Normal Alkane Distributions Research Articles

Geochemical and Organic Petrological Evaluation of Organic Matter from Tertiary Sediments of Baga Field in Chad Basin, Northeast Nigeria

The Upper Cretaceous sediments in Bornu are considered an important regional source rock in the Chad Basin. This study therefore evaluated the geochemical and organic petrological evaluation of organic matter in tertiary sediments of Chad Basin, Northeast Nigeria by collecting 25 cutting samples from these organic-rich shale sediments from four wells drilled in Baga field in the Nigeria sector (Bornu) of the Chad Basin, in order to geochemically assess the type of organic matter, thermal maturity, and palaeoenvironmental conditions. Results reveal that Bornu sediments contain high organic matter more than 2.0 wt% TOC and have an excellent oil-generation potential. This is supported by high bitumen extractions and hydrocarbon yields with values 5827 and 3547 ppm, respectively. The investigated biomarkers indicated that the shale sediments contain a high abundance of C27 regular sterane concentrations, high C27/C29 regular sterane ratios and relatively low value of the biomarker sterane/hopane ratio as well as the presence of tricyclic terpanes. A mainly suboxic to relatively anoxic preservation conditions is inferred from Pr/Ph ratios (1.03–2.53). This is support by normal alkane distributions, which are characterized by dominance of types I/II kerogen and low medium molecular weight n-alkane compounds, respectively. This is further supported by lower amounts of acyclic isoprenoids compared to n-alkanes (e.g., pristane/n-C17 and phytane/n-C18 ratios). This is also supported by a mixture of algal and amorphous organic matter that was deposited in a lacustrine environment identified from kerogen microscopy. Based on the analyzed biomarkers, triterpanes and terpanes thermal maturity indicates that the Bornu sediments organic matters have entered into early mature stage for oil generation. This is also supported by vitrinite reflectance values of 0.57–0.71 % Ro indicate that these organic matters have reached oil window maturity.

Prospects of oil and gas potential of the South Torgai sedimentary basin

One of the main directions for assessing the prospects of oil production is the study of oils. In this regard, modern geochemical studies are widely used in forecasting the oil and gas potential of the subsurface, occupying an important role in the question of the origin and source of hydrocarbons. The study is aimed at a comprehensive analysis of the geochemical characteristics of the South Torgai sedimentary basin in order to identify and assess the prospects for oil and gas potential. Comparing the composition of oils from different deposits makes it possible to determine the oil source strata, zones of oil formation and oil accumulation. The compounds in oils that are most or least susceptible to changes under the influence of factors such as water leaching, biodegradation and thermal transformation are subject to comparison. The relative content of individual classes of compounds in the oils of the Aryskum trough, the geological characteristics of oil samples and the distribution of normal alkanes are presented. In this work, a comparative analysis of previously conducted geochemical studies was carried out to determine the composition and genesis of oils in the Aryskum trough. Biomarkers in oils, which make it possible to restore the genetic properties of oils and determine the conditions of sedimentation of oil-generating organic substances, indicate the presence of suboxidation conditions, redox potential and predominantly oxidative environment in the process of sedimentation of organic substances. The results obtained are important for understanding the processes of oil formation and generation, as well as for further forecasting the oil content of the South Torgai sedimentary basin.

Crude Oils of Domanik Genotype from Middle Devonian Deposits of the Timan–Pechora Oil-and-Gas Province

The composition of biomarker hydrocarbons in crude oil samples from Middle Devonian deposits of the Western Tebuk, Dzh”er, and Michayu oil fields of the Omra–Lyzha saddle in the Timan–Pechora oil-and-gas province was studied. Significant effect of the Upper Devonian Domanik source rocks on the formation of the composition of these crude oils was revealed. The main parameters demonstrating the genetic relationship of the oils from Middle Devonian reservoirs with this source rocks are distribution of steranes С27 : С28 : С29, ratio of isoprenoid to normal alkanes, and distribution of normal alkanes. All these characteristics sharply distinguish the crude oils under consideration from paraffinous oils syngenetic to Middle Devonian deposits, characteristic of deposits in the southern part of the Pechora–Kozhva megarampart.

ORGANIC MATTER IN THE PARATUNKA GEOTHERMAL FIELD (KAMCHATKA) THERMAL WATERS

Link for citation: Poturay V.A. Organic matter in the Paratunka geothermal field (Kamchatka) thermal waters. Bulletin of the Tomsk Polytechnic University. Geo Аssets Engineering, 2023, vol. 334, no. 8, рр. 98-109. In Rus. The relevance of the research is determined by the need to obtain actual data on the composition of organic compounds in thermal mineral waters. Hydrothermal systems contain different classes of organic matter, its composition in the Far East thermal waters being poorly investigated. The organic matter study is primarily aimed at elucidating the mechanisms of organic components transformation under high temperatures and pressure. This study contributes to deeper understanding of the processes occurring in the system «water–rock–organic matter». The main aim of the research is to determine the organic compounds composition and genesis in the Paratunka geothermal area (Northern and Karymshin sites) thermal waters; estimation of the hydrocarbons molecular weight distribution; compare the obtained data with that for other hydrothermal systems of Kamchatka. Objects: the Paratunka hydrothermal system (thermal water from deep wells in the Northern and Karymshin areas), the Mutnovka and Uzon hydrothermal systems (steam-water mixture from deep wells in the Dachnoe and North Mutnovskaya thermal fields, and thermal water from shallow wells in the Eastern thermal field). Methods: field routes, solid-phase extraction, capillary gas chromatography-mass spectrometry, calculation of geochemical hydrocarbon distribution indices. Results. In the Paratunka geothermal area thermal waters 40 organic compounds are found, which belong to 11 homological series. Aromatic and aliphatic hydrocarbons of thermogenic (formed as a result of thermocatalytic transformation of organic residues) and bacterial origin reach their maximum distribution. The specific molecular-weight distribution of normal alkanes showing only even low-molecular-weight homologues is characteristic of the Karymshin thermal waters. Comparison of the data with the results of the study of organic matter in Kamchatka (the Paratunka, Mutnovka, and Uzon geothermal areas) demonstrates a great similarity of main organic components composition, all of them showing a sharp predominance of aliphatic and aromatic hydrocarbons.

Source rock characteristics and 1D basin modeling of the lower Cretaceous Latrobe Group, Gippsland Basin, Australia

The aim of this study is to perform source rock characterization of the Lower Cretaceous Latrobe Group's formations in the Gippsland Basin. A total of 138 source rock samples with coal and shale lithologies were selected from three formations represented by Chimaera, Curlip and Kipper Shale formations. The geochemical analyses consisting Rock-Eval pyrolysis, total organic carbon (TOC), vitrinite reflectance (% VR), maceral composition, and biomarkers were used for source rock characterization of the studied formations. It can be interpreted that the formations have poor to very good TOC (average of 2.32 wt %) indicating good organic abundance, while the coal samples from Chimaera Formation have higher organic abundance with excellent TOC (average of 45.25 wt %). These indicate good hydrocarbon generative potential. The formations mostly generate type II/III (mixed) to type III (gas prone) kerogens. Maturity parameters including production index (PI), temperature of maximum pyrolysis (Tmax), % VR and carbon preference index (CPI) indicated that the source rocks are immature to late mature (oil to oil/gas windows). Paleodepositional environment of source rocks is evaluated with biomarker data – normal alkane distribution, pristane/phytane (Pr/Ph) and isoprenoid/normal-alkane ratios. The results show that the source rocks are dominantly terrestrial, deposited in oxic setting. The rock samples did not show any sign of hydrocarbon migration, but experienced biodegradation. However, biomarker analyses were only done on the Chimaera Formation and the results do not represent the whole source rocks in this study. 1D basin modeling was done for Kipper wells. The results show that in Kipper-1, the oil and gas generations started in Kipper Shale at depths 1900 m about 24 Ma, and 2510 m about 15.4 Ma, respectively. In Kipper-2, oil and gas generations started in Chimaera Formation at depths 2540 m about 8 Ma, and 2580 m about 2.5 Ma, respectively. Transformation ratio (TR) plots show that the oil and gas generations have not reached the peak. Petroleum system event (PSE) chart suggested that the main hydrocarbon generation of the Latrobe Group started 26 Ma and is simultaneously being preserved in the Gippsland Basin. This study hopes to give insight of the burial history concept, hydrocarbon generation, and give support in the development of the hydrocarbon fields in the Gippsland Basin.

Geochemistry and organic petrology of the bituminite shales from the Kapurdi mine, Rajasthan of NW India: implications for waxy oil generation potential

This study examines the geochemical and petrographic characteristics of seven bituminite shales from the Kapurdi mine in the Rajasthan, NW India, in order to assess their organic matter inputs and evaluate the oil-prone potentials. These bituminite shale samples exhibit high total organic carbon (TOC) content (up to 45.11 wt.%). The high TOC contents were correlated with low total sulfur content of less than 1 wt.% and suggest that these bituminite shales were deposited in a fresh lacustrine environment. The dominance of such lacustrine environmental setting was confirmed by the presence of the Botryococcus algae. The analyzed bituminite shales are characterized by a bimodal distribution of normal alkanes and relatively low isoprenoid Pr/Ph, Pr/n-C17 and Ph/n-C18 ratios. These characteristics suggest that these bituminite shales contain a blend of organic matter that was derived primarily from algal lacustrine and other aquatic organic matter, with terrigenous land plants and deposited under suboxic to anoxic environmental conditions. Such findings of the organic matter (OM) input and environmental conditions are consistent with mainly Types I and II kerogen and small amounts of Type II/III kerogen, thus yielding both oil and gas prone to higher concentrations of oil generation potential. The dominance of hydrogen-rich kerogen and oil generation potential is in agreement with the findings of high hydrogen index (HI = 240–425 mg HC/g TOC) and H/C atomic ratio of more than 1.20. The abundance of n-alkene and n-alkane doublets in the pyrolysis–gas chromatography (Py–GC) also indicates that these bituminite shales have potential to generate high concentrations of paraffinic waxy oil. Most of the maturity indicators show that the bituminite shales from the Kapurdi mine have not yet entered the main stage of oil generation window, exhibiting a range of immature stages. Therefore, as highlighted in this study, these bituminite shales can be considered as a good candidate for oil shale reoterting processes to release commercial amounts of oil upon using artificial heating techniques such as hydrothermal conversion.

Nitrogen–Sulfur–Oxygen compounds in the study of oil migration in Block TW, eastern flank of the Oriente Basin, Ecuador

Nitrogen–Sulfur–Oxygen compounds of crude-oil samples were analyzed to study oil migration in Block TW. The 15 crude-oil samples of the Upper Cretaceous Napo Formation M1ss Member had similar geochemical characteristics; a similar normal alkane distribution mode (forward peak-single peak model); and similar terpane, hopane, and regular sterane distribution characteristics, which are similar to those of the Upper Cretaceous marl in the eastern flank. The nitrogen compounds of the crude oils from the M1ss Member in Block TW show a prominent geochromatographic effect-an obvious decrease in the total absolute abundance of pyrrole (a kind of biomarker), absolute abundance of exposed pyrrolic hydrogen. The ratios of “shielded pyrrolic hydrogen/exposed pyrrolic hydrogen” and “partially shielded pyrrolic hydrogen/exposed pyrrolic hydrogen” increase with oil migration while the ratios of “shielded pyrrolic hydrogen/partially shielded pyrrolic hydrogen” exhibited almost no change. The ratios of 1,8-/2,6-dimethylcarbazole, 1,4-/2,6-dimethylcarbazole, and 1,5-/2,6- dimethylcarbazole were good indicators of oil migration, which greatly decreased in short-distance migration in the Johanna reservoir and Alice West reservoir and could be used to semiquantitatively analyze the oil migration direction within the same reservoir. The main oil migration in Block TW was from southwest to northeast, and the geochromatographic effects between different reservoirs were not obvious, which might be the results of different oil charging points, different migration pathways, or the simultaneous supply of local and far sources. Heteroatomic compounds of oxyfluorene and thiofluorene series have strong biodegradation resistance and can assist in identifying the direction of oil migration. The variation trend of total abundance of oxyfluorene and thiofluorene in Block TW is similar to that of carbazole series compounds, but the migration fractionation effect is not as obvious as that of pyrrole series compounds. A set of parameters should be used in studying oil migration, which can be determined according to most of their variation trends. The ratios of 1,8-/2,6-dimethylcarbazole, 1,4-/2,6-dimethylcarbazole, and 1,5-/2,6-dimethylcarbazole in the M1ss Reservoir of Block TW have similar and obvious geochromatographic effects, which can be used as regional oil and gas migration indicators. The pyrrole compounds (particularly the carbazole series) have obvious geochromatographic effects along with oil migration, which could be used to analyze its direction, particularly in highly explored areas with several wells.

Model of hydrocarbon compounds distribution in pore space of bazhenov horizon

The article provides the results of the hydrocarbon compounds (HCS) molecular composition in open and closed pores of the Bazhenov horizon source rocks studying. Extraction with solvents of different polarity allows to withdraw additional HCS from both open and closed pores of rock samples, and their composition systematically differs both in the distribution of normal alkanes and in the values of biomarker parameters characterizing the maturity and sedimentary conditions. HCS in open pores is more thermally maturated than HCS in closed pores, and in both cases, maturity can decrease in blocked pores, especially in those sealed with soluble in alcohol-benzene resins-asphaltenes. The values of parameters Pr/Ph and dia/(dia+reg)C27 are higher for bitumen in open pores, but the values of C29/C30 and H35S/H34S are much higher for bitumen in closed pores, and can vary in blocked pores with respect to the open ones. As a result, a improved model of HCS distribution in the pore space was proposed, which shows the presence of residual light HCS in open pores, as well as two types of blocked pores, in which HCS are sealed by different resins-asphaltenes in both open and closed pore spaces.

Hydrothermal Impact on Hydrocarbon Generation from Low-Permeable Domanic Sedimentary Rocks with Different Lithofacies

This study is intended to reveal the impact of hydrothermal treatments at temperatures of 200, 250, 300, and 350 °C on organic matter (OM) of low-permeable rocks of two different lithofacies types (carbonate and carbonate–siliceous rocks) from Domanic deposits of Upper Devonian Tatarstan. Autoclave experiments were carried out in a carbon dioxide environment. The content of OM and the yield of rock extracts, as well as the stability of kerogen structures to hydrothermal influences, were evaluated. The content of saturated hydrocarbons in the rock extracts increases after the hydrothermal transformation of kerogen and high-molecular-weight compounds, while the content of aromatic hydrocarbons and asphaltenes decreases. The results of molecular weight distribution of normal alkanes and isoprenoids show that rock extracts according to the classification of A. Petrov correspond to the A type of crude oil. Exposing hydrothermal factors on Domanic rocks at low and high temperatures provides more total extraction of hydrocarbons from rocks. The most intensive kerogen transformation process occurred at 350 °C. Hydrothermal impact on the carbonate rocks leads to almost complete transformation of kerogen with the formation of hydrocarbons, while in carbonate–siliceous rock samples, significant part of kerogen does not undergo transformation. The specific features of some biomarkers such as alkanes, aryl isoprenoids, steranes, and terpanes in petroleum products before and after hydrothermal treatment were discussed. The results indicate the general genetic nature of OM, but different geochemical conditions of its maturation in the sedimentary strata. Thus, steam injection leads to different hydrocarbon generating potential from different reservoir rocks.

Influence of Biodegradation Processes on the Relative Distribution of Normal and Isoalkanes in Oil

The article presents research and describes the mechanism of aerobic biodegradation of oils of various origins. The influence of degradation processes on the relative distribution of normal alkanes and isoprenoids is considered. When drawing conclusions about the type of source substance, sedimentation conditions, and maturity parameters based on biomarker correlations, it is essential to exclude the presence of biodegradation, or take into account its influence in relation to the objects under study. The practical significance of the research lies in the fact that the selectivity of oil biodegradation in terms of various effects on the ratio of isobutane/n-butane can be used to clarify the remaining reserves of oil fields.

Oil-source correlation in the West Esh El Mellaha, southwestern margin of the Gulf of Suez rift, Egypt

There are several source rock units in the Gulf of Suez graben, but the Upper Cretaceous–Miocene sequence has probably produced most of the commercial hydrocarbons in this petroleum province. One hundred and nine shale, marl and marly shale samples collected from five wells in the West Esh El Mellaha Concession and surrounding area were studied by petrographic and organic geochemical methods to determine organic facies, depositional paleoenvironment, and thermal maturity. We also investigated the molecular and stable carbon isotopic compositions of nine oil samples to establish genetic relationships with the source rock samples.Pyrolysis data for samples from the Cenomanian–Santonian Matulla, Paleocene Esna, Eocene Thebes, Oligo-Miocene Nukhul and Lower–Middle Miocene Rudeis formations contain hydrogen-poor terrigenous Type-III to II/III kerogen. However, the Campanian–Maastrichtian Brown Limestone samples contain Type-II and Type-II/III kerogens indicating very good to excellent generation potential. The acyclic isoprenoids and normal alkane distributions and biomarkers in the source rock extracts indicate derivation from bacteria and algae, with varying contributions from land plants, deposited under suboxic to anoxic conditions in normal marine to higher salinity waters.The oil samples have high sulfur content and low to moderately high API gravity, typical of mature oils from pre-rift marine carbonate or calcareous shale lithofacies. Hierarchical cluster analysis (HCA) of 18 source-related biomarker ratios revealed four genetic families of oil samples. The two South Malak-1 oils (Family-4) are substantially different from the Rabeh E−8 and Rabeh E−10 (Family-1), Rabeh-1 and Hurghada-1 (Family-2) and Abu Marwa-1 and Wadi El Sahl-1 (Family-3) oil families, which are more closely related. Principal component analysis (PCA) and HCA based on the 18 ratios for the total data from extracts and oils indicate three groups. The South Malak-1 oils seem to be most closely related to the two Brown Limestone extracts. Group-1 oils appear to represent mixtures with one end member consisting of the South Malak-1 oils and the Brown Limestone source rock, but the other end member is not in the dataset.

Autoignition of varied cetane number fuels at low temperatures

The reactivity of six kerosene based control fuels, specifically formulated for cetane number variation, are investigated by measuring ignition delay time in a heated rapid compression machine. Cetane numbers vary from 30 to 55 (increment of 5) while holding other properties relatively constant by adjusting chemical group composition. Main cetane variation was controlled through the distribution of normal alkanes and isoalkanes, which was fine-tuned using additives. Other fuel properties such as density, viscosity, H/C ratio, etc. were balanced using cyclic compounds and aromatics. Fuels were tested in the RCM at compressed pressures of Pc = 10 and 20 bar, equivalence ratios of ϕ = 0.25, 0.5 and 1.0, in the low to intermediate temperature range (620 K ≤ Tc ≤ 730 K). Relations between cetane number and ignition delay time have been evaluated at multiple test conditions, and further analysis on multistage ignition has been conducted. Ignition delay times of fuels with higher cetane numbers are shorter at these temperatures for most conditions. First stage ignition delay time measurements have been observed to be relatively insensitive to Pc, ϕ, and fuel type, while deviations in overall ignition delay times are mainly attributed to second stage ignition delay time, impacted by variations in the first stage temperature. Control fuels of this type offer an opportunity to be used in practical experiments to determine the impact of cetane number on combustion dynamics.

Organic geochemical characteristics and generating potential of source rocks from the Lower-Middle Jurassic coal-bearing strata in the East Junggar Basin, NW China

Abstract The Junggar Basin located in NW China is a large, intracontinental superimposed basin. Samples were collected from the Lower-Middle Jurassic coal-bearing strata of the eastern Junggar Basin and include mudstones, carbargilites and coal. The origin of organic matter, thermal maturity, paleoenvironment of sediment deposition and hydrocarbon potential of drill core samples was investigated. Organic geochemical analysis performed on 65 source rock samples indicates a wide range of TOC values from 0.81 wt % to 81.06 wt %. This study combined sedimentology, biomarker, organic petrography, and stable carbon isotopic composition of kerogen and extracts analysis demonstrating the organic matter of the source rocks is derived from terrestrial higher plants with a minor contribution of aquatic algae and microbes. Rock-Eval data, elemental composition of kerogen and odd over even normal alkane distribution reveal immaturity to low maturity with a humic - type organic matter. The source rocks were deposited in a freshwater oxic to sub-oxic environment indicated by high Pr/Ph ratios, a predominance of C29 steranes, low tricyclic terpanes and a low gammacerane index. High dia/regular C29 sterane ratios and moderate to high C29/C30 hopane ratios found in most samples are related to the presence of clay minerals. Based on the following parameters: H/C vs. O/C, TOC, S1+S2, hydrogen index, saturated hydrocarbons, aromatic hydrocarbons and Chloroform A, we concluded that the samples collected from organic-rich coal-bearing strata may yield not only gas, but also have the capability to generate and release liquid hydrocarbons.

Normal Alkane Distributions in Soil Samples along a Lhasa‐Bharatpur Transect

AbstractWe present n‐alkane distributions in the soil samples along a transect from Lhasa on the Tibetan Plateau to Bharatpur in Nepal, which covers a large geographical area and a wide range of climatic conditions. These data allow us to assess the significance of n‐alkane distributions in different vegetation types and their relationships to temperature and precipitation. In the tropical rainforest and broadleaved forest zones, n‐alkanes exhibit a bimodal distribution pattern with dominant homologues around n‐C31 and n‐C23. The bimodal distribution of tropical rainforest n‐alkanes may be a general pattern because of the presence of many lianas, epiphytic plants, algae and the strong microbial activity and degradation involved in the postdepositional process. In the warm‐temperate mixed forest and needle‐leaved forest zones, the long‐chain alkanes have a pattern of n‐C31 > n‐C33 » n‐C27. In the alpine shrub and grassland zone, although the most abundant homologue is n‐C31, relatively high n‐C23 concentrations have also been observed in some samples. The statistical results show a good correlation between n‐alkane proxies and climatic factors. The average chain length (ACL) values are positively correlated with precipitation and temperature across the transect. The carbon preference index (CPI) values show a negative correlation with temperature and precipitation along a Lhasa–Bharatpur transect. Although there is a positive relationship between ACL and temperature, it is difficult to separate the two climatic variables (temperature and precipitation) because they are well coupled in the monsoon region.

Hydrocarbon potential of Ordovician–Silurian successions in Akkas field, western desert of Iraq

The shale beds of the Khabour and Akkas Formations (Ordovician–Silurian) in Akkas field of western Iraq have been studied to determine their hydrocarbon-generation potential. The total organic carbon (TOC) values of the Khabour Formation were generally low and associated with low S2 and hydrogen index (HI) values indicating that this formation is not a hydrocarbon source, although this could reflect advanced thermal maturity. The gray-green shales of the upper part of the Akkas Formation also have low TOC and S2 values. On the other hand, the TOC, S2, and HI values of the black shales of the lower part of the Akkas Formation were high. The values indicate that the gray-green shales of the upper part of the Akkas Formation are not petroleum sources, whereas the black shales of the lower part can be regarded as potential hydrocarbon source rocks. Organic petrology studies reveal that marine amorphous organic matter is predominant, and no significant differences were observed between Khabour and Akkas samples in terms of organic-matter type. Molecular geochemical data also indicate that the kerogen of the two formations is of similar origin. The normal alkane distribution is unimodal, with a maximum at , indicating marine algal organic matter. Rock-Eval and biomarker data indicate that the organic matter of the black shales of the lower part of the Akkas Formation is early mature, whereas the Khabour Formation is highly mature in the Akkas field.

Indication origin and type of organic matter and its relation to depositional conditions using molecular composition and geochemical elements: the Jurassic Amran sediments from Samae area in the Taiz Governorate, Southwestern Yemen

This study is the first attempt which provides information regarding the biomarker characteristics and geochemical elements of the Jurassic Amran sediments from Samae area in the Taiz Governorate, Southern Yemen. The geochemical results helped us to investigate the origin and type of organic matter and its relation to environment conditions during deposition of the sediments. The Amran sediments have the highest concentration of terrestrial detritus elements (e.g., SiO2, Al2O3) with relatively high carbonate element (CaO), indicating that these sediments are limestones with argillaceous and clastic contents that are deposited in a shallow marine environment. This is supported by low total sulfur (TS) contents and Sr/Ba ratios and biomarker environment indicators. Their biomarkers provide also evidence for a mixed organic matter by aquatic and terrigenous organic matter contributions. This is confirmed by bimodal distribution of normal alkanes, relation of acyclic isoprenoids to normal alkanes, relatively high tricyclic terpanes compared to tetracyclic terpanes, and high proportion of C27 (36.1–44.4 %) and C29 (33.4–41.1 %) compared to C28 (21.9–23.8 %) regular steranes. Moreover, the suboxic bottom water conditions are evidenced in the Jurassic Amran argillaceous limestone sediments, as identified from V/Ni, and pristane/phytane (Pr/Ph) ratios in the range of 1.53–2.54 and 1.09–1.38, respectively. Therefore, suboxic conditions contribute to organic matter (OM) preservation during deposition of the Amran sediments.

Organic Geochemistry of the Fossil-Bearing Phosphorites from Neoproterozoic Doushantuo Formation at Weng'an, South China

Phosphorites of the uppermost Neoproterozoic Doushantuo Formation were exposed at Weng'an, South China. Here, We report the origin of organic matter and paleoceanographic conditions of the fossil-bearing phosphorites at Weng'an, in terms of sedimentary facies, biomineralization and organic geochemistry, including the biomarker feature. GC-MS analysis showed that a normal alkane distribution pattern with a wide range of carbon atom numbers; Terpane, isoprenoids and steranes were detected in phosphorite. The biomarker implied that the sources of organic matters were the eukaryotes of phototrophic multicellular algae, protests and bacteria. Ph and Pr derivatived from Chlorophyll-a suggested that there may exist a photosynthetic process in palaeoocean. The result shows that phosphorite at Weng 'an generated from biomineralization. In summary, the evidence suggests microorganism were the major contributors to organic matter deposited as part of phosphorite, and exist biomineralization.

Biological markers and organic petrology study of organic matter in the Lower Cretaceous Abu Gabra sediments (Muglad Basin, Sudan): origin, type and palaeoenvironmental conditions

The organic-rich claystone and shale sediments of Lower Cretaceous Abu Gabra Formation are considered an important regional source rock in the Muglad Basin, Sudan. A total of 20 cutting samples from these organic-rich sediments were collected from six wells drilled at oilfields in the Fula sub-basin, Muglad Basin, in order to geochemically assess the type of organic matter, thermal maturity, and palaeoenvironmental conditions. Results reveal that Abu Gabra organic-rich sediments contain high organic matter more than 2.0 wt% TOC and have a very good to excellent oil-generation potential. This is supported by high bitumen extractions and hydrocarbon yields with values exceeding 5,000 and 3,000 ppm, respectively. The investigated biomarkers indicated that the Abu Gabra sediments contain a mixture of algal and amorphous organic matter that were deposited in a lacustrine environment setting. This has been identified from kerogen microscopy and normal alkane distributions, which are characterized by dominance of types I/II kerogen and low-medium molecular weight n-alkane compounds, respectively. This is also supported by high abundance of C27 regular sterane concentrations, high C27/C29 regular sterane ratios and relatively low value of the biomarker sterane/hopane ratio as well as the presence of tricyclic terpanes. A mainly suboxic to relatively anoxic preservation conditions is inferred from Pr/Ph ratios (1.01–2.51). This is further supported by lower amounts of acyclic isoprenoids compared to n-alkanes (e.g., pristane/n-C17 and phytane/n-C18 ratios). Based on the analyzed biomarker thermal maturity indicators, it may be deduced that the Abu Gabra sediments have entered an early mature stage for oil generation. This is also supported by vitrinite reflectance values of 0.58–0.72 % Ro indicative that these sediments have reached oil window maturity.

Migration of immiscible hydrocarbons recorded in calcite-hosted fluid inclusions, Ordos Basin: a case study from Northern China

In this study one- (hydrocarbon liquid), two- (hydrocarbon liquid and vapor) and three- (hydrocarbon liquid and vapor, and aqueous liquid) phase fluid inclusions have been investigated in calcites occurring in veinlets in fine grained sandstones of Chang 7 source rock and Chang 8 reservoir rock. These rocks are parts of the Upper Triassic Yangchang Formation in Ordos Basin, Northern China. The hydrocarbon inclusions studied show high variance in vapor-liquid volume ratio at ambient temperature, suggesting a heterogeneous entrapment of vapor and liquid phases those existed before or during formation of the calcite. This is supported by homogenizations happened into both liquid and vapor phase. Homogenization temperatures are ranging between 70 and 120 °C. We consider that this wide range are rather resulted in heterogeneous entrapment of immiscible liquid and vapor phases than high temperature (e.g., 120 °C) formation of the hydrocarbon inclusions. Therefore, the lower range of homogenization temperatures (around 80 °C) seem to be probable for formation of the hydrocarbon inclusions studied. Fluorescent microscopic results on the hydrocarbon inclusions show bright yellow color for the oil. Fluorescence spectra indexes indicate that oil in the inclusions is quite mature, similarly to the oil extract from Chang 7 source rock. The differences in fluorescent spectra among the hydrocarbon inclusions suggest their chemical modification during evolution, which might be determined by continuous separation of vapor phase (gas condensate) from the system. On the basis of organic geochemistry of the studied samples (e.g., akin distribution of normal-alkanes and similar isoprenoid ratios), it can be concluded that the oil in the inclusions and the crude oil from the reservoir rock Chang 8 are actually derived from the Chang 7 source rock. During tectonic evolution, the hydrocarbon might suffer phase separation (boiling) forming two phases (a liquid and a vapor phase) due to intensive uplifting of Ordos Basin after the Late Cretaceous. The boiling in the accumulated hydrocarbon could result in overpressure in the source rock. This phenomenon might favor formation of fractures and migration of hydrocarbons from their source toward into sandstone reservoirs. Our study demonstrates the significance of detailed analytical investigation of hydrocarbon inclusions in correlation with their potential source rock.

Petroleum composition in the Cuu Long Basin (Mekong Basin) offshore southern Vietnam

The Cuu Long Basin (Mekong Basin) is a rift basin off southern Vietnam, and the most important petroleum producing basin in the country. However, information on petroleum type and characteristics has hitherto been largely unavailable to the public. This paper presents petroleum geochemical data on nine oil samples from four different producing fields in the Cuu Long Basin: the Dragon (Rong), Black Lion (Sutu-Den), Sunrise (Rang Đong) and White Tiger (Bach Ho) Fields. The oils are highly paraffinic with bimodal normal alkane distributions and show moderate pristane to phytane ratios and a conspicuous hyperbolic decrease in abundance with increasing carbon number of hopane homologues from C 30 to C 35. The TPP-index of Holba et al. (Holba, A.G., Dzou, L.I., Wood, G.D., Ellis, L., Adam, P., Schaeffer, P., Albrecht, P., Greene, T., Hughes, W.B., 2003. Application of tetracyclic polyprenoids as indicators of input from fresh–brackish water environments. Organic Geochemistry 34, 441–469) is equal to 1 in all samples which in combination with tricyclic triperpane T26/T25 ratios >1 and the n-alkane and hopane distributions mentioned above provide a strong indication of an origin from lacustrine source rocks. This is supported by the absence of marine C 30 desmethyl steranes (i.e. 24- n-propylcholestanes) and marine diatom-derived norcholestanes. Based on the overall biological marker distributions, the lakes probably belonged to the overfilled or balanced-fill types defined by Bohacs et al. (Bohacs, K.M., Carroll, A.R., Neal, J.E., Mankiewicz, P.J., 2000. Lake-basin type, source potential, and hydrocarbon character. An integrated sequence-stratigraphic–geochemical framework. AAPG Studies in Geology 46, 3–34). The oils were generated from source rocks at early- to mid-oil-window maturity, presumably Oligocene lacustrine shales that are present in the syn-rift succession. Oils from individual fields may, however, be distinguished by a combination of biological marker parameters, such as the oleanane index, the gammacerane index, the relative abundance of tricyclic terpanes, the proportions of diasteranes and 28-norspergulane, complemented by other parameters. The oils of the Cuu Long Basin show an overall similarity to the B-10 oil from the Song Hong Basin off northern Vietnam, but are markedly different from the seepage oils known from Dam Thi Nai on the coast of central Vietnam.