Introduction

Gebel el-Silsila is located south Edfu and north Kom Ombo, and it is about 65 km north of Aswan [24° 38.48`, 24° 39.05` N and 32° 55.75`, 32° 56.04` E], (Fig. 1). It seems as elevations of Nubian Sandstone (Temraz and Khallaf 2016) on West and East Banks of the Nile River. The Nubian Sandstone was studied by many authors (Nabawy et al. 2016; Temraz and Elnaggar 2016; Sarhan and Basal 2019). Quseir Formation represents a unit of the group previously called “Nubian Sandstone” (Hermina et al. 1989; Tawadros 2001). Quseir Formation is composed mainly of sandstones of very fine to medium grain sizes. These sandstones have sedimentary structures as cross-bedding which is tabular, occasionally planar and Late Campanian in age. The sandstone of Gebel el-Silsila was excavated for obtaining stones used in building purposes. The Nubian Sandstone sequence was deposited southwestern Egypt, where the cycles of marine regressions and transgressions and soil deposits interleaved with marine silty clay and alluvial plain sand with interbedded channel controlled its deposition. Nubian Sandstone has been studied in terms of depositional environment by many authors (Said 1962; Harms 1979; Ward and McDonald 1979; Klitzsch 1979; Bhattacharyya 1980; Mansour 1984). The typical Nubian Sandstone cycles represent continuously deltaic and fluvial changing depositional environments, Klitzsch (1984). Quartzose Nubia sandstone is a name that used by early workers close to Aswan involves five progressive lithofacies predominated by quartzose sandstone, Van Houten and Bhattacharyya (1979), where feldspars in the lower facies are lower than 5% and reach to 15% in the higher facies in the northern limits. The Nubian Sandstone outcrops of Cretaceous age in Kurusku plateau around Lake Nasser, southern Egypt, are subdivided into four formations: Abu Aggag Fm. (the oldest), Timsah Fm., Umm Brammily Fm. and Quseir Fm. (the youngest), EGPC/CONOCO-Coral (1987). Abu Aggag Fm. extends in North–South direction as a vast belt of even beds that covers Kurkur area and also east of Aswan. It is for the most part composed of fluvial stores cross-bedded, lenticular sand bodies, ripple-laminated and channel fills.

Fig. 1
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Location map of Gebel el-Silsila

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Timsah Fm. is outcropped in the southeastern Desert and consists essentially of fluviatile close shore marine and locally is eolian sandstone, fine to medium grain size, interbedded with soil and channel deposits. Umm Brammily Fm. is made mainly of fluviatile sandstone, changes to marine toward north direction. Quseir Fm. covers a broad region in north of Aswan direction, where its thickness is 280 m and reaches to 425 m in north direction. Quseir Fm. is mainly littoral shale of different colors, siltstone AND flaggy sandstone that contain blended marine and crisp water gastropods. Because Quseir Fm. is fair oil and gas source in adjacent area of Al Baraka oil field, Kom Ombo basin, El Nady et al. (2018), so this work is aimed at investigating the lithofacies and available flow zones of the studied samples of Quseir Fm. as a potential reservoir in the study area, using experimental relations of capillary pressure derived parameters in addition to porosity and permeability values. The capillary pressure is an important property that used to evaluate reservoir rocks through many parameters as pore size distribution, displacement pressure, height above water level, transition zone and also fluid saturations that rely on dimensions and the geometry of the pore space (Øren and Bakke 2003; Mousavi and Bryant 2012; Likos and Jaafar 2013; Torskaya 2014). Flow zones determination helps to know the potential reservoir capabilities and the expected production, of course with other parameters of interest.

The study area was not explored before for oil production purposes and perhaps this because it contains much of antiquities, so this work is considered an adding value in terms of reservoir evaluation to know more about the characteristics of the potential reservoir. It is possible to be allowed in future for oil exploration under certain conditions in this area, and then, this study and others become important and form a database for reservoir description or evaluation and this is another benefit would be gained from this work.

Methodology

Fourteen surface sandstone samples represent Quseir Fm. were obtained from Gebel el-Silsila. The petrographical properties through thin sections were investigated using a polarizing microscope. The mineral composition identification was conducted using X-ray diffraction, and scanning electron microscope was used for detection the morphology of the rock compositions. For carrying out the petrophysical measurements, the studied specimens plugged into cylindrical plugs of one-inch diameter sizes, where they cleaned using methanol to remove any salt remains and dried through a drying oven. Porosity was measured using both helium porosimeter of Heise Gauge type for grain volume determination and DEB-200 apparatus for measuring bulk volume parameter. Permeability measurements were taken using air permeameter. Cross-sectional area and length of the sample, flow rate and viscosity of the used fluid and differential pressure through the tested sample are parameters used to calculate the permeability value.

Results and discussion

Petrography

The present petrographic examination of Gebel el-Silsila sandstone was carried out to show facies type, the principle rock constituents, cement, pores, diagenesis and depositional environment. It found out that this sandstone represents quartz arenite facies. The terminology of the examined sandstone follows Williams et al. (1982), where unclean sandstones are those contain at least 10% argillaceous materials as quartz wacke and lithic wacke, whereas clean sandstones as arenites are free from argillaceous materials. Lowering the percent of argillaceous matter increases the degree of sandstone maturation as the feldspathic arenites, while quartz arenite represents complete mature case. The majority of the mature sandstones have more extended sedimentary history than that of the less mature rocks, where they often include cycles of erosion and deposition. Sand stones are rich in feldspar typically sourced from granitoid volcanic rocks or higher rank feldspathic gneisses or schists. The examined sandstone samples are mostly quartz arenite microfacies made of fine monocrystalline quartz grains, subangular, moderately sorted and cemented by authigenic kaolinite clay mineral. Sandstones always are grain-supported with point or elongate contacts and characterized by high-percent intergranular porosity as distinguished by blue color within the studied thin section. This arenite microfacies may points out to feldspathic arenite because of existence of feldspar in dissolved and fresh state. The dissolving of feldspar caused development of pore filling kaolinite clay mineral which may affect negatively the rock porosity and permeability to some degree (Fig. 2a, b). This arenite is considered a mature microfacies due to its mineralogy and texture. The existence of altered and fresh feldspars (Fig. 3a, b), subangular grains and high maturity nature, demonstrates that this sandstone obtained from granitoid high-grade feldspathic gneisses/schists or igneous rocks. The depositional condition of this microfacies may be fluvial environment due to the existence of straight and curved grooves on the quartz grain surfaces (Fig. 3b).

Fig. 2
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Photomicrograph of high-porosity quartz arenite, S#3, group (B), ϕ = 29.3%, K = 3578mD. a PPL, b SEM

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Fig. 3
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Photomicrograph of high-porosity quartz arenite with fresh and altered feldspar, S#15, group (A), ϕ = 28.8%, K = 257mD. a CN, b SEM

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XRD

XRD analysis of bulk mineral composition of sandstone samples (Fig. 4a, b) displays that they composed mainly of quartz (SiO2) with traces of kaolinite Al2Si2O5(OH)4 and orthoclase K(Al,Fe)Si2O8.

Fig. 4
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XRD graph displays bulk mineral composition of sandstone samples. a S#8, group (A), ϕ = 29.9%, K = 149mD. b: S#3, group (B), ϕ = 29.3%, K = 3578 mD

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Petrophysics

Petrographical description shows that all the studied samples are related to one lithofacies, but at the same time, two different petrophysical units can be differentiated (A and B), and this is shown through permeability–porosity correlation that displayed with sample numbers, (Fig. 5a). The values of porosity and permeability of the studied samples reflect very good reservoir properties, Levorsen (1967).

Fig. 5
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a Permeability (mD) versus porosity (%) b flow units differentiation using Winland flow lines

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Porosity and permeability can be used to characterize the reservoir quality to great extent, and many authors studied the relation between them (Tiab and Donaldson 2004; Díaz-Viera 2006; Erdely and Díaz-Viera 2009; Nabawy and Al-Azazi 2015). The parameter √k/ϕ (pore geometry factor) was selected to express the two previous properties together for plotting with other different petrophysical parameters for estimating the studied samples (Fig. 6a, b). Petrophysical evaluation for the studied samples was achieved using experimental correlations to calculate different reservoir parameters utilizing the results of porosity and permeability. These are r35, rthresh, rapex and reservoir quality index (RQI). The first one is r35 and calculated using the equation of Winland, Kolodzie (1980).

Fig. 6
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a Different pore throat values (μm) versus √k/ϕb RQI versus √k/ϕ

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$${\text{log}}r_{{{35}}} = 0.732 + 0.588{\text{log }}k_{{{\text{air}}}} {-} \, 0.864{\text{log}}\phi$$
(1)

where r35 = the pore radius equivalent to 35% saturation of mercury. Kair = sample permeability (mD). ϕ = sample porosity (%).

Winland displayed in field examples that r35 can be applied to describe stratigraphic traps of economical hydrocarbon accumulations. The previous conclusion confirmed by Pittman (1989), where r35 higher than 0.5 µm used to delineate the trap. According to Martin et al. (1997), and based on r35 values, the studied samples were separated into two groups (Fig. 5b) based on Winland lines using his equation, where macroport flow unit samples (group A) lie below 10-µm line and megaport flow unit samples (group B) lie above 10-µm line; hence, r35 tell us that group (B) has great potentiality for fluids production/injection relative to that of group (A).

Although Winland did not point out the reason that r35 gave the best correlation in his work, Pittman (1992), mentioned, this perhaps due to at this radius, the pore network is evolved to an effective pore system which dominates flow as described by Swanson (1981). Another petrophysical parameter that calculated according to Pittman (1992) is the pore aperture radius (rthresh) that refers to the threshold pressure and determined by (). It is the pressure at which mercury builds connected way through the sample.

$${\log}r_{{{\text{thresh}}}} = \, 0.{137 } + \, 0.{\text{479 log }}k_{{{\text{air}}}} {-} \, 0.{\text{143 log}}\phi$$
(2)

where rthresh = the pore radius equivalent to a threshold pressure, μm. Kair = sample permeability (mD). ϕ = sample porosity (%).

The results of (rthresh) displayed that samples of group (B) have higher values of (rthresh) relative to those of group (A), and (Fig. 6a), this confirms the high-quality properties of group (B) samples. An important reservoir parameter is determined by Swanson (1977), where he determined the position of the point on the mercury injection curve which clarifies a well-interconnected pore system across the rock, where this point refers to apex of the hyperbola of a log–log plot of capillary pressure and bulk volume mercury saturation by Swanson (1981); hence, pore radius (rapex) that corresponds to apex was calculated as follows according to Pittman (1992), (Fig. 6a):

$${\log}r_{{{\text{apex}}}} = \, - 0.{117 } + \, 0.{\text{475 log }}k_{{{\text{air}}}} {-} \, 0.0{\text{99 log}}\phi$$
(3)

where rapex = the pore radius apex of hyperbola of a log–log plot on the mercury injection curve. Kair = air permeability (mD). ϕ = porosity (%).

The results of (rapex) showed that (Fig. 6a) samples of the group (B) have higher (rapex) values relative to those of group (A), and this is agreed with (rthresh) results and confirms that the best rock quality is for group (B) samples. Also r35 is displayed again (Fig. 6a), to show the consistence between different pore throat concepts, where the higher values of r35 exist within group (B). The last rock parameter determined for the studied samples is RQI or reservoir quality index. This parameter was used (Amaefule et al. 1993) with the normalized porosity to separate the different flow units existing within a rock, where group (B) has the best RQI values (Fig. 6b).

All the results confirmed that the samples of the group (B) are better than those of group (A) in terms of reservoir properties, and this means that group (B) represents the best flow properties and hence the best performance for a the potential oil productive reservoir. Actually, pore throat size distribution is an important factor responsible for giving a reservoir its own capillary pressure, quality and performance. Although the two groups have very close porosity values, they have different pore throat size distributions. This difference leads to different capillary pressures characterizing the accompanying flow zones. The wide spaces pore size distribution has low capillary pressure and is characterized by largest pore throats, which means a permeable flow unit capable of producing petroleum or infiltrating injection fluids in an easy way that will affect positively oil recovery and the reverse is right in case of the narrow spaces pore size distribution. Thin sections photomicrograph (Fig. 7a, b) represents the two flow groups, where sample#8 of group (A) has the permeability equals 149 mD and sample#3 of group (B) has the permeability equals 3578 mD, although there is only 1.4% difference between them in porosity values. Figure 7b displays that sample#3 of group (B) has the widest pore spaces network characterized by largest pore throats comparing with those of sample#8 of group (A) (Fig. 7a). The different pore space networks were a strong factor behind the differentiation of the studied samples of Quseir Fm. into macroport and megaport flow units according to r35 values. The macroport flow unit has the narrower pore spaces network, as a result the relatively higher the capillary pressures hence the lower the values of permeability, r35, rthresh, rapex and RQI. The reverse is right in case of megaport flow unit that has the wider pore spaces system, and consequently, the lower the capillary pressures and the higher the values of permeability, r35, rthresh, rapex and RQI. The values of r35 tell us that Quseir Fm. as a potential reservoir would be able to produce tens of thousands and thousands of barrels of oil per day from megaport and macroport flow units, respectively, Martin et al. (1997). All petrophysical properties of the studied samples are displayed (Table 1), where the samples are arranged according to permeability increasing.

Fig. 7
figure 7

Photomicrograph (PPL) of high-porosity quartz arenite. a S#8 represents group (A), K = 149 mD & ϕ = 27.9%. b S#3 represents group (B), K = 3578 mD & ϕ = 29.3%

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Table 1 Petrophysical properties of the studied samples
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Conclusion

Surface sandstone samples of Quseir Fm. were collected from Gebel el-Silsila and subjected to petrographical and petrophysical investigation. The studied sandstones represent quartz arenite microfacies (feldspathic). The depositional environment of the studied sandstones is fluvial-marine to fluvial. The samples suffered post-depositional alteration as diagenesis (clay infiltration and original detrital grains disintegration), weathering, deterioration phenomena as erosion and voids existence due to dissolution and absence of bound materials. The mineralogical description indicated that quartz is the main constituent of sandstone in addition to kaolinite clay mineral as a cementing material. Petrophysical investigation showed that all the studied samples are porous and permeable but can be separated into two groups (A and B). The samples of two groups have close porosity values to great extent but with obvious different permeability values. The samples differentiation into macroport (group A) and megaport (group B) flow units is attributed to the dissimilar distribution of pore throats, perhaps as a result of uneven clay distribution within the two groups of samples. Different petrophysical parameters confirmed that Quseir Fm. has different flow properties where pore throat size distribution for group (B) is better than that of group (A). The best flow properties of group (B) reflect the best performance for the reservoir of interest in case of being oil productive. Someday, if the petroleum explorations in the studied area proved that the presence of complete oil system in terms of source rocks, traps and cap rocks, in addition to an enough thickness and lateral extension for the oil carrier beds, while megaport flow units are prevailing, then a high oil productivity would be expected from Quseir Fm.