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Generalized stratigraphy of the offshore and onshore Western Sabah (simplified after Tongkul, 1994; Leong, 1999; Hall, 2013; Gartrell et al., 2011).
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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 offsh...
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![Figure-6. A) Plot of S2 versus TOC [13], B) Plot of T max vs Hydrogen...](profile/Zulqarnain-Sajid/publication/355442559/figure/fig4/AS:1081161250013186@1634780337205/Figure-6-A-Plot-of-S2-versus-TOC-13-B-Plot-of-T-max-vs-Hydrogen-Index-HI-is_Q320.jpg)
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Citations
... However, liptinic organic matters possibly enhanced the oil generation potential of source rocks (PETRONAS, 1999;Algar, 2012;Hakimi et al., 2013). Abdullah et al. (2017) analyzed MTCs in deepwater sediments onshore Sabah and reported potential Type II/III kerogen, supporting a model for the transport of terrestrial organic matter by MTCs to the deepwater area. As source rocks were buried and matured, they initiated oil expulsion in the Late Miocene, followed by the peak and gas expulsion in the Early Pliocene (Grant, 2004). ...
... This time coincides with the most prominent and rapid global sea level falls (13.8-13.1 Ma) during the Neogene without rebounding, related to major expansion of the East Antarctic ice sheet (Shackleton et al., 2001;Holbourn et al., 2013;Morley et al., 2021). This global sea level fall could trigger shelf collapses at the NW Borneo margin (Morley et al., 2021) and may have contributed to the transport of land-derived organic matters to the deepwater area and thus source rock formations (Abdullah et al., 2017). After the deposition of the source rock, turbidites which work as reservoir rocks, semi-pelagic mudstones and MTCs filled the sedimentary basins. ...
The generation of hydrocarbons in source rocks can lead to overpressure, which can support development of detachments and the deformation of sedimentary rocks. In turn, the deformation of rock units by e.g., large-scale overthrusting can lead to tectonic-driven burial. Tectonic-driven burial can generate overpressure, which in turn can influence the petroleum system. In fold-thrust belts, an integrated understanding of both, the tectonic and the petroleum systems is important for understanding the potentially complex interaction of faulting, folding and fluid geochemistry. This study combines structural restoration and basin-modeling techniques to provide a comprehensive view of the fold-thrust system offshore northwest Borneo.
In the deepwater region offshore northwest Borneo a major fold-thrust belt is present. The thrust belt is characterized by a mix of gravity-driven folding and faulting in a southwestern domain, and deep-seated crustal deformation in a northeastern domain. Oil and gas preferentially accumulated in thrust-top anticlines. The NW Borneo fold-thrust belt has a low taper angle; likely related to fluid overpressure along the basal detachment. The basin models presented in this study are based on an integration of regional 3D seismic-reflection interpretation, borehole analysis and 2D kinematic restoration. 2D petroleum systems modeling shows oil and gas generation and expulsion from Middle Miocene coaly source rocks since the Late Miocene, migration of the hydrocarbons through carrier beds and faults, and the accumulation of oil and gas in thrust-hangingwall anticlines. Vertical gas leaks modeled are comparable with gas clouds observed on 3D seismic-reflection data. The risk of biodegradation was estimated for reservoirs shallower than 1000–1500 m, and their burial is influenced by uplift due to thrusting. Combined tectonic and thermal modeling of the fold-thrust belt indicates the initiation of shortening at the time when the maturation of the source rock at the basal detachment was within the oil window. The timing of the maximum shortening rate, however, exhibits regional variations across the fold-thrust belt. In the gravity-driven fold thrust system in the southwest, the primary control on the peak of shortening is the maturation of the source rock at basal detachment level (gas window). In contrast, in the northeast the timing of deep-seated crustal compressive tectonics is interpreted to have exerted the dominant control on the petroleum system.
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https://doi.org/10.1016/j.geoen.2023.212060
... Accordingly, we deem that such non-waxy lacustrine algal oils, or other unreported oils with similar characterization in other unexplored basins, were plausible sources. As to the nearby Wan'an, Zengmu, Brunei-Sabah, and Liyue reservoirs, the main source rocks reported in these basins are made up of terrestrial OM (e.g., Abdullah et al., 2017;Zhang et al., 2021) and are thus tentatively excluded as sources of recorded hydrocarbon contamination in the Meiji coral reefs. ...
... The huminite, liptinite, and inertinite macerals (Table 1) were utilized to characterize the organofacies and their kerogen types in these carbonaceous shales. The observations drew inspiration from the ternary diagram initially presented in the work of Abdullah et al. 12 Accordingly, from the analysis of samples, it was observed that they contained a mixture of organic matter, exhibiting a gradient from type II/III to type III/II kerogen ( Figure 7A). Most of the investigated shale samples have high contributions of huminite, and liptinite macerals are likely type II/III kerogen ( Figure 7A). ...
Carbonaceous shales of the Early Eocene Dharvi/Dunger Formation in the onshore Barmer Basin, northwest India were studied for the first time by integrating geochemical and organic petrological analyses. The carbonaceous shales of the Early Eocene Dharvi/Dunger Formation are characterized by a higher organic carbon content (TOC) of >10 wt. % and consist mainly a mixture of organic matter of Types II and III kerogen, with exhibited hydrogen index (HI) values ranging between 202 and 292 mg HC/g TOC. The dominance of such kerogen confirms from the high amounts of huminite and fluorescent liptinite macerals. Consequently, the carbonaceous shales of the Early Eocene Dharvi/Dunger Formation are promising source rocks for both oil- and gas generation potential, with oils of high wax contents, according to pyrolysis–gas chromatography results. The chemical and optical maturity results such as low values huminite/vitrinite reflectance, production index (PI), and Tmax show that most of the examined carbonaceous shale rocks from the outcrop section of the Kapurdi mine have entered the low maturity stage of oil generation, exhibiting a range of an immature to the very early-mature. Therefore, as highlighted in this study, the substantial abundance in hydrocarbon generation potential from these carbonaceous shales in the Dharvi/Dunger Formation, may represent future conventional petroleum exploration in the southern part of the Barmer Basin, where the Dharvi/Dunger Formation has reached deeper burial depths.
... 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 standalone 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. ...
... A heat map was generated using the ranking of the formations' TOC, GP, S2, and R o 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 R o values, respectively. The weighted ranking percentages were provided, given the parameters' order of importance. ...
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.
... Other studies considered it only for middle to outer fan deposition containing channel-lobe complex (Leong et al., 2018). The West Crocker Formation was also known as low-density turbidites and mass-transport deposition that are interpreted as distal fan environments (Abdullah et al., 2017). ...
Deep‐water massive sandstones (DWMS) are characterized by large volumes of sand accumulations which are considered as potential reservoir intervals in deep‐marine environments. Lithological variations and bed thickness statistics are used to interpret the distribution of massive sandstones in a deep‐marine fan‐lobe system. These massive sandstones are interpreted based on lithological heterogeneities and detailed facies analysis in seventeen exposed sections of the Late Palaeogene deposits in Sabah, NW Borneo. Sedimentary logs containing details of lithology textures and structures were used to recognize nine sedimentary facies of DWMS. These lithofacies were then grouped into three sedimentary facies associations: (1) massive facies association with basal part of turbiditic Bouma sequence, (2) massive facies association having soft‐sediment deformation structures, and (3) massive facies association with erosional features. The facies analysis portrays inner to middle submarine fan deposition and was later applied to reconstruct the distribution of a channel‐lobe complex. Individual sandstone bed thicknesses vary from 1 m to more than 8 m and the number of massive sandstones in submarine lobes range from less than 10% to more than 50%. The thicknesses of massive sandstones in channels are more than 8 m, whereas distal lobes have thicknesses from 1–2 m only. These sandstones are concentrated in channels, proximal and medial lobe settings that can also be verified from calculating the average of all maximum thickness of massive sand intervals that is, 8.91 m. The lithological heterogeneities and the processes associated with the deposition of these massive sandstones are vital for potential hydrocarbon reservoirs in the deep‐marine environments around the globe.
... The Hydrogen Index (HI) is defined as the ratio between the area of the S2 peak and the TOC. The most used diagram for kerogen classification is the modified Van Krevelen's one, which is based on the Hydrogen Index (HI) and the Oxygen Index (OI) (Abdullah et al., 2017;Tissot and Welte, 1978). ...
... The Pliocene to Early Miocene aged Setap Shale Formation overlies the Meligan Formation, which is composed of a thick monotonous succession of grey shale and minor turbidities bed of sandstone that is deposited in a shallow marine environment Saw et al., 2019). Meanwhile, the Meligan Formation is composed of massive sandstone with minor shale that forms prominent mountain ranges and the suggested age is Oligocene to Late Miocene (Morley et al., 2008;Van Hattum et al., 2013;Abdullah et al., 2017). The sandstone is grey with medium to coarse-grained and in general, quartzose is deposited from the fluviatile-deltaic-shallow environment . ...
The extraction of mountain salt from the saline waters is the basic livelihood of the Ba'kelalan communities of Sarawak. The current integrated approach is the first attempt to study the sources and geochemical processes of the saline groundwaters in this mountain region. Hence, in this study, saline groundwater samples from five existing wells in different seasons was analysed for hydrochemical parameters and multi-isotope composition (δ¹⁸O, δD, δ³⁴S, δ¹¹B and δ³⁷Cl). The significant increase in TDS, EC and salinity was due to seasonal variation and fluctuation in water level based on hourly, daily and monthly observations. The geochemical ratios and the statistical techniques revealed that the salinity was due to the dissolution of marine evaporites as a dominant process, coupled with other factors such as water-rock interaction, ion exchange and sulphate reduction. From the isotopic signatures, it was inferred that the origin of saline groundwater was from the intense dissolution of marine evaporites such as halite dissolution and oxidation of sulfide (pyrite). 2D electrical resistivity and seismic refraction methods were used to identify the lithological variations, depth of potential sources of saline groundwater, and the subsurface structures. It was inferred the probability of a conductive zone at a depth of 1–14 m, from which the saline groundwater plume migrates towards the perched aquifer. The presence of subsurface faults facilitated the movement of hypersaline groundwater from the saturated zone to the surface. The outcome of the study will support the dependent community to enhance their commercial salt production.
... On the other hand, Rock-Eval pyrolysis is used to estimate the total organic matter present in a source rock that can contribute to the generation of hydrocarbon (Espitali e et al. 1977;Chen et al. 2016;Longbottom et al. 2016). Estimation of source rock potential for hydrocarbon by using Rock-Eval pyrolysis for the characterization of organic matter or kerogen has become a vital part of hydrocarbon exploration programs (Peters, Walters, and Moldowan 2005;Abdullah et al. 2017), and it involves the determination of maturity level, quality, and the total amount of organic matter (Peters, Walters, and Moldowan 2005;Abdullah et al. 2017;Ratnayake, Kularathne, and Sampei 2018). ...
... On the other hand, Rock-Eval pyrolysis is used to estimate the total organic matter present in a source rock that can contribute to the generation of hydrocarbon (Espitali e et al. 1977;Chen et al. 2016;Longbottom et al. 2016). Estimation of source rock potential for hydrocarbon by using Rock-Eval pyrolysis for the characterization of organic matter or kerogen has become a vital part of hydrocarbon exploration programs (Peters, Walters, and Moldowan 2005;Abdullah et al. 2017), and it involves the determination of maturity level, quality, and the total amount of organic matter (Peters, Walters, and Moldowan 2005;Abdullah et al. 2017;Ratnayake, Kularathne, and Sampei 2018). ...
The study area is situated in the Meghalaya state (East Khasi Hills), North-East India. The notable petroliferous basins that were formed during the Paleogene time occurred in the state of northeast India. This work focused on characterizing the source rock of Late Paleocene (Shella Formation) of Pynursla-Lynkerdem area, East Khasi Hills, Meghalaya for their hydrocarbon potential based on Rock-Eval pyrolysis and elemental data. The coals of the Pynursla-Lynkerdem area have been characterized by high total organic carbon (TOC) range between 67.2 wt% and 74.5 wt%. The remaining hydrocarbon yield (S2) ranges from 215.5 to 294.0 mg HC/g rock. S2 and TOC data plots entail that these coals contain Type II–III kerogen and can act as a good hydrocarbon source rock. The hydrogen index (HI) ranges from 311.1 to 405.7 mg HC/g TOC, which indicates most of the sample can generate gases. Tmax varies between 405 and 433 °C (less than 435 °C), revealing the immaturity of organic matter. The plot of elemental composition places these samples from sub-bituminous to high volatile bituminous in rank and furnishes these coals’ suitability for gasification.
... The huminite, liptinite, and inertinite macerals (Table 1) were utilized to characterize the organofacies and their kerogen types in these carbonaceous shales. The observations drew inspiration from the ternary diagram initially presented in the work of Abdullah et al. 12 Accordingly, from the analysis of samples, it was observed that they contained a mixture of organic matter, exhibiting a gradient from type II/III to type III/II kerogen ( Figure 7A). Most of the investigated shale samples have high contributions of huminite, and liptinite macerals are likely type II/III kerogen ( Figure 7A). ...
... Oil and/or gas generation potential is generally evaluated based on the amount and type of organic matter and their maturation history through geological time (Dow, 1977;Peters and Cassa, 1994;Ardakania et al., 2017;Abdullah et al., 2017). ...
This study deals with organic matter in the Early Jurassic Datta shale in the Upper Indus Basin, Pakistan. Organic geochemical and microscopic techniques were used to investigate organic matter input, environmental conditions of deposition as well as petroleum generation potential. The geochemical results suggest that the shales display mainly fair to good source rock generation potential, with poor petroleum generation potential in some samples. The HI varies between 32 and 519 mg HC/g TOC, with many of the samples appearing to be mainly Type II and mixed Type II-III kerogen, and thereby exhibiting the ability to generate both oil and gas. The dominance of such Type II kerogen in some samples is consistent with the high HI values (> 300 mg HC/ g TOC) and high fluorescence alginite macerals. A section of the shale within the Datta Formation appears to be gas-prone, with HI values of less than 200 mg HC/g TOC. Biomarkers also indicate the presence of mixed organic matter of planktonic/bacterial and land plant input, which were deposited in a marine environment under relatively oxic conditions. The biomarker characteristics of the extracted shales correlate well with those of the oil from the Chanda Oilfield, indicating that the Datta shales are likely to be the effective source rock. This is supported by the thermal maturity, which ranges from moderate to peak-maturity, as indicated by vitrinite reflectance values of 0.69-0.82%, and the biomarker maturity indicators.
