Field attributes and organic geochemical analysis of shales from early to middle Permian Dohol Formation, Peninsular Malaysia: Implications for hydrocarbon generation potential

2.1 Geology of Southeast Asia

Numerous continental blocks and a volcanic arc in Southeast Asia were originally Tethyan Ocean basins (Hall, 2013; Metcalfe, 2011b; Metcalfe, 2017; Searle et al., 2012). Peninsular Malaysia has three N—S trending geological bands based on stratigraphy, structure, magmatism, and geophysical characteristics (Burton et al., 1973; Ismail et al., 2007). The Bentong–Raub suture zone serves as a boundary where the Sibumasu block and Sukhothai Arc collide. Sibumau and Indo-china East Malay evolved from Gondwanaland and collided, forming the Sukhothai Arc (Ismail et al., 2007; Metcalfe, 2017; Metcalfe and Hall, 1998; Sevastjanova et al., 2011; Sevastjanova et al., 2016). Fragments of the Sukhothai Arc were unearthed on the eastern side of the Bentong-Raub Suture. Southeast Asia's tectonic evolution consisted of three periods: the Devonian to Triassic rifting with Paleotethys, the late Early Permian to the Late Cretaceous separation with meso-Tethys, and the Late Triassic to Late Cretaceous northward drift with Ceno-Tethys (Metcalfe, 1994; Metcalfe, 1996; Metcalfe, 2011a). Sibumasu block moved west of the Bentong-Raub suture in the Late-Early Permian. Palaeo-Tethys shrank during Sibumasu's northward flight, generating the Sukhothai Arc on the block's continental margin (Ismail et al., 2007; Metcalfe, 2011b; Metcalfe, 2017; Oliver et al., 2014). This arc split from the margin to form the Jinghong Nan-Sra Kaeo back-arc basin system. This arc (Sukhothai Arc) is accreted to the continental margin after the back-arc collapses (Ismail et al., 2007; Oliver et al., 2014). Permian to Triassic strata and the I-type granitoid plutons document the Sukhothai Arc. Singapore and neighbouring locations have the Sukhothai Arc exposures.

2.2 Geology of Peninsular Malaysia

Peninsular Malaysia covers an area of approximately 130,268 km². It has a maximum length of 750 km and a breadth of 330 km (Hutchison and Tan, 2009). The Johor Strait and the Straits of Malacca separate it from Singapore Island in its south and Sumatra Island in its west. Peninsular Malaysia results from the crucial part of the Eurasian Plate, the South-East Asian portion called Sunderland (Hutchison and Tan, 2009). The Peninsula is thought to be tectonically stable, with barely uplifts, tilting, fault movements, and local gentle down warps occurring (Burton et al., 1973; Gobbett and Tjia, 1973). Peninsular Malaysia is divided into three belts: the Eastern belt, the Western belt, and the Central belt. The division was based on the belts' different geological characteristics (Metcalfe, 2013).

2.3 Geology of the Dohol Formation

The Dohol Formation is located in the Eastern Belt of Peninsular Malaysia. The Eastern Belt consists primarily of Carboniferous to Permian-aged strata that extend from east Kelantan through Terengganu and east Pahang to east Johor in the south (Hutchison and Tan, 2009). It is believed that regional metamorphism, folding, and uplift took place in the Late Palaeozoic (Permian), and then the deposition of an older series of continental deposits, including the Murau and Redang conglomerates occurred (Khoo and Tan, 1983). The Eastern Belt was uplifted by the Pan-peninsula Triassic orogeny (Khoo and Tan, 1983). Subsequently, a younger succession of gently dipping continental deposits were deposited, which were likely raised in the late Cretaceous (Khoo and Tan, 1983). The Eastern belt may have been uplifted during the end of the Permian due to the absence of younger marine deposits, which correlates to the deposition of Lower Triassic ignimbrite (Hutchison and Tan, 2009).

2.4 Stratigraphy of the study area

The Dohol Formation is one of the Palaeozoic rocks in East Johor composed of several metasedimentary to metamorphic, volcanic and siliciclastic rocks (Surjono et al., 2020) (Fig. 1a). The ages of Palaeozoic rocks are usually Carboniferous and Permian. Some of the key areas we found outcrops belonging to the Dohol Formation were Kota Tinggi, Kluang, Jemaluang, and the outskirts of Mersing (Fig. 1b). These Palaeozoic rocks in East Johor are grouped into seven (7) lithostratigraphic units: Mersing, Marau, Dohol, Linngui, Sedili, Pengerang, and Tanjung Leman formations (Surjono et al., 2020) (Fig. 1c).

Close

Fig. 1

(a) Geological map of East Johor (b) Map of study area showing outcrop locations (c) Stratigraphy of East Johor region with various Paleozoic formations.

Export to PPT

3.1 Field study

The field study was in three (3) stages; rock description, sediment logging, and sample collection. The rock description involves identifying and describing the rocks that make up the Dohol Formation and the stratigraphic units in the area. The sediment logging involved graphically noting down the stratigraphic setup of the rocks. Some samples were also collected for laboratory analysis. Seventeen (17) fresh samples from the various lithofacies were collected using the hammer. Some tools used to identify the samples, pick the locations, and record the outcrop locations are the hand lens, hammer, GPS, and camera.

3.2 Xray diffraction (XRD) analysis

XRD analysis was undertaken on seventeen (17) shale samples collected from the studied area. The samples were analyzed at Centralized Analytical Laboratory (CAL) on Universiti Teknologi PETRONAS (UTP) campus. Powdered samples were fitted in an X-ray holder to examine mineral peaks. The samples were analyzed using a Panalytical Xpert3 Powder scanning from 4° to 60° 2θ. Mineral identification was based on the International Center for Diffraction Data (ICDD) data using HighScore Plus Software.

3.3 Total organic carbon (TOC) analysis

The TOC analysis was performed at CORELAB Malaysia. It was done by grinding and weighing a part of the rock sample. The carbonate minerals in the weighed sample were subsequently eliminated by applying hydrochloric acid to the samples. The samples were then burned to extremely high temperatures in an oxygen-rich atmosphere in order to transform the carbon in the sediments into carbon dioxide. (Carvajal-Ortiz and Gentzis, 2015; Dembicki, 2016). The carbon dioxide was then recorded, and the TOC content was calculated using the LECO carbon analyzer. The same procedure was done for all seventeen (17) shale samples.

3.4 Rock Eval-Pyrolysis

The Rock Eval-Pyrolysis was performed at CORELAB Malaysia by heating between 50 and 100 mg of rock sample in the pyrolysis oven. The samples were heated to a temperature of about 300 °C in a helium environment and kept there isothermally for about 5 min. (Carvajal-Ortiz and Gentzis, 2015). A flame ionization detector was used to measure the volatile organic material that emerged from the sample. It was recorded as the S1 peak (Tissot and Welte, 1984), representing the already generated hydrocarbons. The rock sample was then heated from 300 °C to 550 °C at a rate of 25 °C/minute, and the volatile organic material that popped out was gauged and documented as the S2 peak, with the S2 representing the remaining hydrocarbon potential in the rock sample (Tissot and Welte, 1984). The sample was heated from 300 to 390 °C to obtain the S2, and the amount of carbon dioxide that evaporated from the sample was measured and noted as the S3 peak. (Tissot and Welte, 1984). The S3 represents the amount of oxygen in the sediment associated with the kerogen. Tmax also represents the temperature whereby the S2 peak reaches its highest point. The duration of the analysis was approximately twenty minutes. The Production Index (PI), Hydrogen Index (HI) and the Oxygen Index (OI) for each sample was then calculated.

3.5 Calculated vitrinite reflectance

The Vitrinite Reflectance (R_o) values were calculated using standard models like the Barnett shale model (Jarvie et al., 2001) and the Duvernay shale model (Wust et al., 2013). According to the Barnett shale model Vitrinite Reflectance (R_o) was calculated as R_o = (0.0180 × Tmax) – 7.16. According to the Duvernay shale model, the Vitrinite Reflectance was calculated as R_o = (0.0149 × Tmax) – 5.85. The Tmax used was obtained from the Rock-Eval Pyrolysis. All the plots were drawn using vitrinite reflectance values from the Barnett shale model.

4.1 Facies characteristics

The four (4) shale facies were encountered with different characteristics and compositions. The study reveals the area possesses many shales, albeit most are buried by vegetation. As a result, the only possible access to these shales is via fresh exposures due to the excavations resulting from road expansion or housing societies projects. Most of the outcrops analyzed in this study were fresh exposures.

4.1.1

4.1.1 Black shale facies

This fine-grained shale facies is dark grey to black in colour (Fig. 2a). With respect to the bedding, the outcrops of these facies are very thin-bedded to thinly laminated and fissile in some parts while medium to massive in other areas (Fig. 2a). The shales are highly fractured at some outcrop locations, possibly due to the composition, high fine sand/silt content, or tectonic activities. Some outcrops also contain silty lenses, which can be found randomly in the samples (Fig. 2b). Outcrops of this shale facies can be found in Jemaluang and along the Jalan Felda Nitar Timur road.

Close

Fig. 2

(a) Massive black shales beds with laminations (b) black shales with silty lenses and laminations (c) Massive red shale facies with sands at the top (d) Red weathered shale facies showing laminations.

Export to PPT

4.1.3

4.1.3 Dark brown facies

This type of shale facies is fine-grained and dark brown in colour (Fig. 3a). The bedding of the outcrops are made up of very thin laminae. This shale facies is highly weathered, fissile, and flaky (Fig. 3a). The outcrop is located a few meters from light grey facies (Fig. 3b). The outcrops can be found at Kota Tinggi.

Close

Fig. 3

(a) Fissile dark brown shale facies (b) Evidence showing the dark brown shales are probably weathered light grey shale facies (c) Light grey shale facies showing thick laminations (d) Light grey shale facies with intrusions of quartzite.

Export to PPT

4.1.4

4.1.4 Light grey facies

This type of shale facies is fine-grained and light grey in colour (Fig. 3c). The bedding of the outcrops is composed of thin laminae in some areas and medium bedded in others. The outcrops are seen to have intrusions of quartz veins (Fig. 3d). At some locations, the light grey shale facies were covered with vegetation and were also in contact with the red shale facies (Fig. 4a & 4b). The shales are highly fractured, which could be due to the composition, high fine sand/silt content, and tectonic activities (Fig. 4c). This shale facies also forms a boundary with sandstones at some outcrop locations. The near-surface exposures of this facies is affected by weathering at some outcrop locations (Fig. 4d). Outcrops of this shale facies can be found in Kota Tinggi and along the Jalan Felda Nitar Timur road.

Close

Fig. 4

(a) Fissile light grey shale facies (b) Huge exposure of the light grey shales. At the far end of this field photo, it has contact with red shale facies (c) Light grey shale facies having brittle texture and laminations (d) The near surface exposures of fissile light grey shales showing dull brown colour due to weathering process.

Export to PPT

4.2 Mineralogy of the shales using XRD analysis

From the results of XRD data of 17 shale samples, it is evident that all specimens display almost similar XRD patterns, only with very minimal differences in peak intensities and peak shapes (Fig. 5a & 5b). As shown in Table 1, the minerals in the Dohol Formation shales are primarily quartz, kaolinite, chlorite, feldspars, illite, and montmorillonite, with minor amounts of calcite, dolomite, muscovite, pyrite, and hematite. The quartz content ranges from 3 % to 39 %, with an average of 22.9 %. The kaolinite mineral, which is the second most abundant mineral after quartz, ranges from 6 % to 46 %, with an average of 15 %. Followed by the chlorite, feldspars, montmorillonite muscovite, respectively as shown in Table 1. Overall, clay minerals make up 47.7 % of the rock samples, followed by quartz, feldspars, and mica (QFM) which constitutes 38 %. The carbonates in the samples constitute only 8 % of the minerals.

Close

Fig. 5

(a) A representative XRD analysis pattern of one shale sample along with few identified mineral phases. C- Chlorite, M- Montmorillonite, K- Kaolinite, Q- Quartz, F- Feldspars and I- Illite (b) Stacked XRD patterns of all the 17 shale samples from the Dohol Formation.

Export to PPT

4.3 Total organic carbon (TOC) of the samples

Results show that the TOC of the analyzed samples range from 0.03 wt% to 2.46 wt% with an average value of 0.40 wt%, which is generally low. Only a few shale samples had a TOC value greater than 1 wt% (Table 2).

4.4 Rock-Eval pyrolysis

The pyrolysis experiment provided results on the S1, S2, and Tmax of the rock samples. The S1 values from the analyzed samples range from 0.02 to 0.38 mg HC/g, with an average S1 value of 0.18 mg HC/g. The S2 values range from 0.08 to 0.68 mg HC/g with an average value of 0.34 mg HC/g. Finally, the Tmax values from the analyzed samples range from 256 to 518 °C with an average value of 430.86 °C (Table 2).

4.5 Calculated vitrinite reflectance (R_o)

From the Duvernay shale model, the R_o values range from 0.38 % to 1.87 %, with an average value of 0.94 %. The values range from 0.36 to 2.16 % from the Barnett shale model, with an average value of 1.03 % (Table 2).

5.1 Interpretation of facies

5.1.5

5.1.5 Depositional environment

Based on the analysis of the different facies (Fig. 6a) and their interpretation, the rocks analyzed in this study were deposited in a marine setting, as indicated by (Hutchison and Tan, 2009; Surjono et al., 2020). The four different facies types are assumed to have been deposited by turbidites (Fig. 6b). The facies were deposited by hemipelagic mud particles in a low-energy environment, with the occasional pebbly clasts being deposited by debris flow. A turbidity current is a newtonian, turbulent sediment flow deposits sediment through suspension settling (Shanmugam, 2006). Turbidity currents are non-uniform, surge-type fading flows (Shanmugam, 2006). Turbulent mixing causes turbidity currents to entrain seawater as they travel downslope (Allen, 1985). Unlike debris flows, turbidity currents lack the strength to convey gravel and coarse-grained sand in suspension.

Close

Fig. 6

(a) Showing the stratigraphic logs of the various facies studied (b) showing the depositional model of the facies in the Dohol formation.

Export to PPT

5.2 Mineralogy

The trends in the XRD analysis are quite similar, with a few exceptions. According to the ternary diagram by (Gamero-Diaz et al., 2013), superposition with a sCore lithology classification shows that most of the shale samples from the Dohol Formation are mixed argillaceous mudstone (Fig. 7). For the ternary diagram in Fig. 7, quartz, feldspar, and mica were grouped as QFM, whereas kaolinite, chlorite, illite and montmorillonite were also grouped as clays and finally calcite, dolomite, and siderite were represented as carbonates. The ternary diagram indicates that the rocks samples are poor in carbonate minerals and rich in clay and quartz-feldspar-mica minerals (Fig. 7). The most abundant clay minerals are kaolinite and illite, each contributing 15.1 percent and 13 percent respectively to the overall average. The relatively high presence of illite and kaolinite compared to the other clay minerals confirms a paleohumid deep marine environment of deposition (AlQuraishi et al., 2020). The results from the XRD ternary diagram agree with the findings of the depositional environment made with the facies analysis. Both analyses indicate that the rocks are from marine environment.

Close

Fig. 7

sCore lithotype classification of Dohol formation’s shales. Modified after (Gamero-Diaz et al., 2013).

Export to PPT

5.3 Richness of organic matter

Organic richness measures the quantity of organic matter in the sediment capable of generating hydrocarbon, not just the amount of organic matter available (Dembicki, 2016). According to the TOC classification (Peters, 1986), the shales from the Dohol Formation are poor in organic matter richness. The average TOC from all the shale facies is 0.40 wt%, indicating that the shales contain a low amount of organic matter. However, the dark grey shale facies have the highest TOC value among the others, with an average TOC value of 0.69 wt%, which shows that the richness is intermediate. This supports the claim that black shale has more organic matter than other shales (Speight, 2016). All the other shale facies have very poor organic richness, with TOC values less than 0.2 wt% (Table 2). However, it is not advisable to use only TOC to determine how much hydrocarbon sediments can generate (Dembicki, 2009). As a result, it is also necessary to analyze the amount of organic matter that will generate hydrocarbons, which can be accomplished by combining TOC with S2 (Dembicki, 2009). Some of the organic matter in sediments produces oil, while some produce gas, and others produce nothing (Tissot et al., 1974). Combining TOC and S2 will give an idea of the amount of organic matter present and how much hydrocarbon is associated with the TOC. Organic matter decreases as the sediment generates and expels hydrocarbon (Daly and Edman, 1987) (Fig. 8a). This means the TOC and S2 will decrease as the sediment generates hydrocarbons. Therefore, the low amount of organic matter present could result from the mature nature of the organic matter.

Close

Fig. 8

(a) A plot of S2 vs TOC showing hydrocarbon yield potential (b) A plot of HI versus OI showing the type of kerogen (c) A plot of HI vs Tmax showing thermal maturity of the studied samples (d) A plot of PI vs Tmax showing maturity of studied samples.

Export to PPT

5.4 Quality of organic matter

Rock eval-pyrolysis is highly relied on to provide information regarding the type of kerogen (Baskin, 1997; Dembicki, 2016; Espitalie et al., 1977). The data obtained allow the derivation of HI and OI, equivalent to the H/C atomic ratio and O/C atomic ratio, respectively (Baskin, 1997; Espitalie et al., 1977; Peters, 1986). Rock-Eval employs HI and OI plotted on a pseudo-van Krevelen diagram to interpret source quality (Dembicki, 2016). Fig. 8b shows that most of the type II and III samples had low HI and OI. Type I kerogens are generated from lacustrine algal material, generating waxy oil. Type II is also derived from autochthonous organic materials deposited in decreasing marine settings and yields naphthenic oil. Type III is generated by terrestrial plant debris or aquatic organic materials in an oxidizing environment (Tissot et al., 1974). However, Type IV kerogen originates from the alteration or oxidation of organic components in the depositional environment which make it inert (Tissot and Welte, 1984).

Moreover, due to the low S2 and TOC values, the samples plotted in Fig. 8 do not clearly interpret the type of kerogen found in the samples. Therefore, the HI vs S2/S3 classification from (Peters, 1986) provided a clearer kerogen type for the samples. This classification showed that most shale samples would generate oil and gas.

5.5 Maturity of organic matter

Time and temperature increase the reflectivity of vitrinite, which was discovered in coals and later used to determine its rank or thermal maturity (Teichmüller and Teichmüller, 1982). After vitrinite was accepted as a source rock kerogen component, systematic increments in vitrinite reflectance were related to sediment hydrocarbon production history and used as a source rock maturity indicator (Dembicki, 2009; Teichmüller and Teichmüller, 1982). According to the standard interpretations of the phases of hydrocarbon exploration by (Dow, 1977), the samples are in the late oil generation zone. However, samples 1, 4, and 8 had R_o values that were out of range. This could probably occur due to a lack of vitrinite (Dembicki, 2016). Due to a lack of significant contributions from higher plants, some depositional environments could have very low levels of locally sourced vitrinite (Dembicki, 2016).

Furthermore, due to its higher plant origins, vitrinite should not be found in lower Paleozoic and Precambrian Pre-Devonian sediments (Dembicki, 2009). Researchers normally use plots of Tmax versus HI and PI to determine sedimentary rock's hydrocarbon potential and maturity. In addition, Tmax values are extensively used to evaluate the maturity of organic-rich rocks. The Tmax readings, which range from 430 °C to 470 °C, are assumed to be mature source rocks located in the top oil and gas window. (Dorrins et al., 2016). The HI vs Tmax plots in Fig. 8c indicate that most samples have matured to the extent that they have formed oil, wet gas, or dry gas condensate, with only a few in the pre-oil zone. The PI and Tmax plots in Fig. 8d indicate that the kerogen has matured enough to form hydrocarbon.