A new approach to interpreting Rock-Eval S2 and TOC data for kerogen quality assessment

A simple method for application in source potential mapping is used to assess the original oil and gas potentials in source rock horizons based upon Rock-Eval potential (S₂) and total organic carbon (TOC) values. The method assumes that kerogens consist of mixtures of end-members with assigned hydrogen index values. Based on suggested algorithms, the average amounts of oil-prone, gas-prone and inert organic material over source rock intervals are determined in TOC units. The method uses regression lines from plots of remaining hydrocarbon potentials (S₂) versus total organic carbon (TOC), and “quick-look” transparent overlays are used to read the appropriate kerogen mixture.Mineral matrix effects during pyrolysis, when strong, can cause erroneous results. This effect which occurs for oil-prone kerogens and adsorptive minerals can cause problems particularly for lean samples (S₂ = 0–3 mg HC/g rock) whilst the errors for richer samples are less.The method is applied on three sections of Upper Jurassic organic-rich rocks from the Danish North Sea sector, which are at different maturity stages. One of these sections is dominated by gas-prone material, one is dominated by oil-prone material and the third section contains a mixture of oil- and gas-prone material.The method has been compared with other methods that split kerogens in oil and gas generating potential and has given reasonable results.Experience using the method and a presented example suggest that sedimentological, system tract information may be derived from S₂ to TOC cross-plots. A constructed modelling example suggests that the end-member concept used in this approach may be used in forward type source rock prediction models when combined with sedimentological models. The resulting S₂–TOC plots can be used in order to check the forward modelling results against observed values.     

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.     

Gas-generation potential of shales in small and medium-sized basins: a case study from the Xuanhua Basin,north China

Abstract

Small- and medium-sized basins are widely distributed, and some contain commercial gas reservoirs demonstrating their gas-generation potential. The Xuanhua Basin, which is a small-sized coal-bearing basin in north China, includes a promising target for shale-gas exploration in the Xiahuayuan Formation. In this study, we used this basin as a case study to assess the critical geochemical features for small or medium-sized basins to form commercial gas reservoirs. Total organic carbon (TOC) analysis, Rock-Eval pyrolysis, microscopic observation of macerals, vitrinite reflectance measurement and kerogen stable carbon isotope analysis were performed to characterise the organic geochemistry of the Xiahuayuan shales. The original total organic carbon (TOC_o) content and hydrocarbon-generative potential (S_2o) were reconstructed to further evaluate the gas-generation potential of these shales. In addition, geochemical data of shales from other similar-sized basins with gas discoveries were compared. The results showed that the kerogen from the Xiahuayuan Formation is Type III (gas-prone), and macerals are dominated by vitrinite. TOC values showed a strong heterogeneity in the vertical profiles, with most higher than 1.5?wt%. The measured R_o values ranged from 1.4 to 2.0%. However, thermal maturity was not correlated with the present-day burial depth with higher maturity in the wells closest to the diabase intrusion centre. The remaining generation potential (S₂) averaged 0.91?mg HC/g rock, equal to 1.4?cm³ CH₄/g rock, and the average amount of hydrocarbon generated was 4.33?cm³ CH₄/g rock. In small and medium-sized basins, the TOC content of commercially developed gas shales ranged from 0.5 to 2.5?wt%, organic matter was mainly humic (gas-prone), and the burial depth was generally shallow. Biogenic gas reservoirs for commercial exploitation tend to have larger shale thicknesses (120–800?m) than thermogenic gas reservoirs (60–90?m).

1. The Xiahuayuan Formation is a good gas-source rock with gas-prone kerogen type, relatively high TOC values and moderate thermal maturity.

2. The average amount of hydrocarbon generated from the Xiahuayuan shales is about 4.33?cm³ CH₄/g rock, indicating a potential to form a shale gas reservoir.

3. Owing to the influence of diabase intrusions, the Xiahuayuan shales have entered the dry gas window at relatively shallow-buried depths.

4. Small- and medium-sized basins have the potential to generate commercial gas reservoirs with the generated volume mainly a product of the thickness and maturity of black shales.

     

Organic matter geochemistry and petrography of Late Cretaceous (Cenomanian-Turonian) organic-rich shales from the Belle Fourche and Second White Specks formations,west-central Alberta,Canada

Organic-rich mudstones with up to 10 wt% TOC from the upper portion of the Belle Fourche Formation and the lower part of the Second White Specks Formation in the Western Canada Sedimentary Basin were evaluated as source rocks. Both geochemistry and organic petrography indicate an open marine paleoenvironment with deposition of Type II kerogen based on the predominance of marine alginite and amorphous organic matter (OM), limited amounts of terrigenous vitrinite and inertinite macerals, the presence of marine fossils, and the low ratio of TOC to total sulfur (∼1.26). The prevalence of short-chain n-alkanes (n-C₁₃ to n-C₁₉), a predominance of C₂₈ αββ(H)-20S steranes, and small concentrations of oleanane confirm the dominantly algal and planktonic origin of OM. Alternating oxic to anoxic paleoenvironmental sedimentary conditions are proposed based on common bioturbation, abundant inoceramid prisms, and good organic richness. Biomarker distributions are consistent with intermittent anoxia, without unequivocal evidence for water column stratification or hypersalinity. The thermal maturity measured in seven sediment cores by different methods consistently indicates a westward increase in maturity according to vitrinite reflectance, T_max, and hopane and sterane biomarkers. Two cores are thermally immature (∼0.42 %Ro), one is early mature (∼0.65 %Ro), and four cores are within the oil window (∼0.78 to 0.89 %Ro). All thermally mature cores retain good to very good hydrocarbon potential (248 mg HC/g rock) and are dominantly oil-prone and minor gas-prone based on their maceral compositions. The upper Belle Fourche and lower Second White Specks Formations represent potential targets for unconventional light shale oil production.     

The shale gas potential of Tournaisian, Visean, and Namurian black shales in North Germany: baseline parameters in a geological context

Carboniferous black mudrocks with known petroleum potential occur throughout Northern Germany. However, despite numerous boreholes exploring for conventional hydrocarbons, the potential for shale gas resources remains uncertain. Therefore, an integrated investigation was conducted to elucidate the shale gas potential for three different Carboniferous facies incorporating baseline parameters from sedimentological and organic-geochemical analyses. Tournaisian–Namurian fine-grained rocks of the Culm-facies, with Type II + III kerogen were deposited in the basin center. TOC contents of up to 7 % occur in the Lower Alum Shale (3.6 % VRr) and up to 6 % in the Upper Alum Shale (4.4 % VRr). Bands of organic-rich black shales, reflecting sea-level variations controlled by global eustatic cycles, occur within the Tournaisian–Visean “Kohlenkalk”-facies north of the Rhenish Slate Mountains and in the Rügen island area. In both areas the organic matter is characterized by a kerogen Type II + III with TOC contents of up to 7 % and maturities of up to 4.2 and 1.8 % VRr, respectively. Black hemipelagites intercalated with coarser-grained silt- and sandstones occur in the Synorogenic Flysch Formation of the Namurian A along the southern basin margin. TOC contents vary from 0.5 to 2.0 % with Type III kerogen dominated organic matter and maturities of up to 2.5 % VRr. The baseline parameters presented in this paper indicate a shale gas potential for the sediments of the Culm-facies on the southern basin margin and of the “Kohlenkalk”-facies in the Rügen area.     

川东地区东岳庙段沉积环境演化及其页岩油气富集主控因素分析

川东地区下侏罗统自流井组东岳庙段富有机质泥页岩发育，且在局部地区已获工业页岩油气流，但尚未实现规模开发，其页岩油气富集机理研究滞后于生产实践。本文在野外调查和测试分析的基础上，对其沉积环境演化及页岩油气地质条件进行分析，并探讨其页岩油气富集主控因素，以期为实现东岳庙段页岩油气突破提供有益借鉴。结果显示：川东地区东岳庙段发育一个完整的水进水退沉积旋回，富有机质泥页岩主要发育于中部半深湖相，厚约15~30m，TOC平均为1.79%，以II型有机质为主，热演化程度较高，达凝析油—湿气阶段。以黏土矿物粒间孔和有机质孔为主，脆性矿物含量中等，脆性指数平均为62.1%。平均孔隙度为8.85%，而渗透率极低，均值仅0.239mD，呈现出“高孔低渗”特征，层内油气以侧向运移为主。其页岩油气的富集主要受富有机质泥页岩分布、热演化程度和裂缝发育条件的控制。推论垂向富有机质泥页岩连续发育的现今油气低势区是川东地区东岳庙段潜在的页岩油气高产区。     

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.     

松南上白垩统青山口组一段不同赋存状态页岩油定量评价

松辽盆地南部青山口组一段页岩油资源丰富,多口井试油获得工业及高产油流,具有较大的勘探开发潜力。本文以青山口组一段下段为研究对象,以页岩油赋存状态为切入点,重点针对研究区页岩油富集优质岩相,即高有机质薄片状页岩和中有机质纹层状页岩中溶胀油、吸附油以及游离油量进行定量评价,揭示页岩油在地下页岩层系储层中的赋存特征。青山口组一段页岩油主要以干酪根溶胀态、干酪根吸附态、有机质孔隙游离态、无机矿物吸附态及无机孔隙游离态等5种赋存形式存在于页岩层系储层中。其中：高有机质薄片状页岩中页岩油赋存状态以干酪根溶胀油、干酪根吸附油和有机质孔隙游离油等有机赋存油为主,有机赋存油量可高达253.0 mg/g TOC,以TY1井页岩油赋存量最大,其次为CY8井,H238井页岩油量最低;中有机质纹层状页岩中页岩油赋存状态以无机矿物吸附油、无机孔隙游离油等无机赋存油为主,可达167.0 mg/g TOC,CY8井页岩油赋存量最大,H258井次之,H238井页岩油量最低。TY1井、CY8井位于半深湖—深湖区,发育大套泥页岩;H238井位于三角洲外前缘,离物源区较近,导致其页岩油赋存量明显低于半深湖—深湖区。因此,沉积环境是导致不同工区页岩油赋存量差异的主要原因。     

柴达木盆地北缘侏罗系页岩油气成藏条件地质地球化学分析

基于柴达木盆地北缘侏罗系中下统富有机质泥页岩厚度、有机地化特征、物性及泥页岩含油气性等的分析研究,探讨了该地区页岩油气成藏的地质条件,对有利的勘探层段和区带进行了预测。结果表明,柴达木盆地北缘湖西山组和大煤沟组富有机质泥页岩厚度大,有机碳含量多在1.5%以上;有机质类型主要为Ⅱ和Ⅲ型;有机质成熟度从未成熟至过成熟皆有;泥页岩中脆性矿物含量约占50%,孔隙度多在1%~8%之间,孔隙类型多样。湖西山组和大煤沟组泥页岩显示出较强的吸附气体能力,多口钻井在泥页岩段存在明显全烃异常。综上表明,柴达木盆地北缘地区湖西山组、大煤沟组2个层位具备形成页岩油气的地质条件,其中湖西山组中上部泥页岩段为页岩油气有利层段,有利区在冷湖4号-5号构造一带;大煤沟组五段为页岩气有利层段、大煤沟组七段为页岩油有利层段,有利区分布于苏干湖坳陷、鱼卡断陷、红山断陷、欧南凹陷和德令哈断陷东部、南部区。     

Palynofacies,organic geochemical analyses and hydrocarbon potential of some Upper Jurassic-Lower Cretaceous rocks,the Sabatayn-1 well,Central Yemen

The current work investigates the hydrocarbon potentiality of the upper Jurassic–lower Cretaceous rocks in the Marib-Shabwah Basin, Central Yemen, through the Sabatayn-1 well. Therefore, palynological and organic geochemical analyses were carried out on 37 ditch cutting and 12 core samples from the well. Palynofacies analysis of the Madbi (late Oxfordian–early Tithonian) and Nayfa (Berriasian–Valanginian) Formations sediments indicates deposition of their organic-rich shale, calcareous shale and marl in middle to outer shelf environments under dysoxic–anoxic conditions, containing mainly kerogen of types II to III. However, the shales of the lower Sabatayn (Tithonian) Formation were deposited in an inner shelf environment of prevailing dysoxic–suboxic conditions, and show kerogen types III to II. Regional warm and relatively dry palaeoclimate but with local humid conditions developed near the site of the well is thought to have prevailed during deposition of the studied well sediments. The geochemical analyses of the Madbi Formation show higher total organic carbon content (TOC) than the overlying Sabatayn and Nayfa formations: it is varies between 1.2 and 7, and with average 4 wt% TOC, and the obtained S2 values (～3–10, average 7 mg HC/g rock) indicates that the Madbi Formation is mainly good source rock. It shows a good petroleum potential of 4–11 mg HC/g dry rock, and the Rock-Eval pyrolysis indicates mainly kerogen types II to III (oil to gas prone) of hydrogen index values (132–258, and only one sample from Lam Member is of 360 and average 215 mg HC/g TOC). The thermal maturation parameters as T _max (425–440 °C), production index (average 0.13 mg HC/g rock) and thermal alteration index (2 to 2+) reflected that this formation is present at margin of maturation to early mature stage oil window. So, the Lam Member (upper part) of the Madbi Formation is considered the main hydrocarbon (oil and gas) source rock in the Marib-Shabwah Basin. Accordingly, we predict that the Meem Member is an active source for gas and oil accumulations in the overlying sandstone reservoir of the Sabatayn Formation in the Sabatayn-1 well.     

Comparison of source rock geochemistry of selected rocks from the Schei Point group and Ringnes formation, Sverdrup basin, arctic Canada

Organic-rich from the Schei Point group (middle to late Triassic in age) and the Ringnes formation (late Jurassic) from the Sverdrup basin of the Canadian arctic archipelago have been geochemically evaluated for source rock characterization. Most samples from the Schei Point group are organic-rich (> 2% TOC and are considered as immature to mature oil-prone source rocks [kerogen types I, I–II (IIA) and II (IIA)]. These kerogen types contain abundant AOM1, AOM2 and alginite (Tasmanales, Nostocopsis, Leiosphaeridia, acritarch and dinoflagellate) with variable amounts of vitrinite, inertinite and exinite. Samples from the Ringnes formation contain dominant vitrinite and inertinite with partially oxidized AOM2, alginite and exinite forming mostly immature to mature condensate- and gas-prone source rocks [kerogen type II–III (IIB), III and a few II (IIA)]. Schei Point samples contain higher bitumen extract, saturate hydrocarbons and saturate/ aromatic ratio than the Ringnes samples. Triterpane and sterane (dominant C₃₀) distribution patterns and stable carbon isotope of bitumen and kerogen suggest that the analyzed samples from the Schei Point group are at the onset of oil generation and contain a mixture of sapropelic (algal) and minor terrestrial humic organic matter. Sterane carbon number distributions in the Ringnes formation also suggest a mixed algal and terrestrial organic matter type. There are some variations in hopane carbon number distributions, but these are apparently a function of thermal maturity rather than significant genetic differences among samples. Pyrolysis-gas chromatography/mass spectrometry of the two samples with similar maturity shows that the Schei Point sample generates three times more pyrolyzate than the Ringnes sample. Both samples have a dominant aliphatic character, although the Ringnes sample contains phenol and an aromaticity that is higher than that of the Schei Point sample.     

断陷和坳陷盆地富有机质泥岩测试参数及研究意义

以松辽盆地和桦甸盆地为例,对盆地中富有机质泥岩进行系统测试。分析表明,富有机质泥岩中含油率和TOC、气体损失率呈明显的正相关; 而与半焦、密度呈负相关; 与全水的相关性不明显。结合相关研究表明,松辽盆地富有机质泥岩中有机质主要来自湖泊自身生产物,沉积速率较慢,且成岩作用相对较强,此盆地油页岩适合低温干馏炼油,因干馏后半焦中残留有机质较少,适合烧砖、制作水泥等。桦甸盆地油页岩有机质为湖泊生物和陆源有机质共同来源,沉积速率相对较快,成岩作用较弱,此盆地油页岩适合低温干馏炼油,干馏后半焦中残留有机质较多,适合发电和烧砖等,损失气体可以回收进行瓦斯发电。     

富有机质泥页岩微纳米孔隙系统演化特征及模式研究新进展

富有机质泥页岩孔隙系统演化特征及其模式的研究有助于完善页岩油气微纳米储层地质理论,进一步揭示页岩油气富集成藏机理,并促进页岩油气综合地质评价与勘探开发.通过综述富有机质泥页岩孔隙系统特征及发育演化影响因素,简述了泥页岩复杂孔隙系统研究发展历程,分析了自然成熟序列泥页岩和模拟序列泥页岩孔隙系统演化特征,总结了国内外富有机...     

Changes in the composition of bitumen extracts and chemical structure of kerogen during hydrous pyrolysis

The paper presents data on the composition of biomarkers from bitumen extracts and the chemical structure of kerogen from C_org-rich sedimentary rocks before and after hydrothermal treatment in an autoclave at 300°C. Samples selected for this study are kukersite and Ordovician Dictyonema shale from the Baltics, Domanik oil shale from the Ukhta region, Upper Permian brown coal from the Pre-Ural foredeep, carbonaceous shale from the Oxfordian horizon of the Russian plate, and Upper Jurassic oil shales from the Sysola oil shale bearing region. The rocks contain type I, II, III, and II-S kerogens. The highest yield of extractable bitumen is achieved for Type II-S kerogen, whereas Type III kerogen produces the lowest amount of bitumen. The stages of organic matter thermal maturation achieved during the experiments correspond to a transition from PC_2–3 to MC_1–2. The ¹³C NMR data on kerogen indicate that the aromatic structures of geopolymers underwent significant changes.     

Apparent permeability and representative size of shale: a numerical study on the effects of organic matter

The impact of organic matter on the flow capacity of shale oil rocks is presumably significant, and the knowledge about the representative size is fundamental for the upscaling studies. The error of the experimentally determined permeability values is comparable with the contribution of kerogen to shale permeability, instead a 2D numerical model is employed to explore the normalised equivalent permeability and the representative elementary area (REA) of shale oil rocks in detail incorporating the effects of kerogen. The discussions on the normalised equivalent permeability and the REA are based on the statistical average and standard deviation from 1000 different runs, respectively. The inorganic permeability heterogeneity is introduced based on the assumption of a lognormal pore size distribution and the Monte Carlo sampling method. The effects of kerogen geometric characteristics are incorporated by putting forward several representative cases for comparison. The effects of the organic permeability contrast (ratio of permeability to the inorganic permeability with no heterogeneity), total organic carbon (TOC, volume fraction), inorganic permeability heterogeneity and kerogen geometric characteristics on the normalised equivalent permeability (ratio of the intrinsic equivalent permeability to inorganic permeability with no heterogeneity) and the REA are discussed comprehensively. This work can provide a better understanding of shale oil rocks at the micrometer scale.     

Application of low-pressure gas adsorption to nanopore structure characterisation of organic-rich lower Cambrian shale in the Upper Yangtze Platform,South China

The pores in shales are mainly on a nanometer scale, and the pore-size distribution is vital with regard to the preservation and exploitation of shale gas. This study focuses on the organic-rich lower Cambrian black shale in the Upper Yangtze Platform, South China and investigates their TOC, mineralogical composition and nanopore structure. Low-pressure N₂ and CO₂ adsorption experiments were conducted at 77.35 K and 273.15 K, respectively, and the nanopore structures were characterised by the modified Brunauer–Emmett–Teller, Dubinin–Radushkevich, t-plot, Barrett–Joyner–Halenda and density functional theory (DFT) methods. The results indicate the following. (1) The lower Cambrian shale has a high TOC content (1.77–7.23 wt%) and a high quartz content (27.7–51.6 vol%). The total specific surface area varies from 12.02 to 28.87 m²/g. Both the total specific surface area and quartz content are positively associated with the TOC content. (2) Shale samples with a higher TOC content have a greater number of micropores, resulting in more complicated nanopore structures. Micropore volumes/surface areas and non-micropore surface areas all increase with increasing TOC content, indicating that TOC is the key factor determining the nanopore structure of the lower Cambrian shale. (3) A combination of N₂ and CO₂ adsorption provides the most suitable detection range (～0.3–60 nm) and is both highly reliable and accurate with regard to nanopore structure characterisation.     

Analysis of geological effects on methane adsorption capacity of continental shale: a case study of the Jurassic shale in the Tarim Basin,northwestern China

The Jurassic shale is an important source rock for the found gas reservoirs in the Tarim Basin, northwestern China, but has never been researched for shale gas potential. The geological effects on methane adsorption capacity for the gas shale have been investigated in this paper through the geochemical, mineralogical and adsorption analyses on samples from wells and sections. The methane adsorption capacity ranges from 0.58 to 16.57 cm³/g, and the total organic carbon (TOC) content is between 0.5 and 13.5 wt%. The organic maturity measured by T_max is between 410 °C (immature) and 499 °C (overmature). The methane adsorption capacity of the Jurassic continental shale in the Tarim Basin is affected by many geological factors, including the TOC content, organic matter maturity, mineral composition, surface area and pore size distribution. The TOC content is the most significant factor with a positive effect on the adsorption capacity of the Jurassic shale, and the influence varies piecewise according to the TOC content. The TOC content contributes much more to the methane adsorption capacity of organic‐rich shale samples (TOC content > 0.7 wt%) than to the organic‐lean samples (TOC content < 0.7 wt%). The mineral composition is a secondary factor, and the abundance of clay content has a positive effect on the methane adsorption capacity despite its relatively weaker adsorption ability compared to TOC. The pore size distribution has different effects on surface area and pore volume. Mesopores and micropores provide the major surface area and are mainly derived from TOC and illite, which has a positive influence on the adsorption capacity. Mesopores and macropores offer the major pore volume and are mainly formed by illite, which is the major contributor for pore volume rather than surface area. In addition, the TOC and illite contents of the Jurassic shale in the Tarim Basin are closely related to the origin, maturity and diagenesis evolution of the shale: (1) both TOC and illite content variations are related to the different provenances and depositional environments of shale; (2) the decrease of TOC content with increasing maturity is also partly attributed to hydrocarbon generation; and (3) the increase of illite content with increasing maturity is due to illitization in the diagenesis of shale. Copyright © 2015 John Wiley & Sons, Ltd.     

鄂尔多斯盆地南缘铜川地区三叠系延长组长9段浊积岩特征及对有机质富集的影响

通过岩芯观察、岩石薄片粒度分析,在鄂尔多斯盆地南缘铜川地区三叠系延长组9段识别出了浊积岩,并揭示了其垂向上典型鲍马序列组合及沉积特征。同时,对鄂尔多斯盆地延长组长9段的油页岩、富有机质泥岩等样本进行TOC、热解测试,分析了该段浊积岩特征及对有机质富集的特征及影响。结果表明:半深湖--深湖区油页岩、泥岩干酪根类型以Ⅱ1型为主,浊积岩上下层位的泥岩、泥页岩、粉砂质泥岩等干酪根类型主要为Ⅲ型和Ⅱ2型。长9段浊积岩对含油页岩段的有机质富集具有一定影响,浊积岩AB及ABC序列对底部沉积的泥岩、泥页岩有机质含量影响最大,其有机碳含量相对较低;浊积岩DE序列对底部沉积的泥岩、泥页岩有机质含量影响相对较小,有机质含量相对较高。     

Prognostication of hydrocarbon generative potential in the onshore and offshore Niger Delta,Nigeria using TOC content and rock-eval pyrolysis techniques

This article prognosticates the hydrocarbon generation potential of core samples from fields A, B, C and D in Niger delta, Nigeria. The objectives of this study are to characterize the quality of these core samples by organic geochemical analyses. A total of ten core samples collected from fields A, B, C and D in Niger delta were analyzed using total organic carbon （TOC） content analysis, rock-eval pyrolysis technique. The analytical results of the stud- ied core samples reveal that they have generally high total organic carbon contents （TOC）, suggesting that conditions in the Niger delta favour organic matter production and preservation. There is a variation in the kerogen types and this may be attributed to the relative stratigraphic positions of the core samples within the Niger delta. The rock-eval results indicate that the samples from fields C and D contain predominantly Type II kerogen with a capacity to gen- erate oil and gas and hence have good generative potential. The samples from fields A and B contain mainly Type III kerogen and are gas-prone with moderate generative potential.     

Carbon isotopes of organic matter from the upper Jurassic oil shales from the Volgian-Pechora shale province and its accumulation mechanisms

The isotopic composition of carbon from the organic matter of late Jurassic oil shales from the Volgian-Pechora shale province is studied. The existence of a dependence between C_org content in the rock and the isotopic composition of kerogen carbon is ascertained. The content of the heavy carbon isotope increases with increasing C_org. This dependence is accounted for by the progressive accumulation of isotopically heavy hydrocarbons of the initial organic matter due to sulfurization. The data on the isotopic composition of individual n-alkanes of bitumen in the rocks and the data on the absence of isotopic fractionation between thermobitumen and the residual kerogen from oil shales from the Volgian-Pechora shale province obtained by treating shale in an autoclave in the presence of water are presented first in this paper.