 2022). Based on the obtained shale volume values, water saturation (S w ) was deduced using Indonesian equation which is more appropriate for S w calculations in shale-rich reservoirs (Poupon and Leveaux 1971). Formation water resistivity (R w ) and cementation factor (m) values in the studied Khatatba sediments were deduced using Pickett plot (Pickett 1972). Hydrocarbon-bearing intervals were interpreted using theoretical cutoff values of 35% for shale volume (V sh ), 7% for effective porosity (∅ eff ), and 65% for water saturation (S w ).

Routine and special core analysis
Routine core analysis (RCA) involves the measurement of porosity, permeability, and grain density of 56 cylindrical core plugs retrieved from the Khatatba pay zone interval in Jasmin-002 well. RCA measurements were performed in Corex laboratories, Egypt, using helium gas expansion porosimeter and nitrogen permeameter for measuring the porosity (∅) and permeability (K), respectively. Prior to RCA measurements, the core plugs were cleaned with distilled water and dichloromethane to remove the drilling fluids and hydrocarbon residues. Porosity and permeability measurements were performed on clean dry plugs under an ambient pressure of 400 psi. According to Amaefule et al. (1993), the measured ∅-K values were utilized to investigate the reservoir performance, quality, and heterogeneity. Amaefule scheme involves the calculation of flow zone indicator (FZI in μm), reservoir quality index (RQI in μm), and normalized porosity index (NPI in decimals) as functions of porosity (∅, in decimals) and permeability (K, in millidarcy mD) as follows: Additionally, effective pore throat radius (R 35 ) values are calculated as function of the obtained ∅-K values for each plug sample. The R 35 was calculated to delineate the effect of pore sizes on the reservoir quality as follows Winland (1972): where R 35 represents the pore throat radius at 35% mercury saturation.
Special core analysis (SCA) was carried out on 5 samples in order to investigate their pore system characteristics (e.g. pore throat size geometry, distribution, and connectivity) (Rose and Bruce 1949;Swanson 1981; Wells and Amaefule 1985; Vavra et al. 1992). SCA involves the measurement of mercury injection capillary pressure (MICP) following the analytical procedure of Leverett (1941) and Vavra et al. (1992). The impact of incremental increase in confining pressure (from 400 up to 8000 psi) on ∅-K values was also investigated as follows: where PR ∅ and PR K are the reduction in pore size and permeability due to confining pressure. ∅ and K are the measured porosity and horizontal permeability values at ambient pressure (~ 400 psi), while ∅ 6000-8000 and K 6000-8000 represent the measured values at confining pressure levels of 6000 and 8000 psi.

Seismic interpretation
The boundary between syn-rift Masajid carbonate and the underlying Khatatba clastics is represented by a paramount shift in seismic polarity with an abrupt decrease in acoustic impedance. Top Khatatba Formation is characterized by an abrupt increase in seismic reflectivity (Figs. 3,4). The Khatatba seismic facies consists of parallel, continuous seismic reflections with high reflectivity and amplitude. The latter vary vertically and laterally in the study region. Khatatba seismic reflections display a lateral decrease in seismic amplitude toward the southwest direction where their configuration changes from a prograding, and well-bedded to a slightly chaotic typifying a lateral variation in depositional facies. The studied wells were drilled in order to target the well-bedded reflections which display an upward decrease in seismic amplitude. The depth to top of the Khatatba Formation varies greatly with a general dipping in the southwestern part of the study region (Fig. 5). Structural highs adjacent to the major faults form several four-dip way closure structures in the central and southeastern parts of the study region. The thickness of the Khatatba Formation increases northward where a maximum value of > 1800 ft is observed in the northwestern part of the study area ( Fig. 6).

Sedimentary lithofacies and facies associations
Seven sedimentary lithofacies were identified in the studied cored interval of the Khatatba Formation (Fig. 7). Massive mudstone (LF1) is represented by structureless thin beds of dark gray to black mudstone. LF1 is common at the base of the cored interval reaching a maximum thickness of ~ 0.5 ft (15 cm). In other parts, LF1 beds display a thickness of less than 5 cm. LF1 beds have a massive appearance and are slightly bioturbated with rootlets ( Fig. 7). Laminated mudstone (LF2) comprises medium to dark gray sharp-based, planar-, cross-laminated, and non-bioturbated mudstone beds. LF2 beds range in thickness from ~ 3 to 7 cm, and they are more common in the upper part of the cored interval. Pebbly sandstone (LF3) encompasses approximately 20% of the studied cored interval. LF3 sandstone beds are mainly structureless except an occasional occurrence of planar cross-stratifications. Beds of LF3 range in thickness from a few centimeters up to 1 m, and they are more frequent in the lower part of the cored interval where they occur in stacked in fining-upward patterns. LF3 beds often contain dark irregular stylolites (Fig. 7).
Massive sandstone (LF4) consists of light gray structureless beds. LF4 sediments are often associated with LF3 in the lower part of the cored interval. LF4 beds also display gradational bases and tops and range in thickness from several centimeters up to 2 m, thereby comprising more than 25% of the studied cored interval. Sedimentary structures and bioturbation are absent, however, irregular dark stylolites are frequently present. Cross-stratified sandstone lithofacies (LF5) consists of light gray, coarse-grained sandstones stacked in finning-up patterns which comprise ~ 40% of the investigated cored interval. LF5 beds are stratified with thin (~ 1-3 cm) tabular cross-beds sets. LF5 sandstone beds range in thickness from few centimeters up to several decimeters and are often associated with LF3 and LF4 sandstones (Fig. 7).
Heterolithic siltstone/mudstone lithofacies (LF6) is made of medium gray siltstones interlaminated with mudstones and very fine-grained sandstones. LF6 sediments are only present in the upper part of the cored interval. LF6 beds often display sharp bases and topes (Fig. 7). LF6 beds are thin (< 5 cm), and contain lenticular and flaser bedding with thin flat siltstone lenses interlaminated with mud drapes and ripple laminations. Soft sediment deformation structures (SSDS) are frequently observed in LF6 beds (Fig. 7). Laminated sandstone lithofacies (LF7) is localized in the uppermost part of the studied cored interval. LF7 sandstones consist of medium gray, fine-grained argillaceous sandstones cross-laminated with thin (< 1 cm) pinstripe laminae. LF7 beds range in thickness from 3 to 10 cm and are commonly associated with LF6 and LF5 sediments.
Based on the sedimentary characteristics of the different lithofacies and their vertical stacking patterns, several sedimentary facies associations were identified in the studied cored interval of Khatatba Formation. The studied intervals are dominated by fluvial facies at the base grading upward into tidally influenced sediments (Fig. 8). The base of the studied succession consists of fluvial facies made of overbank mudstones followed by fluvial channel-fill sandstones. The fluvial overbank facies (FA1) consists of alternated massive and laminated mudstone lithofacies (LF1, LF2). The mudstones are sparsely bioturbated by small root traces. These characteristics confirm the deposition of these mudstones in a continental, subaerial conditions likely in a floodplain environment as a channel overbank facies (e.g. Varejão et al. 2021; Leila et al. 2022a, b).
Fluvial channel sandstone bars (FA2) comprise amalgamated beds of pebbly (LF3), massive (LF4) and crossstratified sandstones (LF5). FA2 is erosionally-based, and the erosion surface is mantled by pebbly sandstone beds (Fig. 7). FA2 sandstones are stacked in a successive finningupward patterns where the pebbly sandstone lithofacies is often followed by interbedded massive and cross-stratified  Leila et al. 2022a, b). The gamma ray values of FA2 sandstones are generally low (20-30 API) and display successive bellshaped patterns. The sandstones are non-bioturbated with very low mud content. FA2 has a massive appearance where the sedimentary structures are only represented by tabular low-angle cross-beds sets in the cross-stratified sandstone lithofacies (LF5). Basal erosion surface, repeated cut and fill structures, and the fining-upward sandstone patterns confirm in-channel deposition of FA2 sandstones in a fluvial environment (Fig. 8). Moreover, the coarse-grained sandstones with very low mud content and absence of bioturbation suggest the deposition of FA2 sandstones by high energy fluvial channels (Miall 1977;Tucker 2001).
Tidal bars facies association (FA4) occurs at the uppermost part of the studied interval (Fig. 7). FA4 consists of interbedded medium and fine-grained laminated sandstones (LF7), heterolithic siltstone/mudstone, massive and laminated mudstone (LF1, LF2). Fine-grained massive and cross-stratified sandstones (LF4, LF5) are also present in the upper part of FA4. The lithofacies of FA4 display serrated gamma ray motifs reflecting a sharp variation in the sand/ mud ratio. Syneresis cracks, low-angle cross, and lenticular beddings as well as mud drapes are frequently present. These sedimentary features suggest deposition of FA4 during periods of slack water conditions. Common occurrence of mud drapes and lenticular beddings demonstrates the tidal influence on FA4 sedimentation. Additionally, the presence of syneresis cracks points to a subaqueous deposition with periodic variation in salinity ( Fig. 8; Nio and Yang 1991;Bhattacharya and Walker 1991;Leila and Moscariello 2019;El Adl et al. 2021;Leila et al. 2022a, b).
The interpreted fining-upward fluvial-tidal succession corresponds to the well-bedded seismic facies in the study region. The upward decrease in seismic amplitude and reflectivity coincides with the upward decrease in fluvial, and increase in tidal influence coupled with increase in the mud content.

Petrography and microfacies
The Khatatba sandstones are grain-supported with low content of matrix. Based on the modal composition and relative abundance of quartz, feldspars, and rock fragments, the Khatatba sandstones were classified as quartz arenite. The sandstones display an average composition of Q 97.8 F 1.9 L 0.25 (Fig. 9). They contain variable contents of authigenic mineral phases, and therefore, five sandstone microfacies have been observed.

Quartz arenite (MF1)
Quartz arenite is the most common microfacies in the studied Khatatba sandstones. The detrital framework grains of MF1 are dominated by rounded to sub-angular quartz grains (average = 74%) ( Table 1). Matrix content is very low, and MF1 consists mainly of quartz, while other detrital and authigenic mineral phases are relatively rare (Fig. 10a). Feldspars (average = 1.49%) are mainly K-feldspars. MF1 is moderately to strongly compacted where the grain-to-grain contacts are mainly sutured and concavo-convex. Syntaxial quartz overgrowth (Fig. 11a) and silica cement are the most common authigenic mineral phases in MF1 (average = 5.8%). Carbonate (mainly dolomite) and clay materials (mainly kaolinite) are also common authigenic mineral phases in MF1 (average = 2.75% and 9.1%, respectively). Large intergranular pores are observed and have good connectivity, and therefore, MF1 sandstones have a well-connected pore network (Fig. 10a).

Dolomitic quartz arenite (MF2)
MF2 sandstones comprise a carbonate-rich quartz arenite. MF2 consists of detrital quartz and carbonate cement. Quartz grains are slightly compacted with long and point grain-to-grain contacts. Quartz grains are angular to subrounded and are partly coated with clays. Feldspars are represented by slightly dissolved K-feldspars (Fig. 10b, c). Carbonate cements (average = 8.22%) are represented by emerging patches of pore-filling ferroan dolomite (Fig. 10b,  c). Quartz overgrowth and silica cement are also common (average = 2.89%). The intergranular pores are mainly filled with carbonate cement, and therefore, MF1 pore network is partly blocked where the size of most pore throats is smaller than that in MF1.

Quartz wacke (MF4)
MF4 sandstones consist of fine to medium-grained, wellsorted, sub-rounded quartz grains. Feldspars and rock fragments are rarely observed. The framework grains are coated with clays (Fig. 10f). Authigenic phases are mainly calcite (average = 3.17%), quartz overgrowth (average = 5), and pyrite (average = 3%) ( Table 1). No intergranular pores were observed as the clay matrix materials completely infill the intergranular volume (Fig. 10f). Clays in MF4 occur as massive, loose aggregates and occasionally form thin coatings around the detrital framework grains. Clays also form thin lamina distributed parallel to the detrital quartz grains (clay cutans). Such distribution of clays points to their dominant detrital origin where the syndepositional suspended clays were preferentially settled in the pore spaces during the deposition (e.g. De Ros et al. 1994; Leila and Moscariello 2019).

Wireline logging results
The cored interval of the Khatatba Formation in Jasmin_002 well displays a notable upward increase in gamma ray values consistent with the upward transition from fluvial to tidal environment. The fluvial channel sandstone bars at the base have shale volume values < 20%. On the other hand, the overbank and abandoned fluvial channel facies display the highest shale volume values ~ 60% (Fig. 12). Movable hydrocarbons preferentially occur in the fluvial channel sandstone bars displaying the highest values of effective porosity > 10% (Fig. 12). This is correlated with a high-amplitude seismic peak corresponding to the top reservoir interval (Fig. 4). Similarly, the calculated permeability decreases upward with highest values ~ 100 mD observed in the fluvial channel and tidal bars. Water saturation increases upward where the greatest water saturation and lowest hydrocarbon saturation values are, respectively, observed in the overbank and abandoned fluvial channel facies. The prominent separation Fig. 9 Quartz-feldspars-lithic fragments (QFL) ternary plot shows the modal classification of the Khatatba sandstones (interpretation fields from Blatt and Tracy 1996) between shallow and deep resistivity logs in the fluvial channel and tidal bar facies reveals the presence of movable hydrocarbons within the Khatatba pay zone where the hydrocarbon saturation reaches up to 79%. Thus, the pay zone thickness and connectivity are largely dependent on the vertical distribution and architecture of sedimentary facies and reservoir rock types (RRTs).
The neutron-density cross-plot reveals the dominant sandstone matrix composition of the Khatatba sediments (Fig. 13). Notably, the samples of fluvial channel sandstone bars are plotted on and above the sandstone line confirming their clean quartzose composition with minimal contents of clays and carbonate phases. The upward deviation from the sandstone line is mostly attributed to the occurrence of movable hydrocarbons.

Pore system of the Khatatba sediments
The petrophysical properties and pore system characteristics vary greatly among the studied Khatatba sedimentary facies (Table 2). This aligns with the petrographic observation which demonstrated a heterogeneous pore system ranging from a well-connected intergranular network in the quartz arenite microfacies "MF1" to a tight pore system with no visual intergranular pores in quartz wacke microfacies "MF4." The measured RCA data show elevated values of horizontal permeability in the fluvial channel bars (average = 250 mD). The fluvial channel bars sandstones have permeability values tenfold greater than those in other sedimentary facies. Helium porosity values are also greater in fluvial channel bars sandstones than in the other sedimentary facies. However, the average porosity values in the Khatatba sedimentary facies vary in a narrow range from 9.04 to 14.06%. Thus, the wide variation in permeability among the studied sedimentary facies is related to variation in pore structure and geometry rather than the pore volume.
The reservoir quality index (RQI) values confirm a good reservoir quality for the fluvial channel bars sandstones with average RQI ~ 1 µm, whereas the average RQI values in the other sedimentary facies are less than 0.5 µm. Similarly, flow zone indicator (FZI) typifies occurrence of excellent fluid flow zones only in the fluvial channel bars (average > 5 µm). Additionally, pore throat radius (R 35 ) values greater than 10 µm are restricted to the fluvial channel bars sandstones, while the other sedimentary facies display average R 35 values < 4 µm ( Table 2).
Porosity-horizontal permeability cross-plot demonstrates a wide variation in the pore system network among the studied sedimentary facies. Sandstones of the fluvial channel bars have high porosity and permeability, where the latter increases with increasing porosity values which are mostly above 15% typifying a pore system dominated by well-connected pore channel network (Fig. 14a). Other sedimentary Table 1 Petrographic modal composition of the Khatatba sandstone microfacies facies, for example, the abandoned fluvial channel facies, display a flat porosity-permeability curve suggesting the abundance of isolated pores and a tight pore system. The well-connected pore network of the fluvial channel bars sandstones is also dominated by pore channels with large pore throats (Fig. 14b). Thus, the pore system of the fluvial

Reservoir rock typing
The studied Khatatba sedimentary facies have been grouped in three different reservoir rock types (RRTs) with variable petrophysical and sedimentological characteristics (Fig. 15a,  b). RRTI consists mainly of fluvial channel bars sandstones having reservoir quality index (RQI) values greater than 1 µm and flow zone indicator (FZI) values above 5 µm (Fig. 15a). RRTI rocks have the best flow properties among all the studied Khatatba facies and are classified as hydraulic flow units HFU5 and HFU6 with FZI values ranging from 5 to 15 µm (Fig. 15a). RRTII sediments include some intervals of the fluvial channel bars facies with fair reservoir characteristics and RQI values in the range of 0.5 µm and 1 µm. RRTII sandstones have also fair hydraulic flow properties with FZI values in the range of 2.5 µm and 5 µm. Therefore, RRTII sediments are classified as HFU4 with fair hydraulic flow characteristics but good storage properties. We hypothesize that the variation in petrophysical properties between RRTI and RRTII sediments is linked to the evolution of their pore structure and network. RRTIII includes all the other sedimentary facies having poor reservoir quality and fluid flow characteristics with average RQI and FZI values of 0.5 µm and 2.5 µm, respectively (Fig. 15a). RRTIII sediments display variable flow capacities and are classified as HFU1, HFU2, and HFU3 (Fig. 15b). The interpreted RRTs are clustered according to their pore throat radius values (Fig. 16). RRTI sandstones contain large, very well-connected pores with the highest pore throat radius values greater than 10 µm. The large pore throat radii connect the intergranular pores of RRTI, and therefore, no dead ends were observed where the intergranular pore system is dominated by connected, wide pore channel network. The pore throat radius values decrease progressively from RRTI to RRTIII, and the content of dead-end porosity increases in the pore system from RRTI to RRTIII. Notably, RRTII rocks have abundant dead ends; however, some connected pores are still present in the pore system. On the other hand, no connected pores have been observed in RRTIII rocks, and their pore system contains only scattered dead ends. The occurrence of stylolites in RRTII sandstones, which reflect a possible pressure solution, may explain their tighter pore system than that in RRTI rocks. On the other hand, abundance of clay lamiae and mud drapes which may act as permeability barriers explains the poor reservoir quality of RRTIII facies (Fig. 16).
The mercury injection capillary pressure (MICP) results reveal a wide variation in the pore system characteristics   of the Khatatba RRTs. Capillary pressure versus water saturation cross-plot clearly separates the three interpreted RRTs reflecting the paramount control of their lithological and petrophysical parameters on the entry pressure and hydrocarbon-water displacement. A progressive decrease in water saturation with increasing capillary pressure has been observed in all the Khatatba rock types (Fig. 17a). RRTI sandstones display flat curves parallel to the X-axis from 100% to less than 20% typifying that more than 80% of the pore water can be displaced at low entry pressure levels < 500 psi. On the other hand, RRTII and RRTIII sediments display steeper curves than that in RRTI where in RRTIII less than 50% of the pore water would be displaced at pressure levels < 500 psi. Additionally, the capillary entry pressure increases progressively from RRTI to RRTIII, and the irreducible water saturation values decrease from RRTIII to RRTI. Notably, irreducible water saturation values of less than 20% are only observed in RRTI rocks. On the mercury injection capillary pressure "MICP" versus mercury saturation cross-plot (Fig. 17b), greatest volume of mercury up to 80% would intrude the pore system of RRTI rocks at capillary pressure levels less than 100 psi. Furthermore, the capillary entry pressure values in RRTI sandstones are twofold greater than those in RRTII and RRTIII sediments. Such variation in the volume of intruded mercury reflects the abundance of dead ends and irreducible water in RRTII and RRTIII sediments. The MICP curves versus water and mercury saturations demonstrate that the pore system connectivity and pore geometry, structure, and network differ significantly in the studied RRTs. However, the best pore system properties for optimized reservoir performance are observed in RRTI rocks.
The measured pore throat radius values and their distribution reveal that the RRTI sandstones display a unimodal pore throat size distribution (PTSD) with one maxima observed in the range of 10 µm and 100 µm (Fig. 18a). Such distribution aligns with the dominance of mega-and super-capillary pores in RRTI sediments, while a bimodal distribution of pore throats has been observed in RRTII and RRTIII rocks with two maxima in the range of macropores and mesopores. Notably, sub-capillary pores/micropores (< 0.1 µm) are more abundant in the pore system of RRTII and RRTIII than in RRTI where the micropores represent less than 5% of the pore system. The pore throat size distribution versus Fig. 16 Pore throat radius (R 35 ) versus reservoir quality index (RQI) cross-plot illustrates the variation in pore system characteristics in the Khatatba reservoir rock types. Core photographs and thin sections highlight wide variations in sediment composition and microscale pore network among the Khatatba reservoir rock types Fig. 17 Mercury injection capillary pressure versus water saturation (A) and mercury saturation (B) demonstrating the variation in pore system properties of the Khatatba reservoir rock types mercury saturation highlights the prominent variation in the mechanism of mercury intrusion in the Khatatba RRTs (Fig. 18b). The presence of capillary and super-capillary pores (> 10 µm) in RRTI facies results in a quick displacement of pore water where more than 80% of the pore water would be displaced by mercury. On the other hand, mercury would only displace 60% of the pore water in RRTII and RRTIII rocks due to the absence of super-capillary pores.

Compositional controls on reservoir performance
Primary (rock texture and detrital mineralogy) and secondary (authigenic mineralogy) compositional attributes often induce large-scale heterogeneities on the reservoir quality and pore system characteristics (e.g. Pittman and Larese 1991;Houseknecht and Ross 1992;Pittman 1992;Ehrenberg 1993;Tournier et al. 2010). Several studies have demonstrated that some specific compositional attributes (e.g. clays) can accelerate the pore volume reduction and pore throat blockage during compaction (Houseknecht 1987;Wilson and Stanton 1994), while the dominance of some mineral phases such as quartz and scattered carbonate cement often supports the facies-framework against mechanical compaction and pore network reduction (Leila and Moscariello 2018;Leila and Moscariello 2019;El Adl et al. 2021;Leila and Mohamed 2020).
A wide heterogeneity in the reservoir characteristics has been observed in the studied Khatatba facies. A prominent variation in pore system characteristics is correlated with variation in sedimentary facies (Fig. 19). Some sedimentary facies are enriched in specific mineral phases which influence their pore system properties. For example, clays are more abundant in the overbank and abandoned channel facies, which are classified as RRTII and RRTIII rocks with tight pore system. Furthermore, quartz content is high in the fluvial channel bars sandstones which are mostly classified as RRTI.
All the reservoir quality parameters (RQI, FZI, and R 35 ) decrease from RRTI to RRTIII. This is consistent with an increase in the clay volume and decrease in quartz content (Fig. 19). RRTI sandstones have the lowest content of silica cement (< 10%), while the content of silica cement increases in the other RRTs (Fig. 20a). Notably, sandstones with silica cement content greater than 10% often exhibit permeability values less than 100 mD. Silica represents the most porosity-destructive cement in siliciclastic reservoirs as it often blocks the entire intergranular volume (Ehrenberg 1993;Leila et al. 2021). Thus, the emergence of silica cement in sandstones is commonly accompanied by a significant decrease in the pore throat size, and hence the pore system connectivity. In RRTI sandstones, the wide range of permeability values (1000-100 mD) is clearly attributed to the relative abundance of silica cement (Fig. 20a). This explains the tight pore system in the stylolite-rich sandstones (Fig. 16).
Analogue to silica cement, a progressive decrease in permeability with increasing carbonate cement content has been observed in all the studied Khatatba RRTs (Fig. 20b). However, the impact of carbonate cement on the fluid flow capacity is more pronounced in RRTIII sandstones. RRTI and RRTII sandstones with carbonate cement contents < 2% display permeability values greater than 100 mD. Furthermore, the carbonate-rich samples with cement contents > 5% often have permeability values less than 50 mD. Detrital and authigenic clays display a composite trend with horizontal permeability where the latter initially increases with increasing the clay content before decreasing progressively as clay content increases above a threshold of 10% (Fig. 20c). Similar trends have been described in several publications due to the impact of clay coatings in inhibiting silica cementation, thereby allowing the preservation of the primary intergranular porosity and flow efficiency (e.g. Pittman 1992;Bloch et al. 2002;Tournier et al. 2010;Leila 2019;Leila et al. 2022a, b), while the decreasing trend is most likely attributed to the emergence of thick clay coatings in the intergranular pores, thereby blocking the pore system connectivity, thus creating a pore network dominated by scattered dead ends. Comparing permeability versus silica cement and clay content curves demonstrates the impact of clay coatings on silica cement authigenesis. Additionally, emergence of scattered dead ends in the sandstone samples with abundant clay contents is consistent with the proposed detrimental impact of clays on the sandstone pore system (Figs. 10e, f, 15). This aligns with capillary pressure results, which confirmed the abundance of meso-and micropores in the clay-rich RRTIII facies.
The content of pyrite has a minimal influence on the permeability of the Khatatba RRTs where no distinctive trend is observed in all the studied samples (Fig. 20d). Analogue to the other mineral phases, sandstones with the highest permeability values have the lowest content of pyrite. Therefore, we hypothesize that the sandstones with the highest permeability values display a clean intergranular volume with minimal contents of silica cement, carbonate, clays and pyrite. Clay-and pseudomatrix-rich sandstones are more prone to porosity reduction due to mechanical compaction (Ehrenberg 1990;Midtbø et al. 2000;El Adl et al. 2021;Nabawy et al. 2023). This has been confirmed by the porosity and permeability versus confining pressure curves which demonstrated a significant reduction in the pore volume and pore network connectivity as pressure increases from 400 to 7000 psi (Fig. 21a, b). RRTI rocks display a slightly flat ∅-K versus confining pressure curves signifying a mild pore volume reduction and blockage of the pore throat due to compaction. On the other hand, RRTII and RRTIII sandstones display steeper curves relative to RRTI rocks with an approximate 10% reduction in the pore volume as pressure increases from 400 to 7000 psi. The variation in confining pressure-porosity and permeability curves among the Khatatba RRTs is attributed to their mineralogical composition where the quartzose framework of the RRTI sandstones would resist compaction, and hence pore volume reduction. On the other hand, ductile materials (e.g. clays, pseudomatrix) abundant in RRTII and RRTIII rocks are often squeezed between the rigid framework grains, thereby blocking the intergranular volume and pore throats. Thus, the compositional attributes also control the ability of RRTs to preserved their initial pore system connectivity up on compaction, and hence their reservoir potentiality in the deeply buried stratigraphic successions.  Depositional controls: prediction of the best reservoir facies Initial depositional attributes influencing the eodiagenetic pathways induce paramount controls on the pore system evolution (e.g. De Ros et al. 1994;Kim et al. 2007;Leila and Moscariello 2019;Leila et al. 2023a, b). Early emergence of specific diagenetic phases is restricted to specific depositional environments. For example, the pre-compactional carbonate and glauconite authigenesis was reported in shallow marine sandstones (e.g. Worden and Morad 2003;Kim et al. 2007;Leila and Moscariello 2019). Moreover, some clay mineral phases and pseudomatrix materials tend to concentrate in the low-energy fluvio-deltaic and estuarine facies (De Ros et al. 1994;El Adl et al. 2021;Leila et al. 2021). Petrophysical characteristics and reservoir quality of the Khatatba RRTs show a significant reservoir heterogeneity where the distribution of the RRTs is largely influenced by the depositional facies (Fig. 19). Previous studies reported a wide variation in the Khatatba Formation facies along the major faults where repeated variation in fault offset triggers accumulation of successive progradational and aggradational-retrogradational sedimentary successions (Leila et al. 2022a). Local structural highs and lows are reported in the study region (Fig. 5); however, the Khatatba facies displays a gradual thickening norward without any prominent variation in thickness along the faults (Fig. 6). Thus, a lateral variation in sedimentary facies architecture along the fault patterns is not obvious in the study region. However, interpreted seismic profiles demonstrated a lateral variation in seismic facies where the well-bedded seismic reflections in the study region change into chaotic facies southward (Fig. 3), thereby a southward decrease in the reservoir quality is assumed.
On the stratigraphic modified Lorenz plot (SMLP), RRTIII sediments display a flat curve parallel to the storage capacity axis (Fig. 22a). This behavior is due to abundance of micro-capillary pores in the RRTIII sediments, which are able only to store fluids without obvious contribution to the flow capacity. RRTIII sediments are often restricted to the overbank, tidal bars and abandoned channel facies. RRTII sandstones display a steeper SMLP curve compared with RRTIII sandstones where the former contribute to more than 30% of the Khatatba reservoir storage but accounts only for 15% of the reservoir flow capacity. This is mostly attributed to the occurrence of sub-capillary and capillary pores in RRTII sandstones. Therefore, RRTIII and RRTII sandstones are, respectively, classified as fluid flow barriers and baffle zones. This is consistent with the MICP data, and the classification of RRTII and RRTIII facies as HFU1-HFU4 units.
RRTI sandstones display a steep SMLP curve where they contribute to 40% of the Khatatba reservoir storage and more than 80% of its flow capacity (Fig. 22a). Excellent flow capacity of RRTI rocks is largely due to their well-connected pore system consisting of super-capillary pores. Notably, better reservoir quality sandstones are often associated with pebbly and massive sandstones lithofacies. Additionally, the transition from these lithofacies to the laminated sandstone or heterolithic siltstone/mudstone lithofacies results in a change in the reservoir rock type from RRTI into RRTII or RRTIII (Fig. 22b). Moreover, some lithofacies such as crossstratified sandstones and laminated sandstones are relatively enriched in clays when associated with a specific sedimentary facies (tidal bars and abandoned channel facies). Therefore, the transition from fluvial channel bars into any other sedimentary facies would result in a shift in the reservoir quality from RRTI to RRTII and RRTIII. Thus, a reduction in the hydrodynamic energy from fluvial channel to overbank or abandoned channel, as well as increasing the marine influence, and transition into tidally influenced environment would result in decreasing the reservoir quality. Hence, any variation in the depositional context and sedimentary facies is usually accompanied by a progressive shift in the reservoir quality and reservoir rock type.

Conclusions
• Seismic-stratigraphic, sedimentological, and petrophysical approaches were integrated to identify the different reservoir rock types (RRTs) encountered in the Middle Jurassic Khatatba Formation and decipher the controls on the evolution of their pore system. • Khatatba cored interval displays a fining-upward succession where the sedimentary facies changes from fluvial to tidally influenced sediments. The reservoir quality decreases upward where the best reservoir facies coincide with the fluvial channel sand bars. • Three RRTs were identified in the Khatatba cores. The pore system characteristics of each RRT are largely influenced by both depositional and compositional attributes. • Fluvial channel bars facies mainly constitute clean quartz arenite sandstones having a well-connected intergranular pore system and contain super-capillary pores (> 10 µm). These sandstones have the best flow properties (HFU5 and HFU6) and preliminary classified as RRTI which contributes to more than 95% of the Khatatba reservoir flow capacity. • RRTII, RRTIII rocks are common in the abandoned channel, overbank, and tidal bars facies. These rock contain abundant pseudomatrix materials, clay, and carbonate cements. RRTII, RRTIII pore system is dominated by sub-capillary pores with high irreducible water saturation content (~ 40%). • Mineralogical and lithofacies composition of RRTI rocks characterized by a minimal content of clays and pseu-domatrix materials prompted the preservation of their initial pore network even at great depths (> 12,000 ft). • The best reservoir facies within the Khatatba sediments are associated with the high energy fluvial regimes where the RRTs with excellent petrophysical characteristics exist in the fluvial channel bars, which host the main fluid flow conduits.
Funding Open access funding provided by The Science, Technology & Innovation Funding Authority (STDF) in cooperation with The Egyptian Knowledge Bank (EKB). The authors declare that they did not receive any funding to perform this work.

Conflict of interest
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