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1.
The geochemical and petrographic characteristics of saline lacustrine shales from the Qianjiang Formation, Jianghan Basin were investigated by organic geochemical analysis, X-ray diffraction (XRD), scanning electron microscopy (SEM) and low pressure nitrogen adsorption analysis. The results indicate that: the saline lacustrine shales of Eq3 member with high oil content are characterized by type I and type II oil-prone kerogen, variable TOC contents (1.0–10.0 wt%) and an early-maturity stage (Ro ranges between 0.41 and 0.76%). The mineral compositions of Eq3 saline shale show strong heterogeneity: brittle intervals with high contents of quartz and carbonate are frequently alternated with ductile intervals with high glauberite and clay contents. This combination might be beneficial for oil accumulation, but may cause significant challenges for the hydraulic stimulation strategy and long-term production of shale oil. The interparticle pores and intraparticle pores dominate the pore system of Eq3 shale, and organic matter hosted pores are absent. Widely distributed fractures, especially tectonic fractures, might play a key role in hydrocarbon migration and accumulation. The pore network is contributed to by both large size inorganic pores and abundant micro-factures, leading to a relatively high porosity (2.8–30.6%) and permeability (0.045–6.27 md) within the saline shale reservoir, which could enhance the flow ability and storage capacity of oil. The oil content (S1 × 100/TOC, mg HC/g TOC and S1, mg HC/g rock) and brittleness data demonstrate that the Eq33x section has both great potential for being a producible oil resource and hydraulic fracturing. Considering the hydrocarbon generation efficiency and properties of oil, the mature shale of Eq3 in the subsidence center of the Qianjiang Depression would be the most favorable zone for shale oil exploitation. 相似文献
2.
The Upper Jurassic marlstones (Mikulov Fm.) and marly limestones (Falkenstein Fm.) are the main source rocks for conventional hydrocarbons in the Vienna Basin in Austria. In addition, the Mikulov Formation has been considered a potential shale gas play. In this paper, organic geochemical, petrographical and mineralogical data from both formations in borehole Staatz 1 are used to determine the source potential and its vertical variability. Additional samples from other boreholes are used to evaluate lateral trends. Deltaic sediments (Lower Quarzarenite Member) and prodelta shales (Lower Shale Member) of the Middle Jurassic Gresten Formation have been discussed as secondary sources for hydrocarbons in the Vienna Basin area and are therefore included in the present study.The Falkenstein and Mikulov formations in Staatz 1 contain up to 2.5 wt%TOC. The organic matter is dominated by algal material. Nevertheless, HI values are relative low (<400 mgHC/gTOC), a result of organic matter degradation in a dysoxic environment. Both formations hold a fair to good petroleum potential. Because of its great thickness (∼1500 m), the source potential index of the Upper Jurrasic interval is high (7.5 tHC/m2). Within the oil window, the Falkenstein and Mikulov formations will produce paraffinic-naphtenic-aromatic low wax oil with low sulfur content. Whereas vertical variations are minor, limited data from the deep overmature samples suggest that original TOC contents may have increased basinwards. Based on TOC contents (typically <2.0 wt%) and the very deep position of the maturity cut-off values for shale oil/gas production (∼4000 and 5000 m, respectively), the potential for economic recovery of unconventional petroleum is limited. The Lower Quarzarenite Member of the Middle Jurassic Gresten Formation hosts a moderate oil potential, while the Lower Shale Member is are poor source rock. 相似文献
3.
Two sets of Lower Paleozoic organic-rich shales develop well in the Weiyuan area of the Sichuan Basin: the Lower Cambrian Jiulaodong shale and the Lower Silurian Longmaxi shale. The Weiyuan area underwent a strong subsidence during the Triassic to Early Cretaceous and followed by an extensive uplifting and erosion after the Late Cretaceous. This has brought about great changes to the temperature and pressure conditions of the shales, which is vitally important for the accumulation and preservation of shale gas. Based on the burial and thermal history, averaged TOC and porosity data, geological and geochemical models for the two sets of shales were established. Within each of the shale units, gas generation was modeled and the evolution of the free gas content was calculated using the PVTSim software. Results show that the free gas content in the Lower Cambrian and Lower Silurian shales in the studied area reached the maxima of 1.98–2.93 m3/t and 3.29–4.91 m3/t, respectively (under a pressure coefficient of 1.0–2.0) at their maximum burial. Subsequently, the free gas content continuously decreased as the shale was uplifted. At present, the free gas content in the two sets of shales is 1.52–2.43 m3/t and 1.94–3.42 m3/t, respectively (under a current pressure coefficient of 1.0–2.0). The results are roughly coincident with the gas content data obtained from in situ measurements in the Weiyuan area. We proposed that the Lower Cambrian and Lower Silurian shales have a shale gas potential, even though they have experienced a strong uplifting. 相似文献
4.
The Songliao Basin is a large-scale petroliferous basin in China. With a gradual decline in conventional oil production, the exploration and development of replacement resources in the basin is becoming increasingly important. Previous studies have shown that the Cretaceous Qingshankou Formation (K2qn) has favorable geological conditions for the formation of shale oil. Thus, shale oil in the Qingshankou Formation represents a promising and practical replacement resource for conventional oil. In this study, geological field surveys, core observation, sample tests, and the analysis of well logs were applied to study the geochemical and reservoir characteristics of shales, identify shale oil beds, build shale oil enrichment models, and classify favorable exploration areas of shale oil from the Cretaceous Qingshankou Formation. The organic matter content is high in shales from the first member of the Cretaceous Qingshankou Formation (K2qn1), with average total organic carbon (TOC) content exceeding 2%. The organic matter is mainly derived from lower aquatic organisms in a reducing brackish to fresh water environment, resulting in mostly type I kerogen. The vitrinite reflectance (Ro) and the temperature at which the maximum is release of hydrocarbons from cracking of kerogen occurred during pyrolysis (Tmax) respectively range from 0.5% to 1.1% and from 430 °C to 450 °C, indicating that the K2qn1 shales are in the low-mature to mature stage (Ro ranges from 0.5% to 1.2%) and currently generating a large amount of oil. The favorable depth for oil generation and expulsion is 1800–2200 m and 1900–2500 m, respectively as determined by basin modeling. The reserving space of the K2qn1 shale oil includes micropores and mircofractures. The micropore reservoirs are developed in shales interbedded with siltstones exhibiting high gamma ray (GR), high resistivity (Rt), low density (DEN), and slightly abnormal spontaneous potential (SP) in the well-logging curves. The microfracture reservoirs are mainly thick shales with high Rt, high AC (acoustic transit time), high GR, low DEN, and abnormal SP. Based on the shale distribution, geochemical characteristics, reservoir types, fracture development, and the process of shale oil generation and enrichment, the southern Taikang and northern Da'an are classified as two favorable shale oil exploration areas in the Songliao Basin. 相似文献
5.
Shales of the Silurian Dadaş Formation exposed in the southeast Anatolia were investigated by organic geochemical methods. The TOC contents range from 0.24 to 1.48 wt% for the Hazro samples and 0.19 to 3.58 wt% for the Korudağ samples. Tmax values between 438 and 440 °C in the Hazro samples indicate thermal maturity; Tmax values ranging from 456 to 541 °C in the Korudağ samples indicate late to over-maturity. Based on the calculated vitrinite reflectance and measured vitrinite equivalent reflectance values, the Korudağ samples have a maximum of 1.91%R(g-v), in the gas generation window, while a maximum value of 0.79%R(amor-v) of one sample from the Hazro section is in the oil generation window. Illite crystallinity (IC) values of all samples are consistent with maturity results.Pr/Ph ratios ranging from 1.32 to 2.28 and C29/C30 hopane ratios > 1.0 indicate an anoxic to sub-oxic marine-carbonate depositional environment.The Hazro shales do not have any shale oil or shale gas potential because of their low oil saturation index values and early to moderate thermal maturation. At first glance, the Korudağ shales can be considered a shale gas formation because of their organic richness, thickness and thermal over-maturity. However, the low silica content and brittle index values of these shales are preventing their suitability as shale gas resource systems. 相似文献
6.
The Upper Cretaceous Mukalla coals and other organic-rich sediments which are widely exposed in the Jiza-Qamar Basin and believed to be a major source rocks, were analysed using organic geochemistry and petrology. The total organic carbon (TOC) contents of the Mukalla source rocks range from 0.72 to 79.90% with an average TOC value of 21.50%. The coals and coaly shale sediments are relatively higher in organic richness, consistent with source rocks generative potential. The samples analysed have vitrinite reflectance in the range of 0.84–1.10 %Ro and pyrolysis Tmax in the range of 432–454 °C indicate that the Mukalla source rocks contain mature to late mature organic matter. Good oil-generating potential is anticipated from the coals and coaly shale sediments with high hydrogen indices (250–449 mg HC/g TOC). This is supported by their significant amounts of oil-liptinite macerals are present in these coals and coaly shale sediments and Py-GC (S2) pyrograms with n-alkane/alkene doublets extending beyond nC30. The shales are dominated by Type III kerogen (HI < 200 mg HC/g TOC), and are thus considered to be gas-prone.One-dimensional basin modelling was performed to analysis the hydrocarbon generation and expulsion history of the Mukalla source rocks in the Jiza-Qamar Basin based on the reconstruction of the burial/thermal maturity histories in order to improve our understanding of the of hydrocarbon generation potential of the Mukalla source rocks. Calibration of the model with measured vitrinite reflectance (Ro) and borehole temperature data indicates that the present-day heat flow in the Jiza-Qamar Basin varies from 45.0 mW/m2 to 70.0 mW/m2 and the paleo-heat flow increased from 80 Ma to 25 Ma, reached a peak heat-flow values of approximately 70.0 mW/m2 at 25 Ma and then decreased exponentially from 25 Ma to present-day. The peak paleo-heat flow is explained by the Gulf of Aden and Red Sea Tertiary rifting during Oligocene-Middle Miocene, which has a considerable influence on the thermal maturity of the Mukalla source rocks. The source rocks of the Mukalla Formation are presently in a stage of oil and condensate generation with maturity from 0.50% to 1.10% Ro. Oil generation (0.5% Ro) in the Mukalla source rocks began from about 61 Ma to 54 Ma and the peak hydrocarbon generation (1.0% Ro) occurred approximately from 25 Ma to 20 Ma. The modelled hydrocarbon expulsion evolution suggested that the timing of hydrocarbon expulsion from the Mukalla source rocks began from 15 Ma to present-day. 相似文献
7.
Nine organic-rich shale samples of Lower Cambrian black shales were collected from a recently drilled well in the Qiannan Depression, Guizhou Province where they are widely distributed with shallower burial depth than in Sichuan Basin, and their geochemistry and pore characterization were investigated. The results show that the Lower Cambrian shales in Qiannan Depression are organic rich with TOC content ranging from 2.81% to 12.9%, thermally overmature with equivalent vitrinite reflectance values in the range of 2.92–3.25%, and clay contents are high and range from 32.4% to 53.2%. The samples have a total helium porosity ranging from 2.46% to 4.13% and total surface area in the range of 9.08–37.19 m2/g. The estimated porosity in organic matters (defined as the ratio of organic pores to the volume of total organic matters) based on the plot of TOC vs helium porosity is about 10% for the Lower Cambrian shales in Qiannan Depression and is far lower than that of the Lower Silurian shales (36%) in and around Sichan Basin. This indicates that either the organic pores in the Lower Cambrian shale samples have been more severely compacted than or they did not develop organic pores as abundantly as the Lower Silurian shales. Our studies also reveal that the micropore volumes determined by Dubinin–Radushkevich (DR) equation is usually overestimated and this overestimation is closely related to the non-micropore surface area of shales (i.e. the surface area of meso- and macro-pores). However, the modified BET equation can remove this overestimation and be conveniently used to evaluate the micropore volumes/surface area and the non-micropore surface areas of micropore-rich shales. 相似文献
8.
Fluctuations in lacustrine sedimentary environments significantly affect distributions of organic matter (OM), uranium, and other elements in shales. In this study a high-resolution geochemical record of fluctuations in the paleo-depositional environment of a terrestrial lake basin is provided on the basis of extensive samples collected from the Member 3 of the Paleogene Shahejie Formation (Es3) of the Niu-38 well in the Dongying Depression, Eastern China. These samples were tested for total organic carbon (TOC), element concentrations, and biomarkers to study the evolution and fluctuation in the depositional environments of an ancient lake basin and associated geochemical response. The evolution and fluctuation of the sedimentary environment from a deep lake to a semi-deep lake and then to a shallow lake delta were indicated by geochemical response. During this evolution, the values of TOC, S1, S2, Sr, and Ts/(Ts + Tm) remarkably decreased, whereas those of Co, Ni, Rb, Na, Fe/Mn, Fe/(Ca + Mg), and C29 mortane/C29 hopane significantly increased. The deep lake basin shows depositional fluctuations, as indicated by rock lithofacies and their geochemical parameters. A close interrelationship was observed among U concentration, TOC content, and inorganic element content. Uranium concentrations are positively correlated with TOC contents, Ca and Sr concentrations, and Sr/Ba and Ca/Mg ratios but negatively with K, Na, Ba, and Rb contents and Fe/(Ca + Mg) and Fe/Mn ratios. The observed increase in U concentration in the lower Es3 section is closely related to surface adsorption by clay minerals and OM, together with some replacements of Ca and Sr by U in the shales. 相似文献
9.
The pore size classification (micropore <2 nm, mesopore 2–50 nm and macropore >50 nm) of IUPAC (1972) has been commonly used in chemical products and shale gas reservoirs; however, it may be insufficient for shale oil reservoirs. To establish a suitable pore size classification for shale oil reservoirs, the open pore systems of 142 Chinese shales (from Jianghan basin) were studied using mercury intrusion capillary pressure analyses. A quantitative evaluation method for I-micropores (0–25 nm in diameter), II-micropores (25–100 nm), mesopores (100–1000 nm) and macropores (>1000 nm) within shales was established from mercury intrusion curves. This method was verified using fractal geometry theory and argon-ion milling scanning electron microscopy images. Based on the combination of pore size distribution with permeability and average pore radius, six types (I-VI) shale open pore systems were analyzed. Moreover, six types open pore systems were graded as good, medium and poor reservoirs. The controlling factors of pore systems were also investigated according to shale compositions and scanning electron microscopy images. The results show that good reservoirs are composed of shales with type I, II and III pore systems characterized by dominant mesopores (mean 68.12 vol %), a few macropores (mean 7.20 vol %), large porosity (mean 16.83%), an average permeability of 0.823 mD and an average pore radius (ra) of 88 nm. Type IV pore system shales are medium reservoirs, which have a low oil reservoir potential due to the developed II-micropores (mean 57.67 vol %) and a few of mesopores (mean 20.19 vol %). Poor reservoirs (composed of type V and VI pore systems) are inadequate reservoirs for shale oil due to the high percentage of I-micropores (mean 69.16 vol %), which is unfavorable for the flow of oil in shale. Pore size is controlled by shale compositions (including minerals and organic matter), and arrangement and morphology of mineral particles, resulting in the developments of shale pore systems. High content of siliceous mineral and dolomite with regular morphology are advantage for the development of macro- and mesopores, while high content of clay minerals results in a high content of micropores. 相似文献
10.
This study investigates the source rock characteristics of Permian shales from the Jharia sub-basin of Damodar Valley in Eastern India. Borehole shales from the Raniganj, Barren Measure and Barakar Formations were subjected to bulk and quantitative pyrolysis, carbon isotope measurements, mineral identification and organic petrography. The results obtained were used to predict the abundance, source and maturity of kerogen, along with kinetic parameters for its thermal breakdown into simpler hydrocarbons.The shales are characterized by a high TOC (>3.4%), mature to post-mature, heterogeneous Type II–III kerogen. Raniganj and Barren Measure shales are in mature, late oil generation stage (Rr%Raniganj = 0.99–1.22; Rr%Barren Measure = 1.1–1.41). Vitrinite is the dominant maceral in these shales. Barakar shows a post-mature kerogen in gas generation stage (Rr%Barakar = 1.11–2.0) and consist mainly of inertinite and vitrinite. The δ13Corg value of kerogen concentrate from Barren Measure shale indicates a lacustrine/marine origin (−24.6–−30.84‰ vs. VPDB) and that of Raniganj and Barakar (−22.72–−25.03‰ vs. VPDB) show the organic provenance to be continental. The δ13C ratio of thermo-labile hydrocarbons (C1–C3) in Barren Measure suggests a thermogenic source.Discrete bulk kinetic parameters indicate that Raniganj has lower activation energies (ΔE = 42–62 kcal/mol) compared to Barren Measure and Barakar (ΔE = 44–68 kcal/mol). Temperature for onset (10%), middle (50%) and end (90%) of kerogen transformation is least for Raniganj, followed by Barren Measure and Barakar. Mineral content is dominated by quartz (42–63%), siderite (9–15%) and clay (14–29%). Permian shales, in particular the Barren Measure, as inferred from the results of our study, demonstrate excellent properties of a potential shale gas system. 相似文献
11.
The purpose of this paper is to provide both quantitative and qualitative visual analyses of the nanometer-scale pore systems of immature and early shales, as well as to discuss the biogenic shale gas accumulation potential of the Upper Cretaceous section of the Songliao Basin. To achieve these goals, mineralogical compositions were determined using transmitted and reflected light petrography, X-ray diffractometry and scanning electron microscopy (SEM), while the nanostructure morphology and pore size distributions (PSDs) were quantified using field emission scanning electron microscopy (FE-SEM) and low-pressure nitrogen gas adsorption (LP-N2GA). The results of these analyses indicate that nanometer-scale pores are well developed in the immature and low-maturity shale, and that these shales contain many types of reservoir pores. The mudstone layer of the Qingshankou Formation (K2qn) contains a high permeability characteristic and good rock fracturing conditions, while it is also thick (>9 m in thickness) and rich in fine organic matter. Overall, analysis of the entire formation using source rock and reservoir evaluations indicate that the first member of the Qingshankou Formation (K2qn1) has a greater shale gas accumulation potential than the second and third members of the Qingshankou Formation (K2qn2-3). 相似文献
12.
13.
《Marine and Petroleum Geology》2012,37(1):13-34
Structured organic matters of the Palynomorphs of mainly dinoflagellate cysts are used in this study for dating the limestone, black shale, and marl of the Middle Jurassic (Bajocian–Bathonian) Sargelu Formation, Upper Jurassic (Upper Callovian – Lower Oxfordian) Naokelekan Formation, Upper Jurassic (Kimeridgian and Oxfordian) Gotnia and Barsarine Formations, and Upper Jurassic – Lower Cretaceous (Tithonian-Beriassian) Chia Gara source rock Formations while spore species of Cyathidites australis and Glechenidites senonicus are used for maturation assessments of this succession. Materials' used for this palynological study are 320 core and cutting samples of twelve oil wells and three outcrops in North Iraq.Terpane and sterane biomarker distributions, as well as stable isotope values, were determined for oils potential source rock extracts of Jurassic-Lower Cretaceous strata to determine valid oil-to-source rock correlations in North Iraq. Two subfamily carbonate oil types-one of Middle Jurassic age (Sargelu) carbonate rock and the other of mixed Upper Jurassic/Cretaceous age (Chia Gara) with Sargelu sources as well as a different oil family related to Triassic marls, were identified based on multivariate statistical analysis (HCA & PCA). Middle Jurassic subfamily A oils from Demir Dagh oil field correlate well with rich, marginally mature, Sargelu source rocks in well Mk-2 near the city of Baiji. In contrast, subfamily B oils have a greater proportion of C28/C29 steranes, indicating they were generated from Upper Jurassic/Lower Cretaceous carbonates such as those at Gillabat oil field north of Mansuriyah Lake. Oils from Gillabat field thus indicate a lower degree of correlation with the Sargelu source rocks than do oils from Demir Dagh field.Palynofacies assessments are performed for this studied succession by ternary kerogen plots of the phytoclast, amorphous organic matters, and palynomorphs. From the diagram of these plots and maturation analysis, it could be assessed that the formations of Chia Gara and Sargelu are both deposited in distal suboxic to anoxic basin and can be correlated with kerogens classified microscopically as Type A and Type B and chemically as Type II. The organic matter, comprised principally of brazinophyte algae, dinoflagellate cysts, spores, pollen, foraminifera test linings, and phytoclasts in all these formations and hence affected with upwelling current. These deposit contain up to 18 wt% total organic matters that are capable to generate hydrocarbons within mature stage of thermal alteration index (TAI) range in Stalplin's scale (Staplin, 1969) of 2.7–3.0 for the Chia Gara Formation and 2.9–3.1 for the Sargelu Formation. Case study examples of these oil prone strata are; one 7-m (23-ft) thick section of the Sargelu Formation averages 44.2 mg HC/g S2 and 439 °C Tmax (Rock-Eval pyrolysis analyses) and 16 wt% TOC especially in well Mk-2 whereas, one 8-m (26-ft) thick section of the Chia Gara and 1-m (3-ft) section of Naokelekan Formations average 44.5 mg HC/g S2 and 440 °C Tmax and 14 wt% TOC especially in well Aj-8. One-dimension, petroleum system models of key wells using IES PetroMod Software can confirm their oil generation capability.These hydrocarbon type accumulation sites are illustrated in structural cross sections and maps in North Iraq. 相似文献
14.
The Es3L (lower sub-member of the third member of the Eocene Shahejie Formation) shale in the Jiyang Depression is a set of relatively thick and widely deposited lacustrine sediments with elevated organic carbon, and is considered to be one of the most important source rocks in East China. We can determine the mineralogy, organic and inorganic geochemistry of the Es3L shale and calculate paleoclimate indexes by using multiple geochemical proxies based on organic chemistry (total organic carbon [TOC] and Rock-Eval pyrolysis), major and trace elements, X-Ray diffraction, and carbon and oxygen isotope data from key wells alongside ECS (Elemental Capture Spectroscopy) well log data. These indicators can be used to analyze the evolution of the paleoenvironment and provide a mechanism of organic matter (OM) accumulation. The Es3L oil shale has high TOC abundance (most samples >3.0%) and is dominated by Type I kerogens. Additionally, the organic-rich shale is rich in CaO and enrichment in some trace metals is present, such as Sr, Ba and U. The positive δ13C and negative δ18O values, high Sr/Ba, B/Ga and Ca/Ca + Fe ratios and low C/S ratios indicate that the Es3L shales were mainly deposited in a semi-closed freshwater-brackish water lacustrine environment. The consistently low Ti/Al and Si/Al ratios reflect a restricted but rather homogeneous nature for the detrital supply. Many redox indicators, including the Th/U, V/(V + Ni), and δU ratios, pyrite morphology and TOC-TS-Fe diagrams suggest deposition under dysoxic to suboxic conditions. Subsequently, the brackish saline bottom water evolved into an anoxic water body under a relatively arid environment, during which organic-lean marls were deposited in the early stage. Later, an enhanced warm-humid climate provided an abundant mineral nutrient supply and promoted the accumulation of algal material. OM input from algal blooms reached a maximum during the deposition of the organic-rich calcareous shale with seasonal laminations. High P/Ti ratios and a strongly positive relationship between the P and TOC contents indicate that OM accumulation in the oil shale was mainly controlled by the high primary productivity of surface waters with help from a less stratified water column. Factors such as the physical protection of clay minerals and the dilution of detrital influx show less influence on OM enrichment. 相似文献
15.
Source rock potential of 108 representative samples from 3 m intervals over a 324 m thick shale section of middle Eocene age from the north Cambay Basin, India have been studied. Variation in total organic carbon (TOC) and its relationship with loss on ignition (LOI) have been used for initial screening. Screened samples were subjected to Rock-Eval pyrolysis and organic petrography. A TOC log indicated wide variation with streaks of elevated TOC. A 30 m thick organic-rich interval starting at 1954 m depth, displayed properties consistent with a possible shale oil or gas reservoir. TOC (wt%) values of the selected samples were found to vary from 0.68% to 3.62%, with an average value of 2.2. The modified van Krevelen diagram as well as HI vs. Tmax plot indicate prevalence of Type II to Type III kerogen. Tmax measurements ranged from 425 °C to 439 °C, indicating immature to early mature stage, which was confirmed by the mean vitrinite reflectance values (%Ro of 0.63, 0.65 and 0.67 at 1988 m, 1954 m, and 1963 m, respectively). Quantification of hydrocarbon generation, migration and retention characteristics of the 30 m source rock interval suggests 85% expulsion of hydrocarbon. Oil in place (OIP) resource of the 30 m source rock was estimated to be 3.23 MMbbls per 640 acres. The Oil saturation index (OSI) crossover log showed, from a geochemical perspective, moderate risk for producing the estimated reserve along with well location for tapping the identified resource. 相似文献
16.
The reflectance of chitinozoa (%ChR0) was investigated as an alternative technique of determining the level of thermal maturity of organic-rich Palaeozoic rocks in southern Ontario. These sedimentary strata, which include the Ordovician Collingwood Member and the Blue Mountain Formation, as well as the Devonian Marcellus Formation, lack vitrinite precluding the application of a standard vitrinite reflectance (%VR0) technique. ChR0 shows a proportional increase at marginal to moderate maturities, being on average 20 to 25% higher than expected vitrinite reflectance. The reflectance data fall into a very narrow range showing a high degree of consistency for each lithostratigraphic unit. The average ChR0 are as follows: Collingwood Mbr 0.63% (Georgian Bay area) and 0.88% (Toronto area), Blue Mountain Fm 0.92%, Marcellus Fm 0.68%. Correlation with more conventional optical and geochemical maturity parameters obtained from the same set of samples (fluorescence of Tasmanites, Leiosphaeridia and Gloeocapsomorpha alginite, Rock-Eval Tmax, extract data, distribution of terpanes and steranes in extracts) indicates that, within the area of study, the beginning of the catagenetic stage corresponds to ChR0=0.65% (equivalent VR=0.50%) whereas the threshold of significant oil generation is reached at ChR0=0.9% (equivalent VR=0.70%). Therefore the Blue Mountain Formation is thermally mature with respect to hydrocarbon generation throughout the whole area of study. The Collingwood shales are mature only in the Toronto area while those occurring in the Georgian Bay area as well as the Marcellus shales have yet to enter the main stage of hydrocarbon generation. This integrated approach of assessing thermal maturity shows that ChR0, when constrained with other maturity parameters, is a very reliable indicator of thermal maturity in Lower to Middle Palaeozoic sedimentary rocks. 相似文献
17.
Three bitumen fractions were obtained and systematically analysed for the terpane and sterane composition from 30 Paleozoic source rocks and 64 bitumen-containing reservoir rocks within the Upper Sinian, Lower Cambrian, Lower Silurian, Middle Carboniferous, Upper Permian and Lower Triassic strata in the Sichuan Basin and neighbouring areas, China. These bitumen fractions include extractable oils (bitumen I), oil-bearing fluid inclusions and/or closely associated components with the kerogen or pyrobitumen/mineral matrix, released during kerogen or pyrobitumen isolation and demineralization (bitumen II), and bound compounds within the kerogen or pyrobitumen released by confined pyrolysis (bitumen III). In addition, atomic H/C and O/C ratios and carbon isotopic compositions of kerogen and pyrobitumen from some of the samples were measured. Geochemical results and geological information suggest that: (1) in the Central Sichuan Basin, hydrocarbon gases in reservoirs within the fourth section of the Upper Sinian Dengying Formation were derived from both the Lower Cambrian and Upper Sinian source rocks; and (2) in the Eastern Sichuan Basin, hydrocarbon gases in Middle Carboniferous Huanglong Formation reservoirs were mainly derived from Lower Silurian source rocks, while those in Upper Permian and Lower Triassic reservoirs were mainly derived from both Upper Permian and Lower Silurian marine source rocks. For both the source and reservoir rocks, bitumen III fractions generally show relatively lower maturity near the peak oil generation stage, while the other two bitumen fractions show very high maturities based on terpane and sterane distributions. Tricyclic terpanes evolved from the distribution pattern C20 < C21 < C23, through C20 < C21 > C23, finally to C20 > C21 > C23 during severe thermal stress. The concentration of C30 diahopane in bitumen III (the bound components released from confined pyrolysis) is substantially lower than in the other two bitumen fractions for four terrigenous Upper Permian source rocks, demonstrating that this compound originated from free hopanoid precursors, rather than hopanoids bound to the kerogen. 相似文献
18.
Potential source rocks on the Laminaria High, a region of the northern Bonaparte Basin on the North West Shelf of Australia, occur within the Middle Jurassic to Lower Cretaceous early to post-rift sequences. Twenty-two representative immature source rock samples from the Jurassic to Lower Cretaceous (Plover, Laminaria, Frigate, Flamingo and Echuca Shoals) sequences were analysed to define the hydrocarbon products that analogous mature source rocks could have generated during thermal maturation and filled the petroleum reservoirs in the Laminaria High region. Rock-Eval pyrolysis data indicate that all the source rocks contain type II–III organic matter and vary in organic richness and quality. Open system pyrolysis-gas chromatography on extracted rock samples show a dominance of aliphatic components in the pyrolysates. The Plover source rocks are the exception which exhibit high phenolic contents due to their predominant land-plant contribution. Most of the kerogens have the potential to generate Paraffinic–Naphthenic–Aromatic oils with low wax contents. Bulk kinetic analyses reveal a relatively broad distribution of activation energies that are directly related to the heterogeneity in the kerogens. These kinetic parameters suggest different degrees of thermal stability, with the predicted commencement of petroleum generation under geological heating conditions covering a relatively broad temperature range from 95 to 135 °C for the Upper Jurassic−Lower Cretaceous source rocks. Both shales and coals of the Middle Jurassic Plover Formation have the potential to generate oil at relatively higher temperatures (140–145 °C) than those measured for crude oils in previous studies. Hence, the Frigate and the Flamingo formations are the main potential sources of oils reservoired in the Laminaria and Corallina fields. Apart from being a reservoir, the Laminaria Formation also contains organic-rich layers, with the potential to generate oil. For the majority of samples analysed, the compositional kinetic model predictions indicate that 80% of the hydrocarbons were generated as oil and 20% as gas. The exception is the Lower Cretaceous Echuca Shoals Formation which shows the potential to generate a greater proportion (40%) of gas despite its marine source affinity, due to inertinite dominating the maceral assemblage. 相似文献
19.
A reconnaissance study of potential hydrocarbon source rocks of Paleozoic to Cenozoic age from the highly remote New Siberian Islands Archipelago (Russian Arctic) was carried out. 101 samples were collected from outcrops representing the principal Paleozoic-Cenozoic units across the entire archipelago. Organic petrological and geochemical analyses (vitrinite reflectance measurements, Rock-Eval pyrolysis, GC-MS) were undertaken in order to screen the maturity, quality and quantity of the organic matter in the outcrop samples. The lithology varies from continental sedimentary rocks with coal particles to shallow marine carbonates and deep marine black shales. Several organic-rich intervals were identified in the Upper Paleozoic to Lower Cenozoic succession. Lower Devonian shales were found to have the highest source rock potential of all Paleozoic units. Middle Carboniferous-Permian and Triassic units appear to have a good potential for natural gas formation. Late Mesozoic (Cretaceous) and Cenozoic low-rank coals, lignites, and coal-bearing sandstones also display a potential for gas generation. Kerogen type III (humic, gas-prone) dominates in most of the samples, and indicates deposition in lacustrine to coastal paleoenvironments. Most of the samples (except some of Cretaceous and Paleogene age) reached oil window maturities, whereas the Devonian to Carboniferous units shared a maturity mainly within the gas window. 相似文献
20.
The “free” or “natural” light hydrocarbon composition obtained by thermal extraction-GC of source rock samples is compared with the light fraction generated by pyrolysis products of the kerogens. Even though there are large differences between the composition of the “free” C4–C13 hydrocarbon fraction and the same fraction generated by pyrolysis, some characteristics have been detected which can be used interchangeably for both data types. Visual inspection of gas chromatograms from thermal extracts and pyrolysates indicates that in particular the relative content of m+p xylene corresponds well between these two analytical methods. The source rock samples used are Upper Jurassic marine shales and Middle and Lower Jurassic coals and coaly shales from offshore Mid-Norway and Denmark. More detailed analysis of the data shows that the most effective parameter which can distinguish between different source rock types in both thermal extracts and pyrolysates is the m+p xylene/nC8 ratio. This parameter has been used to derive classification diagrams for interpreting the source of light hydrocarbons of both natural petroleum fluids analysed by gas chromatography and the same fraction generated by pyrolysis of asphaltenes from the fluids.The model was first tested on 17 natural petroleum fluids from Mid-Norway since a comprehensive study of light hydrocarbon distributions already has been published. Further, the parameter was applied to correlate with asphaltene pyrolysates of the fluids from Mid-Norway and a total of 22 natural oils and condensates from the southernmost Norwegian and Danish sectors. 相似文献