Introduction

Sabah province has been an oil producer since its first discovery of Klias and Kudat peninsulas oil seeps in the late 1800s. Later on, petroleum has been actively explored, resulting in more wells drilled in the onshore and offshore regions. The first exploration well was spud in the Klias peninsula in 1897, and the number has increased throughout the years as in the 2000s, to the extent of 504 exploration wells and 452 appraisal wells (Mazlan et al. 1999). Petroleum exploration and development were mainly concentrated in the offshore Sabah basin that located in the western side, whilst the northern part of Sabah (onshore Kudat area) remain unexplored. In this study, we investigate Bongaya Formation that distributed in onshore as this sediment believed to be extended offshore.

Structural analysis by using seismic data in the offshore Sub-Malawi Basin indicated a similar sediment that distributed in offshore is extended onshore and have a possible hydrocarbon occurrence (Mazlan et al. 1999). This has increased the interest to explore the Bongaya Formation’s source rock potential, as no further study has been conducted in the area. To date, this study is the first comprehensive study focusing on detailed optical analysis and organic geochemistry assessment of the Bongaya Formation to investigate the petroleum potential. The only preliminary study on source rock evaluation in the Bengkoka peninsula was conducted by Mazlan et al. (1999), indicating coal as a good source rock with a higher TOC value compared to shale. It is noteworthy that other equivalent source rocks of the same age (Miocene to recent) distributed in other part of Sabah provinces such as the Timohing Formation and South Banggi Formation have been discovered and are thermally immature (Mazlan et al. 1999). Mustapha et al. (2017) also studied the equivalent Miocene sediments of the Sandakan Formation in northeastern Sabah, indicating similar results with the sediment is rich in organic matter and more prone to gas with limited oil, but it remains immature. Therefore, there is strong justification to investigate the Bongaya Formation in this frontier area for its potential of hydrocarbon generation, to aid future petroleum exploration.

This study aims to provide a comprehensive geochemical evaluation of the Bongaya Formation, particularly in the Pitas region, Sabah (Fig. 1), as a petroleum source rock, subsequently enhancing knowledge of its hydrocarbon generation potential. A petroleum source rock’s potential is determined by three key criteria: (i) the organic richness of the source rock as indicated by TOC content, (ii) the kerogen quality (kerogen type), and (iii) the level of thermal maturity of the source rock (Peters and Cassa 1994). Total organic carbon (TOC) represents the amount of organic matter accumulated in the sediments and provides an initial indication of the carbon content available for hydrocarbon generation. The maturity level of the source rock identifies their quality and plays a crucial role in preserving the source rock’s original characteristics (Dembicki 2009).

These criteria have been used as main reference to investigate source rock geochemical and petrological properties. The assessment identifies the diversity of organic matter origin, accumulation, preservation, and transformation in sediments, as well as determining the organic matter and hydrocarbon quality (Tissot and Welte 1984; Hunt 1995).

General geology and stratigraphy

The present tectonic complexity in Sabah is the result of at least five deformation events that began in the Early Cretaceous, involving a large fold-thrust belt (accretionary complex) (Tongkul 1991). These main events were significantly linked to the proto-South China Sea subduction and NW-SE compression collision (Balaguru and Hall 2009). The collision of the oceanic basement has resulted in the creation of the Sabah Crystalline Basement, leading to more folding and thrusting events that paved the way for the Rajang Group formation. The older Rajang Group (Sapulut, Trusmadi, and East Crocker Formation) has been uplifted, eroded, and deposited the sediment to the new deepwater environment known as the younger Rajang Group, which comprises the West Crocker Formation, Temburong, Setap Shale, and Kudat Formation.

A series of uplift and erosion events that occurred during the Mid-Eocene, early Mid-Miocene, and late Miocene has produced significant Base Miocene Unconformity, Deep Regional Unconformity (DRU), and Shallow Regional Unconformity (SRU). These events marked changes from deep water to shallow deltaic environments and contributed to the deposition of sediments in younger basins. Hydrocarbon-bearing Neogene onshore sediments, such as the Bongaya Formation, Belait, Liang, and South Banggi Formations, were deposited between DRU and SRU, mainly in the clastic unit. Extensional tectonism in Eastern Sabah caused the formation of the eastern Neogene basin of Tanjong Formation and Kapilit Formation. Subsequent units (Dent Groups) deposited on top of SRU exhibit minor inclusion of carbonates (Sebahat and Ganduman formations), while the Timohing, Togopi, and Wallace formations consist mostly of limestones, conglomerates, carbonaceous shales, and calcareous sandstones.

Pitas is located in the northeastern part of the Kudat Division on Sabah’s right horn (Fig. 1). The Bongaya Formation in Pitas, Sabah, is a Neogene sediment located in Bengkoka Peninsula, occurring on top of older sediments, namely Crocker, Kudat, and Chert-Spilite Formations (Fig. 2). The formation is present in several isolated basins (Tongkul 1991) and is bounded by the South Banggi Formation in the north and the Crocker Formation in the south (Peng et al. 2004).

The Bongaya Formation lithology comprises mostly sandstone, shale series, and limestone facies, with thickness estimated to exceed 750 m (Wilson 1961). Tongkul (1991) reported that the Bongaya Formation consists predominantly of grey sandstone interbedded with carbonaceous shale and minor conglomerate beds with with thickness estimated to be less than 200 m and varied in different areas (thicker sections towards the basin’s edge). The conglomerate beds are part of the Crocker and Chert-Spillite sediments. Sedimentary structures, such as vertical trace fossils and cross-bedding, indicate that this formation represents a shallow water depositional environment.

Previous structural analysis by Tongkul (1991) suggest that the Bongaya Formation basin occurred as gently dipping beds and was controlled by ancient structures on old formations, such as the Basement and Crocker Tongkul (1990) reported that early north Sabah deformations were folded and thrust faulted in the NW-SE trend, later being cross-cut by several sets of NE-SW and N-S horizontal faults up to the middle Miocene (Tongkul 1994). The N-S compression resulted in the formation of an E-W basin, which was later filled by the South Banggi Formation and Bongaya Formation. Although N-S fault extensional features are present in the basin, they show no intense deformation, and profound folding was not found. A combination of fault structures with NW-SE, NE-SW, and W-E trends formed an almost circular-shaped basin of the Bongaya Formation. Continuous extension developed the existing structures into a V-shaped graben-type basin that deepens towards the sea in the northeastern part.

Four Bongaya Basins are distinguished and identified as Basin 1, Basin 2, Basin 3, and Basin 4. Sediments in Basin 1 and 2 are composed of typical thick Bongaya Sediments, sandstones and shale sequences (Fig. 3a), and coal lenses found between the layers. The perspicuous outcrop of Basin 2 was also observed to have a series of thin lenticular layers of interbedded grey sandstones and shale sediments (Fig. 3b) up to 2 m. The conglomerate layer found at the bottom sequence in an outcrop is made of smalls gravel and has a minor presence in this formation (Fig. 3c). The lithologies, however, changed towards the sea. The northern basins (Basin 3 and 4) are mostly dominated by thick white sand, where the sandstone occurred coarser compared to sediments in Basin 1 and 2. The seaside observed a small folding comprised of coarse sandstone and trace fossils in the mangrove area near Kg. Malubang (Fig. 3d).

Fig. 1
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Map of the Northern part of Bengkoka Peninsular (modified after Lim and Heng 1985) shows outcrop and sampling localities of Bongaya Formation

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Fig. 2
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(modified from Tongkul 1990)

General stratigraphy column of the northern Sabah shows Bongaya Formation age of Upper Miocene to Pliocene

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Fig. 3
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Field photograph of Miocene Bongaya Formation; (A) thick interbedded sandstone and shale, (B) thin interbedded carbonaceous shale and sandstone, (C) conglomerate bed, and (D) folded coarse-grained sandstone

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Samples and methodology

A total of 25 outcrops were mapped in the field for the study area in Pitas, Sabah (Fig. 1). Out of 25 outcrops of the Bongaya Formation, a total of 15 outcrops were selected for laboratory analysis that cover organic-rich bearing sediments which include thirty samples (Fig. 1). The samples include 10 coals, 3 coal-laminated sandstones, 8 shales, and 9 carbonaceous shales (Table 1).

The organic geochemical analysis was performed by using Hawk Pyrolyser (equivalent to Rock Eval-7 pyrolyser), Bitumen Extraction, and pyrolysis-gas chromatography (Py-GC) together with petrographic analyses for maceral compositions and huminite reflectance analysis (%VRo).

All thirty samples were crushed into fine powder for bulk pyrolysis screening analysis by Hawk Pyrolyser. The Hawk pyrolyser operates at two cycles of analyses i.e. pyrolysis and oxidation. Prior to the analysis, the Hawk Pyrolyser was calibrated with a known standard rock powder sample. The analysis begins with pyrolysis when the sample was heated at initial temperature of 180 °C and ramped-up to final temperature at 650 °C. The ionized organic compound was transferred by helium and detected by Flame Ionization Detector (FID), while the CO2 and CO generated during the pyrolysis were detected by dual Infra-Red (IR) detectors. During the pyrolysis, S1 (free hydrocarbons), S2 (kerogen cracking), S3 (CO2 pyrolysis) were detected and quantify while Tmax (maximum temperature during kerogen cracking) was measured at maximum temperature from S2 peak. The pyrolysis mode was then changed to oxidation after the oven cooled at 300 °C and the remaining kerogen was heated up to 750 °C in the presence of air to detect and quantify the remaining CO2 and CO (S4) by dual Infra-Red (IR) detectors. TOC was calculated as a function of S1 + S2 + S3 + S4.

Bitumen was extracted from 19 source rock samples using a Soxhlet extraction apparatus for 72 h with an azeotropic mixture of dichloromethane (DCM) and methanol (CH3OH) in a ratio of 93:7. The concentrated bitumen were then separated by liquid column chromatography into aliphatic, aromatic and NSO fractions using petroleum ether, DCM and CH3OH, successively.

Pyrolysis gas chromatography was performed on selected solid powdered samples using a Frontierlab pyrolyzer connected to GC-FID. The equipment setup for pyrolyer and GC used in this study was following the method as described by Mustapha and Abdullah (2013).

Petrographic analyses were conducted on 15 selected samples of the Bongaya Formation. These analyses include maceral identification and huminite reflectance measurements under oil immersion petrographic technique, using an X50 objective. Notably, huminite reflectance expression was employed instead of vitrinite reflectance to account for the low reflectance of humic materials, as defined by the ICCP system (Sykorova et al. 2005). Fifteen samples were used for polish block preparation. The samples were crushed into 2–3 mm size clasts and embedded in molds with liquid epoxy resin, left to harden for 24 h at room temperature. The prepared blocks were then successively polished with 350, 800, and 1200 silicon carbide paper, followed by 1 μm > 0.3 μm alumina powder-deagglomerate and OPS solutions at the final stage.

Maceral point counting was conducted on every polished block using a LEICA CTR 6000 photometry microscope under reflected white light and ultraviolet (UV) light for 500–1000 macerals counting. The huminite reflectance measurements were performed with approximately 10–50 measurements using a high-resolution Basler camera aided by DISKUS FOSSIL software and calibrated with the standard Saphire refractive index (0.589%).

Table 1 Result of TOC (wt%), bulk Hawk Pyrolysis and hydrocarbon fractionation of the analyzed Bongaya formation samples
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Table 2 Petrographic analysis of vitrinite reflectance (VRₒ %) and maceral analysis of selected samples from Bongaya Formation
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Results and discussion

Organic matter richness

The geochemical, TOCs and pyrolysis results (i.e., S1, S2, S3, Tmax, PI, HI, OI) are presented in Table 1. To produce hydrocarbon, the petroleum source rock requires a sufficient amount of organic matter (Peters 1986; Bordenave 1993; Peters and Cassa 1994), as annotated by the TOC value. The analyzed shale samples represent TOC content ranging from 0.74 to 23.71 wt% as compared to organic-rich sediments like coals, carbonaceous shales, and coal laminated sandstone with values in the range of 42.26–64.5 wt%, 5.47–44.29 wt%, and 0.93–12.88 wt%, respectively (Table 1).

Based on the TOC contents of more than 1 wt% (above average level of organic matter richness), the majority of analyzed Bongaya sediments are organically rich with high quantities of organic matter, and these sedimentary strata can be classified as a good source rock potential for hydrocarbon (Peters and Cassa 1994). However, to meet all of the potential generative requirements, TOC content alone is insufficient and must be supported by pyrolysis S1 and S2 results in terms of petroleum yield (e.g., Peters 1986; Peters and Cassa 1994; Dembicki 2009; Hakimi et al. 2012; Shalaby et al. 2012; Jumat et al. 2017; Shalaby et al. 2019; Shalaby et al. 2021; Osli et al. 2021).

The pyrolysis results show the coal samples have high S2 values and range from 19.3 to 189.07 mg HC/g, followed by carbonaceous shales (1.61–92.7 mg HC/g), indicating a fair to excellent generative hydrocarbon capacity with coals as very good-excellent generative hydrocarbon samples (Fig. 4). In contrast, the analyzed shales and coal laminated sandstone have low pyrolysis S2 values (0.53–15.33 wt% and 0.47–23.93 wt%), thus interpreted to have wide range of poor to very good hydrocarbon generating potential (Fig. 4). The coal and carbonaceous shale samples have good petroleum generative potential when compared to shale and coal laminated sandstone samples, based on PY values of > 5 mg/g (Fig. 5a). Consequently, the result shows that the Upper Miocene Bongaya Formation sediments are capable to generate significant amounts of petroleum at optimal thermal maturity levels at deeper burial depth.

Fig. 4
figure 4

S2 vs. Total Organic Carbon (TOC) plot used to interpret source rock richness and generative potential for Bongaya Formation samples (after Peters and Cassa 1994)

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Examination of source rock richness was also performed by determining the quantity of extractable organic matter (EOM). The experiment was conducted on all selected lithologies except coal laminated with sandstone. The analyzed samples have low to high concentration of bitumen extract, range between 802 and 77,297 ppm (Table 1). Coals and carbonaceous shale have good to excellent potential with 13,104 to 77,297 ppm and 4,339 to 21,102 ppm of EOM, respectively. Shale has the lowest EOM concentrate, range between 802 and 4,372 ppm. This suggesting that coal and carbonaceous shale have higher generative potential than shale (Fig. 5b). The interpretation is also supported by the hydrocarbon fractions (saturated and aromatics) derived from EOM, which showed that coal and carbonaceous shale contain good to excellent hydrocarbon compounds in the range between 641 ppm to 12,798 ppm (Peters and Cassa 1994).

Kerogen characteristics

Kerogen characteristics and the source of organic matter input in the Bongaya sediments were investigated to identify the kerogen type. The kerogen type commonly was assessed by bulk geochemical parameters involving the hydrogen index (HI) and Oxygen Index (OI) (e.g. Tissot and Welte 1984; Espitalie et al. 1985; Peters and Cassa 1994; Hunt 1995; Mukhopadhyay et al. 1995). The HI values of the analyzed samples are in the range between 24 and 334 mg HC/g TOC (Table 1). Coal samples recorded the highest HI values > 200 mg HC/g TOC whilst the other sediments have HI values below 200 mg HC/g TOC. The OI values are in the range between 31 and 73 mg CO2/g TOC. In general, the cross-plot of HI vs. Tmax (Fig. 6a) shows that the analyzed samples are dominated by Type III kerogen whilst three coal samples, one carbonaceous shale and one coal laminated sandstone indicate Type II/III kerogen. High HI values in carbonaceous shale and the coal laminated sandstone were attributed by the presence of transported resin grains in these sediments. The type of kerogen is also been classified by using HI vs. OI plot (Fig. 6b) with the diagram is in good agreement with the HI vs. Tmax interpretation.

These coal samples yielded a relatively more significant amount of hydrocarbon compared to other samples. As most of the kerogen type in the studied Bongaya sediments is suggested to be mainly contributed by terrestrially-derived organic matter (Type III kerogen), occurrence of fluorescing macerals is commonly observed in the two Type II/III-coals which contributed to the high level of the HI index.

Fig. 5
figure 5

Cross plot of (A) petroleum yields (S1 + S2) vs. Total Organic Carbon (TOC) use to interpret hydrocarbon generative potential for the analysed samples (after Waples 1985) and (B) Total Organic Carbon (TOC) vs. bitumen extraction shows the source rock potential of each sample (modified after Peters and Cassa 1994)

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Fig. 6
figure 6

Kerogen type cross-plots diagrams of (A) Hydrogen Index vs. Tmax classify the kerogen type along with their maturity stage of the analysed samples (modified after Peter and Cassa 1994); (B) HI-Tmax, a pseudo-diagram of van Krevelen (HI vs. OI) indicating the type of kerogen (modified after Peters 1986; Peters and Cassa 1994)

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The bulk geochemistry results, notably HI values were compared with molecular compounds analysis by open pyrolysis (Py-GC) data to interpret kerogen characteristics and provide a more accurate kerogen type assessment (Horsfield 1989; Abbassi et al. 2016). Dembicki (2009) explained that it is a rare occasion for a source rock to demonstrate a single kerogen type where most of them have a mixed type. The kerogen mixture interpretation was supported by kerogen molecular compounds by Py-GC trace and maceral analysis.

The pyrograms of the S2 pyrolysate of the selected Bongaya sediments, i.e., coal and carbonaceous shale samples are shown in Fig. 7. The pyrograms of the analyzed samples display unimodal distribution peak that dominated by relatively higher abundance of low molecular weight hydrocarbon compounds (< C10), with n-alkene/n-alkane doublets at higher molecular weight up to n-C30 were getting lower abundance. The hydrocarbon compounds in several samples contain high abundance of specific aromatic compounds (i.e., benzene, toluene, m(+ p)-xylene, and phenol). Very low quantities of organic sulfur can also be found in the pyrolysates of the analysed samples. The distribution pattern of Py-GC traces was also compared with traces from established pyrograms by Dembicki (2009) Mustapha and Abdullah (2013); Hakimi et al. (2013, 2018). The Py-GC pyrograms of molecular distribution pattern display a similar Type III kerogen pattern that contain less abundance n-alkene/alkane doublets as extended beyond C13, thus suggesting gas generation potential with very minor liquid oil generation. It is also identified that there is kerogen mixture of Type II/III in some samples when compared to previous work by Dembicki (2009) pyrograms distribution pattern, which have mixture of 75% Type III and 25% Type II kerogen. This evidence supports the findings by Hawk Pyrolysis as display in Fig. 6a and b which indicate most of the samples classified as Type III kerogen with some samples are of Type II/III kerogen.

Fig. 7
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Pyrolysis-GC pyrograms of selected coals and carbonaceous shale indicate a high abundance of aromatic compounds, n-alkene/alkane doublets, and a low abundance of organic sulphur compounds, serving as kerogen type proxies

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The xylene over n-Octane (Xy/C8) ratio in Py-GC was also used to calculate the Type Index (R) value, which was then used to describe kerogen types and their hydrocarbon generation potential (Adegoke et al. 2015). The ratio was separated into three categories, with 0.4 representing Type I and II kerogens, a mixed Type II/III kerogen having an intermediate Xy /C8 ratio between 0.4 and 1.3, and Type III kerogen having a Xy /C8 ratio more than 1.3 (Dembicki 2009). The coaly sediments with a kerogen mixture of Type II/III have a type index (R) ratio of less than 1.3, while other samples vary from 1.3 to 6.5, indicating Type III kerogen (Fig. 8).

Thermal maturity

The huminite reflectance (% VR), Rock-Eval Tmax and Production Index (PI) values were used to determine thermal maturity. Huminite reflectance (%VRo) is the most accurate maturity predictor, which provides useful information about the organic maturation and evolution of the petroleum generation capacity (Waples et al. 1994). A mature source rock must have at least 0.55%VR (Sweeney and Burnham 1990), whilst the %VRo values for Bongaya sediments are in the range of 0.32–0.43 (Table 2), indicating immature source rocks.

The maximum pyrolysis temperature (Tmax), which increases with maturity, is also widely used in petroleum exploration studies (Peters 1986; Tissot and Welte 1984; Tissot et al. 1987; Bordenave 1993). Source rock that has Tmax below 430 °C is considered immature. Most samples from Bongaya Formation have Tmax values ranging between 380 and 433 °C (Table 1), thus confirming the immature organic matter (Fig. 9a).

The thermal maturity level of the selected samples was further evaluated based on the Production Index, PI (Peters and Cassa 1994; Hunt 1995). The PI values for coals samples are below 0.1 (Table 1) showing low maturity level conversion (Fig. 9b).

Fig. 8
figure 8

Ratios of n-Octene/xylene and ‘Type index’ (Xylene/n-Octane) to determine kerogen potential and kerogen quality, respectively

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This is further supported by the bulk molecular composition of the extracted bitumen from the rock samples which are dominated by NSO compounds (570‒64,499 ppm), followed by notable amounts of aromatic hydrocarbons (164‒11,660 ppm), and a low concentration of saturated hydrocarbons in the range of 117‒1811 ppm (Table 1).

Based on these consensuses, the surface Bongaya sediments are therefore interpreted as immature for hydrocarbon generation at the present time. However, the subsurface Upper Miocene Bongaya Formation sediment extended in the deeper section of offshore Sabah Basin can be considered a prospective petroleum resource, encouraging further exploration efforts.

Maceral composition and petrographic description

Maceral counting is another quantitative tool for defining kerogen characteristics (Cornford 1979; Hakimi et al. 2020). Light microscopy was used to examine the maceral content and mineral matter present in the analyzed samples using both plane-polarized reflected white light and UV light. The findings for the 15 analyzed were recorded as volume percent (Table 2). A substantial amount of huminite was found in the samples, followed by liptinite, which was predominantly present in the coals, and minimal inertinite maceral, identified in only a few samples. Generally, the amount of huminite content varies from 10 to 98%, while liptinite (0 to 42%) and inertinite show a much lower amount (0 to 30%).

Huminite of 54–98% macerals point was found dominating the coal samples, followed by varying quantities of liptinite (0–42%). Three of the total 8 coal samples contain a large amount of inertinite, ranging from 2 to 30%. Liptinite’s morphological features were enhanced under UV light and have a distinct fluorescent feature as shown in Figs. 10 and 11. Common liptinite macerals are resinite, cutinite, sporinite, and suberinite. Resinite appears in significant amounts.

Fig. 9
figure 9

Thermal maturity of Bongaya Formation as identified in (A) measured huminite reflectance (VR0) vs. Tmax (°C) plot (modified after Peters and Cassa 1994; Mustapha and Abdullah 2013) and (B) a cross plot production index (PI) and Tmax (modified after Espitalie et al. 1985; Peters and Cassa 1994) that were interpreted to be immature for all samples

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(2–40%) and shows intense fluorescing yellow under UV light (Fig. 10) in some coals, giving a waxy characteristic to the expected hydrocarbon generation (Taylor et al. 1998). These resinite macerals are structured as parallel separate globular bodies, showing a possibility of micro lamination (Petersen et al. 2013).

Other common liptinite macerals are cutinite and sporinite (Fig. 11a and b). The cutinite and sporinite were naturally associated with each other and fluorescing pale yellowish-green color. Cutinites commonly appear in strand-like structures while sporinite is present in a more ring agglomerated form (Pickel et al. 2017). A small portion of cell wall-like suberinite was also found (Fig. 11c). Nevertheless, two coals showed a profound amount of inertinite besides significant huminite existence. The small proportion of inertinite occurrence indicates that the depositional environment is away from the shoreline; it may be interpreted as a back-mangrove environment. The carbonaceous shale and shale samples are mostly dominated by mineral matters of about 50% and more (Table 2). The most abundant mineral matter found is clay, along with some pyrites.

The organic facies of the analyzed Bongaya sediments were classified using the ternary diagram developed by Cornford (1979), based on the three main macerals observed under the microscope: huminite, liptinite, and inertinite (Table 2). Most Bongaya sediments predominantly composed of huminite woody-cellulosic matter, representing Type III kerogen, while some samples contain liptinite is a minor oil-generated source rock potential which reflects Type II/III kerogen (Fig. 12).

Fig. 10
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Coal maceral comparison under UV and white light shows (A) B7-3 coal of resinite and huminite maceral, (B) high fluorescents of resinite aligned inside huminite maceral in sample B9-2, and (C) resinite appear much more compressed in sample B12-2, implying more burial force in the sample. Res = Resinite; Ul = Ulminite; Att = Attrinite

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Fig. 11
figure 11

Photomicrograph of coal macerals under reflected white light (left) and ultraviolet light (right). (A) and (B) shows low fluorescence of sporinite and cutinite macerals with huminite and some pyrites. (C) represents coal maceral of suberinite associated with micrinite. Cu = Cutinite; Spo = Sporinite; Sub = Suberinite; Py = Pyrite; Cly = Clay; Ul = Ulminite; De = Densinite; Co = Corpohuminite

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Fig. 12
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Ternary diagram of liptinite, inertinite, and huminite to identify kerogen type based on maceral composition (after Cornford 1979)

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Petroleum generating potential

The quantity and type of organic matter, as well as their thermal maturity, are used to assess the capacity of petroleum resources, whether oil or gas (Dow 1977; Peters and Cassa 1994; Hunt 1995; Ardakania et al. 2017; Abdullah et al. 2017). A combination of geochemical data and petrographic analyses were utilized onto Upper Miocene Bongaya Formation to identify its potential for petroleum source rock.

The correlation between Total Organic Carbon (TOC) and Hydrogen Index (HI) has been used to assess the petroleum generation potential of each sample (Fig. 13). The majority of the studied Bongaya samples are predominantly identified as a gas-prone source rock, although some coal samples have potential in generating liquid oil. The coal, carbonaceous shale, and shale samples are mainly composed of huminite organic matter originated from terrestrial plants as observed under microscope, thus classified as Type III kerogen gas-prone source rock. However, three coal samples contain relatively significant amount of liptinite macerals, indicating gas-prone samples with limited oil generation capabilities (Fig. 14). Additionally, the abundance of resinite macerals implies the potential for substantial amounts of waxy oil (Horsfield et al. 1988). The presence of resinite-rich maceral, however, caused the discrepancy in kerogen type interpretation between bulk geochemical, petrographic, and Py-GC analyses. High amount of mixture vitrinite-resinite macerals content as observed by the petrographic method (Fig. 10) has significantly increased S2 pyrolysates that detected by Hawk pyrolyser. However, resinites contain a high number of aromatic compounds and have less ability to generate liquid hydrocarbon as previously reported by Lewan and William (1987) through a hydrous pyrolysis experiment. Specific type of maceral components, particularly liptinite, play a crucial role in identifying hydrocarbons, as different macerals possess distinct characteristics (Tissot and Welte 1984).

The hydrocarbon generation potential interpretations are supported by the n-Octane and xylene (C8/xy) ratio obtained from Py-GC pyrograms. The C8/xy ratio higher than 1.0 contributes to good oil generation potential (oil) while values less than 1.0 show the potential of being more gas-prone rather than oil-prone (Mustapha and Abdullah 2013; Adegoke et al. 2015). Figure 8 demonstrates that the majority of the samples have C8/xy values of less than one, with only one contributing to value greater than one. These show that the samples are gas-prone dominant, with some of the samples potentially contributing to oil generating potential.

Fig. 13
figure 13

Geochemical correlation between hydrogen index (HI) and total organic carbon (TOC) shows the majority of Bongaya sediments are gas-prone, with two coals being good oil-prone source rock (modified after Jackson et al. 1985)

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Fig. 14
figure 14

Petroleum generation interpreted from macerals identified from a ternary diagram modified from Tissot and Welte (1984) showed that most samples are gas-prone with a little mix of oil-and gas-prone

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Conclusions

Coal, carbonaceous shale, and shale sediments from the Upper Miocene Bongaya Formation in Pitas, onshore Sabah Basin, were investigated to determine their petroleum source rock potential and thermal maturity. The findings can be summarized as below:

  1. (1)

    The geochemical results show that the Total Organic Carbon (TOC) content of the Bongaya sediments ranges from 0.74 wt% to 64.5 wt%, indicating wide range of poor to high TOC content source rock and mostly exceeding the minimum requirement for hydrocarbon generation. The excellent source rock has been identified to be coal, while the less potential rock is shale.

  2. (2)

    The majority of studied Bongaya sediments were derived predominantly from terrestrial organic matter with huminite are mainly derived from higher terrestrial plants. Consequently, the Type III kerogen-rich sediments consist HI values less than 200 HC/g TOC, thus interpreted to be gas-prone source rock. In addition, few coal samples are characterized as having mixed Type II/III kerogens as described from Pyrolysis Gas-Chromatography (Py-GC) data and maceral compositions. Some of the coal samples indicate a gas-prone source rock with little waxy liquid hydrocarbon can be generated upon mature which expected to be at deeper depth.

  3. (3)

    Both chemical and optical maturity results indicate most of Bongaya Formation is presently at an immature stage for hydrocarbon generation. Thus, the Type III and II/III kerogens in the analyzed Bongaya sediments have not been cracked to release oil and/or gas.

  4. (4)

    Considering the low level of thermal maturity in the onshore Bongaya Formation, a deeper stratigraphically equivalent basin is recommended for future hydrocarbon exploration approaches in the area (e.g., offshore Sub-Malawi Basin) as mature source rock for gas and minor oil could be anticipated.