Evaluation of the petroleum composition and quality with increasing thermal maturity as simulated by hydrous pyrolysis: A case study using a Brazilian source rock with Type I kerogen

Hydrous pyrolysis (HP) experiments were used to investigate the petroleum composition and quality of petroleum generated from a Brazilian lacustrine source rock containing Type I kerogen with increasing thermal maturity. The tested sample was of Aptian age from the Araripe Basin (NE-Brazil). The temperatures (280–360 °C) and times (12–132 h) employed in the experiments simulated petroleum generation and expulsion (i.e., oil window) prior to secondary gas generation from the cracking of oil. Results show that similar to other oil prone source rocks, kerogen initially decomposes in part to a polar rich bitumen, which decomposes in part to hydrocarbon rich oil. These two overall reactions overlap with one another and have been recognized in oil shale retorting and natural petroleum generation. During bitumen decomposition to oil, some of the bitumen is converted to pyrobitumen, which results in an increase in the apparent kerogen (i.e., insoluble carbon) content with increasing maturation.The petroleum composition and its quality (i.e., API gravity, gas/oil ratio, C₁₅₊ fractions, alkane distribution, and sulfur content) are affected by thermal maturation within the oil window. API gravity, C₁₅₊ fractions and gas/oil ratios generated by HP are similar to those of natural petroleum considered to be sourced from similar Brazilian lacustrine source rocks with Type I kerogen of Lower Cretaceous age. API gravity of the HP expelled oils shows a complex relationship with increasing thermal maturation that is most influenced by the expulsion of asphaltenes. C₁₅₊ fractions (i.e., saturates, aromatics, resins and asphaltenes) show that expelled oils and bitumen are compositionally separate organic phases with no overlap in composition. Gas/oil ratios (GOR) initially decrease from 508–131 m³/m³ during bitumen generation and remain essentially constant (81–84 m³/m³) to the end of oil generation. This constancy in GOR is different from the continuous increase through the oil window observed in anhydrous pyrolysis experiments. Alkane distributions of the HP expelled oils are similar to those of natural crude oils considered to be sourced from similar Brazilian lacustrine source rocks with Type I kerogen of Lower Cretaceous age. Isoprenoid and n-alkane ratios (i.e., pristane/n-C₁₇ and phytane/n-C₁₈) decrease with increasing thermal maturity as observed in natural crude oils. Pristane/phytane ratios remain constant with increasing thermal maturity through the oil window, with ratios being slightly higher in the expelled oils relative to those in the bitumen. Generated hydrocarbon gases are similar to natural gases associated with crude oils considered to be sourced from similar Brazilian lacustrine source rocks with Type I kerogen of Lower Cretaceous, with the exception of elevated ethane contents. The general overall agreement in composition of natural and hydrous pyrolysis petroleum of lacustrine source rocks observed in this study supports the utility of HP to better characterize petroleum systems and the effects of maturation and expulsion on petroleum composition and quality.     

Geochemical and petrographic characterization of organic matter in the Upper Jurassic Madbi shale succession (Masila Basin,Yemen): Origin,type and preservation

The Upper Jurassic Madbi Formation, located in the Masila Basin, eastern Yemen, represents the major source rock in this basin. Organic rich shales from two oilfields (Kharir and Wadi Taribah) were analysed to evaluate the type and origin of the organic matter and to determine the factors controlling its deposition. This study is based on geochemical analyses of whole rock (total organic carbon content, Rock-Eval pyrolysis and carbon isotope data) and petrographic analyses on organic matter (kerogen maceral composition and palynofacies) by optical and scanning electron microscopy. Organic petrographic composition of kerogen shows that the Madbi shale is characterized by high amounts of organic matter, consisting predominantly of yellow fluorescing amorphous organic matter and alginite of marine origin. Terrigenous organic materials such as vitrinite, spores and pollen are present in low quantities. The predominance of marine plankton, as indicated by visual kerogen analysis, is consistent with reported carbon isotopic values. It appears that the high amounts of organic matter in the Madbi shale succession might be mainly due to good preservation under suboxic–anoxic conditions. Consequently the Madbi shales possess very good petroleum generative potential, owing to high content of hydrogen rich Type II and I oil prone kerogen.     

西非塞内加尔盆地深水区油气地球化学特征与油气成藏

塞内加尔盆地是西非面积最大、勘探程度最低的含盐被动大陆边缘型盆地。2010年之前仅有少量非商业性的油气和重质油发现,近几年在深水区获得油气勘探的重大突破。对深水区油气进行详细地球化学分析及油源对比,结果表明:深水区发育下白垩统阿普特-阿尔布阶和上白垩统赛诺曼-土伦阶两套烃源岩,下白垩统阿普特-阿尔布阶烃源岩的碳同位素组成偏轻,含硫量低,处于成熟-高成熟演化阶段,局部达到过成熟演化阶段;上白垩统赛诺曼-土伦阶烃源岩碳同位素组成偏重,含硫量中等,处于低成熟度-成熟演化阶段。油源对比的结果显示深水区F-1井阿尔布阶储层原油来自阿普特-阿尔布阶烃源岩,F-1土伦阶储层原油来自赛诺曼-土伦阶烃源岩,而S-1井阿尔布阶储层油样性质介于二者之间,为混源的原油。     

Changes in gas composition during simulated maturation of sulfur rich type II-S source rock and related petroleum asphaltenes

Asphaltenes extracted from crude oils are proposed to possess structural features of the related source rock kerogen. For the present study micro-scale sealed vessel pyrolysis (MSSV) and combustion isotope ratio mass spectrometry (GC–C–IRMS) were used to compare gas generation from a whole rock (type II-S kerogen) from southern Italy with that from related sulfur rich asphaltenes isolated from a low maturity heavy crude oil. The purpose of was to determine whether experimental pyrolysis of oil asphaltenes can be used to predict the timing and the chemical and isotopic composition of hydrocarbon gases generated from genetically related kerogen in the source rock during burial maturation. The results show that parameters such as (gas to oil ratio) GOR and oil and gas formation timing are very similar for these two sample types, whereas gas composition, product aromaticity and sulfur content are remarkably different. Slight differences in GOR are mainly due to differences in gas formation characteristics at very high levels of thermal alteration. Secondary gas formation from the whole rock covers a much broader temperature range under geological conditions than that from the asphaltene products. However, it is remarkable that both the onset and the maximum temperature are nearly identical under geological conditions. The observed differences in gas generation characteristics are supported by discrepancies in the carbon isotopic characteristics of the gas range compounds and indicate different precursors and/or mechanisms for gas generated from whole rock and asphaltenes.     

Organic geochemical evaluation of Cretaceous shale samples from the Orange Basin,South Africa

Organic geochemical evaluation of thirty-two Aptian to Campanian shale samples from seven wells drilled on the shelf of the Orange Basin (southwestern Atlantic margin) was carried out in order to determine their origin, depositional environment, thermal maturity and hydrocarbon potential. The shale samples, selected to represent highstand, lowstand and transgressive systems tracts, were analysed by Rock–Eval pyrolysis for total organic C characteristics and by gas chromatography (GC) and gas chromatography–mass spectrometry (GC–MS) for n-alkanes, aliphatic isoprenoid hydrocarbons and biomarkers (steranes, hopanes and tricylic terpanes). For most of the shale samples Rock–Eval data, hydrogen (HI) and oxygen index (OI) point to mainly Type III terrigenous organic matter. Only a few samples of Turonian age reveal a higher proportion of marine organic matter being classified as Type II/III or Type II. Biomarker parameters suggest that the samples are deposited under suboxic to oxic environmental conditions. Rock–Eval data and biomarker maturity parameters assign for most of the samples a maturity level at the beginning of the oil window with some more mature samples of Aptian, Albian and Cenomanian age. The hydrocarbon generation potential is low for most of the shelf shales as indicated by the S2/S3 ratio and HI values. Exceptions are some samples of Turonian and Aptian age.     

Source rock potential of selected Cretaceous shales,Orange Basin,South Africa

Twenty Cretaceous shale samples from two wells in the Orange Basin of South Africa were evaluated for their source rock potential. They were sampled from within a 1400 m-thick sequence in boreholes drilled through Lower to Upper Cretaceous sediments. The samples exhibit total organic carbon (TOC) content of 1.06–2.17%; Rock-Eval S2 values of 0.08–2.27 mg HC/g; and petroleum source potential (SP), which is the sum of S1 and S2, of 0.10–2.61 mg HC/g, all indicating the presence of poor to fair hydrocarbon generative potential. Hydrogen index (HI) values vary from 7 to 128 mg HC/g organic carbon and oxygen index (OI) ranges from 37 to 195 mg CO₂/g organic carbon, indicating predominantly Type III kerogen with perhaps minor amounts of Type IV kerogen. The maturity of the samples, as indicated by T _max values of 428–446°C, ranges from immature to thermally mature with respect to oil generation. Measured vitrinite reflectance values (%Ro) of representative samples indicate that these samples vary from immature to mature, consistent with the thermal alteration index (TAI) (spore colour) and fluorescence data for these samples. Organic petrographic analysis also shows that amorphous organic matter is dominant in these samples. Framboidal pyrite is abundant and may be indicative of a marine influence during deposition. Although our Rock-Eval pyrolysis data indicate that gas-prone source rocks are prevalent in this part of the Orange Basin, the geochemical characteristics of samples from an Aptian unit at 3318 m in one of the wells suggest that better quality source rocks may exist deeper, in more distal depositional parts of the basin.     

Palynostratigraphy and palaeoenvironmental significance of the Cretaceous palynomorphs in the Qattara Rim-1X well,North Western Desert,Egypt

Palynological and palynofacies analyses were carried out on some Cretaceous samples from the Qattara Rim-1X borehole, north Western Desert, Egypt. The recorded palynoflora enabled the recognition of two informal miospore biozones arranged from oldest to youngest as Elaterosporites klaszii-Afropollis jardinus Assemblage Zone (mid Albian) and Elaterocolpites castelainii–Afropollis kahramanensis Assemblage Zone (late Albian–mid Cenomanian). A poorly fossiliferous but however, datable interval (late Cenomanian–Turonian to ?Campanian–Maastrichtian) representing the uppermost part of the studied section was also recorded. The palynofacies and visual thermal maturation analyses indicate a mature terrestrially derived organic matter (kerogen III) dominates the sediments of the Kharita and Bahariya formations and thus these two formations comprise potential mature gas source rocks. The sediments of the Abu Roash Formation are mostly dominated by mature amorphous organic matter (kerogen II) and the formation is regarded as a potential mature oil source rock in the well. The palynomorphs and palynofacies analyses suggest deposition of the clastics of the Kharita and Bahariya formations (middle Albian and upper Albian–middle Cenomanian) in a marginal marine setting under dysoxic–anoxic conditions. By contrast, the mixed clastic-carbonate sediments of the Abu Roash Formation (upper Cenomanian–Turonian) and the carbonates of the Khoman Formation (?Campanian–Maastrichtian) were mainly deposited in an inner shallow marine setting under prevailing suboxic–anoxic conditions as a result of the late Cenomanian and the Campanian marine transgressions. This environmental change from marginal to open (inner shelf) basins reflects the vertical change in the type of the organic matter and its corresponding hydrocarbon-prone types. A regional warm and semi-arid climate but with a local humid condition developed near/at the site of the well is thought to have prevailed.     

转换大陆边缘盆地深水浊积砂岩油气成藏差异性研究

深水浊积砂岩油气藏是当今世界油气勘探的热点领域。基于地震、钻井、地球化学等资料,系统分析了西非北段科特迪瓦盆地深水浊积砂岩油气成藏的差异性。研究表明,科特迪瓦盆地经历了裂陷期（早白垩世）和漂移期（晚白垩世—现今）两大构造演化阶段,漂移期发育塞诺曼—土伦阶优质海相烃源岩,裂陷期发育阿普特—阿尔布阶湖相烃源岩。漂移期层系为盆地的主力勘探层系,发育两种类型的浊积砂岩油气藏。塞诺曼—土伦阶浊积砂岩油气藏为典型的“砂体运移、自生自储、源内成藏”的油气成藏模式,其油气主要来源于塞诺曼—土伦阶烃源岩,广泛分布的浊积砂岩是油气运移的主要路径,烃源岩的生、排烃期决定了油气成藏时期,是否发育有效烃源岩是该类油气藏成藏的主控因素。圣通—马斯特里赫特阶浊积砂岩油气藏为典型的“断裂运移、下生上储、源外成藏”的油气成藏模式,其油气主要来源于深部裂陷期阿普特—阿尔布阶湖相烃源岩,断裂是油气运移的主要路径,断裂的活动控制了油气的运移和成藏时期,是否发育油源断裂是该类油气藏成藏的主控因素。     

The origin of oil in the Cretaceous succession from the South Pars Oil Layer of the Persian Gulf

The origin of the oil in Barremian–Hauterivian and Albian age source rock samples from two oil wells (SPO-2 and SPO-3) in the South Pars oil field has been investigated by analyzing the quantity of total organic carbon (TOC) and thermal maturity of organic matter (OM). The source rocks were found in the interval 1,000–1,044 m for the Kazhdumi Formation (Albian) and 1,157–1,230 m for the Gadvan Formation (Barremian–Hauterivian). Elemental analysis was carried out on 36 samples from the source rock candidates (Gadvan and Kazhdumi formations) of the Cretaceous succession of the South Pars Oil Layer (SPOL). This analysis indicated that the OM of the Barremian–Hauterivian and Albian samples in the SPOL was composed of kerogen Types II and II–III, respectively. The average TOC of analyzed samples is less than 1 wt%, suggesting that the Cretaceous source rocks are poor hydrocarbon (HC) producers. Thermal maturity and Ro values revealed that more than 90 % of oil samples are immature. The source of the analyzed samples taken from Gadvan and Kazhdumi formations most likely contained a content high in mixed plant and marine algal OM deposited under oxic to suboxic bottom water conditions. The Pristane/nC₁₇ versus Phytane/nC₁₈ diagram showed Type II–III kerogen of mixture environments for source rock samples from the SPOL. Burial history modeling indicates that at the end of the Cretaceous time, pre-Permian sediments remained immature in the Qatar Arch. Therefore, lateral migration of HC from the nearby Cretaceous source rock kitchens toward the north and south of the Qatar Arch is the most probable origin for the significant oils in the SPOL.     

Cretaceous oceanic anoxic events (OAEs) recorded in the northern margin of Africa as possible oil and gas shale potential in Tunisia: An overview

Abstract

Significant attention has been given, during the last decade, to Palaeozoic unconventional oil and gas shale in northern Africa where the productive Palaeozoic basins are located. New tentative strategies shed light on Mesozoic unconventional plays represented by Cretaceous shale reservoirs. In most petroleum systems the proven Cretaceous oceanic anoxic events (OAEs), represented mainly by the Fahdene and Bahloul Formations, played the main role in hydrocarbon generation with good distribution. Their deposition was restricted to the early Aptian (Bedoulian), the early/late Albian, and the Cenomanian–Turonian transition. Additional black shales have been detailed for the first time in Tunisia which relate to the Valanginian Weissert and late Hauterivian Faraoni events. Biostratigraphic and complete geochemical reviews have been undertaken from published papers and unpublished internal reports to better assess these important source intervals. These black shale levels, pertaining to OAEs, were deposited in almost deep marine environments during short-lived periods of anoxia (ca. 2 Ma). In the course of this review, thickness, distribution, and maturity maps have been established for each level using well data from published sources.     

Petroleum source rocks of the Tarfaya Basin and adjacent areas, Morocco

This work characterizes the source rock potential of the Tarfaya Basin and enabled us to reconstruct its geochemical history. Outcrop samples covering different stratigraphic intervals, plus the northwestern part of the Zag/Tindouf Basin (Bas Draa area), were analyzed for total organic carbon (C_org) and total inorganic carbon contents and total sulfur content. Rock-Eval analysis and vitrinite reflectance measurements were performed on 56 samples chosen on the basis C_org content. A set of 45 samples were extracted and non-aromatic hydrocarbons were analyzed by way of gas chromatography-flame ionization detection (GC-FID) and GC-mass spectrometry (GC-MS). Non-isothermal open system pyrolysis at different heating rates was applied to obtain kinetic parameters for modelling petroleum generation from four different source rocks.High quality petroleum source rocks with high C_org content and hydrogen index (HI) values were found for samples of Eocene, Coniacian, Turonian and Cenomanian age. Most samples were carbonate rich and organic/sulfur values were high to moderate. Various maturity parameters indicated immature or possibly early mature organic matter. Based on organic geochemical and petrological data, the organic matter is of marine/aquatic origin (Cenomanian) or a mixture of aquatic and terrigenous material (Eocene). The Early Cretaceous interval did not contain high quality source rocks, but indications of petroleum impregnation were found.     

Brunei Darussalam: Characteristics of selected petroleums and source rocks

The development of three Tertiary deltaic complexes has resulted in the deposition of up to 10 km of sandstones and shales comprising the sources and reservoirs for crude oils that occur onshore, near-offshore and, with future exploration efforts, those likely to be encountered in deepwater reservoirs north of the Brunei coastline. We examined a series of offshore oils and onshore rock samples in Brunei Darussalam (a) to delineate oil family groups and their source rock characteristics, and (b) to assess the source potential of the sedimentary sequence with respect to lithology and depositional setting. Twelve offshore oils and 53 shales, coaly shales and coals were examined. The oils contain indicators of allochthonous (e.g. bicadinanes, oleananes) and autochthonous (e.g. cholestanes and methylcholestanes) components in the source organic matter. Predictable geographic variations of this mixed input are clearly evident in the sample set (e.g. allochthonous input appears to increase in offshore Brunei to the northeast). Although this molecular source signature is relatively clear, migration of these oils from deep (and unidentified) source rocks has resulted in extensive migration-contamination with respect to the tetracyclic and pentacyclic hydrocarbons. This contamination has resulted in strong correlations between certain molecular maturity indicators and the present-day temperature of the reservoirs. Liquid hydrocarbon source rock potential is present in the tidal and coastal embayment facies, and is greatest in the Miocene coals. Neither the shales nor coaly shales contain significant oil generative potential. The thermal immaturity of the sample set precludes valid oil–source rock correlations without conducting artificial maturation experiments on the coals.     

Paléoenvironnements et caractérisation des roches mères pétrolières des séries pré-salifères du bassin intérieur du Gabon

The Interior Basin of Gabon, created during the break-up between South America and Africa, displays thick Neoproterozoic to Aptian p.p. fluvio-lacustrine deposits overlain by Aptian to Albian marine facies. Rock–Eval analyses from outcrop and drillhole samples show high content in organic matter (up to 25%) related to types I and II. These intervals are encountered within Permian, Neocomian–Barremian as well as Aptian siliciclastic succession. They constitute fairly good to excellent potential petroleum source rocks, which are most probably at the origin of oil indices recognized both in drillholes and in surface.     

Oil-generation kinetics for organic facies with Type-II and -IIS kerogen in the Menilite Shales of the Polish Carpathians

The Menilite Shales (Oligocene) of the Polish Carpathians are the source of low-sulfur oils in the thrust belt and some high-sulfur oils in the Carpathian Foredeep. These oil occurrences indicate that the high-sulfur oils in the Foredeep were generated and expelled before major thrusting and the low-sulfur oils in the thrust belt were generated and expelled during or after major thrusting. Two distinct organic facies have been observed in the Menilite Shales. One organic facies has a high clastic sediment input and contains Type-II kerogen. The other organic facies has a lower clastic sediment input and contains Type-IIS kerogen. Representative samples of both organic facies were used to determine kinetic parameters for immiscible oil generation by isothermal hydrous pyrolysis and S₂ generation by non-isothermal open-system pyrolysis. The derived kinetic parameters showed that timing of S₂ generation was not as different between the Type-IIS and -II kerogen based on open-system pyrolysis as compared with immiscible oil generation based on hydrous pyrolysis. Applying these kinetic parameters to a burial history in the Skole unit showed that some expelled oil would have been generated from the organic facies with Type-IIS kerogen before major thrusting with the hydrous-pyrolysis kinetic parameters but not with the open-system pyrolysis kinetic parameters. The inability of open-system pyrolysis to determine earlier petroleum generation from Type-IIS kerogen is attributed to the large polar-rich bitumen component in S₂ generation, rapid loss of sulfur free-radical initiators in the open system, and diminished radical selectivity and rate constant differences at higher temperatures. Hydrous-pyrolysis kinetic parameters are determined in the presence of water at lower temperatures in a closed system, which allows differentiation of bitumen and oil generation, interaction of free-radical initiators, greater radical selectivity, and more distinguishable rate constants as would occur during natural maturation. Kinetic parameters derived from hydrous pyrolysis show good correlations with one another (compensation effect) and kerogen organic-sulfur contents. These correlations allow for indirect determination of hydrous-pyrolysis kinetic parameters on the basis of the organic-sulfur mole fraction of an immature Type-II or -IIS kerogen.     

Paleocene-Eocene potential source rocks in the Avengco Basin,Tibet: Organic geochemical characteristics and their implication for the paleoenvironment

The Avengco Basin is located in the western part of the Tibetan Plateau and is similar to the Nima Basin in the central part of the plateau and the Lunpola Basin in the eastern part in terms of sedimentary characteristics and tectonic settings, which are well known to provide a good source rock potential. However, the organic geochemical characteristics of the Paleocene-Eocene potential source rocks in the Avengco Basin have been under debate. Thirty-four marl and mudstone outcrop samples of the Niubao Formation in the Avengco Basin were collected and subjected to the following analyses: total organic carbon (TOC), Rock–Eval pyrolysis, stable carbon isotopes of kerogen, gas chromatography (GC) and gas chromatography–mass spectrometry (GC–MS). Here, we present the results indicating the organic matter of the upper Niubao Formation is mainly composed of Type II kerogen with a mixed source, which is dominated by algae. However, the lower Niubao Formation has the less oil-prone Type II–III kerogen, and the sources of the organic matter are mainly terrestrial plants with less plankton. In addition, the samples are thermally immature to marginally mature. The Niubao Formation was deposited in an anoxic–oxic environment which was brackish with an imperceptible stratified water column. The upper Niubao Formation has a medium to good hydrocarbon-generating potential. However, the lower Niubao Formation has a zero to poor hydrocarbon-generating potential.     

Hydrocarbon source potential of the Proterozoic Sirban Limestone Formation,NW Himalaya,Jammu

The Proterozoic Sirban Limestone Formation (SLFm) crops out as detached allochthons in the northwest Himalaya (Jammu region, India) and has its coeval equivalents laterally disposed in the west in Salt Range, in the northwest in Abbotabad (Pakistan) and in southeast in Himachal Pradesh (India). The oil and gas occurrences have been reported from the Proterozoic successions globally and the hydrocarbon potential of the SLFm cannot be ruled out.The interbedded shales and algal laminated dolostones within the SLFm have yielded microflora comparable to those reported in the North African Neoproterozoic sandstones and the Late Proterozoic carbonates of the giant oil and gas fields of the Siberian Platform. The SLFm contains a rich and diverse biota comprising ~ 10% of the rock volume in thin section. The rich organic assemblage justified a hydrocarbon source potential analysis of the SLFm, tested in this study by Rock Eval (RE) pyrolysis.RE pyrolysis yielded a total organic carbon (TOC) content of 0.02 to 1 wt. % with very low Hydrogen Index (HI) values for the shales and TOC content averaging 0.02 wt. % for the dolostones. The organically lean shales and dolostones exhibit T_max values indicative of immature to post mature stage. But, since these values are for the samples with complex thermal and tectonic history the results may be unreliable. The highly altered organic matter and kerogen present in the SLFm had the potential to generate hydrocarbons and presently indicates no significant source potential. This study is important for understanding the hydrocarbon occurrences in the SLFm particularly in light of the recent oil and gas discoveries from the coeval Proterozoic successions.     

渤海莱州湾凹陷不同类型烃源岩活化能影响因素分析

选取不同干酪根类型的低熟烃源岩作为剖析对象,从干酪根类型、干酪根中有机硫含量、可溶有机质和黏土矿物对烃源岩活化能的影响进行研究,结果表明：Ⅱ1和Ⅰ干酪根活化能分布范围窄,Ⅱ2和Ⅲ干酪根活化能分布范围宽,干酪根平均活化能Ⅲ>Ⅱ2>Ⅰ>Ⅱ1;有机硫含量高的干酪根平均活化能低,有机硫对烃源岩生烃起催化作用;可溶有机质的存在影响烃源岩平均活化能的大小和分布特征,可溶有机质分布在活化能低值区间,对烃源岩生烃起催化作用;烃源岩黏土矿物中伊/蒙混层含量高,平均活化能高;伊利石含量高,平均活化能低,伊利石对烃源岩生烃起催化作用。     

The effect of organic matter type and organic carbon content on Rock-Eval hydrogen index in oil shales and source rocks

The amount of “gas-prone” kerogen (woody, fungal and “inert”) and the organic carbon content (TOC) are the two predominant factors affecting the hydrogen index (HI) in the 226 samples of lacustrine and marine oil shales and source rocks studied. HI decreases as a function of the amount of “gas-prone” kerogen and increases as a function of TOC. In addition, the type of amorphous kerogen influences the hydrogen index, and this can be roughly estimated from the fluorescence intensity of the amorphous kerogen. Nearly eighty percent of the variation in HI in these samples can be accounted for by the percentage of “gas-prone” kerogen, the TOC content, and the fluorescence of the amorphous kerogen in a multiple regression analysis.Hydrogen index increases as a function of TOC up to about 10% TOC (the relationship can be approximated by a quadratic equation) and then levels off. A possible explanation for this is that the capability of a rock to generate and expel hydrocarbons during pyrolysis increases with TOC. When the retention capacity of the rock matrix is saturated (at about 10% TOC) further increases in TOC have no effect on HI. It is also possible that the quality (i.e. oil-proneness) of the amorphous kerogen is poorer in low TOC samples than in high TOC samples.The samples came from the following oil shales and source rocks: Rundle (Queensland Eocene-Miocene), Mae Sot (northwestern Thailand, Eocene-Pliocene), River River (northwestern Colorado, Eocene), Toolebuc (western Queensland, Late Albian), the “Posidonienschiefer” (southwestern Germany, Toarcian), an Argentinian lacustrine deposit (Eocene-Miocene), the Kimmeridgian sections from four North Sea wells (blocks 21, 30, and 210), Monterey Shale (California, Miocene), and sections from six wells from the Alaskan Tertiary (North Slope, North Aleutian Shelf, Navarin Basin, Norton Sound). Most samples appear to be thermally immature (T.A.I. less than 1.8; R_o less than 0.6%) so they should be considered only potential source rocks.The lacustrine oil shales have a higher conversion ratio (yeild/TOC or S₁ + S₂/TOC) than do the marine oil shales in samples with only amorphous and algal kerogen. These, in turn, have a higher conversion ratio than the marine source rocks. These differences are roughly reflected in the fluorescence intensity of the amorphous kerogen. Free hydrocarbons are higher in the marine source rocks than in the marine oil shales, and are lowest in the lacustrine oil shales.     

Source potential and palynofacies of Late Jurassic “Lemeš facies”, Croatia

Laminated limestone and calcareous shale outcrop samples from the Late Jurassic “Leme?” facies (Croatia) were investigated to characterize their organic facies and palynofacies and their hydrocarbon generative potential. The results indicate that the organic rich sediments of “Leme?” facies were deposited within a relatively shallow marine environment at low redox potential, characterized as an oxygen depleted depositional setting with stratified bottom waters of the carbonate platform (Adriatic Carbonate Platform). The organic rich samples contain a high portion of lipid rich amorphous kerogen of algal/phytoplankton origin, enriched by bacterial biomass. Most of the analyzed samples have total organic carbon contents (TOC) greater than 3%, Rock-Eval S2 >20 mg HC/g rock, yielding Hydrogen Index (HI) values ranging from 509–602 mg HC/g TOC. According to these results, the analyzed samples have very good to excellent oil generative potential. Relatively high sulfur content suggests that the kerogen is best described as Type II-S. Biomarker maturity parameters, as well as the fluorescence of the isolated kerogen, show that the organic matter is at early to peak oil thermal maturity. The observed level of thermal maturity indicates that these samples were once buried to depths of ～5.5–5.8 km before being uplifted in the late Tertiary. The surface outcrops of the “Leme?” facies suggest that these strata have significant source potential and are the likely source of oil in the Croatian External Dinarides.     

焉耆盆地侏罗纪煤系源岩显微组分组合与生油潜力

焉耆盆地为我国西部含煤、含油气盆地, 侏罗系含煤地层是最重要的潜在源岩.对侏罗纪煤系中的暗色泥岩、碳质泥岩和煤层分别进行了有机岩石学、Rock-Eval热解分析和核磁共振分析.泥岩、碳质泥岩和煤层具有不同的有机岩石学和有机地球化学特征, 其中煤层具有3种有机显微组分组合类型, 不同显微组分组合类型的煤层具有不同的生油、生气潜力或倾油、倾气性.基质镜质体、角质体、孢子体等显微组分是煤中的主要生烃组分.侏罗系泥岩、碳质泥岩和煤层具有不同的生物标志物分布特征, 生物标志物组合分析表明焉耆盆地已发现原油是泥岩、碳质泥岩和煤层生成原油的混合产物.含煤地层的地球化学生烃潜力分析和已发现原油的油源对比均表明, 含煤地层不仅是重要的气源岩, 而且可成为有效的油源岩.