Accepted Manuscript

Hydrocarbon source potential of Eocene-Miocene sequence of Western Sabah,Malaysia

Wan Hasiah Abdullah, Olayinka Serifat Togunwa, Yousif M. Makeen, Mohammed HailHakimi, Khairul Azlan Mustapha, Muhammad Hafiz Baharuddin, Say-Gee Sia, FelixTongkul

PII: S0264-8172(17)30077-6

DOI: 10.1016/j.marpetgeo.2017.02.031

Reference: JMPG 2838

To appear in: Marine and Petroleum Geology

Received Date: 2 October 2016

Revised Date: 25 February 2017

Accepted Date: 26 February 2017

Please cite this article as: Abdullah, W.H., Togunwa, O.S., Makeen, Y.M., Hakimi, M.H., Mustapha,K.A., Baharuddin, M.H., Sia, S.-G., Tongkul, F., Hydrocarbon source potential of Eocene-Miocenesequence of Western Sabah, Malaysia, Marine and Petroleum Geology (2017), doi: 10.1016/j.marpetgeo.2017.02.031.

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Hydrocarbon source potential of Eocene-Miocene sequence of Western Sabah, Malaysia

Wan Hasiah Abdullah1,*, Olayinka Serifat Togunwa1, Yousif M. Makeen1, Mohammed Hail

Hakimi2, Khairul Azlan Mustapha1, Muhammad Hafiz Baharuddin1, Say-Gee Sia3, Felix

Tongkul4

1 Department of Geology, University of Malaya, 50603, Kuala Lumpur, Malaysia 2 Geology Department, Taiz University, 6803 Taiz, Republic of Yemen

3Minerals and Geoscience Department Malaysia, 20th Floor, Tabung Haji Building, Jalan Tun Razak, 50658 Kuala Lumpur, Malaysia

4Geology Programme, Faculty of Science and Natural Resources, Universiti Malaysia Sabah, Malaysia E-mail: wanhasia@um.edu.my; wanhasia@hotmail.com

Abstract

An evaluation of the petroleum generating potential of onshore Eocene-Miocene sequences of

Western Sabah, Malaysia was performed based on organic petrological and geochemical

methods. The sequences analysed are the Belait, Meligan, Temburong and West Crocker

formations of western Sabah. The Belait Formation which is Stage IV equivalent in the

offshore represents one of the major source rock/reservoirs of the petroleum-bearing Sabah

Basin. The Eocene-Early Miocene West Crocker and Temburong formations are deepwater

turbidites whilst the Miocene Meligan and Belait formations are shallow marine fluvio-deltaic

deposits. The vitrinite reflectance and pyrolysis Tmax values show that the Belait samples are

generally immature for hydrocarbon generation, whereas the Meligan, Temburong and West

Crocker samples are in the mature to late maturity stage of hydrocarbon generation. The

overall bulk source rock properties of the Belait and Meligan show fair to good petroleum

source rock potential with TOC more than 1 wt. %, hydrocarbon yield in the range of 400-

1300 ppm and moderately high HI for many of the samples. Most of the samples representing

the Temburong and West Crocker formations have TOC less than 1 wt.% and have no to fair

hydrocarbon generating potential. Interestingly, the samples collected in the West Crocker

Formation characterized by slump deposits (MTD) have TOC >2 and possess good to

excellent hydrocarbon generating potential. The organic matter present in all of the studied

formations is mainly of terrigenous origin based on the abundance of woody plant materials

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observed under the microscope. Consequently, the analysed sequences are predominantly gas

prone, dominated by Type III and Type III-IV kerogen except for minor occurrence of mixed

oil-gas prone Type II-III kerogen in the Belait Formation and in the slump mass transport

deposits (MTD) of the West Crocker Formation.

Keywords: hydrocarbon rock source potential; onshore Western Sabah, terrigenous organic

matter; deepwater slump mass transport deposit (MTD).

1. Introduction

Estimation of hydrocarbon source potential by characterisation of the dispersed

organic matter (phytoclasts) or kerogen using geochemical and petrological techniques has

become an integral part of hydrocarbon exploration in frontier basins (Tissot and Welte, 1984;

Hunt, 1996; Peters et al., 2005). This involves identifying the potential source rocks,

measuring the total amount of organic matter present, the type and quality of the organic

matter and the level of thermal maturity attained (Dow, 1977; Hunt, 1996; Peters et al., 2005).

The integration of organic petrological and organic geochemical analyses was performed in

this study. The study area is situated within the onshore Sabah Basin in the western part of

Sabah.

Western Sabah Basin, located in the northwestern part of the Borneo Island, in

particular the offshore region, is one of the most prolific oil-producing basins in Malaysia and

it has been explored for more than one hundred years since the first oil seeps were reported

from the Klias peninsula (Leong, 1999). The source of the hydrocarbons has been investigated

by a number of workers: Abdul Jalil and Mohd Jamaal (1992); Azlina Anuar and Abdul Jalil

(1997); Mazlan et al. (1999), Azlina Anuar et al. (2003); Algar (2012); and Abdullah et al.

(2014). The analysed samples have been grouped into the Eocene-Early Miocene deepwater

turbiditic sequences (West Crocker and Temburong formations) and the Miocene shallow

marine fluvio-deltaic sequences (Meligan and Belait formations). The sedimentary units

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deposited during the Middle to Late Miocene are of primary importance as hydrocarbon

source and reservoir rocks in the western part of the Sabah Basin. The search for commercial

petroleum is focused in the clastic reservoirs of Middle to Late Miocene (Stage IVA-D) in the

offshore areas (Scherer, 1980; Abdul Jalil and Mohd Jamaal, 1992; Azlina Anuar, 1994;

Azlina Anuar and Abdul Jalil, 1997). Minor oil and gas accumulated in Early Miocene (Stage

III) sands (e.g. Pondu-1 well) and oil seeps occurs in the onshore Kudat Formation (Stephens,

1956). Based on geochemical evidence, the origin of the oils is terrigenous organic matter

(e.g. Azlina Anuar and Kinghorn, 1994, Algar, 2012). The occurrence of substantial

hydrogen-rich allochthonous organic matter within the deep water marine sequences in NW

Sabah as reported by Algar (2012) prompted the need to reevaluate the source rock

characteristics in the older sequences such as the deep water marine Temburong and West

Crocker formations and being amongst the main focus of this study.

In the eastern Borneo region such as in the deepwater Kutei Basin (Lin et al, 2005,

Saller et al., 2006) and also in Northwest Sabah (Algar and Waples , 2005; Abdullah et al.,

2014; Zakaria et al., 2013), organic matter is described to be entrained within the sands in the

turbidity currents transported from the shelf as MTDs (mass transport deposits) that also

contain oil-prone organic matter which may act as potential source rocks for liquid

hydrocarbons (Azlina Anuar et al., 2003; Algar and Waples, 2005; Algar, 2012; Abdullah et

al., 2014).

In this study, the petroleum source rock potential was evaluated using organic

geochemical and petrological techniques. The type and quantity of organic matter were

determined and their thermal maturity was assessed. The study area is located in the western

part of Sabah as shown in Fig. 1. The major outcrop locations (GPS coordinates shown in

Table 1) are in Klias Peninsula, Sipitang, and Kota Kinabalu (KK) areas. This region

developed as a Neogene foreland basin and the study of its modern coastline can be

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considered as an analogue for clastic depositional systems of ancient foreland basins (Cullen,

2010).

2. Geological background

The geology of the western part of Sabah, especially its sedimentology, has been well

studied by previous researchers (e.g Tongkul, 1989; Crevello, 2006; Jackson et al., 2009; Tan,

2010; Lukie and Balaguru, 2012; Lambiase and Cullen, 2013). The tectonic evolution of

Sabah is complex. Extensive study on basin evolution has been performed by various authors,

namely Tongkul (1991; 1997), Tan and Lamy (1990), Hutchison (1996), Balaguru and

Nichols (2004), Balaguru and Hall (2009) and Hall (2013). A summary was presented by

Mazlan et al. (1999) in the Petroleum Geology and Resources of Malaysia book published by

PETRONAS. Fig. 2 shows a simplified stratigraphy of the offshore and onshore sequence of

West Sabah.

The Paleogene regional tectonic setting of Sabah region is very complex, with

southeasterly subduction of the proto-South China Sea in NW Borneo (Hall 1996) followed

by a period of continued deposition of deep marine turbidites of the Rajang Group. The

Rajang Group is a widespread association of Late Cretaceous to Eocene deep water

mudstones and turbiditic sandstones which include the Sapulut, Trusmadi and East Crocker

formations. All of them are thought to have been deposited in the large NE-SW trending

Crocker Basin and all are highly deformed with tight isoclinal folds and thrusts (Hutchison,

1996). The Palaeogene was therefore a period of continued deposition of deep marine

turbidites. The strongly deformed turbiditic Rajang Group was interpreted by Hutchison, 1996

as a part of an accretionary prism related to southeasterly subduction of the proto-South China

Sea in the NW Borneo. The Late Eocene tectonic deformation is characterized by folding,

thrusting and regional uplift related to the collision of the Luconia Continental Block with

NW Borneo (Sarawak Orogeny; Hutchison, 1996). An unconformity within the succession of

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Palaeogene turbidites between the Middle and Upper Eocene (Fig. 2) is inferred by Rangin et

al. (1990) on the evidence of reworking of nannofossils, and Hutchison (1996) also argues

that the West Crocker Formation includes detritus from uplifted and eroded Rajang Group and

East Crocker Formation rocks (Fig. 2). Hutchison (1996) refer to this uplift as the ‘Sarawak

Orogeny’ and suggested it was probably driven by collision along the northern Borneo margin

at this time. The unconformity is generally difficult to recognize in outcrop in Sabah because

of similarities in lithologies either side of it, and because of the strong Neogene deformation.

Following the Late Eocene deformation, uplift and erosion of the Rajang Fold-Thrust

Belt provided a source of sediment for the Borneo trough to the NW and also the SE where

material was deposited in a deep water setting that formed the West Crocker and Temburong

formations in western Sabah (Fig. 2). The fold-thrust belt of the West Crocker Formation,

which is well exposed in western Sabah, represents the accretionary complex related to

continued southeasterly subduction of the proto-South China Sea in the NW Borneo

(Balaguru and Hall, 2009).

This Early Miocene (22-20 Ma) deformation, resulted by an arc-continent collision in

the northern Borneo between the Cagayan Arc and Palawan Continental Block (Hall, 2013), is

a major tectonic event. It deformed and elevated much of Sabah and produced a major

regional unconformity (Fig. 2), namely the Top Crocker Unconformity (TCU) (Hall, 2013).

Prior to this intense deformation, widespread carbonates (Burdigalian limestone) were

deposited (Leong, 1999).

This period was followed by a change in depositional environment from deep-water

clastics to a shallow-water deltaic setting of the Meligan Delta (Stage III) (Tongkul, 1994;

Leong, 1999; Hall, 2013; Gartrell et al., 2011). All of offshore Sabah was under slope- to

deep-marine conditions during Early Miocene to early Middle Miocene time.

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The collision and cessation of South China Sea spreading gave rise to an

unconformity, the Middle Miocene (15.5 Ma) Deep Regional Unconformity (DRU) (Fig. 2),

which separates the Meligan Delta from the overlying middle to late Miocene Champion

Delta (Stage IV-ABC) (Tongkul, 1994; Leong, 1999; Gartrell et al., 2011; Hall, 2013). This

stage generally is characterized by coastal aggradation and progradation sequences

comprising the onshore outcrop equivalents of the Belait Formation of NW Sabah. The Belait

Formation is dominated by fluvio-deltaic sandstones with laterally equivalent coastal plain to

marine sandstone successions that comprise the topsets of the Champion Delta depositional

system with stacked sequences (from bottom to top) of fluvial sands, marginal marine

(estuarine and deltaic) and shoreface deposits (van Hattum et al., 2006; Hall et al., 2008).

2.1 A brief petroleum system overview

In this section we present a brief petroleum system overview of the Sabah Basin. A

detailed petroleum system analysis of the Sabah Basin has been presented by Mazlan et al.

(1999). Hydrocarbons in the offshore equivalent of the study area are found mainly in the

Stages IVA, IVC, and IVD (Tongkul, 1994; Leong, 1999; Gartrell et al., 2011; Hall, 2013).

The occurrence of onshore oil seepages in the NW Sabah Province is evidence for a viable

petroleum system in the vicinity of the study area, although the area is still relatively poorly

explored (Mazlan et al., 1999).

Source rocks

Hydrocarbons in various parts of the Sabah Basin are very similar in composition and

appear to have originated from source rocks rich in mainly terrigenous organic matter

(Scherer, 1980; Abdul Jalil and Mohd Jamaal, 1992; Azlina Anuar, 1994; Azlina Anuar and

Abdul Jalil, 1997). The source rocks are most likely within Stage IV sequences, as inferred

from the observation that the older deep marine shales are generally lean and thermally over-

mature (Mazlan et al., 1999). Widespread erosion of the NW Sabah margin during the early

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Middle Miocene and the extensive accumulation of the stage IV siliciclastic wedge, resulted

in deposition of source beds that are rich in terrigenous organic matter, interbedded with sand

prone reservoir facies (Mazlan et al., 1999). Source rock preservation in the Sabah Basin is

the result of the high input of terrigenous organic matter and high sedimentation rates and

seemingly not due to anoxicity (Azlina Anuar, 1994; Azlina Anuar and Abdul Jalil, 1997).

Coaly and carbonaceous shales are the most prolific source rocks in the Sabah basin because

of their abundance in large volumes (>2000m thick in some areas).

Reservoirs, traps and seals

The hydrocarbon generic reservoirs in the Sabah Basin are predominantly siliciclastic.

Good quality reservoirs are formed by coastal to fluvio-marine and stacked shallow marine

sandstones. Moreover, the marine turbidites in stages IVC/IVD also form thick, high–quality

reservoirs (Mazlan et al. , 1999). Carbonate reservoirs, although a minor component, have fair

to excellent reservoir quality. These carbonate mounds and reefs occur on the Kudat Platform

in the Northern Sabah Province. Most of the hydrocarbons occur in complex wrench-induced

faulted anticlines, rollover anticlines associated with growth faults, and other fault-related

closures. The main structural traps in the western Sabah are fault propagation folds and fold

anticlines (Scherer, 1980). The hydrocarbons generally migrate through faults and within beds

(Nor Azidin et al., 2011). The seal in NW Sabah is mainly provided by intraformational shale

and mudstone with effective top and flank seals in many proven accumulations (e.g. Erb

West, Kinabalu, St Joseph fields). In some places, shale filled slump scars and shale diapirs

act as seal (Mazlan et al. , 1999).

3. Methodology

The methods adopted in this research include fieldwork and laboratory studies. The

laboratory studies can be grouped into organic petrological and geochemical analyses.

3.1. Fieldwork and sampling

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Field study was carried out in Klias Peninsula, Kota Kinabalu, Beaufort and Sipitang

areas of West Sabah. The locations of representative outcrops were plotted on the map (Fig.

1B) with an aid of a Global Positioning System (GPS). The sample descriptions are shown in

Table 1. The assignment of the formations was done based on published information from

past researchers (e.g Tongkul, 1994, Tan, 2010). Sampling was limited to well preserved

exposures and much care was taken during sampling to avoid contamination and weathered

outcrops. Organic matter is known to be degraded and partly lost as a consequence of

weathering, however it was reported that large differences in OM composition do not develop

between weathered and unweathered shales (Petsch et al., 2000). Nevertheless any organic

geochemical data obtained from surface samples ought to be interpreted with caution as

earlier studies have reported on effects of weathering on organic matter in sedimentary rocks

(e.g. Leythaeuser, 1973; Clayton and Swetland, 1978; Littke et al., 1991).

3.2. Organic petrographic analyses

Organic petrographic analyses performed in this study involved the use of a LEICA

CTR 6000 photometry microscope. Prior to microscopic analysis, rock samples were crushed

into small pieces (2-3mm) using pestle and mortar. Samples were then embedded in 30 mm

latex moulds with liquid epoxy resin and hardened for 48 hours at 30°C. Samples were then

gradually ground with 350, 550, 800, 1200 silicon carbide papers and finally polished with

1µm alumina powder-deagglomerate, 0.3 µm alumina powder-deagglomerate, and 0.04 µm

OP-suspension solution.

Microscopic study was performed under reflected white light and UV light excitation.

Measurement of vitrinite reflectance was carried out using Diskus Fossil software under

reflected white light, with a x50 oil immersion objective using immersion oil with a refractive

index (ne) of 1.518 at 23°C. Reflectance measurements were determined in the random mode

on vitrinite maceral at a wavelength of 546 nm, and the values reported (%Ro) are arithmetic

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means of at least 25 measurements per sample. Vitrinite reflectance values for main phase of

oil generation ranges from 0.6% to 1.3 % Ro and values greater than 2.0 %Ro indicate dry gas

generation (Tissot and Welte, 1984; Teichmüller et al., 1998; Killops and Killops, 2005).

3.3. Organic geochemical analyses

Source Rock Analyzer (SRA)

The rock samples were crushed to less than 200 mesh and analysed using (SRA-

Weatherford)-TOC/TPH instrument (equivalent to Rock Eval equipment) to assess organic

matter richness, kerogen type and maturation of the organic matter in the rocks. Pyrolysis

analysis was performed on approximately 100 mg crushed samples heated to 600oC in a

helium atmosphere. Several parameters were measured, including S1, S2, S3 and temperature

of maximum pyrolysis yield (Tmax). TOC was also determined using the SRA instrument.

Hydrogen index (HI), Oxygen index (OI), Production yield (PY), and Production index (PI)

were calculated as described by Espitalie et al. (1977) and Peters and Cassa (1994).

Bitumen extraction

Fine powdered rock samples were extracted in a Soxhlet apparatus for 72 hours using

an azeotropic mixture (93:7) of dichloromethane and methanol. Metallic copper was added to

the flask during the extraction process to remove the elemental sulphur and anti-bumping

granules was added. Once the extraction procedure was completed, the solvent was removed

using a rotary evaporator under low pressure. The recovered fractions were air dried and the

weight was measured and recorded as the extractable organic matter (EOM) or bitumen yield.

Subsequently, the extractable organic matter (EOM) was separated into saturated and

aromatic hydrocarbons and polar compounds (NSO) by column chromatography on neutral

alumina over silica gel. A chromatographic column (length/width ratio 50:1) was slurry

packed with activated silica gel and aluminum oxide using petroleum ether. Aliphatic,

aromatic and polar (NSO) fractions were eluted with petroleum ether (100 ml),

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dichloromethane (100ml), and methanol (50 ml) respectively. The solvent was distilled off

using rotary evaporator to about 3 ml and thereafter transferred into a weighed clean vial. The

remaining solvent was removed under a flow of nitrogen gas at a temperature below 50°C.

the recovered yields (in ppm of whole rock) are as shown in Table 3.

Pyrolysis-GC

The Pyrolysis-gas chromatographic (Py-GC) method used is based on Larter (1984) quickly

heating of samples at 600 °C whereby the total evolved hydrocarbons can be monitored as a

function of temperature. The pyrolysis GC analysis is carried out on the isolated kerogen

using a Frontier Lab Pyrolyser System which performed thermal desorption from 40 to 300°C

and pyrolysis at 600°C. The system is coupled to an inert (quartz and Ultra ALLOY-5), 30 m,

0.25 mm internal diameter column fitted to an Agilent GC chromatography equipped with a

flame ionization detector. The identification of peaks is based on reference chromatograms

and was done manually by comparison to published data (e.g. Dembicki et al., 1983; Harry,

2008; Dembicki, 2009).

4. Results and discussion

The results of the analyses are presented in the following sections and their relevance

to petroleum source potential is discussed.

4.1. Petrographic description

A brief petrographic description of the analysed samples is given below and examples of

photomicrographs relevant to this study are shown in Figure 3 a-h. The organic matter content

of the Belait Formation samples is dominated by vitrinite phytoclasts (Fig. 3a-b). The

phytoclasts are often associated with bitumen staining, and pyrite occurrence is fairly

common (Fig. 3a).

The phytoclast content of the analysed Meligan Formation samples is also dominated by

vitrinite phytoclasts, but was relatively poorly preserved compared to that of the Belait

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Formation samples. The vitrinite is mostly pitted in appearance and commonly rimmed with

bitumen staining (Fig. 3d). This pitted appearance is considered to be due to the past presence

of inclusions of mineral matter or soluble organic matter that have since been removed during

diagenesis. They are not regarded as a consequence of weathering as no oxidation rim was

observed to be present either microscopically or macroscopically. When observed under UV

light, yellow fluorescence was observed in the matrix associated with strong bitumen staining

(Fig. 3c). Vitrinite is also the dominant phytoclast in the West Crocker Formation samples,

including the slump MTD samples (Fig. 3e-f). Under UV light excitation, yellow to yellow-

orange fluorescing amorphous organic matter was commonly observed (Fig. 3e). The samples

with fluorescing amorphous organic matter imply a Type II kerogen and are expected to

generate oil (Hunt, 1996; Hakimi and Abdullah, 2013; Makeen et al., 2015).

On the other hand, vitrinite and other phytoclast occurrences are sparse in the Temburung

Formation samples (Fig. 3g-h). Although devoid of structured organic matter, an occasionally

dull fluorescing matrix indicative of high thermal maturity can be observed (Fig. 3h). This is

in agreement with the vitrinite reflectance data as discussed in the following section.

4.2. Organic matter richness and hydrocarbon generative potential

The organic richness of a rock is usually expressed as the total organic carbon (TOC)

content in wt%. The minimum acceptable TOC value for clastic type rocks indicating good

source potential is 1.0% (Peters and Cassa, 1994., Hunt, 1996). There is variation in TOC in

the shaly and sandy facies of the studied formations. However this was not attributed to

weathering effects (see methodology section), as supported by petrographic observation. Most

of the sandy facies in the studied formations have higher TOC than the shaly facies except in

the Temburong Formation, where the shaly facies have higher TOC content (Table 2). Belait

Formation samples have TOC values ranging from 1.05 - 7.87 wt. % with mean values of 2.5

wt. % and 4.38 wt. % in the shaly and sandy facies respectively. TOC values in the Meligan

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Formation samples range from 0.98-3.03wt. % with mean values of 2.0 wt. % and 2.19 wt. %

in the shaly and sandy facies respectively. The shaly and sandy facies in the Temburong and

West Crocker formations have mean TOC values of 1.1wt. % and 0.55wt. %, 1.24 wt. % and

5.68 wt. % (Table 2) respectively. Overall, these values indicate that most of the analysed

samples have sufficient total organic carbon content to be source rocks. It ought to be noted

that samples of relatively higher thermal maturity would have originally possess higher TOC

values compared to its present day value as TOC content are known to decrease with increase

in thermal maturity (Dembicki, 2009).

Moreover, the amount of the S2 pyrolytic hydrocarbon generated during pyrolysis is a useful

parameter to evaluate the hydrocarbon generation potential of source rocks (Peters, 1986;

Bordenave, 1993). A minimum of 5 mg HC/g S2 is required to have good hydrocarbon

generating potential (Peters, 1986; Bordenave, 1993). Generally, the hydrocarbon (S2) yields

range from 0.31-12.8 mg/g, 0.20-1.99 mg/g, 0.19-0.59 mg/g, and 0.02-35.83mg/g (Table 2) in

the Belait, Meligan, Temburong and West Crocker Formations respectively. From the cross

plot of total organic carbon (TOC) content and pyrolysis S2 yields shown in Figure 4, it can be

deduced that the Belait Formation samples have ‘poor to very good’ hydrocarbon generation

potential. The Meligan Formation samples have ‘poor to fair’ hydrocarbon generating

potential, with the majority of these samples being poor. The Temburong Formation shows no

to poor hydrocarbon generating potential. Most of the samples in the West Crocker Formation

possess poor hydrocarbon generating potential except some of the slump MTDs facies that

shows fair to excellent hydrocarbon generating potential.

Distinguishing between migrated hydrocarbons/contaminants and indigenous hydrocarbons

can be done using the migration index (S1/TOC) as suggested by Hunt (1996). According to

Hunt (1996), when S1 is high and the TOC is low, migrated hydrocarbons are indicated.

Figure 5 represents the plot of S1 versus TOC for the analysed samples in this study. It is clear

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from this plot that the hydrocarbons in the studied Belait, Meligan, Temburong and West

Crocker formation samples are all indigenous (Fig. 5).

4.3. Organic matter quality (Kerogen Type)

Kerogen types in the Belait, Meligan, Temburong and West Crocker formations were

evaluated based on their Hydrogen (HI) and Oxygen (OI) indices. The Hydrogen Index (HI)

value ranges are 18-163 mg HC/g TOC, 19-66 mg HC/g TOC, 17-54 mg HC/g TOC, and 2-

337 mg HC/g TOC (Table 2) in the Belait, Meligan, Temburong and West Crocker

formations samples respectively. Based on these pyrolysis data, kerogen classification

diagram were constructed using modified van Krevelen diagrams of HI versus OI, as well as

HI vs Tmax plots (Figs. 6 and 7). Type III and IV kerogens are the dominant kerogen types

within the studied formations except for a MTD sample in the West Crocker Formation with

HI value of 337 mg HC/g TOC indicative of Type II-III kerogen (Fig. 7). This is further

supported by the dominance of vitrinitic phytoclasts with common occurrence of fluorescing

amorphous organic matter in the MTD samples as can be observed in Figure 3e. The type of

kerogen has also been classified using the S2 versus TOC plot as shown in Figure 8 and shown

to be in good agreement with the interpretation based on the van Krevelen diagram. Thus, the

MTD samples can be considered as oil-prone source rocks, although only one sample has

relatively high HI (> 300 mg HC/g TOC). Nevertheless, occurrence of fluorescing

amorphous organic matter is commonly observed (e.g. Figure 3a).

4.4. Thermal maturity of organic matter

Vitrinite reflectance values range from 0.43 to 0.46 %Ro for the Belait

Formation samples (Table 2) and indicate thermal maturity. The vitrinite reflectance values

for Meligan, Temburong and West Crocker formations samples ranges are 0.69-0.87% Ro,

0.99-1.14% Ro, 0.79-1.14% Ro respectively (Table 2), and this indicates they are thermally

mature.

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The Belait Formation samples have pyrolysis Tmax values in the range of 418-437°C (Table 2)

indicating immature to very early maturity level for hydrocarbon generation. The pyrolysis

Tmax values in the Meligan Formation samples range from 444 to 472 °C (Table 2) indicating

peak of oil generation and late oil window level of maturity. The Temburong and West

Crocker formations samples have Tmax values in the range of 474-497°C and 450-515°C

(Table 2), respectively indicating over-maturity for the Temburong Formation and peak of oil

window to over-maturity for West Crocker Formation samples. This is supported by the plot

of present day HI versus pyrolysis Tmax as shown in Figure 7. There is also a good agreement

with the measured vitrinite reflectance data, as illustrated by a good correlation between Tmax

and VR data (R2=0.817) (Fig. 9).

The maturity of organic matter can also be expressed by its production index (PI),

which is defined as the ratio of the amount of hydrocarbons already generated to the total

amount of hydrocarbons that the organic matter is capable of generating (Tissot and Welte,

1984; Peters and Cassa, 1994). As reported by these authors, samples with PI values less than

0.05 indicate immature organic matter and have generated little or no petroleum. The value

reaches about 0.05-0.10 at the bottom of the oil-window (beginning of the wet gas zone) and

increases to 1.0 when the kerogen hydrocarbon generative capability has been depleted.

Among the analysed samples, lowest PI values (range from 0.02-0.17) were obtained from the

Belait Formation indicative of low maturity (Table 2) thus in agreement with the pyrolysis

Tmax and vitrinite reflectance data. On the other hand, the Meligan, Temburong and West

Crocker samples showed variable values (range from 0.0-0.49) that can be considered

anomalous. The reason for this inconsistency is unknown, however it may be due to the nature

of the kerogen type in association with variation in lithology in which it occurred as well as

the state of preservation of the organic matter. The four samples from Meligan, Temburong

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and West Crocker formations with anomalous values (have low PI values with very high

Tmax) are as shown in Fig. 10.

4.5. Extractable organic matter and hydrocarbon yield

Bitumen obtained by extraction of whole rocks (EOM) can provide organic matter

richness and maturity information (Tissot and Welte, 1984). The summary of the extractable

organic matter (EOM) together with the relative proportion of petroleum fractions is shown in

Table 3. The EOM contains a complex mixture of hydrocarbons and non-hydrocarbon

components (Figure 11). The saturated and aromatic fractions together make up the

petroleum-like hydrocarbon fraction; thus, the sum of these two fractions is referred to as

hydrocarbons (HCs), whereas the NSO (nitrogen sulphur oxygen) non-hydrocarbon

components (Table 3). Detailed compositional analysis of EOM in conjunction with bulk

kerogen types that generated from pyrolysis HI data yields the necessary information to make

at least semi-quantitative predictions about the amount of petroleum which has been or will be

generated by a given amount of source rock (Ahmed et al., 2004). Peters and Cassa (1994)

classified the potential of source rocks using their EOM (wt %) content as Poor, Fair, Good,

and very good when they contain < 0.05, 0.05-0.1, 0.1-0.2, and > 0.2 wt %, respectively. The

EOM yields range from 0.10-0.22 wt.%, 0.09-0.20 wt.%, 0.03-0.07 wt.%, and 0.07-0.41 wt.%

(Table 3) in the Belait, Meligan, Temburong and West Crocker formations, respectively. This

indicates that the hydrocarbon generation potential is fair to good in Belait and Meligan

formations, poor to fair in Temburong Formation and poor to very good in West Crocker

Formation samples. This is in good agreement with S2 and TOC relationship discussed earlier

and as shown in the cross plot of TOC (%) versus EOM (ppm) in Figure 12.

The hydrocarbon portion (Saturated + Aromatic) of the bitumen extracted from sediment is

the petroleum-like portion, and is also an important parameter in assessing the hydrocarbon

generating potential (Peters and Cassa, 1994). Based on classification by Peters and Cassa

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(1994), the analysed Miocene Belait and Meligan samples possess fair to good hydrocarbon

generating potential, having hydrocarbon yields of about 400-1300 ppm. In general, lower

hydrocarbon yields were obtained from the analysed Eocene-Oligocene Temburong and West

Crocker samples, except for the slump mass transport (MTD) samples from West Crocker

Formation. These MTD samples yielded a relatively higher amount of aliphatic fraction

compared to the other analysed samples (Fig. 11). This is indicative of the oil-prone nature of

the analysed MTD samples which is also supported by the pyrograms that are dominated by

n-alkene/alkane doublets (Fig 13).

EOM fractions can also be used to determine the level of maturity. Polar compounds

(NSO) tends to be abundant in immature organic matter as recorded in Belait Formation

samples (Figure 11), and decrease with increasing maturity. On the other hand, the proportion

of aromatic increases with maturity (Fig. 11). Although aromatic hydrocarbons are known to

be influenced by kerogen type and were affected by weathering (Littke et al., 1991), they also

change with increasing thermal maturity as reviewed by Radke (1987). In this study, the

increase of aromatic hydrocarbons appears to be influenced by the level of thermal

maturation.

4.6. Kerogen pyrolysis (Py-GC)

Hydrogen and oxygen indices (HI and OI) based on pyrolysis using SRA equipment

do not always accurately represent the types of kerogen present and types of hydrocarbon that

may be generated by the source rocks (Dembicki, 2009; Abbassi et al., 2016).

The application of Rock-Eval and/or SRA techniques can provide more accurate

assessments of kerogen type when integrated with pyrolysis-gas chromatography (Py-GC)

method (Dembicki, 1993; 2009). The Py-GC analysis provides information regarding the

quantitative chemistry of the thermal decomposition products of the kerogen. This gives a

direct indication of the kerogen types and types of hydrocarbons that can be generated by the

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kerogen during the maturation process (Giraud, 1970; Larter and Douglas, 1980; Horsfield,

1989; Eglinton et. al., 1990; Dembicki, 2009). Behar and Pelet (1985) and Dembicki (2009)

show clearly how the three main types of kerogen can be distinguished by the carbon number

distribution of n-alkanes. These authors stated that Type I kerogen pyrogram contain large

amounts of n-alkanes and n-alkenes in C20-C30 range, whereas a Type III pyrogram shows

most products in the <C10 fraction.

The fingerprints observed in the analysed kerogen samples from the studied

formations (Fig. 13) indicates the dominance of gas prone Type III kerogen characterized by a

dominance of aromatic compounds over n-alkene/alkane doublets whilst the Temburong

Formation, shows Type IV kerogen fingerprints which could be attributed to original source

input and/or condition of deposition. It is interesting to note that some of the MTD samples

from the West Crocker Formation display Type II kerogen with dominance of n-alkene/alkane

doublets over aromatic compounds. This is broadly further supported by the ternary diagram

as defined by Larter (1984) that has been applied to assess the kerogen characteristics by

using the relative percentage of three pyrolysates compounds (m-p-xylene, phenol, and n-

octene) (Fig. 145) whereby aliphatic been represented by n-octene, aromatic by m+p xylene

and phenolic represented by phenol components.

However, in this study, a boundary for the mixed Type II-III kerogen has been

introduced in the original ternary diagram of Larter (1984), as to take into account the

pyrograms of a number of the analysed samples from Belait Formation and the MTDs of the

Crocker Formation which suggest a mixed oil-gas prone characteristic based on pyrograms

shown by Dembicki (2009). Moreover the Py-GC data obtained in this study is in accordance

with the moderately high HI values in particular for the MTD samples and this supported by

the presence of intense amorphous organic matter as observed petrographically (Fig. 3e).

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5. Concluding remarks

Based on organic petrological and geochemical analyses performed in this study to evaluate

petroleum source potential of the Belait, Meligan, Temburong and West Crocker formations

of western Sabah, the results are summarized as follows:

(1) The bulk geochemical results show that the Belait and Meligan samples have fair to

good source rock potential with TOC more than 1 wt. %. In contrast, the majority of

the Temburong and West Crocker formations samples have no to fair source rock

generation potential, consistent with low TOC values (<1 wt.%) except in the slump

mass transport deposits (MTD) in the West Crocker Formation where the shaly facies

has a relatively higher amount of organic matter (TOC >2 wt%). Broadly, the MTD

samples possess fair to excellent source rock generation potential.

(2) The organic matter present in all of the studied formations is mainly terrigenous

derived as indicated from the abundance of woody plant materials, as observed under

the microscope.

(3) The vitrinite reflectance and pyrolysis Tmax values indicate that the Belait Formation

samples are generally immature for hydrocarbon generation whereas the Meligan,

Temburong and West Crocker formations samples are in the mature to late mature-oil

window and oil-generation as expected.

(4) The analysed sequences are predominantly gas prone, being dominated by Type III

and Type III/IV kerogen except for minor occurrence of oil prone Type II/III kerogen

in the West Crocker Formation mass transport deposits (MTD).

(5) The results here suggest that MTD can possess good oil-generation potential, although

it appears to be localized, and thus may act as an oil (in addition to gas) source rock

within deep water settings of Sabah Basin.

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(6) Further investigations are required to include samples of larger size and from other

localities within Sabah that are known to have potential source rocks, in particular the

MTDs, which are of greater interest owing to their apparent oil-prone nature. Other

aspects of analyses, which include biological distribution and palynofacies, would also

be of interest and these have been performed on the samples investigated in this study.

The results of which shall be published in the near future.

Acknowledgement

The authors gratefully acknowledge IPPP, University of Malaya for providing research grants

CG48-2013 and BK085-2016. The constructive comments by Dr J.A. Curiale and Dr. G.

Gambacorta have improved the revised manuscript and are gratefully acknowledged.

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Figure Captions

Figure 1: Geological map of the study area in western Sabah, showing the studied formations

(Belait, Meligan, Temburong and West Crocker formations) and location of the sampling

Figure 2: Generalized stratigraphy of the offshore and onshore Western Sabah (simplified

after Tongkul, 1994; Leong, 1999; Hall, 2013; Gartrell et al., 2011).

Figure 3: (a) Low reflecting vitrinite phytoclast associated with brownish bitumen staining

and high reflecting pyrite under white light; (b) reasonably well preserved vitrinite phytoclast

in a silty shale sample of the Belait Formation as observed under white light; c) weakly

fluorescing bitumen stain rimming poorly preserved vitrinite phytoclasts in a Meligan

Formation sample ; (d) same view as (c) under reflected white light; (e) yellow fluorescing

amorphous organic matter under UV light excitation and in white light (f) is observed to be

commonly associated with vitrinite phytoclast and quartz grains in a slump (MTD) sample of

the West Crocker Formation; (g) Sparse occurrence of vitrinite phytoclasts under reflected

white light and when observed under UV light (h) showed weakly fluorescing matrix in a

Temburong Formation sample. Scale bar for all photomicrographs = 100 µm

Figure 4: Cross plot of total organic carbon (TOC in wt.%) and remaining hydrocarbon

potential (S2 in mg HC/g rock), compared with the reference of Peter and Cassa (1994),

showing the hydrocarbon generating potential of the studied formations.

Figure 5: Cross plot of S1 versus TOC for identifying the migration index of the studied

samples (adapted after Hunt, 1996).

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Figure 6: Modified van Krevelen diagram of Hydrogen index (HI) versus Oxygen index (OI)

showing kerogen quality of the studied formations.

Figure 7: Plot of Hydrogen Index versus Tmax (Mukhopadhyay et al., 1995), showing the type

of kerogen and thermal maturity of the studied samples.

Figure 8: Cross plot of total organic carbon (TOC in wt. %) and remaining hydrocarbon

potential (S2 in mg HC/g rock showing the quality of kerogen in the studied formations.

Figure 9: Correlation plot between pyrolysis Tmax and vitrinite reflectance values of the

studied samples.

Figure 10: Cross-plot of pyrolysis Tmax versus production index (PI), showing the maturation

and nature of the hydrocarbon products of the analysed samples.

Figure 11: Distribution of EOM fractions in the studied samples.

Figure 12: The potential of hydrocarbon generation in a source rock as estimated from TOC

(%) versus EOM (ppm) data, The origin of the fields adapted after Othman (2003).

Figure 13: Pyrolysis GC pyrograms of selected samples showing n-alkene/alkane doublets

and labeled peaks used as kerogen type proxies.

Figure 14: Ternary diagram of the relative percentages m-p-xylene, phenol, and n-octene .

The type fields were modified after Larter (1984).

Tables Captions

Table 1: This table shows the outcrop locations using GPS coordinates and the lithology

description of the samples.

Table 2: Vitrinite reflectance and bulk geochemical characteristics (TOC content, Rock-Eval

pyrolysis) of the studied Belait (BL), Meligan (ME), Temburong (TEM) and West Crocker

(WC) formations. TOC: total organic carbon (wt %), S1: volatile hydrocarbon (HC) content,

mg HC/g rock; S2: remaining HC generative potential, mg HC/g rock; S3: carbon dioxide

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yield, mgCO2/g rock; HI: Hydrogen Index = S2 X 100/TOC, mg HC/g TOC; OI: Oxygen

Index = S3 X 100/TOC, mg CO2/g TOC; PI: Production Index = S1/(S1 + S2); GP: Genetic

Potential=S1+S2 Tmax = Temperature at maximum generation, Ro= Vitrinite reflectance.

Table 3: Extractable organic matter and hydrocarbon yield from the studied samples.

EOM=Extractable organic matter (Bitumen extraction); Sat= Saturated hydrocarbon; Aro =

Aromatic hydrocarbon; HC–Hydrocarbon fractions (Saturated + Aromatic); Non HC– Non-

hydrocarbon fractions (NSO)

Table 4: Py-GC pyrogram quantitative data. C8: n-Octene, Xy: Xylene, Phe: Phenol.

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Table 1

Formation Locality Location Sample ID GPS Coordinates Lithology

Bel

ait

For

mat

ion

Bat

uLua

ng

BL-

A

BL-A2-SH N05.52415,E115.52573 Mudstone

BL-A3-SH N05.52415,E115.52573 Carbonaceous mudstone

BL-A5-SST N05.52415,E115.52573 Organic laminated sandstone

BL-A6-SST N05.52415,E115.52573 Sandstone

BL-A7-SH N05.52415,E115.52573 Mudstone

BL-A8-SST N05.52415,E115.52573 Carbonaceous sandstone

BL-B BL-B1-SH N05.52365,E115.52520 Mudstone

BL-C BL-C2-SH N05.52350,E115.52475 Mudstone associated with coal

Sip

itang

ME-130

ME-130B-SH N05.02157, E115.32355 Mudstone associated with concretions

Mel

igan

F

orm

atio

n

ME-130C-SST N05.02157, E115.32355 Carbonaceous sandstone

ME-130F-SH N05.02157, E115.32355 Mudstone

ME-133 ME-133A-SST N05.00651,E115.33254 Carbonaceous sandstone

ME-133C-SH N05.00651,E115.33254 mudstone

ME-134 ME-134A-SH N05.00651,E115.33254 Coaly mudstone

Sip

itang

-Ten

om

TME-137 TEM-137A-SH --- Dark shale

Tem

buro

ng

For

mat

ion

TEM-137B-SS --- sandstone

TME-138 TEM -138-SH --- Dark shale

TME-139 TEM-139-SH N04.58147,E115.42054 Dark shale

TEM-139-SS N04.58147,E115.42054 sandstone

TME-140 TEM-140-SH N04.58124,E115.42801 Dark shale

Sip

itang

WC-129

WC-129B-SH N0502376,E115.30998 Dark shale

Wes

t Cro

cker

For

mat

ion WC-129E-MTD N0502376,E115.30998 Slumps deposits (silty)

WC-129D-MTD N0502376,E115.30998 Slumps deposits (shaly)

WC-129F-MTD N0502376,E115.30998 Slumps deposits (sandy)

WC-135 WC-135B-SST N04.59835,E115.35441 Carbonaceous sandstone

WC-144 WC-144A-MTD N05.46563,E116.01333 Slumps deposits (sandy)

WC-144B-SH N05.46563,E116.01333 Dark shale

WC-145

WC-145A-SST --- Sandstone

WC-145B-MTD --- Slumps deposits (sandy)

WC-145C-SH --- Dark shale

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Table 2

Formation Sample ID VRo (%)

TOC Wt.%

S1 (mg/g)

S2 (mg/g)

S3 (mg/g)

Tmax (°C) HI OI GP PI S1/

TOC

Bel

ait

For

mat

ion

BL-A2-SH 0.46 1.71 0.03 0.31 0.76 435 18 45 0.34 0.08 0.02

BL-A3-SH 0.44 5.03 0.16 5.19 2.26 428 103 45 5.35 0.03 0.03

BL-A5-SST 0.45 4.18 0.09 5.29 1.07 426 126 26 5.38 0.02 0.02

BL-A6-SST 0.46 1.08 0.06 0.39 0.47 437 36 44 0.45 0.13 0.05

BL-A7-SH 0.43 1.05 0.02 0.25 0.55 431 24 53 0.27 0.08 0.02

BL-A8-SST nd 7.87 0.58 12.8 2.58 418 163 33 13.38 0.04 0.07

BL-B1-SH 0.44 2.27 0.27 3.18 0.59 431 127 23 3.45 0.08 0.12

BL-C2-SH 0.45 1.19 0.08 0.39 0.50 432 33 42 0.47 0.17 0.07

M

elig

an

For

mat

ion

ME-130B-SH 0.87 0.98 0.04 0.20 nd 458 20 nd 0.24 0.17 0.04

ME-130C-SS 0.74 1.34 0.03 0.25 0.42 460 19 32 0.28 0.11 0.02

ME-130F-SH 0.69 2.85 0.22 0.64 0.48 444 22 17 0.86 0.26 0.08

ME-133A-SS 0.72 3.03 0.07 1.99 0.49 452 66 16 2.06 0.03 0.02

ME-133C-SH nd 1.77 0.15 0.99 0.56 471 56 32 1.14 0.13 0.09

ME-134A-SH 0.71 2.42 0.19 1.05 nd 472 43 nd 1.24 0.15 0.08

T

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rong

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orm

atio

n

TEM-137A-SH 1.08 1.1 0.07 0.59 0.17 492 54 15 0.66 0.11 0.06

TEM-137B-SS 1.14 0.51 0.17 0.19 nd 497 37 nd 0.36 0.47 0.33

TEM-138-SH nd 1.38 0.03 0.32 0.35 487 23 25 0.35 0.09 0.02

TEM-139-SH nd 1.26 0.02 0.22 nd 490 17 nd 0.24 0.08 0.02

TEM-139-SS nd 0.58 0.01 0.25 0.13 492 43 22 0.26 0.04 0.02

TEM-140-SH 0.99 0.71 0.05 0.32 0.17 474 45 24 0.37 0.14 0.07

Wes

t Cro

cker

For

mat

ion WC-129B-SH 0.79 1.23 0.03 0.18 0.28 455 14 23 0.21 0.15 0.03

WC-129D-MTD nd 1.73 0.44 1.66 0.31 450 96 18 2.10 0.21 0.25

WC-129E-MTD 0.82 2.26 0.08 0.82 0.47 453 36 21 0.90 0.09 0.04

WC-129F-MTD nd 2.4 0.11 0.95 0.24 459 40 10 1.06 0.10 0.05

WC-135B-SST 0.89 3.94 0.07 4.69 0.44 465 119 11 4.76 0.01 0.02

WC-144A-MTD 0.92 10.63 0.09 35.83 0.52 463 337 5 35.92 0.00 0.01

WC-144B-SH nd 1.72 0.01 0.18 0.79 473 10 46 0.19 0.08 0.01

WC-145A-SST nd 0.65 0.01 0.03 0.29 515 5 44 0.04 0.14 0.01

WC-145B-MTD 1.14 6.32 0.06 3.25 0.46 503 51 7 3.31 0.02 0.01

WC-145C-SH nd 1.06 0.01 0.02 0.29 488 2 27 0.03 0.20 0.01 TOC: total organic carbon (wt %), S1: volatile hydrocarbon (HC) content, mg HC/g rock; S2: remaining HC generative potential, mg HC/g rock; S3: carbon dioxide yield, mg CO2/g rock; HI: hydrogen index = S2 100/TOC, mg HC/g TOC; OI: oxygen index = S3 100/TOC, mg CO2/g TOC; PI: production index = S1/(S1 + S2); GP: genetic potential= S1+S2 Tmax = Temperature at maximum generation, VRo= vitrinite reflectance.

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Table 3

Formations Sample ID TOC

(wt.%) EOM

(wt.%) EOM (ppm)

Sat. (%)

Aro (%)

Non-HC (%)

Sat. (ppm)

Aro. (ppm)

Non-HC

(ppm)

HC yield (ppm)

Bel

ait F

orm

atio

n

BL-A2-SH 1.71 0.14 1420 20 32 48 284 454 682 738

BL-A3-SH 5.03 0.22 2210 19 29 52 420 641 1149 1061

BL-A5-SS 4.18 0.21 2082 18 33 49 375 687 1020 1062

BL-A6-SS 1.08 0.10 1005 18 31 51 181 312 513 492

BL-A7-SH 1.05 0.10 1030 18 34 48 185 350 494 536

BL-A8-SS 7.87 0.17 1654 16 32 52 265 529 860 794

BL-B1-SH 2.27 0.19 1850 17 31 52 315 574 962 888

BL-C2-SH 1.19 0.11 1050 17 25 58 179 263 609 441

Mel

igan

F

orm

atio

n

ME-130B-SH 0.98 0.14 1420 18 39 43 256 554 611 809

ME-130C-SS 1.34 0.11 1053 15 45 40 158 474 421 632

ME-130F-SH 2.85 0.11 1070 17 43 40 182 460 428 642

ME-133A-SS 3.03 0.09 852 20 47 33 170 400 281 571

ME-133C-SH 1.77 0.20 1982 19 48 33 377 951 654 1328

ME-134A-SH 2.42 0.16 1580 16 46 38 253 727 600 980

Tem

buro

ng

For

mat

ion

TEM-137A-SH 1.10 0.03 620 16 56 28 99 347 174 447

TEM-137B-SS 0.51 0.04 545 14 57 29 76 311 158 387

TEM-138-SH 1.38 0.05 582 16 55 29 93 320 169 413

TEM-139-SH 1.26 0.03 683 14 53 33 96 362 225 458

TEM-139-SS 0.58 0.04 642 16 58 26 103 372 167 475

TEM-140-SH 0.71 0.03 550 13 55 32 72 303 176 374

Wes

t Cro

cker

For

mat

ion

WC-129B-SH 1.23 0.07 698 15 58 27 105 405 188 510 WC-129E-MTD 2.26 0.18 1784 37 48 15 660 856 268 1516

WC-129D-MTD 1.73 0.16 1560 36 45 19 562 702 296 1264

WC-129F-MTD 2.40 0.19 1850 37 43 20 685 796 370 1480

WC-135B-SS 3.94 0.18 1058 14 63 23 148 667 243 815 WC-144A-MTD 10.63 0.42 4200 36 42 22 1512 1764 924 3276

WC-144B-SH 1.72 0.07 726 19 63 18 138 457 131 595

WC-145A-SS 0.65 0.08 756 22 65 13 166 491 98 658 WC-145B-MTD 6.32 0.41 4098 41 39 20 1680 1598 820 3278

WC-145C-SH 1.06 0.07 659 17 61 22 112 402 145 514 EOM=Extractable organic matter (Bitumen extraction); Sat= Saturated hydrocarbon; Aro = Aromatic hydrocarbon; HC–Hydrocarbon fractions (Saturated + Aromatic); Non HC– Non-hydrocarbon fractions (NSO+ Asphaltene)

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Table 4

Formation

Sample ID C8 (%)

Xy (%)

Phe (%)

Belait

BL-A3-SH 15 36 49 BL-A5-SS 16 37 46 BL-A6-SS 14 32 54 BL-B1-SH 16 35 49

Meligan

BL-C2-SH 18 55 27 ME-134A-SH 31 55 14 ME-130F-SH 20 47 33 ME-133A-SS 19 54 27

Temburong

TE-139-SH 23 70 7 TE-137A-SH 13 81 6 TE-140-SH 15 81 3

West Crocker

WC-129E-MTD 52 43 8 WC-144A-MTD 53 38 10 WC-145B-MTD 30 61 9 WC-129B-SH 29 63 8 WC-135B-SS 32 56 12

C8: n-Octene, Xy: Xylene, Phe: Phenol

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Highlights:

1. The Belait and Meligan formations generally possess fair to good petroleum source rock

potential.

2. The Temburong and West Crocker formations mostly have none to fair petroleum source rock

potential.

3. The mass transport deposit (MTDs) sequence shows fair to excellent hydrocarbon generating

potential

4. The MTD samples are richer in aliphatic hydrocarbon supported with presence of fluorescing

amorphous organic matter.

5. The proportion of aromatic to aliphatic hydrocarbons of the analysed samples increases with

maturity