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Review

Organic Matter Distribution and Characteristics among Rock Formations in Malaysia: Implications on Hydrocarbon Generation Potential

by
Alidu Rashid
1,*,
Numair Ahmed Siddiqui
1,*,
Cornelius Borecho Bavoh
2,
AKM Eahsanul Haque
1,
Muhammed Usman
3,4,
Sani Ado Kasim
1,
Mohamed A.K. ElGhali
5 and
Syahrir Ridha
6
1
Department of Geoscience, Universiti Teknologi PETRONAS, Seri Iskandar 32610, Perak, Malaysia
2
Chemical Engineering Department, Universiti Teknologi PETRONAS, Seri Iskandar 32610, Perak, Malaysia
3
Laboratory for Provenance Studies, Department of Earth and Environmental Sciences, University of Milano-Bicocca, 20126 Milano, Italy
4
School of Geosciences, China University of Petroleum (East China), Qingdao 266580, China
5
Earth Sciences Research Center, Sultan Qaboos University, Al-Khoudh, Muscat 123, Oman
6
Institute of Hydrocarbon Recovery, Universiti Teknologi PETRONAS, Seri Iskandar 32610, Perak, Malaysia
*
Authors to whom correspondence should be addressed.
Appl. Sci. 2022, 12(19), 9470; https://0-doi-org.brum.beds.ac.uk/10.3390/app12199470
Submission received: 25 July 2022 / Revised: 7 September 2022 / Accepted: 13 September 2022 / Published: 21 September 2022
Browse Figures
Versions Notes

Abstract

:
Numerous studies have been done to determine the hydrocarbon potential of Malaysia’s formations and basins due to the need to identify more conventional or unconventional hydrocarbon resources. Due to the fact that none of these investigations were carried out with any prior knowledge in the relevant regions with hydrocarbon potential, some of them did not, however, yield the expected results. This study aims to provide researchers with all the necessary information about potential hydrocarbon-producing areas in Malaysia and the various lithologies connected to them by analyzing all earlier studies carried out in Malaysia. This was accomplished by determining patterns in the distribution of organic matter and characteristics of the formations in Malaysia. Total Organic Carbon (TOC), Generic Potential (GP), Vitrinite Reflectance (Ro), and Hydrocarbon Yield (S2) were the most important hydrocarbon generation potential indicators discussed. A heat map was created using a statistical weight ranking with a weight of 45% for the TOC value and 30%, 15%, and 10% for the GP, S2, and Ro values, respectively. According to the data, the Bintulu, Pinangah, Begrih, Liang, and Tanjong formations have the highest potential to generate hydrocarbons in Malaysia, while the Kroh, Setap, Kalabakan, Temburong, and Belaga have the least potential. Majority of formations with high hydrocarbon potential are tertiary in age and consist primarily of coal and carbonaceous shale formations. The most promising formations are mostly immature, with type II or type III kerogen quality. It is recommended that critical exploration activities be focused on the tertiary-aged formations, particularly those in East Malaysia, in order to increase Malaysia’s hydrocarbon production.

1. Introduction

Like most Asian countries, Malaysia’s economy depends mainly on oil and gas produced from its current reserves [1]. Most of Malaysia’s hydrocarbon is produced from its petroleum-bearing sedimentary basins, like those in the onshore West Baram Province of North-west Borneo, Neogene Sandakan Formation of North-east Sabah, and the coal-bearing sequence at Batu Arang, and Western Sabah Basin [2,3,4]. Generally, Malaysia’s Western Peninsular area has been least explored for hydrocarbons, compared to the Eastern region, however, all possible petroleum yielding areas should be given much attention due to the decline in conventional resources. Also, due to the decline in hydrocarbon production from conventional reservoirs, more focus has been placed on unconventional reservoirs for hydrocarbon generation [5,6,7].
Currently, in Malaysia, there is a burning and active desire or aim to explore the potential for hydrocarbon production in the eastern and western Malaysia areas, and to discover new conventional and unconventional hydrocarbon basins. Such studies have mainly focused on the known major sedimentary basins, including Penyu, Malay, Sabah, Sarawak, Sandakan, and some parts of the Tarakan basins [8,9,10,11]. There are several stand-alone studies on the source rock potentials of several basins or formations in east and west Malaysia [8,9,12,13,14,15,16]. However, they all fail to provide a holistic insight into Malaysia’s key hydrocarbon generation potential. Therefore, systematic review studies are needed to provide useful state-of-the-art knowledge on the potential of these basins and formations in Malaysia. This would provide new future directions and recommendations toward the discovery of new conventional and unconventional reservoirs.
To fully understand the hydrocarbon potential of formations, it is important to characterize them using geochemical techniques [17,18]. This includes determining the entire amount of organic matter available in the sediments (Source richness), thermal maturity level, and, finally, the type of organic matter (Source quality) [17,19,20]. Source richness deals with the amount of organic matter present in the rocks capable of generating hydrocarbons [19]. According to Ronov [21], the capacity of a rock to generate hydrocarbons depends heavily on the quantity of organic matter available. It is deemed to be a sign of the sediment’s capacity for hydrocarbon generation and not just a measurement of the quantity of organic matter present [19]. Source quality indicates the types of organic matter present in the sediment, giving an idea of the type of hydrocarbons the sediment can generate [19]. As burial depth increases, there is increasing pressure and temperature which cooks the sediments and causes them to lithify and this transforms the organic matter in them to kerogen [22]. Therefore, the thermal maturity parameter indicates the stages of hydrocarbon generation the sediment has undergone [23,24,25]. These three main parameters were used to classify the formations analyzed. It is important to combine several analytical techniques for a more precise source rock evaluation [17]. The analytical techniques often used are Total Organic Carbon (TOC) analysis, Rock-Eval Pyrolysis, and Vitrinite Reflectance analysis [17,25,26,27].
This review reports on almost all the articles in the literature on the source rock potentials in the east and west Malaysia, by systematically providing insight and details on the TOC, generic potential (GP), hydrocarbon yield (S2) and vitrinite reflectance (Ro) of Malaysian formations/basins. For simplicity, the paper categorizes the source rock potential parameters according to the basins’ geographical locations: Peninsula, Sabah, and Sarawak. The findings in this article encourage the discovery of new conventional and unconventional hydrocarbon resources in Malaysia. The data provided in review tables could be used for basin hydrocarbon modeling in Malaysia. Potential green or less studied areas or basins in Malaysia are also discussed in this paper as future research prospects.

2. Geological Setting and Study Area

2.1. Geology of Malaysia

In this study, the formations discussed are scattered across Malaysia. As stated before, Malaysia is generally divided into two main regions, Peninsular Malaysia and East Malaysia. Peninsular Malaysia occupies a total land area of 130,268 km2 [28]. It has a length of 750 km and a breadth of 330 km. It is also known to be elongated in a NNW–SSE direction [28,29]. The Johor Strait and the Straits of Malacca separate Peninsular Malaysia from Singapore Island to its south and western Sumatra Island, respectively (Figure 1). Peninsular Malaysia is a vital part of the Eurasian Plate and it is located at Sunderland, the Southeastern Asian part [28,29]. The Peninsula was formed in the Cenozoic era, and it is known to be tectonically steady, with only a few tectonic activities, like uplifts, movement of faults, tilting, and local gentle down warps [30]. Peninsular Malaysia is divided into three belts: the Eastern belt, the Western belt, and the Central belt. The division is based on the belts’ different geological characteristics [31,32,33]. The Central and Eastern belts of Peninsular Malaysia are split up by the Bentong–Raub suture zone [31,34,35].
The Upper Paleozoic rocks can be seen in the three belts of the Peninsular, while the Lower Paleozoic rocks can only be seen in the Western part of the Peninsular [28]. The following studied rock formations/basins are all located in Peninsular Malaysia; Belata, Semanggol, Kroh, Semantan, Batu Arang, Batu Gajah and the Penyu. All the formations mentioned are in the Western belt of Peninsular Malaysia, except for the Penyu basin, which is in the Central belt (Figure 1). The ages of the formations studied range from the Silurian to the Tertiary periods (Figure 2).
The geology of East Malaysia is divided into two main areas, the Sabah region, and the Sarawak region. Sarawak is subdivided into three tectonostratigraphic zones representing the decreasing stratigraphic and structural complexity towards the east [36,37,38]. The three zones are the Kuching, Sibu, and Miri zones [39,40,41]. The Kuching zone is located in the westernmost Sarawak, west of Batang Lupar [42]. The Kuching zone is thought to be a marginal part of the West Borneo basement, which spreads southwards into Kalimantan [36,43]. The Sibu Zone is located in the center of Sarawak, and it is predominately composed of thick shale–sandstone turbidite sequences accumulated in the oceanic crust [44,45]. The Miri zone is the youngest of the three zones and it is located in the northeast [36]. The Tatau-Mersing line acts as a boundary between the Sibu and Miri zones. The following studied rock formations are all located in the Sarawak region: Bintulu, Belaga, Nyalau, Begrih, Liang, Balingian, Mukah, Lambir, Miri, and Tukau (Figure 1). The ages of the formations studied range from the Middle Cretaceous to Tertiary periods, with most of the formations found in the Miocene epoch (Figure 3a).
Sabah occupies an area of about 76,115 km2 in the northern part of Borneo Island [46,47,48]. It lies next to actively moving plates in the southeast Asia region [49]. The area’s topography is considered rough, particularly on the west coast. Sabah is mainly composed of thick, folded, Upper Cretaceous to Tertiary marine sedimentary rocks, lavas and plutonites, and subordinate Mesozoic metamorphic rocks [46,50,51]. Near the west coast is a distinct mountain range that includes the Palaeogene Crocker formation and other older rock units. It rises to between 3000 to 4000 m above sea level, culminating in the Late Neogene Kinabalu granodiorite intrusion, which peaks at 4101 m [49,50,51]. The following studied rock formations are all located in the Sabah region: Ganduman, Sebahat, Tanjong, Sandakan, Temburong, Pinangah, Beliat, Meligan, West Crocker, Setap, Kapilit, and Kalabakan (Figure 1). All the formations studied in Sabah are found in the Tertiary period, with most of the formations found in the Miocene epoch (Figure 3b).

2.2. Study Area

The study area for this review consisted of all areas in Malaysia where rock formations have been evaluated to determine their potential to generate hydrocarbons. Out of the one hundred and fifty-nine (159) formations in Malaysia, a total of twenty-nine (29) formations from both Peninsular and East Malaysia were analyzed in this study, representing 18% of all the formations in Malaysia. Of the studied formations, 76% were conducted in East Malaysia, while the remaining 24% were in Peninsular Malaysia (Figure 1). Out of the twenty-two formations in East Malaysia, twelve (12) of the formations analyzed were from the Sabah region, and the remaining ten (10) were from Sarawak (Table 1). These formations were chosen based on the studies already done to determine the hydrocarbon generation potential of the said formations. Most of these formations fall under the Tertiary period with the majority under the Miocene epoch. The age of the formations range from the Silurian to Tertiary. The majority of the twenty-nine (29) studied formations were primarily composed of carbonaceous shales and coals. Some of the formations were also composed of mudstone, coaly sandstone, and carbonaceous sandstones.

3. Methodology

Published data on TOC analysis, Rock-Eval Pyrolysis, and Vitrinite Reflectance analysis of the twenty-nine formations (29) in Malaysia were accumulated and analyzed to determine the formations’ characteristics and potentials to generate hydrocarbons. Retrieved data on TOC, GP, S2, and Ro from the analysis mentioned was used for this analysis.
The average of all the data provided by different authors on a particular formation was used to analyze the formation as a whole. Some of the formations without Vitrinite Reflectance (Ro) values from the data accumulated were calculated using the formula [Ro = (0.0149 × Tmax) − 5.85] according to Wust [68]. Even though the Ro formula has limitations, because it may not objectively reflect the actual situation of the various regions within the scope of the study, the formula has been widely used to calculate Ro when no experiment was conducted to determine the actual Ro. In addition, other scholars, such as Ahmed, Shoieb and Owusu [8,12,53], have used it to estimate the Ro of formations in Malaysia. Therefore, this formula sufficed since it is only an estimation of the maturity. Other values, such as HI, PI, and OI, that were not available were calculated using their corresponding formulae [69,70].

Justification for Heat Map

Finally, a heat map was generated to give an idea of all the formations’ hydrocarbon generation potentials using the average weight of the formations’ TOC, GP, S2, and Ro values. A weighted statistical ranking method was used to create the heat map with Forty-five percent weight for TOC value, and thirty, fifteen, and ten for GP, S2, and Ro values, respectively. The weighted ranking percentages were assigned according to the order of importance of the parameters. The weighted statistical ranking score was estimated using the equation below:
R S n = ∑ i = 1 n x w ∑ i = 1 n w
where RS is the weighted statistical ranking score for n variable (TOC, GP, S2, and Ro values), x is the hydrocarbon generation potential indicator variables values, and w is the assigned weighted ranking percentages for each variable.
TOC was allocated 45% because it is arguably the most important parameter to consider in source rock evaluation. This is due to the fact that any prospective source rock should have a high TOC [17]. TOC measures the organic richness of sedimentary rocks by totaling the organic matter quantity available in the rock [21,24]. The TOC analysis is the first analysis conducted to have a fair idea of the hydrocarbon potential of a formation [25,71]. Even though TOC is an important parameter, it should not be used alone; according to Tissot [72], some organic matter can generate hydrocarbons while others cannot generate anything because of their inert nature. TOC analysis cannot differentiate between inert and productive organic matter; it quantifies all the organic matter in the rock [17]. This can result in inaccurate results. Moreover, TOC also reacts to the maturity of organic matter; Daly [73] noticed that the amount of TOC in a rock reduced as hydrocarbons were generated and forced out. Due to these reasons, there is also a need to consider the formations’ hydrocarbon yield (S2) and generic potential (GP).
The GP received 30% of the allocation since it is the closest to TOC in estimating the potential of source rocks. GP represents the hydrocarbons that a source rock can generate if subjected to sufficient temperature [74,75,76]. It is the summation of S1 and S2, with S1 representing the already generated hydrocarbon and S2 representing the hydrocarbon generating potential remaining in the sediment’s kerogen [75,76]. This makes the GP superior to the S2, so a higher statistical weight is given to GP than to S2.
Hydrocarbon yield (S2) was assigned 15% because it represents the hydrocarbon generating capacity remaining in the sediment’s kerogen after a portion of the organic matter has already formed hydrocarbons [75,76].
Finally, the Ro was given the least statistical weight (10%) because even though thermal maturity is essential to the capacity of organic matter to generate hydrocarbons, formations with extraordinarily high organic matter and low thermal maturity can still produce hydrocarbon through thermal cracking [77]. Potential source rocks, according to Waples [78], are immature sedimentary rocks capable of generating and expelling hydrocarbons if their maturity level is higher. As a result, immature formations can still be considered potential source rocks.

4. Hydrocarbon Potential of formations in Malaysia

4.1. Organic Geochemical Characteristics of Formations in Peninsular Malaysia (PM)

4.1.1. Source Richness of Formations in PM

Generally, the formations in Peninsular Malaysia had very good TOC values, ranging from 1.33% to 41.23% wt%, according to the classification of TOC values by Peter [79]. Table 2 provides the classification of TOC values. The Batu Gajah shale formation has the lowest average TOC of 1.33 wt%, which was still good for hydrocarbon generation according to the Peter [79] interpretation of TOC values. The lower the organic content in the rock, the lower its TOC value, and the lower the TOC value, the lower the chance of generating hydrocarbon. The Batu Arang formation and the Penyu basin had the highest TOC values at 41.23% and 15.84 wt%, respectively, as shown in Table 2. The high values of Batu Arang formation and the Penyu basin could be attributed to the formations being primarily composed of coals, and black shales, which contain very high organic content, especially the coals [80,81,82]. The other formations, such as Belata, Semanggol, Kroh, and Semantan, had very good TOC values, ranging from 2.21 to 3.32 wt% (Table 2). The formations with the highest TOC values in Peninsular Malaysia were predominantly composed of coals and oil shales which supported claims made by Pashin, Rullkotter and Speight [83,84,85] that these sedimentary rock types contain high amounts of organic matter. Organic richness measures the amount of organic matter in the sediment capable of generating hydrocarbon, not just the amount of organic matter itself [19]. For this reason, it is not advisable to use TOC alone to determine the quantity of hydrocarbon a rock can generate, as suggested by Dembicki [17]. This is because there are different types of organic matter in sediments, with some generating hydrocarbons while some are also inert and do not generate any hydrocarbon [72]. The increasing maturity of organic matter also causes TOC to decrease [17,73]. As the organic matter matures, the relative inert kerogen content of the organic matter increases as the reactive organic matter is used up in hydrocarbon generation [73]. Therefore, it is key to combine TOC with other analyses, such as Rock-Eval Pyrolysis to make accurate predictions of TOC [17]. Figure 4 shows the combined analysis of TOC and S2 of the formations in Peninsular Malaysia. According to Figure 4, the Batu Arang formation and Penyu basin had the highest chance of producing hydrocarbons. This was demonstrated by the high amount of organic matter present in the formations, as confirmed by their high S2 values. The hydrocarbon generation potentials of these formations are promising and require further research for economic considerations. The lower S2 values in the Belata, Semanggol, Kroh, and Semantan formations indicated that the organic matter in these formations had already been generated, because S2 stands for the residual organic matter in the formations.

4.1.2. Source Quality

Rock-Eval pyrolysis is the most reliable analytical technique to provide information about kerogen type [19,69,86]. The analyzed dataset from the Rock-Eval allows the derivation of HI and OI, which is equivalent to the H/C atomic ratio and O/C atomic ratio, respectively [69,79,86]. The average OI values of the Belata, Semanggol, Kroh, Semantan, and Batu Arang formations ranged from 2.03 to 31.50 mgCO2/g, and their average HI values ranges from 0.02 to 347.38 mg HC/g (Table 3). The Belata and Kroh formations had very low HI and OI values, making it difficult to get a good reading from the plot in Figure 5. There were indications that the samples in both the Semantan and Semanggol formations were of type IV kerogen (Figure 5). However, according to Dembicki [17] the Semantan and Semanggol formations appear gas-prone because type IV kerogen is basically inert and does not really influence S2, but contributes to the TOC, which lowers the HI. The similarities in the kerogen type of both the Semantan and Semanggol formations could be associated with part of both formations being formed in the Triassic period.
To evaluate the kerogen type of the Batu Arang formation and Penyu basin, Tmax and HI values were used, due to limitations on the availability of OI data for those formations in the open literature. The average Tmax of the Batu Arang formation and Penyu basin was 416.86 °C and 416.35 °C, respectively, and the average HI was 463.43 and 434.80, respectively (Table 4). The Batu Arang formation and Penyu basin have type II and type I kerogen types, respectively (Figure 6). This shows that the organic matter from the Penyu basin originated from algal material deposited in lacustrine environments, thereby producing mostly waxy oil [17]. The Batu Arang having type II organic matter gives the impression that it originated from autochthonous organic matter deposited under reducing conditions in marine environments. As a result, it primarily produces naphthenic oil [17].
The classification by Peter [79] (Table 5), that uses the HI vs. S2/S3, suggests that the Belata and Kroh formations are type III, which indicates that they generate gas. Furthermore, the organic matter from the Belata and Kroh formations is derived from terrestrial plant debris or aquatic organic matter deposited in an oxidizing environment, and, thus, might mainly produce gas [72]. The Semantan and Semanggol formations were also classified according to Peter [79] classification and indicated type III kerogen, and this confirmed the conclusion that type IV kerogen appears to be gaseous.

4.1.3. Thermal Maturity

Vitrinite Reflectance (Ro) is the principal thermal maturity indicator in hydrocarbon exploration [76,87]. However, not all the formations had vitrinite reflectance analysis done according to the data analyzed. As a result, Ro was calculated for the formations without Ro data, using the Duvernay shale model [Ro = (0.0149 × Tmax) − 5.85] [68]. The range of Ro values of the formations in Peninsular Malaysia was 0.39% to 3.58%, with an average value of 1.38% (Table 6). The Belata Formation had the highest Ro, with the Penyu and Batu Arang Formations having the lowest values of 0.39 and 0.41, respectively (Table 6). According to the standard interpretations of the stages of organic matter maturity by Dow [88], the samples from Batu Arang and Penyu were immature (Table 6). The immature nature of the Batu Arang and the Penyu indicated that the organic matter in these formations had not been exposed to deep burial and thermal cracking to generate hydrocarbons. It also indicated that the samples from Semantan and Semanggol formations were in the late oil generation stage. Finally, the interpretation by Dow [88] suggests that the Belata formation samples had generated dry gas, while that of Kroh had also generated wet gas. Tmax vs. PI plots are often used to determine the maturity, and they provided results similar to those obtained from the interpretation based on Dow [88] classification. According to the Tmax vs. PI plots, the samples from Batu Arang and Penyu were immature, while the samples from Semantan and Semanggol were in-between the oil and gas zones. The Belata and Kroh formations had matured to the dry gas stage (Figure 7). According to the HI vs. Tmax plots, the Batu Arang, Kroh, Belata formations, and Penyu basin were in the pre-oil stage, indicating that they were still immature (Figure 8). However, the HI vs. Tmax plots results for the Belata and Kroh formations differed from the Ro and Tmax vs. PI plots. This could have been because of the relatively low HI resulting from the low S2 values. Generally, Tmax values of rocks with very low S2 values (<0.2 mg HC/g rock) can be inaccurate [79,89]. The Semantan and Semanggol formations were in the wet gas/condensate zone indicating higher thermal maturity than the others.

4.1.4. Generic Potential (GP)

GP refers to the quantity of hydrocarbons a rock can generate if subjected to sufficient temperature [76]. The GP represents the summation of the S1 and S2 (GP = S1 + S2). S1 denotes previously generated hydrocarbons, while S2 stands for the remaining hydrocarbon generating potential in the sediment’s kerogen, so combining the two gives an idea of the formation’s potential to generate hydrocarbons [75,76]. The GP values ranged from 0.02 to 143.07 mg HC/g with an average of 38.44 mg HC/g. The Batu Arang had the highest value of 143.07 mg HC/g with the Belata having the lowest value of 0.02 mg HC/g (Table 7). According to the Hunt [75] classification of GP, all the formations had very poor GP, except for the Batu Arang formation and Penyu basin which had very good GP. The low GP values of the Belata, Kroh, Semantan and Semanggol formations could be attributed to the matured nature of those formations. As the maturity of the sediment increases, the S2 reduces, resulting in lower GP.

4.1.5. Hydrocarbon Generation Potential of Rock Formations in PM

The Penyu basin and Batu Arang formation stood the highest chance of generating hydrocarbons from all the formations studied in Peninsular Malaysia. This was due to the high TOC, high GP and high hydrocarbon yield (S2) values, which showed that the formations had high organic matter present. As the samples were still immature, most of the hydrocarbons were still intact and stood a high chance of generating hydrocarbons when subjected to high temperatures. The Penyu basin and Batu Arang formation also generate type I and type II kerogens, respectively. The Semantan and Semanggol formations had a low chance of generating hydrocarbons. These formations had relatively average TOC and low GP and matured organic matter, indicating that most hydrocarbons had already been generated. The Semantan and Semanggol formations generate type III kerogen, which is gaseous in nature.
The Kroh and Belata formations have the least possible chance of generating hydrocarbons among the formations studied in Peninsular Malaysia. This was because of the very mature organic matter in those formations and poor GP as well. The formations’ high maturity and low GP represented low hydrocarbon generation potential. The Belata and Kroh formations also generate type III kerogen. A fair assessment of the Batu Gajah shale was not possible, due to inadequate data for its assessment; however, the formation is known to have good TOC.

4.2. Organic Geochemical Characteristics of Rock Formations in Sabah Region

4.2.1. Source Richness of Rock Formations in the Sabah Region

Rocks in East Malaysia are categorized into two sections: (i) Sabah and (ii) Sarawak. Most of the TOC results from the Sabah region were good, ranging from 0.53 to 68.05 wt%, with an average of 17.63 wt%, which was very good according to Peters [79] classification of TOC values (Table 8). The Pinangah formation had the highest TOC value of 68.05 wt%, with the Temburong formation having the lowest TOC value of 0.53 wt% (Table 8). The very high TOC values of the Ganduman, Tanjong, Sandakan, Pinangah, and Kapilit formations could be associated with their composition of coals and carbonaceous shales or mudstones. Coals and carbonaceous shales are known to contain high organic matter [84,85]. Since TOC alone does not give the actual quantity of organic matter capable of producing hydrocarbons, there was also a need to analyze the quantity of organic matter that would generate hydrocarbons, which could be done by combining TOC with S2. The TOC vs. S2 plot indicated that the Pinangah, Tanjong, and Kapilit formations had a very high chance of generating hydrocarbon. On the other hand, the chances of organic matter being generated from the Sandakan and Ganduman formations was below average. In contrast, the rest of the formations in the Sabah region had a meager chance of generating hydrocarbon, as shown in Figure 9.

4.2.2. Source Quality

The average OI values of the Sandakan, Temburong, Pinangah, Beliat, Meligan, West Crocker, and Setap formations ranged from 3.6 to 88.50, while the HI values ranged from 35.19 to 392.5 (Table 9). The Ganduman, Sebahat, Tanjong, Kapilit and Kalabakan formations had HI ranging from 24.69 to 261.78 and Tmax ranging from 372 to 492.7 °C (Table 10). The OI and HI plots indicated that almost all the formations were of type III kerogen, except for the Pinangah and Tanjong formations, which were type 1. This suggested that only the Pinangah and Tanjong formations would generate oil, but the rest would generate gas (Figure 10). The Tmax vs. HI plots also indicated that the Tanjong and Kalabakan formations were Type I, and the Kapilit formation was Type III, with the Ganduman and Sebahat formations being Type IV (Figure 11). However, since type IV kerogen is inert and only minimally contributes to the S2 but significantly contributes to the TOC, this lowered the HI, making the source rock appear more gas-prone [17]. The Pinangah and Tanjong formations were type I kerogen, originating from algal material accumulated in lacustrine environments and producing waxy oil [17]. So, the other formations in the Sabah region, except Pinangah and Tanjong, originated from terrestrial plant debris or aquatic organic matter accumulated in an oxidizing environment that generated mainly gas [72].

4.2.3. Thermal Maturity

The Ro values of the studied formations in the Sabah region ranged from 0.30% to 1.35%, with an average value of 0.7% (Table 11). The Temburong formation had the highest Ro, with the Ganduman formation having the lowest Ro value of 0.30%. According to the standard interpretations of the stages of organic matter maturity by Dow [88], the Ganduman, Sebahat, Sandakan, Pinangah, Setap, and Kapilit formations from the Sabah regions were immature. While the others had generated oil in different stages, only the Temburong formation was highly matured to generate gas (Table 11). The Tmax vs. PI plots provided results like the Dow [88] classification. The Temburong and Kalabakan formations had already generated dry gas, while the West Crocker, Meligan, and Beliat formations had generated oil. The rest of the formations were either immature or between the immature and oil stage (Figure 12). According to the HI vs. Tmax plots, the Gaduman, Pinangah, Kapilit, Sebahat, Sandakan, Setap, and Begrih formations were in the pre-oil stage, indicating that they were still immature. The Tanjong, Beliat, and Meligan formations are in the oil window, while the West Crocker formation was in the wet gas/condensate zone. Finally, the Kalabakan and Temburong formations were in the dry gas zone, indicating the two formations’ matured nature (Figure 13).

4.2.4. Generic Potential (GP)

The GP values of the formations in Sabah ranged from 0.12 to 279.69 mg HC/g with an average of 55.19 mg HC/g. The Pinangah formation had the highest value of 143.07, with the Temburong having the lowest value of 0.12 mg HC/g (Table 12). According to the Hunt [75] classification of GP, the Pinangah, Ganduman, Tanjong, Kapilit and Sandakan formations had very good GP while that of West Crocker and Sebahat were fair (Table 12). The GP of Kalabakan, Meligan, Beliat, and Setap formations are all poor, according to the Hunt [75] classification (Table 12). The low GP values of these formations could be attributed to their low maturity and low organic richness. As the thermal maturity of the sediment increases, the S2 reduces, thereby decreasing the GP. Low thermal maturity and high organic matter could be attributed to the high GP values of the Pinangah, Ganduman, Tanjong, Kapilit, and Sandakan formations.

4.2.5. Hydrocarbon Generation Potential of Rock Formations in Sabah

The Sabah region has many formations that can generate hydrocarbons, probably commercially. The Pinangah, Tanjong, Sandakan, Kapilit, and Ganduman formations can all generate hydrocarbons in commercial quantities. These formations had very high TOC values, high hydrocarbon yield (S2), and very good GP. The Pinangah and Tanjong formations generate type I kerogen, whilst Sandakan, Kapilit and Ganduman formations generate type III kerogen. The Temburong and Setap formations had the slightest chance of generating hydrocarbons in the Sabah region, due to the low TOC nature, poor GP, and the matured nature of the organic matter in the formations. The other formations, such as Sebahat, Beliat, Meligan, West Crocker, and Kalabakan formations, had a moderate to low chance of generating hydrocarbons, due to the relatively average TOC and matured nature of the formations and with some having poor GP.

4.3. Organic Geochemical Characteristics of Formations in Sarawak Region

4.3.1. Source Richness of Rock Formations in the Sarawak Region

The formations in the Sarawak region had TOCs ranging from 0.74 to 97.8 wt% with an average of 38.89 wt% (Table 13). The Belaga formation had the lowest TOC value, while the Begrih formation had the highest TOC value. Overall, the TOC of the Sarawak region was very good according to Peters [79] classification (Table 13). The high TOC values of the Bintulu, Nyalau, Begrih, Liang, Balingian, and Mukah formations could be attributed to the formations being primarily composed of coals, and black shales, which are high in organic matter, especially the coals, which contain very high organic content [80,81,82]. The TOC vs. S2 plots indicated that the Begrih, Liang and Balingian had a very high chance of generating hydrocarbons due to their high S2 values, as shown in Figure 14.

4.3.2. Source Quality

The average OI values of the formations in Sarawak ranged from 3 to 31 mgCO2/g and the average HI values ranged from 10.76 to 400.50 mgHC/g, as shown in Table 14. The OI and HI plots indicated that most of the formations were of type II and III kerogen, except for the Belaga and Begrih, which were of type IV kerogen, and the Bintulu formation, which was of type I kerogen (Figure 15), originating from algal material accumulated in lacustrine environments, producing waxy oil [17]. The Liang, Nyalau, Mukah, and Balingian formations were of type II kerogen (Figure 15). Type II kerogen originates from autochthonous organic matter accumulated in reducing conditions in marine environments, and this mainly produces naphthenic oil. The Tukau, Miri, and Lambir formations were of type III kerogen. They originated from terrestrial plant debris and/or aquatic organic matter accumulated in an oxidizing environment, and this mainly produces gas. The Belaga and Begrih were Type IV kerogen and appeared gas-prone because, according to Dembicki [17], type IV kerogen is basically inert and does not really influence S2 but contribute to the TOC, which lowers the HI. As a result, the rock appears more gas-prone. So, therefore, the Belaga and Begrih mainly generate gas.

4.3.3. Thermal Maturity

The Ro values of the formations in the Sarawak region ranged from 0.37% to 2.39%, with an average value of 0.65% (Table 15). The Belaga formation had the highest Ro, with the Mukah formation having the lowest Ro value of 0.37% (Table 15). Except for the Belaga formation, the average Ro for all the other formations was below 0.60. According to the standard interpretations of the stages of organic matter maturity by Dow [88], all the formations studied in the Sarawak region were immature, apart from the Belaga formation, which was matured to the extent of generating dry gas (Table 15). The Tmax vs. PI plots provided results like the Dow [88] classification. All the nine (9) other formations studied in the Sarawak region were in the immature zone, with only the Belaga formation in-between the wet gas and dry gas window (Figure 16). According to the HI vs. Tmax plots, all the formations studied were in the pre-oil stage, apart from the Belaga formation which is in the dry gas zone (Figure 17). Therefore, the results from all the three classifications for thermal maturity used were in line with one another.

4.3.4. Generic Potential (GP)

The GP values of the formations in Sawarak ranged from 0.1 to 289.37 mg HC/g with an average of 115.58 mg HC/g. The Bintulu formation had the highest value of 289.37, with the Belaga having the lowest value of 0.1 mg HC/g (Table 16). According to the Hunt [75] classification of GP, the Bintulu, Nyalau, Begrih, Liang, Balingian, and Mukah formations had very good GP, while that of the Lambir formation was fair (Table 16). The GP of Belaga, Tukau and Miri formations were all poor, according to the Hunt [75] classification (Table 16). The low GP values of these formations could be attributed to their low maturity and low organic richness. Low thermal maturity and high organic matter were probably the cause of high GP values in most formations.

4.3.5. Hydrocarbon Generation Potential of Rock Formations in Sarawak

For Sarawak, the Begrih, Liang, Balingian, and Bintulu formations had the highest chance of generating hydrocarbons, due to their high TOC, high hydrocarbon yield (S2), and high GP. These formations were immature, indicating that there was still a chance of generating hydrocarbons in huge quantities when subjected to high temperatures. The Belaga formation had the slightest chance of generating hydrocarbons in the Sarawak region due to the very mature nature of the hydrocarbons and poor GP. The significantly matured nature of the Belaga formation indicated that it had already generated to its total capacity; therefore, there was little chance of further generating hydrocarbons. The other formations had a moderate to low probability of generating hydrocarbons, due to their relatively satisfactory TOC and S2 and fair to poor GP. Most of the formations in the Sarawak region generate type II and type III kerogen.

5. Generative Potential of Malaysia

A heat map was generated using the ranking of the formations’ TOC, GP, S2, and Ro values. A statistical weight ranking method was used for the heat map with Forty (40) percent weight for TOC value and thirty (30), fifteen (15), and ten (10) for GP, S2, and Ro values, respectively. The weighted ranking percentages were provided, given the parameters’ order of importance. The ranking indicated that the Bintulu, Pinangah, Begrih, Liang and Tanjong were the top five formations with the highest potential to generate hydrocarbons (Figure 18). Conversely, the Kroh, Setap, Kalabakan, Temburong, and the Belaga formations had the lowest generation potential among all the formations studied (Figure 18). It can be deduced from the heat map that the formations in Sarawak had the highest potential to generate hydrocarbons, followed by the formations in Sabah and then, finally, the formations in Peninsular Malaysia (Figure 18).

6. Prospects and Recommendations

  • The coaly formations, such as Bintulu, Batu Arang, Penyu, Tanjong, Sandakan, Pinangah, Nyalau, Balingian, and Mukah, can serve as unconventional resources, such as for coal bed methane (CBM), and also conventional liquid hydrocarbons.
  • Due to the abundance of coal formations, there is a need to find more uses for these coals to exploit the resource fully.
  • More exploration works for hydrocarbon generation potential of rocks should be focused on formations in the tertiary and, more importantly, the tertiary formations in Sarawak and Sabah regions.
  • Most of the formations with high potential to generate hydrocarbons are immature, indicating that there is a probability that the offshore equivalents might be matured enough to generate hydrocarbons, because they are buried deeper, and they are subjected to higher temperatures deep down.

7. Conclusions

Based on the findings of this review, the following conclusions are drawn:
  • The formations in Sarawak have the highest potential to generate hydrocarbons, followed by the formations in Sabah and then, finally, the formations in Peninsular Malaysia.
  • The formations with the highest potential to generate hydrocarbons among the formations analyzed are primarily coal and carbonaceous shale formations.
  • The hydrocarbon generation potentials in Malaysian formations are mostly high in the younger formations, compared to the older ones.
  • Most of the formations with high potential to generate hydrocarbons have immature organic matter, which is probably because those formations are younger and, thus, have not been buried for long.
  • Most formations with the highest potential to generate hydrocarbons, such as Bintulu, Pinangah Tanjong, and Batu Arang, are of type 1 kerogen, indicating that the organic matter in these rock formations originated from algal material deposited in lacustrine environments and so produces mostly waxy oil.

Author Contributions

Conceptualization, A.R., N.A.S. and C.B.B.; methodology, A.R., N.A.S. and C.B.B.; software, A.R. and C.B.B.; validation, A.R., N.A.S. and C.B.B.; formal analysis, A.R.; investigation, A.R. and C.B.B.; resources, N.A.S. and S.R.; data curation, N.A.S.; writing—original draft preparation, A.R.; writing—review and editing, A.E.H., M.U., M.A.K.E. and S.A.K.; visualization, A.R., A.E.H., M.U., S.A.K.; supervision, N.A.S., A.E.H. and M.A.K.E.; project administration, N.A.S. and S.R.; funding acquisition, N.A.S. and S.R. All authors have read and agreed to the published version of the manuscript.

Funding

This work was supported by Universiti Teknologi PETRONAS and Institute of Hydrocarbon Recovery (IHR) with YUTP Grants (015LC0-363) and (015LC0-366).

Institutional Review Board Statement

Not applicable.

Informed Consent Statement

Not applicable.

Data Availability Statement

If the dataset is required for reference purposes, it can be obtained from the first author.

Acknowledgments

The authors appreciate the efforts of all the researchers whose published articles were used for this review.

Conflicts of Interest

The authors declare no conflict of interest.

Abbreviations

(PM)Peninsular Malaysia
(EM)East Malaysia
(TOC) (wt%)Total Organic Carbon
(GP) (mg HC/g)Generic Potential
(HI) (mg HC/g)Hydrocarbon Index
(PI) Production Index
(OI) (mg CO2/g)Oxygen Index
(Ro) (%)Vitrinite Reflectance
(GP) (mg HC/g)Generic Potential
(S2) (mg HC/g)Hydrocarbon yield

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Figure 1. Map of Malaysia showing the locations of the formations analyzed in this study.
Figure 1. Map of Malaysia showing the locations of the formations analyzed in this study.
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Figure 2. Stratigraphy of the formations studied in Peninsular Malaysia.
Figure 2. Stratigraphy of the formations studied in Peninsular Malaysia.
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Figure 3. (a) A stratigraphic map showing the formations studied in Sarawak (b) A stratigraphic map showing the formations studied in Sabah.
Figure 3. (a) A stratigraphic map showing the formations studied in Sarawak (b) A stratigraphic map showing the formations studied in Sabah.
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Figure 4. A plot of average S2 versus average TOC of formations in Peninsular Malaysia showing hydrocarbon yield potential and type of kerogen.
Figure 4. A plot of average S2 versus average TOC of formations in Peninsular Malaysia showing hydrocarbon yield potential and type of kerogen.
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Figure 5. OI vs. HI plot showing the type of kerogen of formations in PM.
Figure 5. OI vs. HI plot showing the type of kerogen of formations in PM.
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Figure 6. Tmax vs. HI plot showing the type of kerogen in PM.
Figure 6. Tmax vs. HI plot showing the type of kerogen in PM.
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Figure 7. Tmax vs. PI plot showing level of kerogen maturity for formations in PM.
Figure 7. Tmax vs. PI plot showing level of kerogen maturity for formations in PM.
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Figure 8. Tmax vs. HI plot showing level of kerogen maturity of formations in PM.
Figure 8. Tmax vs. HI plot showing level of kerogen maturity of formations in PM.
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Figure 9. A plot of average S2 versus average TOC of formations in Sabah showing hydrocarbon yield potential and kerogen type.
Figure 9. A plot of average S2 versus average TOC of formations in Sabah showing hydrocarbon yield potential and kerogen type.
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Figure 10. OI versus HI plot showing the type of kerogen for formations in Sabah.
Figure 10. OI versus HI plot showing the type of kerogen for formations in Sabah.
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Figure 11. Tmax versus HI plot showing the type of kerogen of formations in Sabah.
Figure 11. Tmax versus HI plot showing the type of kerogen of formations in Sabah.
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Figure 12. Tmax versus PI plot showing the level of kerogen maturity of formations in Sabah.
Figure 12. Tmax versus PI plot showing the level of kerogen maturity of formations in Sabah.
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Figure 13. Tmax versus HI plot showing the level of kerogen maturity of formations in Sabah.
Figure 13. Tmax versus HI plot showing the level of kerogen maturity of formations in Sabah.
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Figure 14. TOC vs. S2 plot of formations in Sarawak showing hydrocarbon yield potential and type of kerogen.
Figure 14. TOC vs. S2 plot of formations in Sarawak showing hydrocarbon yield potential and type of kerogen.
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Figure 15. OI versus HI plot showing the type of kerogen of formations in Sarawak.
Figure 15. OI versus HI plot showing the type of kerogen of formations in Sarawak.
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Figure 16. Tmax vs. PI plot showing kerogen maturity level of formations in Sarawak.
Figure 16. Tmax vs. PI plot showing kerogen maturity level of formations in Sarawak.
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Figure 17. Tmax vs. HI plot kerogen maturity level of formations in Sarawak.
Figure 17. Tmax vs. HI plot kerogen maturity level of formations in Sarawak.
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Figure 18. Heat map showing the ranking of hydrocarbon generation potential of formations in Malaysia.
Figure 18. Heat map showing the ranking of hydrocarbon generation potential of formations in Malaysia.
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Table
Table 1. List of various formations studied, and the references associated with these formations.
Table 1. List of various formations studied, and the references associated with these formations.
No.Formation/BasinRegionLocation (s)CoordinatesPeriod/AgeAuthor (References)
1BelataPeninsular Malaysia (PM)Sungai Gumut/Kg. Air Panas/Junction to Kg. Sg Jang/Kuala Kubu town/Kuala Kubu Bharu03°36′25″,101°35′18.3″/
03°36′27″, 101°35′49.2″/
03°34′31.6″, 101°36′55.9″/
03°33′20.3″, 101°38′25.2″/
03°33′15″, 101°38′41″		Carboniferous[8]
2SemanggolPeninsular Malaysia (PM)Gunung Semanggol/Bukit Merah/Nami Late Permian to Early Triassic[13,14,52]
Nami/TaipingN 06°04′38.10″, E 100°43′52.90″/
N 04°56′38.20″, E 100°41′40.20″
Taiping/Bukit Merah/Nami
3KrohPeninsular Malaysia (PM)Kg Lalang/Kelian Intan/Near Kg Puloh/Felda Nenering/Kg. Lalang to Air Panas/Baling border05°35′43′′0.6, 101°04′9′′0.18/
05°36′6′′0.96, 101°01′8′′0.45/
05°36′9′′0.49, 101°01′8′′0.04/
05°40′34′′0.1, 101°01′8′′0.3/
05°38′30′′0.3, 101°05′24′′0.9/
05°39′16′′0.1, 101°05′45′′0.5/
05°43′14′′0.6, 100°58′53′′0.8		Silurian & Devonian[53]
4SemantanPeninsular Malaysia (PM)Kuala lipis/Benta/Kota Kelanggi/Karak/Thermos shale/Maran/Temerloh/Bahau/Gemas/Tenang/Ayer Hitam04°03′43.5″, 101°59′05.8″/
03°53′39.4″, 102°27′38.9″/
03°11′26.2″, 102°24′06.2″/
02°34′53.7″, 102°36′44.9″/
02°27′17.7″, 102°58′38.6″/
01°53′44.0″, 103°12′38.6″/
03°28′05.4″, 102°03′03.5″/
03°43′13.8″, 103°03′00.0″/
03°35′00.0.2″, 102°46′44.6″/
03°26′24.4″, 102°25′10.5″/
04°11′16.8″, 102°03′45.1″		Triassic[13,52]
Ayer Hitam/Yong Peng/Labis/Bukit Jeram Padang Ridge/Temerloh/Toll Plaza/Benta/Kuala Lipis
5Batu ArangPeninsular Malaysia (PM)Selangor Eocene-Oligocene[54]
Batu ArangPeninsular Malaysia (PM)SelangorN 3°19′22.01″, E 101°28′30.03″Eocene-Oligocene[55]
6PenyuPeninsular Malaysia (PM)Chenor, PahangN 3°29′16.64′’, E 102°44′1.65′’Tertiary[56]
7Batu GajahPeninsular Malaysia (PM)Baju Gajah Devonian[57]
8GandumanSabah/East MalaysiaDent Peninsula05°20.6540, 119°07.312
05°16.2640, 119°05.490 05°16.4130, 119°06.403
05°16.8790, 119°08.231
05°08.5620, 119°06.102 05°20.6560, 119°10.751 05°10.7570, 119°10.524
05°18.6370, 119°00.550 05°19.1070, 119°02.679
05°20.4030, 119°05.977
05°11.6560, 119°10.984
05°18.3000 119°00.000
05°18.630’, 119°00.150
05°18.4330, 119°08.532 05°18.4320, 119°08.531
05°19.3420, 119°08.763		Pliocene[58]
9SebahatSabah/East MalaysiaDent Peninsula05°08.133, 119°01.833
05°13.617, 118°58.950
05°09.067, 118°58.800
05°09.700, 118°54.650
05°09.733, 118°54.900
05°09.067, 119°00.000		Upper Mioceneto Pliocene[58]
9SebahatSabah/East MalaysiaDent Peninsula05°17.283, 118°59.867
05°20.217, 119°00.733
05°08.826′119°00.314
05°08.825′119°02.855′
05°08.463, 119°01.802
05°09.196, 119°00.602
05°13.817, 118°58.210
05°13.748, 118°59.006
05°23.363, 119°14.317
05°05.473, 118°51.761		Upper Miocene to Pliocene[58]
10TanjongSabah/East MalaysiaPinangah area Miocene[59]
TanjongSabah/East MalaysiaSabahN 04°30′58.0′′ E 117°14′32.0′′Oligocene to Early Miocene[55]
TanjongSabah/East MalaysiaSouthern Sabah Middle Miocene to Late Early Miocene[60]
11SandakanSabah/East MalaysiaSandakan Middle to Late Miocene[61]
12TemburongSabah/East MalaysiaTenom Miocene[62]
TemburongSabah/East MalaysiaSipitang-TenomN 04.58147, E 115.42054/
N 04.58124, E 115.42801		Paleogene to early Miocene[15]
13Pinangah coalfieldSabah/East MalaysiaSandakan Early to middle Miocene[63]
14BeliatSabah/East MalaysiaBatu LuangN 05.52415, E 115.52573/
N 05.52365, E 115.52520/
N 05.52350, E 115.52475		Late Miocene[15]
BeliatSabah/East MalaysiaKuala Penyu Miocene[64]
15MeliganSabah/East MalaysiaSipitangN 05.02157, E 115.32355/
N 05.00651, E 115.33254		Early Miocene[15]
16West CrockerSabah/East MalaysiaSipitangN 05.02376, E 115.30998/
N 04.59835, E 115.35441/
N 05.46563, E 116.01333		Paleogene[15]
17SetapSabah/East MalaysiaBeaufort Miocene[64]
18KapilitSabah/East MalaysiaEucalyptus camp Early to Middle Miocene[65]
KapilitSabah/East MalaysiaSouthern Sabah Early to Middle Miocene[60]
19KalabakanSabah/East MalaysiaSouthern Sabah Early Miocene[60]
20Bintulu coalfieldsSarawak/East MalaysiaBintulu Oligocene[63]
21BelagaSarawak/East MalaysiaJalan Sri Aman–Sarikei/Jalan Sibu–Bintulu/Jalan Sibu–Sarikei Late Cretaceous to Late Eocene[12]
22BegrihSarawak/East MalaysiaMukahN 2°45′27.47″ E 112°20′34.98″Lower Pliocene[55]
23NyalauSarawak/East MalaysiaBintuluN 3°11′32.98″E 113°5′17.62″Oligocene-Miocene[55]
NyalauSarawak/East MalaysiaBintulu Oligocene-Miocene[66]
NyalauSarawak/East MalaysiaBintulu Oligocene-Miocene[4]
24LiangSarawak/East MalaysiaMukahN 02°40′11.41″ E 112°20′22.56″Lower to Upper Pliocene-[55]
25BalingianSarawak/East MalaysiaSarawakN 02°47′98.40″ E 112°23′19.41″Late Miocene[55]
BalingianSarawak/East MalaysiaSarawak Upper Miocene[63]
26Mukah coalfieldSarawak/East MalaysiaSarawak Upper Miocene[63]
27LambirSarawak/East MalaysiaSarawak4°11.271’ N,114°2.437’ E/
4°11.230’ N, 114°2.399’ E/
4°11.215’ N, 114°2.410’ E/
4°11.190’ N, 114°2.195’ E		Middle Miocene[67]
28MiriSarawak/East MalaysiaSarawak4°11.618’ N, 113°50.778’ E/
4°12.718’ N, 113°53.661’ E/
4°15.193’ N, 113°54.227’ E		Middle to Late Miocene[67]
29TukauSarawak/East MalaysiaSarawak4°15.519’ N, 114°2.156’ ELate Miocene[67]
Table
Table 2. Interpretation of average TOC values of formations in Peninsular Malaysia according to Peter [79].
Table 2. Interpretation of average TOC values of formations in Peninsular Malaysia according to Peter [79].
No.FormationAvg TOC (wt%)Interpretation after Peter [79]Reference(s)
1Belata3.32Very good[8]
2Semanggol2.85Very good[13,14,52]
3Kroh2.21Very good[53]
4Semantan2.68Very good[13,52]
5Batu Arang41.23Very good[54,55]
6Penyu15.84Very good[56]
7Batu Gajah1.33Good[57]
Table
Table 3. Average OI and HI values of formations in PM.
Table 3. Average OI and HI values of formations in PM.
No.FormationAv OI (mg CO2/g)Av HI (mg HC/g)Reference(s)
1Belata2.030.02[8]
2Semanggol30.1622.89[13,14]
3Kroh5.821.42[53]
4Semantan31.5026.18[13,52]
5Batu Arang22.06347.38[55]
Table
Table 4. Average Tmax and HI values of Batu Arang and Penyu formations in PM.
Table 4. Average Tmax and HI values of Batu Arang and Penyu formations in PM.
No.FormationAv Tmax (°C)Av HI (mg HC/g)Reference(s)
1Batu Arang416.86463.43[54]
2Penyu416.35434.80[56]
Table
Table 5. Source quality interpretation of formations in PM using Peter [79] interpretation.
Table 5. Source quality interpretation of formations in PM using Peter [79] interpretation.
No.FormationAv S2/S3Av HI (mg HC/g)Peter [79] Source Quality InterpretationReference(s)
1Belata00.02Gas[8]
2Semanggol0.3622.89Gas[13,14]
3Kroh0.061.42Gas[53]
4Semantan1.0626.18Gas[13,52]
Table
Table 6. Thermal maturity interpretation for formations in PM according to Dow [88] using Ro.
Table 6. Thermal maturity interpretation for formations in PM according to Dow [88] using Ro.
No.FormationAv Ro (%)Dow [88] Thermal Maturity InterpretationReference(s)
1Belata3.58Dry gas[8]
2Semanggol1.21Late oil[13,14,52]
3Kroh1.40Wet gas[53]
4Semantan1.26Late oil[13,52]
5Batu Arang0.41Immature[54,55]
6Penyu0.39Immature[56]
Table
Table 7. Interpretation of average GP values of formations in PM according to Hunt [75].
Table 7. Interpretation of average GP values of formations in PM according to Hunt [75].
No.FormationGeneric Potential (GP) S1 + S2 (mg HC/g)(Hunt, 1995), GP InterpretationReference(s)
1Belata0.02Poor[8]
2Semanggol0.21Poor[13,14,52]
3Kroh0.05Poor[53]
4Semantan0.84Poor[13,52]
5Batu Arang143.07Very good[54,55]
6Penyu86.46Very good[56]
Table
Table 8. Interpretation of average TOC values of formations in Sabah according to Peters [79].
Table 8. Interpretation of average TOC values of formations in Sabah according to Peters [79].
No.FormationAvg TOC (wt%)Interpretation after Peters [79]Reference(s)
1Ganduman15.75Very good[58]
2Sebahat6.51Very good[58]
3Tanjong52.80Very good[55,59,60]
4Sandakan19.27Very good[61]
5Temburong0.53Fair[15,62]
6Beliat1.64Good[15,64]
7Pinangah68.05Very good[90]
8Meligan1.99Good[15]
9West Crocker3.19Very good[15]
10Setap0.84Fair[64]
11Kapilit39.94Very good[60,65]
12Kalabakan1.03Good[60]
Table
Table 9. Average OI and HI values of formations in Sabah.
Table 9. Average OI and HI values of formations in Sabah.
No.FormationAvg OIAvg HIReference(s)
1Sandakan47.4876.74[61]
2Temburong17.9435.19[15,62]
3Pinangah3.60392.50[63]
4Beliat43.0056.22[15,64]
5Meligan19.4036.60[15]
6West Crocker21.2071.00[15]
7Setap88.5060.10[64]
Table
Table 10. Average Tmax and HI values of formations in Sabah.
Table 10. Average Tmax and HI values of formations in Sabah.
No.FormationAvg Tmax (°C)Avg HIReferences
1Ganduman372.0060.75[58]
2Sebahat405.4424.69[58]
3Tanjong458.33250.08[60]
4Kapilit434.06261.78[60,65]
5Kalabakan492.7039.60[60]
Table
Table 11. Thermal maturity interpretation of formations in Sabah according to Dow [88] using Ro.
Table 11. Thermal maturity interpretation of formations in Sabah according to Dow [88] using Ro.
No.FormationAv RoDow [88], Thermal Maturity InterpretationReference(s)
1Ganduman0.30Immature[58]
2Sebahat0.35Immature[58]
3Tanjong0.66Early Oil[55,59,60]
4Sandakan0.40Immature[61]
5Temburong1.35Wet Gas[15,62]
6Pinangah0.56Immature[90]
7Beliat0.88Peak Oil[15,64]
8Meligan0.76Early Oil[15]
9West Crocker0.91Peak Oil[15]
10Setap0.38Immature[64]
11Kapilit0.59Immature[60,65]
12Kalabakan1.30Late Oil[60]
Table
Table 12. Interpretation of average GP values of formations in Sabah according to Hunt [75].
Table 12. Interpretation of average GP values of formations in Sabah according to Hunt [75].
No.FormationGeneric Potential (GP) S1 + S2 (mg HC/g)(Hunt, 1995), GP InterpretationReference(s)
1Ganduman21.37Very good[58]
2Sebahat3.57Fair[58]
3Tanjong181.29Very good[55,59,60]
4Sandakan18.84Very good[61]
5Temburong0.12Poor[15,62]
6Pinangah279.69Very good[90]
7Beliat1.75Poor[15,64]
8Meligan0.92Poor[15]
9West Crocker4.85Fair[15]
10Setap0.56Poor[64]
11Kapilit148.9Very good[60,65]
12Kalabakan0.45Poor[60]
Table
Table 13. Interpretation of average TOC values of formations in Sarawak according to Peter [79].
Table 13. Interpretation of average TOC values of formations in Sarawak according to Peter [79].
No.FormationAvg TOC (wt%)Interpretation after Peter [79]Reference(s)
1Bintulu70.02Very good[90]
2Belaga0.74Fair[12]
3Nyalau36.10Very good[55,66]
4Begrih97.80Very good[55]
5Liang93.22Very good[55]
6Balingian49.71Very good[55,63]
7Mukah34.83Very good[63]
8Lambir3.25Very good[67]
9Miri1.54Good[67]
10Tukau1.68Good[67]
Table
Table 14. Average OI and HI values of formations in Sarawak.
Table 14. Average OI and HI values of formations in Sarawak.
No.FormationAvg OI (mgCO2/g)Avg HI (mgHC/g)Reference(s)
1Bintulu3.00400.50[63]
2Belaga26.0410.76[12]
3Nyalau12.23259.22[55,66]
4Begrih31.00234.50[55]
5Liang26.75253.35[55]
6Balingian25.71200.83[55,90]
7Mukah23.45210.40[90]
8Lambir27.0081.80[67]
9Miri30.2088.70[67]
10Tukau25.5084.20[67]
Table
Table 15. Thermal maturity interpretation for formations in Sarawak according to Dow [88] using Ro.
Table 15. Thermal maturity interpretation for formations in Sarawak according to Dow [88] using Ro.
No.FormationAv Ro (%)Dow [88], Thermal Maturity InterpretationReference(s)
1Bintulu0.58Immature[63]
2Belaga2.39Dry Gas[12]
3Nyalau0.54Immature[55,66]
4Begrih0.45Immature[55]
5Liang0.44Immature[55]
6Balingian0.40Immature[55,63]
7Mukah0.37Immature[63]
8Lambir0.42Immature[67]
9Miri0.44Immature[67]
10Tukau0.43Immature[67]
Table
Table 16. Interpretation of average GP values of formations in Sarawak according to Hunt [75].
Table 16. Interpretation of average GP values of formations in Sarawak according to Hunt [75].
No.FormationGeneric Potential (GP) S1 + S2 (mg HC/g)(Hunt, 1995), GP InterpretationReference(s)
1Bintulu289.37Very good[63]
2Belaga0.1Poor[12]
3Nyalau131.06Very good[55,66]
4Begrih231.75Very good[55]
5Liang232.57Very good[55]
6Balingian187.06Very good[55,63]
7Mukah78.03Very good[63]
8Lambir2.86Fair[67]
9Miri1.47Poor[67]
10Tukau1.48Poor[67]
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Rashid, A.; Siddiqui, N.A.; Bavoh, C.B.; Haque, A.E.; Usman, M.; Kasim, S.A.; ElGhali, M.A.K.; Ridha, S. Organic Matter Distribution and Characteristics among Rock Formations in Malaysia: Implications on Hydrocarbon Generation Potential. Appl. Sci. 2022, 12, 9470. https://0-doi-org.brum.beds.ac.uk/10.3390/app12199470

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Rashid A, Siddiqui NA, Bavoh CB, Haque AE, Usman M, Kasim SA, ElGhali MAK, Ridha S. Organic Matter Distribution and Characteristics among Rock Formations in Malaysia: Implications on Hydrocarbon Generation Potential. Applied Sciences. 2022; 12(19):9470. https://0-doi-org.brum.beds.ac.uk/10.3390/app12199470

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Rashid, Alidu, Numair Ahmed Siddiqui, Cornelius Borecho Bavoh, AKM Eahsanul Haque, Muhammed Usman, Sani Ado Kasim, Mohamed A.K. ElGhali, and Syahrir Ridha. 2022. "Organic Matter Distribution and Characteristics among Rock Formations in Malaysia: Implications on Hydrocarbon Generation Potential" Applied Sciences 12, no. 19: 9470. https://0-doi-org.brum.beds.ac.uk/10.3390/app12199470

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