An unconventional Neoproterozoic – Early Cambrian source rock interval in southern Oman: Implications for oil and gas generation

ABSTRACT The Neoproterozoic – Early Cambrian Ara intra-salt petroleum system in Oman has been the subject of several studies since the early 1990s, not least because of the exploration success that has accompanied the emergence of the play. As one of the oldest known commercial hydrocarbon systems, the properties of the source organic matter have been of particular interest. The Ara intra-salt hydrocarbon system consists of the Al Shomou Silicilyte, a rock which is composed of pure microcristalline silica, and carbonate colloquially known as “stringers”. Both occur as slabs encased in the Ara salt. In the case of the Silicilyte, the slabs can be shown to act both as source rock and reservoir. However, in the case of the carbonate stringers, the association is more ambiguous. A set of rock and oil samples have been selected from different wells penetrating the silicilyte and carbonate stringer plays to better characterize and understand these systems. As far as the sedimentary organic matter is concerned, the Al Shomou Silicilyte domain has an average Total Organic Carbon (TOC) of approximately 4 wt.%. The carbonate-prone domains exhibit rare organic-rich lithofacies (TOC of approximately 2 wt.%) and additional intra-salt shales (TOC of approximately 4 wt.%). The organic matter present in both the Silicilyte and carbonate plays is associated with a hypersaline and anoxic depositional environment, rich in sulfur, and showing very similar chemical signatures (bulk composition, elemental analysis, biomarker content, δ13C). The organic matter associated with these sequences is characterized by an unusual “asphaltenic” nature. Compared to classical fossil organic matter taken at an equivalent maturity level, the organic matter found in the intra-salt silicilyte, shales or carbonates releases a large amount of solvent soluble material, which is very rich in Nitrogen-Sulfur-Oxygen (NSO) compounds, implying a standard Type II-S kerogen. However, the organic matter differs from this classic characterization of kerogen (solvent insoluble) in that a large proportion appears to be a sulfur-rich “soluble” kerogen, which has not been previously described. Independent geochemical parameters (Rock-Eval analysis, kinetic parameters) seem to be consistent with this hypothesis. The thermal maturity of the whole set of samples examined places them in the oil window. Moreover, Thermochemical Sulfate Reduction (TSR) did not occur in these samples. As far as the soluble part is concerned, differences in the molecular (significant molecular variations for norhopanes, secobenzohopanes, carotane, X compounds, thianes, thiolanes) and sulfur isotopic composition were demonstrated, and are assumed to reflect subtle variations in depositional settings between Silicilyte and carbonate stringers. The specific properties of this unconventional organic matter has to be accounted for in the thermal modeling of oil and gas generation. Although the kinetic distribution for kerogen cracking is close to that of a Type II-S kerogen, it is slightly more mono-energetic. A compositional 2-D basin modeling (Temis 2D) was performed on a cross-section through the South Oman Salt Basin, using specific kinetic parameters measured on this unconventional Neoproterozoic – Early Cambrian kerogen (based on a linear grouping of insoluble kerogen and NSO like “soluble kerogen” kinetic parameters). The gas-to-oil ratio GOR prediction was improved within the silicilyte, when compared to the use of classical parameters assigned to Type II-S kerogen. Finally, the microcrystalline silica mineral matrix of the silicilyte plays is proposed to play a major role in the composition of the fluid, which is expelled and produced by imposing a strong geochromatographic effect on fluids and the retention of polar compounds. The preferential release of aliphatics would lead to the production of oils exhibiting a strong condensate character. This effect has to be considered when modeling the actual composition of the movable fluid in the silicilyte. The significance of the geochromatographic effect is yet to be quantified, but according to available observations, we suggest that this geochromatographic effect could explain the observed API gravity difference between oils produced from silicilyte and carbonate plays.

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Origins of hydrocarbons in the Geneva Basin: insights from oil, gas and source rock organic geochemistry

Swiss Journal of Geosciences ◽

10.1186/s00015-021-00388-4 ◽

2021 ◽

Vol 114 (1) ◽

Author(s):

Damien Do Couto ◽

Sylvain Garel ◽

Andrea Moscariello ◽

Samer Bou Daher ◽

Ralf Littke ◽

...

Keyword(s):

Organic Matter ◽

Source Rock ◽

Oil And Gas ◽

Organic Geochemistry ◽

Source Rocks ◽

Type Ii ◽

Dominant Type ◽

Type Iii ◽

North Alpine Foreland Basin ◽

Migration Pathways

AbstractAn extensive subsurface investigation evaluating the geothermal energy resources and underground thermal energy storage potential is being carried out in the southwestern part of the Swiss Molasse Basin around the Geneva Canton. Among this process, the evaluation of the petroleum source-rock type and potential is an important step to understand the petroleum system responsible of some oil and gas shows at surface and subsurface. This study provides a first appraisal of the risk to encounter possible undesired occurrence of hydrocarbons in the subsurface of the Geneva Basin. Upon the numerous source-rocks mentioned in the petroleum systems of the North Alpine Foreland Basin, the marine Type II Toarcian shales (Lias) and the terrigenous Type III Carboniferous coals and shales have been sampled from wells and characterized with Rock–Eval pyrolysis and GC–MS analysis. The Toarcian shales (known as the Posidonia shales) are showing a dominant Type II organic matter composition with a Type III component in the Jura region and the south of the basin. Its thermal maturity (~ 0.7 VRr%) shows that this source-rock currently generates hydrocarbons at depth. The Carboniferous coals and shales show a dominant Type III organic matter with slight marine to lacustrine component, in the wet gas window below the Geneva Basin. Two bitumen samples retrieved at surface (Roulave stream) and in a shallow borehole (Satigny) are heavily biodegraded. Relative abundance of regular steranes of the Roulave bitumen indicates an origin from a marine Type II organic matter. The source of the Satigny bitumen is supposedly the same even though a deeper source-rock, such as the lacustrine Permian shales expelling oil in the Jura region, can’t be discarded. The oil-prone Toarcian shales in the oil window are the most likely source of this bitumen. A gas pocket encountered in the shallow well of Satigny (Geneva Canton), was investigated for molecular and stable isotopic gas composition. The analyses indicated that the gas is made of a mixture of microbial (very low δ13C1) and thermogenic gas. The isotopic composition of ethane and propane suggests a thermogenic origin from an overmature Type II source-rock (> 1.6 VRr%) or from a terrigenous Type III source at a maturity of ~ 1.2 VRr%. The Carboniferous seems to be the only source-rock satisfying these constraints at depth. The petroleum potential of the marine Toarcian shales below the Geneva Basin remains nevertheless limited given the limited thickness of the source-rock across the area and does not pose a high risk for geothermal exploration. A higher risk is assigned to Permian and Carboniferous source-rocks at depth where they reached gas window maturity and generated large amount of gas below sealing Triassic evaporites. The large amount of faults and fractures cross-cutting the entire stratigraphic succession in the basin certainly serve as preferential migration pathways for gas, explaining its presence in shallow stratigraphic levels such as at Satigny.

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Stratigraphic evolution and source rock potential of a Lower Oligocene to Lower–Middle Miocene continental slope system, Hellenic Fold and Thrust Belt, Ionian Sea, northwest Greece

Geological Magazine ◽

10.1017/s0016756813000289 ◽

2013 ◽

Vol 151 (3) ◽

pp. 394-413 ◽

Cited By ~ 14

Author(s):

A. MARAVELIS ◽

G. MAKRODIMITRAS ◽

N. PASADAKIS ◽

A. ZELILIDIS

Keyword(s):

Organic Matter ◽

Source Rock ◽

Middle Miocene ◽

Oil And Gas ◽

Source Rocks ◽

Geochemical Data ◽

Thrust Belt ◽

Lower Oligocene ◽

Geochemical Parameters ◽

Fold And Thrust Belt

AbstractThe Western flanks of the Hellenic Fold and Thrust Belt are similar to the nearby prolific Albanian oil and gas provinces, where commercial volumes of oil have been produced. The Lower Oligocene to Lower–Middle Miocene slope series at this part of the Hellenic Fold and Thrust Belt provides a unique opportunity to evaluate the anatomy and source rock potential of such a system from an outcrop perspective. Slope progradation is manifested as a vertical pattern exhibiting an increasing amount of sediment bypass upwards, which is interpreted as reflecting increasing gradient conditions. The palaeoflow trend exhibits a western direction during the Late Oligocene but since the Early Miocene has shifted to the East. The occurrence of reliable index species allowed us to recognize several nannoplankton biozones (NP23 to NN5). Organic geochemical data indicate that the containing organic matter is present in sufficient abundance and with good enough quality to be regarded as potential source rocks. The present Rock-Eval II pyrolytic yields and calculated values of hydrogen and oxygen indexes imply that the recent organic matter type is of type III kerogen. A terrestrial origin is suggested and is attributed to short transportation distance and accumulation at rather low water depth. The succession is immature with respect to oil generation and has not experienced high temperature during burial. However, its eastern down-slope equivalent deep-sea mudstone facies should be considered as good gas-prone source rocks onshore since they may have experienced higher thermal evolution. In addition, they may have improved organic geochemical parameters because there is no oxidization of the organic matter.

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Effective source rock selection and oil–source correlation in the Western Slope of the northern Songliao Basin, China

Petroleum Science ◽

10.1007/s12182-021-00554-1 ◽

2021 ◽

Vol 18 (2) ◽

pp. 398-415

Author(s):

He Bi ◽

Peng Li ◽

Yun Jiang ◽

Jing-Jing Fan ◽

Xiao-Yue Chen

Keyword(s):

Organic Matter ◽

Source Rock ◽

Thermal Evolution ◽

Songliao Basin ◽

Source Rocks ◽

Crude Oils ◽

Western Slope ◽

Geochemical Parameters ◽

Group I ◽

Oil Source

AbstractThis study considers the Upper Cretaceous Qingshankou Formation, Yaojia Formation, and the first member of the Nenjiang Formation in the Western Slope of the northern Songliao Basin. Dark mudstone with high abundances of organic matter of Gulong and Qijia sags are considered to be significant source rocks in the study area. To evaluate their development characteristics, differences and effectiveness, geochemical parameters are analyzed. One-dimensional basin modeling and hydrocarbon evolution are also applied to discuss the effectiveness of source rocks. Through the biomarker characteristics, the source–source, oil–oil, and oil–source correlations are assessed and the sources of crude oils in different rock units are determined. Based on the results, Gulong and Qijia source rocks have different organic matter primarily detrived from mixed sources and plankton, respectively. Gulong source rock has higher thermal evolution degree than Qijia source rock. The biomarker parameters of the source rocks are compared with 31 crude oil samples. The studied crude oils can be divided into two groups. The oil–source correlations show that group I oils from Qing II–III, Yao I, and Yao II–III members were probably derived from Gulong source rock and that only group II oils from Nen I member were derived from Qijia source rock.

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Cyclic Subcritical Water Injection into Bazhenov Oil Shale: Geochemical and Petrophysical Properties Evolution Due to Hydrothermal Exposure

Energies ◽

10.3390/en14154570 ◽

2021 ◽

Vol 14 (15) ◽

pp. 4570

Author(s):

Aman Turakhanov ◽

Albina Tsyshkova ◽

Elena Mukhina ◽

Evgeny Popov ◽

Darya Kalacheva ◽

...

Keyword(s):

Energy Demand ◽

Oil Shale ◽

Oil And Gas ◽

Subcritical Water ◽

Pore Space ◽

Water Injection ◽

Microstructural Properties ◽

Gas Generation ◽

Geochemical Parameters

In situ shale or kerogen oil production is a promising approach to developing vast oil shale resources and increasing world energy demand. In this study, cyclic subcritical water injection in oil shale was investigated in laboratory conditions as a method for in situ oil shale retorting. Fifteen non-extracted oil shale samples from Bazhenov Formation in Russia (98 °C and 23.5 MPa reservoir conditions) were hydrothermally treated at 350 °C and in a 25 MPa semi-open system during 50 h in the cyclic regime. The influence of the artificial maturation on geochemical parameters, elastic and microstructural properties was studied. Rock-Eval pyrolysis of non-extracted and extracted oil shale samples before and after hydrothermal exposure and SARA analysis were employed to analyze bitumen and kerogen transformation to mobile hydrocarbons and immobile char. X-ray computed microtomography (XMT) was performed to characterize the microstructural properties of pore space. The results demonstrated significant porosity, specific pore surface area increase, and the appearance of microfractures in organic-rich layers. Acoustic measurements were carried out to estimate the alteration of elastic properties due to hydrothermal treatment. Both Young’s modulus and Poisson’s ratio decreased due to kerogen transformation to heavy oil and bitumen, which remain trapped before further oil and gas generation, and expulsion occurs. Ultimately, a developed kinetic model was applied to match kerogen and bitumen transformation with liquid and gas hydrocarbons production. The nonlinear least-squares optimization problem was solved during the integration of the system of differential equations to match produced hydrocarbons with pyrolysis derived kerogen and bitumen decomposition.

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Liquid hydrocarbon characterization of the lacustrine Yanchang Formation, Ordos Basin, China: Organic-matter source variation and thermal maturity

Interpretation ◽

10.1190/int-2016-0114.1 ◽

2017 ◽

Vol 5 (2) ◽

pp. SF225-SF242 ◽

Cited By ~ 2

Author(s):

Xun Sun ◽

Quansheng Liang ◽

Chengfu Jiang ◽

Daniel Enriquez ◽

Tongwei Zhang ◽

...

Keyword(s):

Organic Matter ◽

Source Rock ◽

Ordos Basin ◽

Depositional Environments ◽

Source Rocks ◽

Type I ◽

Hydrocarbon Generation ◽

Type Ii ◽

Thermal Maturity ◽

Yanchang Formation

Source-rock samples from the Upper Triassic Yanchang Formation in the Ordos Basin of China were geochemically characterized to determine variations in depositional environments, organic-matter (OM) source, and thermal maturity. Total organic carbon (TOC) content varies from 4 wt% to 10 wt% in the Chang 7, Chang 8, and Chang 9 members — the three OM-rich shale intervals. The Chang 7 has the highest TOC and hydrogen index values, and it is considered the best source rock in the formation. Geochemical evidence indicates that the main sources of OM in the Yanchang Formation are freshwater lacustrine phytoplanktons, aquatic macrophytes, aquatic organisms, and land plants deposited under a weakly reducing to suboxic depositional environment. The elevated [Formula: see text] sterane concentration and depleted [Formula: see text] values of OM in the middle of the Chang 7 may indicate the presence of freshwater cyanobacteria blooms that corresponds to a period of maximum lake expansion. The OM deposited in deeper parts of the lake is dominated by oil-prone type I or type II kerogen or a mixture of both. The OM deposited in shallower settings is characterized by increased terrestrial input with a mixture of types II and III kerogen. These source rocks are in the oil window, with maturity increasing with burial depth. The measured solid-bitumen reflectance and calculated vitrinite reflectance from the temperature at maximum release of hydrocarbons occurs during Rock-Eval pyrolysis ([Formula: see text]) and the methylphenanthrene index (MPI-1) chemical maturity parameters range from 0.8 to [Formula: see text]. Because the thermal labilities of OM are associated with the kerogen type, the required thermal stress for oil generation from types I and II mixed kerogen has a higher and narrower range of temperature for hydrocarbon generation than that of OM dominated by type II kerogen or types II and III mixed kerogen deposited in the prodelta and delta front.

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COAL AS A SOURCE OF OIL AND GAS: A CASE STUDY FROM THE BASS BASIN, AUSTRALIA

The APPEA Journal ◽

10.1071/aj02006 ◽

2003 ◽

Vol 43 (1) ◽

pp. 117 ◽

Cited By ~ 18

Author(s):

C.J. Boreham ◽

J.E. Blevin ◽

A.P. Radlinski ◽

K.R. Trigg

Keyword(s):

Organic Matter ◽

Oil And Gas ◽

Middle Eocene ◽

Vitrinite Reflectance ◽

Mineral Resources ◽

Sedimentary Basins ◽

Source Rocks ◽

Gas Generation ◽

Australian Context ◽

Effective Source

Only a few published geochemical studies have demonstrated that coals have sourced significant volumes of oil, while none have clearly implicated coals in the Australian context. As part of a broader collaborative project with Mineral Resources Tasmania on the petroleum prospectivity of the Bass Basin, this geochemical study has yielded strong evidence that Paleocene–Eocene coals have sourced the oil and gas in the Yolla, Pelican and Cormorant accumulations in the Bass Basin.Potential oil-prone source rocks in the Bass Basin have Hydrogen Indices (HIs) greater than 300 mg HC/g TOC. The coals within the Early–Middle Eocene succession commonly have HIs up to 500 mg HC/g TOC, and are associated with disseminated organic matter in claystones that are more gas-prone with HIs generally less than 300 mg HC/g TOC. Maturity of the coals is sufficient for oil and gas generation, with vitrinite reflectance (VR) up to 1.8 % at the base of Pelican–5. Igneous intrusions, mainly within Paleocene, Oligocene and Miocene sediments, produced locally elevated maturity levels with VR up to 5%.The key events in the process of petroleum generation and migration from the effective coaly source rocks in the Bass Basin are:the onset of oil generation at a VR of 0.65% (e.g. 2,450 m in Pelican–5);the onset of oil expulsion (primary migration) at a VR of 0.75% (e.g. 2,700–3,200 m in the Bass Basin; 2,850 m in Pelican–5);the main oil window between VR of 0.75 and 0.95% (e.g. 2,850–3,300 m in Pelican–5); and;the main gas window at VR >1.2% (e.g. >3,650 m in Pelican–5).Oils in the Bass Basin form a single oil population, although biodegradation of the Cormorant oil has resulted in its statistical placement in a separate oil family from that of the Pelican and Yolla crudes. Oil-to-source correlations show that the Paleocene–Early Eocene coals are effective source rocks in the Bass Basin, in contrast to previous work, which favoured disseminated organic matter in claystone as the sole potential source kerogen. This result represents the first demonstrated case of significant oil from coal in the Australian context. Natural gases at White Ibis–1 and Yolla–2 are associated with the liquid hydrocarbons in their respective fields, although the former gas is generated from a more mature source rock.The application of the methodologies used in this study to other Australian sedimentary basins where commercial oil is thought to be sourced from coaly kerogens (e.g. Bowen, Cooper and Gippsland basins) may further implicate coal as an effective source rock for oil.

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PETROLEUM SOURCE ROCKS IN THE ROPER GROUP OF THE MCARTHUR BASIN: SOURCE CHARACTERISATION AND MATURITY DETERMINATIONS USING PHYSICAL AND CHEMICAL METHODS

The APPEA Journal ◽

10.1071/aj93026 ◽

1994 ◽

Vol 34 (1) ◽

pp. 279 ◽

Cited By ~ 1

Author(s):

Dennis Taylor ◽

Aleksai E. Kontorovich ◽

Andrei I. Larichev ◽

Miryam Glikson

Keyword(s):

Organic Matter ◽

Chemical Evolution ◽

Oil And Gas ◽

Source Rocks ◽

Type I ◽

Peak Oil ◽

Gas Generation ◽

Oil Generation ◽

Physical And Chemical ◽

Extractable Organic Matter

Organic rich shale units ranging up to 350 m in thickness with total organic carbon (TOC) values generally between one and ten per cent are present at several stratigraphic levels in the upper part of the Carpentarian Roper Group. Considerable variation in depositional environment is suggested by large differences in carbon:sulphur ratios and trace metal contents at different stratigraphic levels, but all of the preserved organic matter appears to be algal-sourced and hydrogen-rich. Conventional Rock-Eval pyrolysis indicates that a type I-II kerogen is present throughout.The elemental chemistry of this kerogen, shows a unique chemical evolution pathway on the ternary C:H:ONS diagram which differs from standard pathways followed by younger kerogens, suggesting that the maturation histories of Proterozoic basins may differ significantly from those of younger oil and gas producing basins. Extractable organic matter (EOM) from Roper Group source rocks shows a chemical evolution from polar rich to saturate rich with increasing maturity. Alginite reflectance increases in stepwise fashion through the zone of oil and gas generation, and then increases rapidly at higher levels of maturation. The increase in alginite reflectance with depth or proximity to sill contacts is lognormal.The area explored by Pacific Oil and Gas includes a northern area where the Velkerri Formation is within the zone of peak oil generation and the Kyalla Member is immature, and a southern area, the Beetaloo sub-basin, where the zone of peak oil generation is within the Kyalla Member. Most oil generation within the basin followed significant folding and faulting of the Roper Group.

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Organic Geochemical Characteristics of Core Samples from Central Primorsk-Emba Province, Precaspian Basin, Kazakhstan

10.2118/207044-ms ◽

2021 ◽

Author(s):

Tolganay Jarassova ◽

Mehmet Altunsoy

Keyword(s):

Mass Spectrometry ◽

Gas Chromatography ◽

Organic Matter ◽

Aromatic Hydrocarbons ◽

Oil And Gas ◽

Gas Chromatography Mass Spectrometry ◽

Type Ii ◽

Core Samples ◽

Chromatography Mass Spectrometry ◽

Potential Type

Abstract The Primorsk-Emba province is one of the main oil and gas region of the Precaspian basin. The resources of the Primorsk-Emba oil and gas region range from 5 to 12 billion tons of oil and from 2 to 6 trillion m³ of natural gas. This study primarily concentrates on investigating the organic geochemistry and petroleum geology characteristics of sedimentary units that generated oil in the central Primorsk-Emba province. 20 core samples taken from the Jurassic units in the western part of the study area are characterized by organic matter amount, hydrocarbon production potential, type of organic matter, maturity of organic matter. According to the Rock-Eval results Jurassic aged rocks generally have a petroleum potential ranging from weak to excellent, the organic matter is between Type II (oil prone), Type II-III (gas-oil prone) and Type III (gas prone), and the degree of maturation is immature-mature stage. Oil extracts were characterized by geochemical methods including Gas Chromatography (GC) and Gas Chromatography–Mass Spectrometry (GC–MS). n-alkanes and isoprenoids were evaluated by High-Resolution Gas Chromatography (GC-HR), aromatic hydrocarbons were evaluated by Low Thermal Mass Gas Chromatography (GC-LTM), terpanes (hopanes), steranes / diasteranes and aromatic hydrocarbons were evaluated by Gas Chromatography-Mass Spectrometry (GC-MS). The GC and GC-MS data obtained, it has been determined whether the paleoenvironment characteristics of the study area, hydrocarbon potential, type of kerogen, maturity level of organic matter and whether it is affected by biodegradation. Distribution of n-alkanes in the GC showed that no biodegradation was observed in analyzed samples, source rock deposited in a marine environment under reducing conditions and an organic matter that occurred were generated by marine carbonates. Based on maturity parameters, studied oils are mature and located on the oil generation window. According to biomarker age parameters C28 / C29 and norcholestane (NCR)/nordiacholestane (NDR) samples are generally Mesozoic (Triassic-Jurassic- Cretaceous) origin, nevertheless there are also levels corresponding to the Paleozoic (Permian) late stages.

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Comparison of the Domanic outcrops in Volga-Ural and Timan-Pechora basins

Moscow University Bulletin. Series 4. Geology ◽

10.33623/0579-9406-2018-6-57-73 ◽

2018 ◽

pp. 57-73

Author(s):

A. P. Zavyalova ◽

V. V. Chupakhina ◽

A. V. Stoupakova ◽

Yu. A. Gatovsky ◽

G. A. Kalmykov ◽

...

Keyword(s):

Organic Matter ◽

Oil And Gas ◽

Gas Content ◽

Thin Sections ◽

Lower Carboniferous ◽

Oil Companies ◽

Pechora Basin ◽

Geochemical Parameters ◽

Frasnian Stage ◽

Lithological Composition

Domanic (and domanicoid) deposits are in a great interest of researchers and oil companies, since they possess authigenic oil and gas content. The article presents the results of study outcrops in the Volga-Ural and Timan-Pechora basins. The stratigraphic interval included sediments from the Middle Frasnian stage of the Upper Devonian to the Turnasian stage of the Lower Carboniferous. The main types of rocks were characterized by microscopic examination of thin sections and geochemical parameters of organic matter. It is shown that the domanic deposits of the Timan-Pechora basin are similar in structure and lithological composition to the deposits of the Volga-Ural Basin. The upper part of the domanic section is distinguished by the predominance of the carbonate-siliceous type of rocks over the kerogen mixed varieties. According to the geochemical parameters, the organic matter in the rocks of the sheltered deposits of the Volga-Ural and Timan-Pechora basins belongs to type II, but on the outcrops of the Volga-Ural region, the organic matter of the high-carbon sequence is more mature than on the outcrops of Timan-Pechora basin.

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Integration of the outcrop and subsurface geochemical data: implications for the hydrocarbon source rock evaluation in the Lower Indus Basin, Pakistan

Journal of Petroleum Exploration and Production Technology ◽

10.1007/s13202-018-0569-6 ◽

2018 ◽

Vol 9 (2) ◽

pp. 937-951 ◽

Cited By ~ 1

Author(s):

Sajjad Ahmad ◽

Faizan Ahmad ◽

Abd Ullah ◽

Muhammad Eisa ◽

Farman Ullah ◽

...

Keyword(s):

Organic Matter ◽

Source Rock ◽

Vitrinite Reflectance ◽

Indus Basin ◽

Hydrocarbon Generation ◽

Type Ii ◽

Hydrocarbon Source Rock ◽

Hydrocarbon Generation Potential ◽

Well Data

Abstract The present study details the hydrocarbon source rock geochemistry and organic petrography of the outcrop and subsurface samples of the Middle Jurassic Chiltan Formation and the Lower Cretaceous Sembar Formation from the Sann #1 well Central and Southern Indus Basin, Pakistan. The total organic carbon (TOC), Rock–Eval pyrolysis, vitrinite reflectance (Ro) % and Maceral analysis techniques were used and various geochemical plots were constructed to know the quality of source rock, type of kerogen, level of maturity and migration history of the hydrocarbons. The outcrop and Sann #1 well data on the Sembar Formation reveals poor, fair, good and very good quality of the TOC, type II–III kerogen, immature–mature organic matter and an indigenous hydrocarbon generation potential. The outcrop and Sann #1 well data on the Chiltan Formation show a poor–good quality of TOC, type II–III kerogen, immature–mature source rock quality and having an indigenous hydrocarbon generation potential. The vitrinite reflectance [Ro (%)] values and Maceral types [fluorescent amorphous organic matter, exinite, alginite and inertnite] demonstrate that maturity in both Sembar and the Chiltan formation at surface and subsurface fall in the oil and gas generation zone to cracking of oil to gas condensate zone. Recurrence of organic rich and poor intervals within the Sembar and Chiltan formation are controlled by the Late Jurassic thermal uplift preceding the Indo-Madagascar separation from the Afro-Arabian Plate and Early Cretaceous local transgressive–regressive cycles. From the current study, it is concluded that both Sembar and Chiltan formation can act as a potential hydrocarbon source rock in the study area.

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