Introduction

Yemen has several rift basin systems, including onshore and offshore basins (Fig. 1A), which are related to the breakup of Gondwanaland during Mesozoic Era (i.e., Late Jurassic–Early Cretaceous ages) and the Cenozoic Era (i.e., Oligocene–Miocene ages) (Redfern and Jones 1995; Beydoun et al. 1998; Bosence 1997; As-Saruri et al. 2010). The most conventional petroleum exploration activities were focused on the onshore basins, including Sabatayn and Sayun–Masilah (e.g., Mills 1992; King et al. 2003; Hakimi et al. 2010, 2011; Alaug et al. 2011; Hakimi and Abdullah 2013a, b; Al-Areeq et al. 2018).

Fig. 1
figure 1

A Map of the Sabatyen Basin, including the Al-Jawf, Marib, and Hajar grabens, and the Shabwah depression (modified after Al-Areeq et al. 2018), and B location map of the five exploration wells studied in the Al-Jawf sub-basin, northwestern Sabatayn Basin

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The Al-Jawf sub-basin is situated in the northwestern part of the Sabatayn Basin (Fig. 1A) and classified as traditionally explored region for conventional petroleum resources, where drilled wells are limited (Fig. 1B) and the data collected are scarce. However, the hydrocarbon exploration in the Al-Jawf sub-basin has been underway since 1981, and the drilling results range from oil staining to gas appearance in several exploratory wells (SPT 1994). This suggests the presence of several proven source rocks and encourages further petroleum geochemistry studies.

The Al-Jawf sub-basin has promising source rock units for petroleum exploration, including Late Jurassic successions (SPT 1994). The organic-rich intervals within the Oxfordian-Tithonian Arwa, Meem, and Safer units and their characteristics and capacity for hydrocarbon generation potential have received unprecedented attention from numerous scientific researchers (e.g., Hakimi et al. 2019a, b, c, d; Al Areeq and Albaroot 2019). The standard geochemical studies concluded that the Oxfordian to Kimmeridgian Arwa and Meem shale units are likely to be good oil and gas source rocks, containing types II and III kerogen, with minor type IV kerogen (e.g., Hakimi et al. 2019a, b, c). On the other hand, the Tithonian Safer shales are found to bituminous shales with up to 13% TOC and classified as type II-S kerogen oil-prone (e.g., Hakimi et al. 2019d).

Although Hakimi et al. (2019a, b, c, d) discussed the characteristics of organic matter in Late Jurassic organic-rich shales from central, southern, and northern parts in the Al-Jawf region, overall, there is a lack of work concerning organic-rich sediments within the Late Jurassic successions, particularly those of the Tithonian age. Accordingly, the present study investigates the organic-rich shale sediments of the Late Jurassic (Tithonian), particularly those of the Lam Member from several exploration wells in the Al-Jawf exploration region, NW Yemen (Fig. 1B). These shales have not been yet reported on the source rock evaluation. In doing so, we reported the geochemical and petrological characteristics of 115 shale samples of the Tithonian Lam Member collected from four exploration wells, Dahmar Ali-01, Kamaran-01, Start Test AK-01, and Start Test AL-01 in the Al-Jawf region (Fig. 1B) to determine the organic facies (quantitatively and qualitatively), thermal maturity, and evaluate the petroleum generation potential. In essence, this paper expands on knowledge with respect to exploring and exploiting petroleum in the Al-Jawf region.

Geological setting

The Sabatayn Basin is a continental rift formed during Late Jurassic to Early Cretaceous and is associated with the Mesozoic rift system (Redfern and Jones 1995; Beydoun et al. 1998; As-Saruri et al. 2010). The Mesozoic rift system has generated parallel normal faults and several structural elements, such as horsts and tilted fault blocks, which have provided excellent traps for hydrocarbon accumulation (Fig. 2). By the Late Jurassic, the Neo-Tethyan Ocean reached its maximum extent, and the Madagascar-India plates successfully rifted from the Africa-Arabia plates (Redfern and Jones 1995). In the Early Kimmeridgian time, the diachronous rifting began and propagated in the southeast direction, forming the Sabatayn Rift System such as the Al-Jawf, Marib, and Hajar grabens, and Shabwa depressions (Fig. 1A). Rifting ended from the Late Tithonian to lowermost Berriasian (SPT 1994; Beydoun et al. 1998; As-Saruri et al. 2010).

Fig. 2
figure 2

A Structural map of the Sabatyen and Say’un-Masila Basins formed during the Late Jurassic to Early Cretaceous, including the exploration wells in the Al-Jawf sub-basin, northwestern Sabatayn Basin, and B a seismic section in one line (blue line in map A) obtained from four exploration wells (Himyar-01, Dahmar Ali-01, Kamaran-01, and Saba-01), showing primary structural elements, such as horsts and tilted fault blocks (modified after Al-Areeq and Albaroot 2019)

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The Marib-Al-Jawf grabens contain a complete sequence of pre-, syn-, and post-rift sedimentary rocks, ranging from the Lower Paleozoic to Mesozoic. The Paleozoic sedimentary sequence consists of non-marine sandstones and interbedded mudstones of the Wajid and Akbra Formations (Fig. 3). Prior to the first period of rifting during the Late Jurassic, a pre-rift sequence of the Middle to lowermost Late Jurassic sediments was widely deposited across the Sabatayn Basin (Beydoun et al. 1998; As-Saruri et al. 2010). This sequence consists of continental and transgressive marine sandstones of the Kuhlan Formation and also the Shuqra shallow marine carbonates, providing a potential reservoir and regional seal in the Al-Jawf sub-basin (Beydoun et al. 1998; Al-Wosabi and Al-Mashaikie 2006; Al-Hasania et al. 2018). The Shuqra Formation includes the Arwa and Saba Members as defined by the Hunt Oil Company (Fig. 3, SPT 1994). Syn-rift sediments lie unconformably on the pre-rift sequence and consist of fluvio-deltaic, shallow marine, and turbidite sandstones, and shallow marine carbonates of the Lam, Alif, Seen, Yah, and Safer Members (Fig. 3). These rocks provide reservoirs (e.g., Al-Matary 2007; Al-Azazi 2010; Al-Areeq and Al-Ramisy 2013), while more distal, fine-grained terrigenous mudstones and calcareous shales within the members of Safer, Lam, and Meem provide potential source rocks (Alaug et al. 2011; Hakimi et al. 2014; Al-Areeq et al. 2018; Hakimi et al. 2019a, b, c, d; Al Areeq and Albaroot 2019). The Sabatayn Rift System was restricted by the Late Tithonian post rifting (SPT 1994). This resulted in the deposition of salt and subordinate anhydrite of the Sabatayn Formation during highstand periods, leading to the development of regional seal rocks. The Sabatayn Formation was followed by the deposition of the conformable mixed clastic-carbonate sequence of the Azal Formation (Fig. 3).

Fig. 3
figure 3

Generalized stratigraphic column of the Paleozoic sections (Cambrian–Permian) followed by a thick Mesozoic sequence (Jurassic–Cretaceous) in the Marib-Al-Jawf sub-basins

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Samples and analytical methods

The dataset of this study consists of 115 cutting samples from four exploration wells (Dahmar Ali -01, Kamaran-01, Start Test AK-01, and Start Test AL-01) in the Al-Jawf region, northwestern Sabatayn Basin (Fig. 1), releasing from the Yemeni authority of petroleum exploration and production (PEPA).

The cutting samples were selected to represent the shale intervals of the Late Jurassic Lam Member and analyzed using a variety of geochemical and microscopic methods. The geochemical and microscopic analyses were performed at specialized international research centers and laboratories including Simon Petroleum Technology laboratories.

Before the analytical processes, the collected cutting shale samples were washed using cold fresh water to remove excess drilling mud from the cutting samples and then ground to produce homogeneous powder suitable for source rock geochemical analysis, including total organic carbon (TOC) and Rock–Eval pyrolysis. Microscopic examinations such as vitrinite reflectance measurement and visual kerogen were also conducted in this study.

The total organic carbon (TOC) estimation (Table 1) was conducted on around 100-mg powder analyzed shale samples using LECO CS-125 instrument. Of all shale samples, 100 powdered samples were subsequently subjected to basic source rock parameter analysis and screened using a fully equipped instrument of Rock–Eval II. The pyrolysis analysis was performed on 1 g of each shale samples using a programmed pyrolysis system (Rock–Eval II). The oven temperature was programmed between 300 and 600 °C. The Rock–Eval II instrument was used to measure several parameters such as free petroleum (S1, mg HC/g rock) and hydrocarbon yield from kerogen cracking (S2, mg HC/g rock), The programmed pyrolysis results at 300 °C displayed a free petroleum (S1) and hydrocarbon yield from kerogen cracking (S2) at 600 °C. The maximum temperature (Tmax) of S2 peak was also measured during pyrolysis analysis (Table 1). However, Tmax is the temperature at which the measurement S2 peak yield occurs, and the most reliable values of Tmax are when the S2 values are greater than 0.5 mg/g rock (Katz and Lin 2021). In this regard, the Tmax is used for the analyzed samples having S2 values of more than 0.5 mg HC/g TOC (Table 1).

Table 1 Geochemical results of the analyzed shale samples within the Tithonian Lam Member from four wells (Dahmar Ali-01, Kamaran-01, Start Test AK-01, and Start Test AL-01) in the Jawf region, NW Yemen, including TOC content and Rock–Eval pyrolysis parameters
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The geochemical parameters of hydrogen index (HI = S2*100/TOC) and petroleum potential yield (PY = S1 + S2) were also calculated according to Espitalié et al. (1977), Espitalié et al. (1985), and Peters and Cassa (1994).

In addition to the organic geochemical analyses, microscopic examinations including visual kerogen and reflectance measurements of vitrinite organic matter were also performed on 54 shale samples using a Zeiss microscope and a Leitz Orthoplan/MPV photometry system.

Kerogen was isolated from the shale samples using standard palynological procedures after removing the oxidation or acetolysis. In acid maceration, 30% hydrochloric acid (HCl) was used to remove carbonates and 60% hydrofluoric acid (HF) was used to remove or break down silicates. Residual minerals were separated from kerogen by a combination of ultrasonic vibration and zinc bromide flotation.

The kerogen residues were further mounted on glass slides using gel-form glycerin and analyzed in transmitted light using a Leitz Dialux/Laborlux microscope. The volume of kerogen assemblages including vitrinite, inertinite, and sapropel organic matter and their frequency was conducted for each sample (Table 2).

Table 2 Vitrinite reflectance measurement and visual kerogen of the analyzed shale samples in the Tithonian Lam Member from four wells (Dahmar Ali-01, Kamaran-01, Start Test AK-01, and Start Test AL-01) in the Jawf region, NW Yemen
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Vitrinite reflectance analysis was performed on the shale samples using the polished block technique following ISO (2009). The whole rocks were crushed into 2–3 mm size particles, and then, the particles were mounted with epoxy resin. Vitrinite reflectance (VRo %) was measured using standard procedures described by Taylor et al. (1998). The vitrinite reflectance study was performed with a Zeiss microscope and Leitz Orthoplan/MPV photometry system under reflected light using oil immersion technique. The measured vitrinite reflectance (% Ro) data was reported as the average of 10 to 30 measurements using an interactive computer program.

Results and discussion

Abundance of organic matter

The abundance of organic matter in that source rocks is mainly represented by total organic carbon (TOC) content as weight percent, which is used to assess the amount of organic matter in the source rocks and their ability to generate petroleum upon thermal maturity (Peters 1986; Jarvie 1991; Peters and Cassa 1994). The sediments deposited in an open marine environment are rich in organic matter and have TOC content more that about 1 wt. %, while continental and lagoonal sediments generally reached TOC content less than 1 wt. %. However, the prior researchers such as Hunt (1996) and Tissot and Welte (1984) reported that the clastic rocks (i.e., shale) that contain a minimum TOC of 0.5 wt. % are considered to be source rocks potential for hydrocarbon generation. Other geochemical researchers argued that the good source rocks generally contain TOC of more than 1% (e.g., Bissada 1982; Katz and Lin 2014).

In the current study, organic matter content in terms of TOC of the analyzed 115 shale samples in the Tithonian Lam Member is present in Table 1. Based on the TOC measurements, the analyzed Lam shale samples have sufficient organic matter, with values of TOC content between 0.50 and 6.43 wt. % (Table 1). The TOC results show that the majority of the Lam shale samples (n = 58) had TOC content close to 1% (0.50–0.98%), 42 samples possessed relatively high TOC values of more than 1%, while other 15 samples show the highest TOC contents between 2 and 6% (Table 2). In this regard, the relatively high TOC content suggests that the Lam shale sediments were probably favorable source rocks in the Al-Jawf region, with potential ranking from fair to excellent (Fig. 4). Although it has been argued that good source rocks generally contain a TOC > 1 wt. % (Bissada 1982; Katz and Lin 2014), the thermal maturity, however, affects the organic matter and leads to a reduction of the TOC values by transforming the organic matter to petroleum (Cooles et al. 1986; Shalaby et al. 2012). Therefore, the TOC content alone is insufficient to understand the source rock generation potential, and, consequently, the TOC content must be corroborated with other geochemical results such as Rock–Eval pyrolysis data of  S1 and S2 yields, which are used together to evaluate the richness of organic carbon and petroleum generative potential following scales of Peters (1986) and Peters and Cassa (1994).

Fig. 4
figure 4

source rocks, with higher generation potential in several Lam shale samples

Distribution of the total organic carbon (TOC) content next to the depths of the analyzed Lam samples from the studied wells shows that most samples are fair to good

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The analyzed shale samples have been yielded free hydrocarbon (S1) and total hydrocarbon from the cracking of kerogen (S2) in the range of 0.07–7.9 and 0.26–25.28 mg HC/g rock, respectively, during Rock–Eval pyrolysis (Table 1). The combination of TOC content and Rock–Eval S1 and S2 results in terms of petroleum potential yields (PY = S1 + S2) were further used to assess petroleum generation potential from the analyzed Lam shale samples. These data show that the most analyzed samples (87%) range from Fair to good generation potential (Fig. 5), with TOC and PY values of less than 1% and 5 mg HC/g rock, respectively. Other shale samples (13%) show higher petroleum generation potential in the rank of very good to excellent (Fig. 5), with values of greater than 1% and 5 mg HC/g rock for TOC content and PY yield.

Fig. 5
figure 5

source rock generation potential

Cross-plots of the geochemical results of total organic carbon (TOC) content and petroleum yield in the analyzed Lam shales in the studied well, showing fair to excellent

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Organic matter (kerogen) characteristics

Qualitative bulk pyrolysis results together with kerogen microscopic studies were investigated throughout this study and used to assess the characteristics of organic matter and their relation to kerogen types, representing the source of organic matter input in the analyzed Lam shale sediments in the Al-Jawf exploration region.

The qualitative kerogen types in the Lam shale samples under study were evaluated based on important geochemical data of Rock–Eval HI parameter (Espitalie et al. 1985; Peters and Cassa 1994; Mukhopadhyay et al. 1995). HI values for the analyzed shale samples ranged from 50 to 433 mg HC/g TOC (Table 1). In general, the analyzed samples are dominated by the HI with values of up to 204 mg HC/g TOC in the most studied wells, and high values of HI parameter in the range of 217–433 mg HC/g TOC for other shale samples are present in wells Kamaran-01, Start Test AK-01, and Start Test AL-01 (Table 1).

According to the modified Krevelen diagram of the HI and Tmax values (Fig. 6A), the analyzed samples mainly fell into types III and II–III kerogen. Remarkably, only six shale samples were plot on type II kerogen area of the diagram (Fig. 6A), suggesting that they are likely to be highly oil-prone.

Fig. 6
figure 6

Characteristics of kerogen in the analyzed Lam shale samples based on a Rock–Eval hydrogen index (HI) versus Tmax, and b TOC content versus Rock–Eval S2 yields, showing that the type III and type II/III kerogens are common organic facies, with a few type II kerogen

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However, a diagram of pyrolysis S2 and TOC data was used by Langford and Blanc-Valleron (1990) to corroborate the qualitatively confirm organic matter (bulk kerogen). When we plotted our analyzed samples on such a diagram, it corroborated the dominant presence of type III and II–III kerogens, with low contributions of type II kerogen (Fig. 6B), having HI values more than 400 mg HC/g TOC. These types of kerogen suggest that the analyzed Lam shale sediments have received incorporated mixed organic matter, with high contributions of terrestrial organic matter.

In this study, other quantitative analyses of the kerogen microscopy are also used to corroborate the kerogen characteristics (e.g., Cornford 1979; Hakimi et al. 2020).

Table 2 summarizes the visual kerogen results of the analyzed shale samples. The kerogen assemblages in the analyzed shales were characterized mainly by vitrinite organic matter, ranging in volume from 25 to 85%, followed by sapropelic organic matter (10–70%; Table 2). Inertinite organic matter was also present in significant amounts of 5–35% (Table 2). These three main assemblages of kerogen observed under the microscope were used to characterize the organic facies of the analyzed samples according to the Cornford (1979) ternary diagram. Based on this ternary diagram, the organic facies in the analyzed samples were mainly type III and type II/III kerogens, with minor kerogen type II (Fig. 7). The most analyzed shale samples contained a high amount of vitrinite plants, followed by sapropelic organic matter were exhibited a gradient from type III to Type II/III kerogen (Fig. 7). On the other hand, the analyzed shale samples with more than 50% of high sapropelic organic matter were likely type II kerogen (Fig. 7).

Fig. 7
figure 7

Ternary plot of the kerogen assemblages recognized in the analyzed Lam shale samples from the four wells (Dahmar Ali-01, Kamaran-01, Strat Test AL-01, and Strat Test AK-01) in Al-Jawf sub-basin. Note the dominance of type III and type II/III kerogens over type II

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Thermal maturation of organic matter

In this study, the thermal alteration of organic matter in the studied shale units was determined using different geochemical and microscopic results, such as measured vitrinite reflectance (%VRo) and Rock–Eval Tmax for Dahmar Ali-01, Kamaran-01, Start Test AK-01, and Start Test AL-01 as shown in Tables 1 and 2.

Vitrinite is one type of macerals that predominantly derived from higher plants and was classified as type III kerogen (Teichmüller et al. 1998). The vitrinite maceral has moderate reflectance, which its reflectance C% increases with increasing of thermal maturation of organic matter and is related to increasing burial temperature of their hosted rocks. Vitrinite reflectance (%VRo) is an important indicator commonly used to provide information on maturation of organic matter (e.g., Sweeney and Burnham 1990; Teichmüller et al. 1998), and widely applied in petroleum as a maturity indicator (e.g., Osli et al. 2018; Shalaby et al. 2011, 2012; Jarvie et al. 2007).

Based on Waples (1994), the source rock reaches the early oil generation window at 0.6% VR, with peak oil window maturity occurring at VR = 0.8%, and the end of oil generation stage at a VR = 1.35%. Following maturity scale of Waples (1994), the analyzed shale samples in the Lam Member reached different maturity levels ranging from immature to peak maturation within the oil window, corresponding to their VR values between 0.36 and 0.86%VRo (Table 1).

In this work, the relationship between depth and VR of the analyzed Lam shale samples is constructed and shows that the variations in the range of reflectance and their thermal maturity were affected by burial temperatures, as shown by the VR profiles in the wells studied (Fig. 8). The analyzed Lam Shale Member in the studied wells are buried in the depths range from 204 to 2204 m, reaching different thermal maturity levels, ranking from immature to peak maturation in the oil generation window (Fig. 8). Accordingly, these thermal maturity stages of the analyzed shale samples were consistent and correlated well with burial temperatures as implied by the positive relationship between VR values and burial depth (Fig. 8). One good example is the Start Test AK-01 well. Its shallow burial depth showed low VRo values (0.36–0.56%), causing immature zones in other wells studied, with some data points shifting to early maturation levels of oil generation window (Fig. 8). In contrast, the maximum burial depth of up to 2204 m in the Kamaran-01 well showed relatively high VRo values above 0.70% (Figs. 8), leading to the highest maturation level (peak oil window) among the other wells studied (Fig. 8).

Fig. 8
figure 8

Distribution of measured vitrinite reflectance (%Ro) values next to the depths of the analyzed samples from the studied wells, showing that the Lam shale samples are at immature to peak oil window maturity levels

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Besides the VR maturity indicator, the temperature of the maximum pyrolysis rate (Tmax) is also commonly used to estimate the maturity of kerogens, as the maturity of kerogens increased within increasing their Tmax values (Peters 1986; Tissot and Welte 1984; Tissot et al. 1987; Bordenave et al. 1993). Tmax is generally dependent upon the S2 measurement in multiple programmed pyrolysis instruments and the best Tmax values are observed on samples having S2 greater than 0.50 mg/g rock (Katz and Lin 2021). In this respect, most of the analyzed samples (90%) have S2 values more than 0.50 mg/g rock (Table 1). Therefore, the Rock–Eval Tmax values are probably reliable to evaluate the thermal maturity of the organic matter. The analyzed samples have reliable Tmax values in the range of 417 to 451 °C (Table 1), consistent with vitrinite reflectance (VRo %), and confirming immature to mature of oil window generation (Fig. 9). Most of the analyzed samples (n = 77) from four studied wells have Tmax values of less than 435 °C (417–433 °C), while other samples from the Kamaran-01 well have Tmax values between 435 and 451 °C (Table 1), indicative of more mature organic matter intervals for economic oil generation in relatively deeper burial depths as implied from the relationship between Tmax data and burial depth of the Lam shale samples (Fig. 10).

Fig. 9
figure 9

Cross-plot of maturity indicator correlation between the measured vitrinite reflectance (%Ro) and geochemical Tmax data, indicating the immature to peak oil window maturity levels of the analyzed Lam samples in the Al-Jawf sub-basin

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Fig. 10
figure 10

Distribution of geochemical Tmax values next to the depths of the analyzed samples from the studied wells, showing that the Lam shale samples are at immature to peak oil window maturity levels

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Petroleum generation potential

The potential of the petroleum generation either oil or/and gas is generally evaluated based on the amount and type of organic matter and their maturation through geological temperatures (Dow 1977; Ardakania et al. 2017; Abdullah et al. 2017; Edilbi et al. 2019; Tiwari et al. 2020; Hazra et al. 2020; Singh et al. 2021).

In this study, integration of geochemical findings together with microscopic studies was used to characterize the organic facies of the organic-rich shale sediments of the Late Jurassic Lam Member and provide information on their potential as petroleum resources in the Al-Jawf exploration region, NW Yemen.

Based on the geochemical results of the analyzed shale samples, the TOC content together with Rock–Eval S1 and S2 (Table 1) was used to address the relationship between the organic matter abundance and its generation potential and indicates that the analyzed shale samples were mainly ranked as fair to good potential source rocks, except for some samples that showed higher potential in the range of very good to excellent (Fig. 5). Therefore, the analyzed Lam shales can generate significant amounts of petroleum at optimal thermal maturity levels.

Apart from the amount of organic matter present, the type of organic facies is the other important information needed to predict the petroleum generation potential. Bulk pyrolysis data of HI also revealed that the type III and type II/III were the most common kerogens, and the contribution of type II kerogen was small (Fig. 6). These kerogens types were further confirm from the kerogen assemblages observed under the microscope (Fig. 7). Accordingly, the analyzed Lam shale sediments are likely to be both oil- and gas-prone source rocks, with high contribution to gas generation potential. Type III kerogen is predominantly a source of gas, and a mixture of type II and type III kerogens is expected to generate both oil and gas. These petroleum generation resources were demonstrated from the geochemical correlation among TOC and HI (Fig. 11). Furthermore, the kerogen assemblages observed under the microscope play an important role and can provide information on their potential as a hydrocarbon source (Tissot and Welte 1984). The proportion of the kerogen assemblages in the analyzed samples confirms the potential for hydrocarbon generation of mainly gas, with little amounts of oil (Fig. 12). Most of the shale samples represent type III kerogen (Fig. 7), and would be able to generate gas based on their relatively high vitrinite organic matter derived from terrestrial plants (Fig. 12). Other samples that have type II and II–III kerogens (Fig. 7) were interpreted to be both oil- and gas-prone based on their relatively high sapropelic organic matter of more than 30 vol. % (Fig. 12). Being one of the foremost parameters to identify petroleum generation potential, the thermal maturity assessment of this study correlates two leading indicators, namely the measured vitrinite reflectance (%VRo) and the chemical Rock–Eval Tmax data (Tables 1 and 2). In agreement with previously obtained maturity data, these results indicate that the analyzed Lam shale samples from the studied wells in the Al-Jawf exploration region represent immature to mature (i.e., peak oil window) source rocks (Figs. 8, 9, and 10). Accordingly, the organic matter in the analyzed samples at immature to early mature oil window has not yet reached high-maturity level to generate commercial amounts of oil and/or gas. Other shale samples contain type II kerogen and mixture II and III kerogen and reached peak mature of oil window expects to generate significant amounts of oil.

Fig. 11
figure 11

source rocks in terms of both oil and gas generation potential, with significant potential for gas generation from the analyzed Lam shale in the Al-Jawf sub-basin

Relationship between TOC content and HI values, showing good

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Fig. 12
figure 12

Ternary plot of the kerogen assemblages recognized in the analyzed Lam shale samples from the four wells (Dahmar Ali-01, Kamaran-01, Strat Test AL-01, and Strat Test AK-01) in Al-Jawf sub-basin. Note type of petroleum that is expected to be generated from the shales in the Lam Member

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Implications on conventional petroleum exploration

The Al-Jawf region is a part of the Sabatyen Basin in northwestern Yemen, where the traditional petroleum resources have not been well studied. Petroleum exploration operations are ongoing for traditional oil and gas resources across different sections of the Sabatyen Basin such as Marib, Shabwah, and Hajar (Fig. 1A). According to previous studies, hydrocarbon exploration activities in the Marib, Shabwah, and Hajar sections focused primarily on the Late Jurassic Lam, Meem, and Saar shale intervals (e.g., Alaug et al. 2011; Hakimi and Abdulla 2013a; Hakimi et al. 2014; Hakimi and Ahmed 2016; Al-Areeq et al. 2018; Hakimi et al. 2020). Most of the oils discovered are from the organic-rich shales of the Lam and Meem Members (Hakimi and Abdulla 2013b; Hakimi et al. 2019e). However, the preliminary findings on the Lam shale sequence were important to support prospects and exploration goals for the Al-Jawf exploration region in the northwestern Sabatyen Basin (Fig. 1A). Based on the results of this study, the analyzed shale intervals within the Lam Member are likely to be oil and gas source rocks. The known deeper locations in the Lam shale strata shifted to a higher thermal maturity level and are expected to commercially generate petroleum.

In addition, the source rock characterization of the Lam shale intervals, including organic matter content, kerogen type, thermal maturity level, and petroleum generation potential, was discussed using the data obtained from the studied wells. This discussion of the distribution of the source rock properties through the studied wells will help prospects and exploration goals. In this regard, geochemical results, including TOC content, HI, and VR data together with burial depth of the Lam Shale Member from four studied wells (i.e., Dahmar Ali-01, Kamaran-01, Start Test AK-01, and Start Test AL-01), were mapped to show the overall lateral variations across the study area (Fig. 13). The distribution map shows that the amount of organic matter in terms of TOC% in the Lam shale intervals increased from the area around Dahmar Ali-01 well (TOC = 0.97%) toward the north and southeast of the study area, particularly in the areas around Kamaran-01 (TOC = 1.32%), Start Test AK-01 (TOC = 1.33%), and Start Test AL-01 (TOC = 1.70%) as shown in Fig. 13A.

Fig. 13
figure 13

Map of the lateral distribution of geochemical results, i.e., TOC, HI, and Tmax (A, B, C) and the depth of the Lam Shale Member (D), showing that the most prospective areas are located in the southeastern area in the Al-Jawf region, particularly around Kamaran-01well

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The Lam shale intervals in the studied wells had HI values between 50 and 433 mg HC/g TOC (Table 1). These values also increased from the area around Dahmar Ali-01 well (HI = 68–246 mg HC/g TOC) to the north and southeast of the study area around Kamaran-01, Start Test AK-01, and Start Test AL-01 wells (HI = 50–433 mg HC/g TOC) (Fig. 13B). Consequently, the Al-Jawf region was considered a prospect area for both oil and gas generation potential, with higher gas generation potential in areas around Dahmar Ali-01 well (Fig. 13B). In addition, the distribution map for the optical maturity indicator (i.e., %VRo) showed that the Lam shale intervals are more mature in the southeastern part of the study area, especially around Kamaran-01 well. The maturity level decreased with decreasing the VR values toward the Start Test AK-01, Start Test AL-01, and Dahmar Ali-01 wells (Fig. 13C). Variations in maturity level of the Lam shale intervals can be attributed to the regularly increasing burial depth from Kamaran-01 well toward the Start Test AK-01, Start Test AL-01, and Dahmar Ali-01 wells (Fig. 13D). Therefore, temperature gradient was a major factor involved in the thermal alteration of organic matter intervals in the Lam Shale Member.

The distribution of source rock characteristics in the wells studied suggested that the Lam shale intervals in the southeastern part of the study area, especially around the Kamaran-01 well, have good source rock characteristics that can generate commercial quantities of oil because of high TOC and HI values (Fig. 13 A and B). The strata in the above-mentioned area have reached extreme maturity levels compatible with the peak oil window (Fig. 13C), where the Lam shale intervals are deeply buried at the depth of up to 2204 m (Fig. 13D). Therefore, we expect that the oil exploration plans in the future must concentrate on the Lam shale intervals along the deep parts of Al-Jawf region, with elevated thermal maturation and thickness, particularly in the areas around the Kamaran-01 well.

Conclusion

This study discusses a combination of organic geochemical and kerogen microscopy results of the organic matter in the interbedded shale samples within the Late Jurassic (Tithonian) Lam Member from four exploratory wells in the Al-Jawf exploration region, northwestern Yemen. Integrated organic geochemical and microscopic results in the current study offer the main achievements explained below:

  1. 1.

    The shale intervals within the Lam Member have moderate to high concentrations of organic matter based on TOC content between 0.50 and 6.43wt. %, indicating favorable source rock characteristics.

  2. 2.

    The analyzed Lam shale rocks contain mixed organic matter of largely contributions of terrestrial-derived organic matter (i.e., vitrinite), with aquatic-derived sapropel or sapropelite organic matter, and are mainly classified as Types III and II/III kerogen, with little Type  II. Thus, these shale rocks can potentially generate both oil and gas, with high contributions of gas generation potential.

  3. 3.

    Both chemical and optical maturity indicators (i.e., VRo and Tmax) show that the Lam shale intervals in the studied wells of the Al-Jawf region are currently at different maturity stages, ranging from an immature to peak oil generation window.

  4. 4.

    The lateral distribution of source rock characteristics of the Lam shale intervals in the studied wells suggests that the Lam shales in the southwestern part of the Al-Jawf exploration region, particularly in the areas around Kamaran-01 well, are likely to be promising source rocks as implied from high TOC content and peak oil window, and thus, commercial amounts of oil can be generated.

  5. 5.

    These conclusions enhance the prospects and exploration strategies for oil generation and production from the Lam Shale Member in the Al-Jawf region, particularly around the deeper locations of the region, where the Lam Shale Member may have reach relatively high level of thermal maturity for oil and gas generation windows.