Table 1 shows the detailed mineral compositions from XRD data for the samples. The mineral components are dominated by dolomite (0–63.24 wt%, average 37.32 wt%) and quartz (1.67–70.13 wt%, average 22.33 wt%) followed by feldspar (albite) (0–37.26 wt%, average 22.18 wt%). The calcite content ranged from 0 to 31.27 wt% and averaged 9.32 wt%. Pyrite was only detected from coaly mudstone samples and ranged from 4.57 to 14.09 wt%.

To classify the rock types and brittle index, this study used a ternary diagram from Glaser et al. (2014). The ternary diagram was used to plot the mineral composition of the collected samples, where the total contents of quartz, feldspar, and mica (QFM), of calcite, dolomite, ankerite, siderite, and magnesite (Carbonates), and of kaolinite, illite, chlorite, and montmorillonite (Clays) were equal to 100%. The results show that Huai Hin Lat mudstones from both locations, A and B, are relatively rich in carbonate minerals and very poor in clay minerals (Figure 5A). The mudstone samples from Highway 2216 (location A) were divided into carbonate-rich siliceous mudstone and carbonate-dominated lithotype (Figure 5A), while the mudstone samples from Grand Canyon Nam Nao (location B) were classified as silica-rich carbonate mudstone (Figure 5A). Coaly mudstones from location A were classified as clay-rich siliceous mudstone in the diagram (Figure 5A).

The mineral composition from the ternary diagram in Figure 5B can be used to evaluate the mineral-based brittleness index (MBI). The mineral composition is a result of the burial diagenesis and is useful for hydraulic fracturing due to the existence of brittle minerals. The ternary diagram divides the mineral compositions from the samples into three major categories: clay dominated (kaolinite, illite, chlorite, and montmorillonite), silicate dominated (quartz, feldspar, and pyrite) and carbonate dominated (calcite and dolomite) (Figure 5B). As shown in the diagram, the samples were mainly classified into two groups as follows: brittle-mineral-rich mudstones and clay-rich mudstones (Figure 5B). Quartz, feldspar, pyrite calcite, and dolomite are the main brittle minerals in the samples, while the others are plastic minerals. The plastic minerals play a dominant role in coaly mudstones, which indicates that the coaly mudstones in the study area are easy to transform. The other rock samples are suitable for hydraulic fracturing based on their MBI. In addition, Figure 5B shows a comparison between the studied samples and two analogues from the United States as follows: the Eagle Ford and Barnett Formations. The coaly mudstones lie inside the Barnett Formation, while the others are not matched with the two formations.

Significant variations can be observed in the major element concentrations in the samples (Table 2). SiO₂ concentrations in the samples varied from 13.91 to 45.88 wt% with an average of 38.48 wt%. Wide variations was also observed in Al₂O₃ (5.32–20.45 wt%), CaO (0.24–60.26 wt%), MgO (0.91–12.19 wt%), and K₂O content (1.03–3.26 wt%) with an averages of 13.36 wt%, 21.00 wt%, 5.98 wt%, and 2.54 wt%, respectively. The TFe₂O₃ (total iron) concentrations in the samples varied from 4.68 to 17.36 wt% with an average of 7.95 wt%. An anomalous high TFe₂O₃ content (17.36) in sample A4 may be due to pyrite occurrence (Table 1). Sodium (Na) concentrations are low in coaly mudstone samples compared to carbonate mudstones and carbonate-siliceous mudstones (Table 2). The Na contents in carbonate mudstones and carbonate-siliceous mudstones reflect the presence of plagioclase (albite) (Tables 1,2).

The most abundant elements are silicon (Si), aluminum (Al), calcium (Ca), iron (Fe), and magnesium (Mg) (Table 2). Silicon is mainly associated with quartz and clay minerals in fine-grained sediments (Fu et al., 2010a; Fu et al., 2010b; Zeng et al., 2015). Thus, the Si/(Si + Al + Fe) ratio can be used to indicate the terrigenous provenance distance in which the ratio decreases with the increasing distance (Li et al., 2018). The Si/(Si + Al + Fe) ratio of the samples varies from 0.54 to 0.71 with an average of 0.64 (Table 2), and indicates that the samples were deposited near terrigenous provenance.

TOC analysis was performed to provide information on the quantity of organic matter in the rock samples. The studied samples have a high average TOC content at 5.91 wt%, which ranges from 0.91 to 20.17 wt% (Table 3). The highest TOC content appears in the coaly mudstone samples, whereas the carbonate-siliceous mudstone has the lowest TOC value of 0.91 wt% in sample A2 (Table 3). The results indicate that TOC generally exceeds the kerogen threshold of 0.2 wt% for carbonate rock and 0.5 wt% for shale necessary for the generation of hydrocarbon (Tissot and Welte, 1984; Hunt, 1995). The TOC contents from all samples suggest that samples are good to excellent petroleum source rocks based on Peters and Cassa (1994). The EOM contents of the coaly mudstone samples are significantly high and in the range of 2,939–4,127 ppm (Table 3). Other samples from both studied locations have similar values in the range of 100–200 ppm (Tables 3). All samples from both locations have poor to excellent generation potential for petroleum source rocks (Figure 6A; Tissot and Welte, 1984).

The cross-plot between TOC and EOM indicates that the hydrocarbon generation potential is poor in the carbonate mudstone samples, while the coaly mudstone has excellent hydrocarbon generation potential (Figure 6A). It should be noted that TOC and EOM contents can only be used to determine the amount of organic matter in sedimentary rock. TOC and EOM contents cannot be used to determine the types and origins of organic matter, and doing so may cause misinterpretation of the hydrocarbon potential of the samples. Thus, other parameters from pyrolysis analysis were used to support the organic facies and organic matter types of the source rocks in the study area (Table 3). Moreover, the amount of the S2 was also plotted against the TOC content to evaluate the hydrocarbon generation potential of the source rocks (Figure 6B).

The pyrolysis S1 and S2 yields were in the range of 0.03–0.05 mg HC/g rock and 0.10–8.34 mg HC/g rock, respectively (Table 3). The highest values were recorded in the coaly mudstones, where the TOC values are also high (Table 3). Generally, an S2 value lower than 4.0 mg HC/g rock indicates source rocks with poor genetic potential, while yields greater than 4.0 are known as hydrocarbon source rocks. The cross-plot between S2 and TOC shows that the coaly mudstones were classified as very good hydrocarbon potential source rocks (Figure 6B). Meanwhile, the other rock samples have fair to very good hydrocarbon generation potential. However, Erik (2016) suggested that if the S2 value is lower than 0.2 mg HC/g rock, the pyrolysis data are not reliable.

Organic matter types can be defined by pyrolysis parameters and TOC contents for conversion to the hydrogen index (HI) and oxygen index (OI) contents, which can be plotted in the modified Van-Krevelen diagram. The HI and OI values of the samples depend on the organic matter sources and conditions during the formation deposition. High HI content can indicate that the organic matter was deposited under anoxic conditions, while high OI content is usually related to oxidized organic matter (Chenrai and Fuengfu, 2020). The relationship between HI and OI is used to classify organic matter types or kerogen types including kerogen type I, II, and III. In addition, when organic matter is post-mature or has experienced microbial biodegradation, it can turn into kerogen type IV, which has no potential for hydrocarbon generation (Tissot and Welte, 1984).

Kerogen types of the samples from the Huai Hin Lat Formation in this study were determined using the modified Van–Krevelen diagram, which suggests that the organic matter of the samples consists of type III and IV kerogens (Figure 7A). Type IV kerogen may be derived from oxidized terrestrial plants or reworked from other sources (Tissot and Welte, 1984), which were strongly degraded, either during deposition or during thermal maturation that lead to a reduction in HI values. Thus, the TOC and S2 values of the samples were plotted to confirm the kerogen types from the modified Van–Krevelen diagram (Figure 7B). The coaly mudstone samples were classified as type III kerogen, which suggests a mainly gas-prone source rock (Figure 7B). Meanwhile, the other rock samples were classified as type IV kerogen (Figure 7B).

The HI values from this study ranged from 6 to 45 mg/g TOC with the highest values occurring in the coaly mudstone sample (Table 3). The HI values suggest that the Huai Hin Lat Formation in the study area has poor hydrocarbon generation potential based on Peters (1986). However, HI can be reduced with increasing maturity. Therefore, the low HI values of the samples from this study may be partly caused by a higher level of thermal maturity (e.g., Chenrai and Fuengfu, 2020). This is supported by the plot between HI and Tmax (Figure 8A). Based on the cross-plot in Figure 8A, the maturity level of the samples in the study area currently occurs in a post-mature stage . Meanwhile, Tmax can also be used to evaluate the maturation level of the source rock by using a production index (PI) parameter (Figure 8B). The cross-plot between PI and Tmax shows that the samples are also in a post-mature stage (Figure 8B). However, the very low PI and high Tmax from the coaly mudstone samples indicate anomalous values in the sample. The inconsistency between PI and Tmax values may be due to various possibilities such as lithology, mineral composition, uranium content, and oxidized or reworked organic matter (Gao et al., 2019; Yang and Horsfield, 2020).

The organic matter type and depositional condition of the study area is complicated because TOC and pyrolysis data are poor, which is possibly due to strong maturation. In this study, the organic matter type and the depositional condition were determined using organic geochemical data such as non-biomarker and biomarker parameters. The GC–MS method was used to analyze the characteristics of the biomarker and non-biomarker parameters from the aliphatic hydrocarbon fraction (Table 4). This method can be used for the interpretation of the organic matter type, the conditions of the depositional environment, and thermal maturity.

Pristane (C19H40) and phytane (C20H42) are regular isoprenoids derived from the phytol side chain of chlorophyll molecules (Miles, 1989). The phytol can be transformed into pristane under oxidizing conditions and/or into phytane under reducing conditions in the depositional environment. The pristane/phytane ratio (Pr/Ph) is used to determine the redox condition of the depositional environment and organic matter type (Powell, 1988; Chandra et al., 1994; Large and Gize, 1996). However, organic matter in a non-redox condition may report a higher Pr/Ph ratio during thermal maturity (Powell, 1988). According to Didyk et al. (1978), the Pr/Ph ratio values lower than 1.0 represented an anoxic condition associated with a hypersaline or carbonate environment, while oxic condition values higher than 3.0 indicate the prevalence of terrigenous inputs (Peters et al., 1995; Peters et al., 2005). In addition, an intermediate or suboxic condition ranges from 1.0 to 3.0 (Amane and Hideki, 1998).

The average Pr/Ph ratio of the samples is 1.14 (Table 4). The coaly mudstone samples show Pr/Ph ratios between 0.99 and 2.02 (Table 4). The other samples show lower ratios, ranging from 0.70 to 1.57 (Table 4). In addition, most carbonate mudstone samples have Pr/Ph ratios lower than 1.0, except sample A1 from location A with a Pr/Ph ratio of 1.57. Hence, the Pr/Ph ratios of the samples can indicate that the carbonate mudstones were deposited under anoxic conditions with a hypersaline environment. In contrast, the coaly mudstones were deposited under suboxic conditions.

From Figure 7A, the modified Van-Krevelen diagram is seemingly unqualified for kerogen classification in the study area due to low HI and low OI. Hence, isoprenoid/n-alkane was used for organic matter types using a pristane (Pr)/n-C17 and phytane (Ph)/n-C18 diagram (e.g., Shanmugam, 1985; Sachse et al., 2011; Alkhafaji et al., 2015). The diagram shows that organic matter from the studied samples of the Huai Hin Lat Formation is originally from a transitional and algal aquatic environment (Figure 9). Furthermore, a Pr/n-C17 and Ph/n-C18 diagram is usually used as an indicator of organic matter maturation and the level of biodegradation (Peters et al., 2007). The diagram is consistent with high organic matter content (TOC >0.5 wt%) in an anoxic to suboxic environment, which is supported by the Pr/Ph ratios (Table 4; Figure 9).

The regular sterane distribution can indicate organic matter sources within sedimentary rocks and can be divided into three groups as follows: C27, C28, and C29. C27 regular sterane indicates a marine plankton influence, C28 regular sterane can be formed in a freshwater lacustrine environment associated with yeast, fungi, plankton, and algae, and C29 regular sterane indicates higher terrestrial plants associated with brown and green algae (Volkman, 1986). However, C29 regular sterane can also be derived from microalgae or cyanobacteria (Volkman and Maxwell, 1986). In addition, some C27 and C28 regular steranes might be derived from planktonic and/or algal freshwater inputs (Volkman and Maxwell, 1986). The relative amounts of C27, C28, and C29 regular steranes were converted to relative percentages and plotted in a ternary diagram as presented in Figure 10.

In this study, a predominance of C29 regular sterane over C28 and C27 regular steranes was clearly shown in the coaly mudstone samples (Table 4; Figure 10). Meanwhile, other samples included a mix of various organic matter sources. The results from the diagram can be distinguished between samples from location A and B. Location A is dominated by a terrestrial organic source or higher plants, while location B is dominated by plankton from an aquatic environment. Also, the sedimentary facies change from siliciclastic sediments in location A to carbonate sediments in location B. Thus, the studied section gradually changes from a shallow (location A) to deep (location B) water environment.

Carbonate source rocks usually show a predominance of C29-hopane (norhopane) over C30-hopane (hopane) with C29/C30 hopane ratios above 1. In contrast, mudstone source rocks show a predominance of C30-hopane over C29-hopane with C29/C30 hopane ratios mostly below 1 (Alimi, 2017). The biomarker analysis from the samples reveals that the C29/C30 hopane ratios are generally more than 0.80, except for coaly mudstone (A3) with a ratio of 0.59. These ratios suggest that C29-hopane is slightly higher than C30-hopane and indicates that carbonate source rocks predominantly occur in the study area (Waples and Machihara 1991; Alimi, 2017).

Ts (C27 18α (H)-22,29,30-trisnorneohopanes) and Tm (C27 17α (H)-22,29,30-trisnorhopane) can be used for the thermal maturation and lithology of the source rocks using the Ts/(Ts+Tm) ratio (Bordenav et al., 1993). During catagenesis of petroleum generation, Tm is less stable than Ts (Bordenav et al., 1993). Organic source rock is mature when the values of the Ts/(Ts+Tm) ratio are between 0.35 and 0.95 (Peters et al., 2007). In addition, the Ts/Ts+Tm ratio may also be influenced by the variation in lithology in which carbonate source rock is significantly lower than mudstone source rocks (Waples and Machihara, 1991; Bordenav et al., 1993; Peters and Moldowan, 1993; Sherifa and Reza, 2018). In this study, all samples occur in the range of 0.41–0.59 with a mean value of 0.53, which indicates that the organic matter is currently in a mature stage (Table 4). The results of the Ts/(Ts+Tm) ratios in this study correspond with the Tmax data.

The results of the isoprenoid ratio, isoprenoid/n-alkane, and regular sterane suggest that the organic matter accumulated in a mixed aquatic–terrigenous environment (Table 4; Figures 9,10). The samples in the study area show relatively high TOC values and are classified as type III kerogen, which suggests more gas-prone generation. The geochemical data in this study indicates that the samples have experienced high maturation resulting from the complex tectonic events in the area. Nevertheless, one or more locations in this region could meet conditions that place the Huai Hin Lat Formation as an active source rock.

Previous hydrocarbon exploration activities in the Huai Hin Lat Formation have primarily focused on shale source rocks (Arsairai et al., 2016; Phujareanchaiwon et al., 2021; Arsairai et al., 2022). However, the preliminary results of this study indicate that the carbonate mudstones of the Huai Hin Lat Formation are also a potential petroleum source rock. This important finding will be beneficial for potential prospects and exploration targets in the study area, where the known Huai Hin Lat strata entered the peak oil window in the Late Triassic (Kozar et al., 1992). The geochemical results of the Huai Hin Lat source rock suggest good source rock properties, which have a high brittleness index (Figure 5B). In terms of mineral composition, the samples show ultra-high carbonate and quartz contents, which indicates their high fracability and good hydraulic fracturing potential. Therefore, the carbonate mudstone source rocks offer guidance for potential shale gas prospects. Moreover, the biomarker parameters and depositional environment indicators presented and discussed in this study are also useful for future petroleum exploration in the study area.

Generally, CO₂ can be captured and stored in geological formations and structures with various trapping mechanisms such as depleted gas reservoirs, saline aquifers, and coal bed methane. However, enhanced oil recovery (EOR) and enhanced gas recovery (EGR) techniques can be used to increase the rate and volume of oil and gas recovered from conventional and unconventional reservoirs (Khosrokhavar et al., 2014; Sherifa and Reza, 2018; Goodman et al., 2021). These techniques require the injection of fluid, such as water, natural gas, and CO₂, into conventional reservoirs or hydraulic fractured reservoirs. Thus, CO₂ can be stored in shale gas through sorption onto organic matter and clay minerals with the displacement of natural gas by injected CO₂ (Metz et al., 2005; Goodman et al., 2021). The benefits of CO₂ injection into unconventional shale reservoirs are as follows: 1) a reduction in the cost of the injected fluid, 2) an acceleration of the displacement rate due to higher density compared with methane, and 3) higher sorption capacities in organic matter compared to methane. Moreover, CO₂ injection is estimated to enhance gas production by up to 7% in the Marcellus Shale in the United States (Godec et al., 2013). Goodman et al. (2021) recommended methane-bearing shale with a TOC content over 2.0 wt% for good geological CO₂ storage by hydraulic fracturing.

The TOC contents of the Huai Hin Lat Formation in this study demonstrate that the coaly mudstone samples are a suitable geological CO₂ storage area with current methane generation. The carbonate mudstones have good TOC ranging from 1.39 to 2.1 wt% and are a secondary target due to the uncertainty of methane generation. The relatively lower TOC content in the carbonate mudstone samples is possibly due to the presence of carbonate minerals and relatively high-water depth far from organic matter sources. Moreover, the Huai Hin Lat Formation is expected to be widely extensive and have a high thickness due deposition in a large lake environment or an aquatic depositional environment. Since the study area is dominated by carbonate-siliceous mudstone and carbonate mudstone, the geochemical reaction between the shale reservoir and acidified water during CO₂ injection needs to be further studied.