Introduction

Producing commercial rates of hydrocarbons in the shale reservoirs cannot be achieved without hydraulic stimulation, so it is described as unconventional reservoirs. Shale is not a rock type rather than a term widely used to describe rocks, i.e., mudstones that contain extremely fine grains typically <4 microns in diameter (Passey et al. 2010). Shale could also contain different amount of silt size particles which are up to 62.5 microns. Conventional sandstone rocks are composed of sand grains which can vary from 62.5 to 2000 microns in diameter (Passey et al. 2010). Shale contains variety of mineral grains, e.g., clay, quartz, feldspar, and heavy minerals like pyrite (Passey et al. 2010). This mixture of minerals is more heterogeneous in mudstones compared to sandstones. Evaluation of a shale gas formation is necessary to have a productive and commercial play. The work carried out by Kundert and Mullen (2009) reported the key properties necessary to have productive shale gas play which are illustrated in Table 1.

Table 1 Essential and desirable property of a shale gas play (Kundert and Mullen 2009)
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The Western Desert constitutes approximately two-thirds of the surface area of Egypt. It has been subjected to different tectonic regimes since the Paleozoic, which resulted in the formation of many sedimentary basins and sub-basins, ridges, troughs, and platforms. The study of the Cretaceous rock in Egypt in general and in the northern part of the Western Desert in particular is interesting due to its high hydrocarbon potentiality. This area consists of a number of sedimentary basins that received a thick succession of Mesozoic sediments. Many workers such as Abdine and Deibis (1972), Meshref et al. (1980), Meshref (1982), Abu El-Naga (1984), Moussa (1986), Barakat et al. (1987), El Shaarawy and Haggag (1990), Fawzy and Dahi (1992), EGPC (1992), and Schlumberger (1984, 1995) studied the most important geologic characteristics of these sedimentary basins which included stratigraphy, facies distribution, and tectonic framework.

The studied well Betty-1 (BYX-1) is located between latitude 29° 40′ 08′′N and longitude 27° 26′ 45′′E, Qattara Depression, northern part of the Western Desert of Egypt, represented in Fig. 1.

Fig. 1
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Location of Betty-1 well

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In the north Western Desert, Alam El Bueib (AEB) Formation is one of the main conventional hydrocarbon-producing zones. It is mainly composed of fine to coarse clastic sediments which conformably overly the carbonates of Masajed Formation (Upper Jurassic) and conformably underlay the Alamein Dolomite (Fig. 2). In the studied well, Alam El Bueib Formation composed mainly of sandstone, siltstone, calcareous shale, limestone with some streaks of coal (Fig. 3). These facies reflect shallow marine environment of deposition (Ramadan et al. 2012 and Temraz et al. 2016).

Fig. 2
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Simplified stratigraphic column of the Western Desert, Egypt (modified after Schlumberger 1984, 1995)

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Fig. 3
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Lithofacies of Alam El Bueib Formation in the Betty-1 (BYX-1) well

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The sandstone within the Alam El Bueib Formation is the main conventional hydrocarbon-producing reservoir in the Western Desert and is studied by many authors such as El Nady (2013, 2015, and 2016), Ramadan et al. (2016), El Nady and Hakimi (2016), Eysa et al. (2016). They recognized that Alam El Bueib Formation is mature formation, derived from mixed organic sources, and has fair to good capability to generate gas. The present work aims to evaluate the shale within AEB through the interpretation of geochemical analysis data such as total carbon (TC), total sulfur (TS), total organic carbon (TOC), and Rock–Eval pyrolysis to highlight its potentiality to be a source rock or an unconventional reservoir.

Materials and methods

Nine shale core samples were collected from AEB Formation in Betty-1 (BYX-1) well. They were studied using LECO SC632 and Rock–Eval-6 pyrolysis techniques represented by different parameters.

Total organic carbon content (TOC) is used to assess the source rock quality. Approximately 200 mgs of homogenous pulverized rock sample was required. The samples were treated with hydrochloric acid (HCl) for about 12–24 h with intermittent stirring. When the dissolution of carbonates was observed to be complete (no effervescence with stirring or additional acid), the samples were washed several times using distilled water to remove any traces of HCl. The samples were dried to eliminate any moisture prior to analysis. Prepared samples were then combusted at ~1350 °C using LECO SC632 analyzer, and the amount of carbon dioxide (CO2) generated was measured using an infrared cell.

The pyrolysis analysis data obtained from Rock–Eval-6 analyzer, summarized as the “S1” and “S2”, are expressed in (mg/g of rock). “S3” peaks represent the quality of CO2 formed by pyrolysis of organic matter expressed in mg of CO2/g of rock. Tmax represented the temperature of maximum pyrolytic hydrocarbon generation; it is a useful parameter to evaluate the level of maturation for the studied samples. The “S2” and “S3” peaks values were normalized by the total organic carbon content (TOC wt%) in order to provide hydrogen index (HI = S2/TOC wt%) and oxygen index (OI = S3/TOC wt%). These parameters are used to indicate the kerogen type using the modified Van Krevelen type’s diagram (Espitalie et al. 1977). The analyses were performed at the Exploration Department of the Egyptian Petroleum Research Institute (EPRI), Cairo, Egypt.

Results and discussion

Organic richness

The organic carbon richness of the rock samples is expressed by the weight percent of total organic carbon content (TOC wt%). Peters and Casa (1994) reported that rocks containing <0.5% TOC are considered as poor source rocks. Between 0.5 and 1% TOC indicates fair source rock. TOC% value between 1 and 2% indicates good source rocks. TOC% values above 2% often indicate highly reducing environment with excellent source potential. In addition to the TOC content, the hydrocarbon potentiality has been also evaluated using S1 and S2. S1 from 0 to 0.5 and S2 from 1 to 2.5 are considered poor, S1 from 0.5 to 1 and S2 from 2.5 to 5 are fair, S1 from 1 to 2 and S2 from 5 to 10 are good, S1 from 2 to 4 and S2 from 10 to 20 are very good, and S1 > 4 and S2 > 20 are rated as excellent source rock. In the studied samples, the organic richness using TOC wt% ranges from 0.45 to 6.87 wt% (Table 2, Fig. 4a), indicating poor to excellent organic richness. Consequently, the hydrocarbon potential of the studied samples using S1 and S2 ranges from 0 to 0.36 and from 0 to 2.05 mg/g, respectively, which indicates poor source potential (Table 2, Fig. 4b).

Table 2 Geochemical analysis data of the studied samples
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Fig. 4
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Rock–Eval pyrolysis of Alam El Bueib Formation in the Betty-1 (BYX-1) well, Western Desert, Egypt

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Kerogen type

The pyrolysis data were used to evaluate the kerogen type of the studied samples utilizing the hydrogen index (HI) and oxygen index (OI) values. Waples (1985) used the hydrogen index values (HI) to differentiate between the types of organic matter. Kerogen with hydrogen indices above 600 mg/g usually consists of type I or type II kerogen and has excellent potential to generate oil. Kerogen with hydrogen indices between 300 and 600 mg/g contains a substantial amount of type II macerals and is considered to have good potential for generating oil and minor gas.

Kerogen with hydrogen indices between 150 and 300 mg/g contains type III kerogen more than type II and therefore is capable of generating mixed gas and oil but mainly gas. Hydrogen indices below about 150 mg/g indicate a potential source for generating gas (mainly type III kerogen). The hydrogen index (HI) of the studied samples ranges from 0 to 201 mg/g (Table 2, Fig. 5), which reflects type III/II kerogen, so it may be good source for generating mainly gas with minor amount of oil. This result is confirmed using Jackson et al. (1985) plot (Fig. 6).

Fig. 5
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Modified Van Krevelen type’s diagram showing kerogen type of the studied samples (Espitalie et al. 1977)

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Fig. 6
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Source rock characterization plot of HI versus TOC of the studied (Jackson et al. 1985)

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Maturation

In the present study, the thermal maturity level of the source rocks has been determined by studying the geochemical parameters as Rock–Eval-6 temperature pyrolysis “Tmax” and production index “PI”. Peters (1986), Bordenove et al. (1993), and Espitalie et al. (1977) reported that the organic matter is in immature stage when ‘‘Tmax” has a value below 435 °C, ‘”Ro%” <0.5 and “PI” <0.2. Oil generation from source rocks began at “Tmax” 435–465 °C, vitrinite reflectance “Ro%” between 0.5 and 1.35%, and production index “PI” between 0.2 and 0.4. On the other hand, gas generation from source rocks began at “Tmax” 470 °C, “Ro%” >1.35%, and production index “PI” >0.4. In the studied samples, the Tmax ranges from 285 to 444 °C, indicating immature to marginally mature samples (Table 2, Fig. 7a). The PI ranges from 0 to 1, representing oil and gas production in case of maturation (Table 2, Fig. 7b).

Fig. 7
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Maturation evaluation diagrams for the studied samples

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Conclusion

Sandstone within the AEB Formation forms the main conventional hydrocarbon-producing zone in the Western Desert, while the shale intervals within the AEB Formation can be candidate unconventional reservoirs. The organic richness of the studied shale samples using TOC wt% ranges from 0.45 to 6.87 wt%, indicating poor to excellent organic richness. S1 and S2 range from 0 to 0.36 to 0 to 2.05 mg/g, respectively, indicating poor source potential. The hydrogen index (HI) of the studied samples ranges from 0 to 201 mg/g with kerogen type III/II. So it may be good source for generating gas with minor amount of oil. In the studied samples, the temperature pyrolysis “Tmax” ranges from 285 to 444 °C, indicating immature to marginally mature rocks. On the other hand, production index “PI” ranges from 0 to 1, representing oil and gas production in case of maturation.