共查询到20条相似文献，搜索用时 312 毫秒
1.
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
2.
An evaluation of the petroleum generating potential of onshore Eocene-Miocene sequences of Western Sabah, Malaysia was performed based on organic petrological and geochemical methods. The sequences analysed are the Belait, Meligan, Temburong and West Crocker formations of western Sabah. The Belait Formation which is Stage IV equivalent in the offshore represents one of the major source rock/reservoirs of the petroleum-bearing Sabah Basin. The Eocene-Early Miocene West Crocker and Temburong formations are deepwater turbidites whilst the Miocene Meligan and Belait formations are shallow marine fluvio-deltaic deposits. The vitrinite reflectance and pyrolysis Tmax values show that the Belait samples are generally immature for hydrocarbon generation, whereas the Meligan, Temburong and West Crocker samples are in the mature to late maturity stage of hydrocarbon generation. The overall bulk source rock properties of the Belait and Meligan show fair to good petroleum source rock potential with TOC more than 1 wt %, hydrocarbon yield in the range of 400–1300 ppm and moderately high HI for many of the samples. Most of the samples representing the Temburong and West Crocker formations have TOC less than 1 wt% and have no to fair hydrocarbon generating potential. Interestingly, the samples collected in the West Crocker Formation characterized by slump deposits (MTD) have TOC>2 and possess good to excellent hydrocarbon generating potential. The organic matter present in all of the studied formations is mainly of terrigenous origin based on the abundance of woody plant materials observed under the microscope. Consequently, the analysed sequences are predominantly gas prone, dominated by Type III and Type III-IV kerogen except for minor occurrence of mixed oil-gas prone Type II-III kerogen in the Belait Formation and in the slump mass transport deposits (MTD) of the West Crocker Formation. 相似文献
3.
Ever since a breakthrough of marine shales in China, lacustrine shales have been attracting by the policy makers and scientists. Organic-rich shales of the Middle Jurassic strata are widely distributed in the Yuqia Coalfield of northern Qaidam Basin. In this paper, a total of 42 shale samples with a burial depth ranging from 475.5 m to 658.5 m were collected from the Shimengou Formation in the YQ-1 shale gas borehole of the study area, including 16 samples from the Lower Member and 26 samples from the Upper Member. Geochemistry, reservoir characteristics and hydrocarbon generation potential of the lacustrine shales in YQ-1 well were preliminarily investigated using the experiments of vitrinite reflectance measurement, maceral identification, mineralogical composition, carbon stable isotope, low-temperature nitrogen adsorption, methane isothermal adsorption and rock eval pyrolysis. The results show that the Shimengou shales have rich organic carbon (averaged 3.83%), which belong to a low thermal maturity stage with a mean vitrinite reflectance (Ro) of 0.49% and an average pyrolytic temperature of the generated maximum remaining hydrocarbon (Tmax) of 432.8 °C. Relative to marine shales, the lacustrine shales show low brittleness index (averaged 34.9) but high clay contents (averaged 55.1%), high total porosities (averaged 13.71%) and great Langmuir volumes (averaged 4.73 cm−3 g). Unlike the marine and marine-transitional shales, the quartz contents and brittleness index (BI) values of the lacustrine shales first decrease then increase with the rising TOC contents. The kerogens from the Upper Member shales are dominant by the oil-prone types, whereas the kerogens from the Lower Member shales by the gas-prone types. The sedimentary environment of the shales influences the TOC contents, thus has a close connection with the hydrocarbon potential, mineralogical composition, kerogen types and pore structure. Additionally, in terms of the hydrocarbon generation potential, the Upper Member shales are regarded as very good and excellent rocks whereas the Lower Member shales mainly as poor and fair rocks. In overall, the shales in the top of the Upper Member can be explored for shale oil due to the higher free hydrocarbon amount (S1), whereas the shales in the Lower Member and the Upper Member, with the depths greater than 1000 m, can be suggested to explore shale gas. 相似文献
4.
Although extensive studies have been conducted on unconventional mudstone (shales) reservoirs in recent years, little work has been performed on unconventional tight organic matter-rich, fine-grained carbonate reservoirs. The Shulu Sag is located in the southwestern corner of the Jizhong Depression in the Bohai Bay Basin and filled with 400–1000 m of Eocene lacustrine organic matter-rich carbonates. The study of the organic matter-rich calcilutite in the Shulu Sag will provide a good opportunity to improve our knowledge of unconventional tight oil in North China. The dominant minerals of calcilutite rocks in the Shulu Sag are carbonates (including calcite and dolomite), with an average of 61.5 wt.%. The carbonate particles are predominantly in the clay to silt size range. Three lithofacies were identified: laminated calcilutite, massive calcilutite, and calcisiltite–calcilutite. The calcilutite rocks (including all the three lithofacies) in the third unit of the Shahejie Formation in the Eocene (Es3) have total organic carbon (TOC) values ranging from 0.12 to 7.97 wt.%, with an average of 1.66 wt.%. Most of the analyzed samples have good, very good or excellent hydrocarbon potential. The organic matter in the Shulu samples is predominantly of Type I to Type II kerogen, with minor amounts of Type III kerogen. The temperature of maximum yield of pyrolysate (Tmax) values range from 424 to 452 °C (with an average of 444 °C) indicating most of samples are thermally mature with respect to oil generation. The calcilutite samples have the free hydrocarbons (S1) values from 0.03 to 2.32 mg HC/g rock, with an average of 0.5 mg HC/g rock, the hydrocarbons cracked from kerogen (S2) yield values in the range of 0.08–57.08 mg HC/g rock, with an average of 9.06 mg HC/g rock, and hydrogen index (HI) values in the range of 55–749 mg HC/g TOC, with an average of 464 mg HC/g TOC. The organic-rich calcilutite of the Shulu Sag has very good source rock generative potential and have obtained thermal maturity levels equivalent to the oil window. The pores in the Shulu calcilutite are of various types and sizes and were divided into three types: (1) pores within organic matter, (2) interparticle pores between detrital or authigenic particles, and (3) intraparticle pores within detrital grains or crystals. Fractures in the Shulu calcilutite are parallel to bedding, high angle, and vertical, having a significant effect on hydrocarbon migration and production. The organic matter and dolomite contents are the main factors that control calcilutite reservoir quality in the Shulu Sag. 相似文献
5.
The Gordondale Member is a hydrocarbon source rock and potential unconventional reservoir that extends across northeastern British Columbia and central-northwestern Alberta. It is an organic-rich, calcareous, fossiliferous mudstone with a median total organic carbon value of 6.0 wt%. A total of 230 samples were collected from approximately 25 m of Gordondale Member core for organic matter analysis using Rock-Eval 6 analysis and organic petrology. Detailed core logging provides sedimentological context for organic matter characterization. The predominant organic material in the samples is solid bitumen and liptinite with lesser zooclast and inertinite. Most kerogen is Type II, autochthonous marine biomass, with minimal dilution by inert organic carbon. Rock-Eval Tmax values and random reflectance measurements of solid bitumen indicate the samples are within the oil generation window. Solid bitumen contributes a substantial amount of hydrocarbon potential to the interval. A micro-reservoir structure within the core is produced by thin intervals of impermeable displacive calcite that act as barriers to the upward migration of free hydrocarbons. These free hydrocarbon accumulations could make excellent targets for horizontal wells within the Gordondale Member. 相似文献
6.
《Marine and Petroleum Geology》2012,32(1):125-136
As a result of a long-lasting and complex geological history, organic-matter-rich fine-grained rocks (black shales) with widely varying ages can be found on Ukrainian territory. Several of them are proven hydrocarbon source rocks and may hold a significant shale gas potential.Thick Silurian black shales accumulated along the western margin of the East European Craton in a foreland-type basin. By analogy with coeval organic-matter-rich rocks in Poland, high TOC contents and gas window maturity can be expected. However, to date information on organic richness is largely missing and maturity patterns remain to be refined.Visean black shales with TOC contents as high as 8% and a Type III-II kerogen accumulated along the axis of the Dniepr-Donets rift basin (DDB). They are the likely source for conventional oil and gas. Oil-prone Serpukhovian black shales accumulated in the shallow northwestern part of the DDB. Similar black shales probably may be present in the Lviv-Volyn Basin (western Ukraine).Middle Jurassic black shales up to 500 m thick occur beneath the Carpathian Foredeep. They are the likely source for some heavy oil deposits. TOC contents up to 12% (Type II) have been recorded, but additional investigations are needed to study the vertical and lateral variability of organic matter richness and maturity.Lower Cretaceous black shales with a Type III(-II) kerogen (TOC > 2%) are widespread at the base of the Carpathian flysch nappes, but Oligocene black shales (Menilite Fm.) rich in organic matter (4–8% TOC) and containing a Type II kerogen are the main source rock for oil in the Carpathians. Their thermal maturity increases from the external to the internal nappes.Oligocene black shales are also present in Crimea (Maykop Fm.). These rocks typically contain high TOC contents, but data from Ukraine are missing. 相似文献
7.
In different areas of the Western Desert of Egypt, the Abu Roash “G” Member exhibits either a reservoir or source affinity. Thus, thirteen cutting samples covering the Abu Roash “G” Member were selected from the Nest-1A well at Matruh Basin to investigate its hydrocarbon source potential. Palynological age dating of the section that is calibrated with foraminifera and ostracodes enabled a proper identification of the “G” Member. Detailed analysis of the vertical distribution of particulate organic matter of this member shows two palynofacies types. PF-1 reflects an outer middle shelf depositional environment of prevailed reducing (suboxic-anoxic) conditions for the organic-rich shales of the lower “G” Member (samples 1–8). While, PF-2 reflects a minor regression that resulted in deposition of another organic-rich shales of the upper “G” Member (samples 9–13) in an inner middle shelf setting under the same prevailing reducing (suboxic-anoxic) conditions.Organic geochemical analysis reveals good to very good potential of the “G” Member as a hydrocarbon source rock (1.8–2.41, avg. 2.15 total organic content wt %). It also shows good to very good petroleum potential (PP: 4.8–11 , avg. 8 mg HC/g rock). Pyrolsis and palynofacies analyses show kerogen type II for the lower “G” Member (samples 1–8), which is characterized by high Hydrogen index (HI: 396 and 329 mg HC/g TOC at depths 1500 and 1560 m) and very high dominance of oil-prone material (amorphous organic matter “AOM”, marine palynomorphs, and sporomorphs) and very rare occurrence of gas-prone material (brown phytoclasts). The upper “G” Member (samples 9–13) shows kerogen type II-III, which is characterized by a lower HI value of 213 mg HC/g TOC at depth 1340 m and it contains fewer amounts of gas-prone material and relatively lower AOM and marine palynomorphs in comparison to the upper “G” Member. Maturation parameters Tmax (430–433 °C), production index (PI: 0.1 mg HC/g rock), and thermal alteration index (TAI: 2+) indicate the lower “G” Member has already entered the early oil-window kitchen, and it is expected to produce oil. The upper “G” Member is expected to produce only oil with no gas shows, because it is marginally mature (Tmax 426 °C, PI 0.2, TAI 2). The source potential index (SPI: 5.3 t HC/m2) of the “G” Member shows it as currently generating moderate quantities of oil in the area of Nest-1A well.Consequently, the organic-rich shales of the “G” Member are suggested here as a promising, active oil source rock in that extreme northwestern part of the Western Desert of Egypt. However, for commercial oil recovery from the Abu Roash “G” Member, it is highly recommended to explore the depocentre of Matruh Basin at about 150 km east the Nest-1A well. 相似文献
8.
《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
9.
This study is the first attempt which provides information regarding the bulk and quantitative pyrolysis results of the Chia Gara Formation from the Kurdistan region, northern Iraq. Ten representative early-mature to mature samples from the Chia Gara Formation were investigated for TOC contents, Rock Eval pyrolysis, pyrolysis-GC and bulk kinetic parameters. These analyses were used to characterize the petroleum generated during thermal maturation of the Chia Gara source rock and to clarify the quantity of the organic matter and its effect on the timing of petroleum generation.Pyrolysis HI data identified two organic facies with different petroleum generation characteristics; Type II–III kerogen with HI values of >250 mg HC/g TOC, and Type III kerogen with HI values < 100 mg HC/g TOC. These types of kerogen can generate liquid HCs and gas. This is supported by the products of pyrolysis–gas chromatography (Py–GC) analysis of the extracted rock samples. Pyrolysis products show a dominance of a marine organic matter with variable contributions from terrestrial organic matter (Types II–III and III kerogen), and produces mainly paraffinic-naphthenic-aromatic low wax oils with condensate and gas.Bulk kinetic analysis of the Chia Gara source rock indicates a heterogeneous organic matter assemblage, typical of restricted marine environments in general. The activation energy distributions reveal relatively broad and high values, ranging from 40 to 64 kcal/mol with pre-exponential factors varying from 2.2835 E+12/sec to 4.0920 E+13/sec. The predicted petroleum formation temperature of onset (TR 10%) temperatures ranges from 110 to 135 °C, and peak generation temperatures (geological Tmax) between 137 °C and 152 °C. The peak generation temperatures reach a transformation ratio in the range of 42–50% TR, thus the Chia Gara source rock could have generated and expelled significant quantities of petroleum hydrocarbons in the Kurdistan of Iraq. 相似文献
10.
Eight lacustrine Type I kerogen samples from the Songliao Basin were pyrolyzed using the Rock-Eval equipment, and parallel first-order reaction models including the model with a single frequency factor and a discrete distribution of activation energies (SFF model) and the model with multiple frequency factors and a discrete distribution of activation energies (MFF model) were adopted to analyze kinetic characteristics of hydrocarbon generation of the Type I kerogen samples. The results show that the MFF and SFF models can satisfactory simulate hydrocarbon generation under laboratory conditions and the Type I kerogen shows relatively concentrated activation energy distributions (activation energies of MFF model range from 190 kJ/mol to 250 kJ/mol, activation energies of SFF model range from 220 kJ/mol to 240 kJ/mol), which indicates a homogeneous chemical bond structure of the Type I kerogen. The hydrocarbon generated curves from Type I kerogen were calculated by using the two models with a linear heating rate (3.3 K/Ma). It indicates that the hydrocarbon generation potentials (reaction fractions) are underestimated by using the SFF model during the kerogen thermal degradation for the components with chemical bond of lower and higher activation energies, while this problem can be avoided by using the MFF model. The calculated temperatures for 50% transformation ratio (TR) of all samples differ by as much as 20 °C. For the SFF model, the hydrocarbon generation curve obtained by using the weighted averaged kinetic parameters and the SFF model almost includes every curve calculated by using its own kinetic parameters. While the curve obtained by using the weighted averaged kinetic parameters and the MFF model cannot include every curve for all samples, it lies at the position of the averaged curve of all samples. The application of the MFF model in Songliao Basin shows that if TR 10% is taken as the onset of hydrocarbon generation, the threshold depth of hydrocarbon generation is about 1700 m, which is consistent with other geochemical parameters, such as S1/TOC, S1/(S1 + S2) and HC/TOC. 相似文献
11.
Geochemical characteristics and hydrocarbon generation modeling of the Jurassic source rocks in the Shoushan Basin, north Western Desert, Egypt 总被引：1，自引：0，他引：1
Mohamed Ragab ShalabyMohammed Hail Hakimi Wan Hasiah Abdullah 《Marine and Petroleum Geology》2011,28(9):1611-1624
The Shoushan Basin is an important hydrocarbon province in the Western Desert, Egypt, but the origin of the hydrocarbons is not fully understood. In this study, organic matter content, type and maturity of the Jurassic source rocks exposed in the Shoushan Basin have been evaluated and integrated with the results of basin modeling to improve our understanding of burial history and timing of hydrocarbon generation. The Jurassic source rock succession comprises the Ras Qattara and Khatatba Formations, which are composed mainly of shales and sandstones with coal seams. The TOC contents are high and reached a maximum up to 50%. The TOC values of the Ras Qattara Formation range from 2 to 54 wt.%, while Khatatba Formation has TOC values in the range 1-47 wt.%. The Ras Qattara and Khatatba Formations have HI values ranging from 90 to 261 mgHC/gTOC, suggesting Types II-III and III kerogen. Vitrinite reflectance values range between 0.79 and 1.12 VRr %. Rock−Eval Tmax values in the range 438-458 °C indicate a thermal maturity level sufficient for hydrocarbon generation. Thermal and burial history models indicate that the Jurassic source rocks entered the mature to late mature stage for hydrocarbon generation in the Late Cretaceous to Tertiary. Hydrocarbon generation began in the Late Cretaceous and maximum rates of oil with significant gas have been generated during the early Tertiary (Paleogene). The peak gas generation occurred during the late Tertiary (Neogene). 相似文献
12.
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
13.
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
14.
Cretaceous sedimentary rocks of the Mukalla, Harshiyat and Qishn formations from three wells in the Jiza sub-basin were studied to describe source rock characteristics, providing information on organic matter type, paleoenvironment of deposition and hydrocarbon generation potential. This study is based on organic geochemical and petrographic analyses performed on cuttings samples. The results were then incorporated into basin models in order to understand the burial and thermal histories and timing of hydrocarbon generation and expulsion.The bulk geochemical results show that the Cretaceous rocks are highly variable with respect to their genetic petroleum generation potential. The total organic carbon (TOC) contents and petroleum potential yield (S1 + S2) of the Cretaceous source rocks range from 0.43 to 6.11% and 0.58–31.14 mg HC/g rock, respectively indicating non-source to very good source rock potential. Hydrogen index values for the Early to Late Cretaceous Harshiyat and Qishn formations vary between 77 and 695 mg HC/g TOC, consistent with Type I/II, II-III and III kerogens, indicating oil and gas generation potential. In contrast, the Late Cretaceous Mukalla Formation is dominated by Type III kerogen (HI < 200 mg HC/g TOC), and is thus considered to be gas-prone. The analysed Cretaceous source rock samples have vitrinite reflectance values in the range of 0.37–0.95 Ro% (immature to peak-maturity for oil generation).A variety of biomarkers including n-alkanes, regular isoprenoids, terpanes and steranes suggest that the Cretaceous source rocks were deposited in marine to deltaic environments. The biomarkers also indicate that the Cretaceous source rocks contain a mixture of aquatic organic matter (planktonic/bacterial) and terrigenous organic matter, with increasing terrigenous influence in the Late Cretaceous (Mukalla Formation).The burial and thermal history models indicate that the Mukalla and Harshiyat formations are immature to early mature. The models also indicate that the onset of oil-generation in the Qishn source rock began during the Late Cretaceous at 83 Ma and peak-oil generation was reached during the Late Cretaceous to Miocene (65–21 Ma). The modeled hydrocarbon expulsion evolution suggests that the timing of oil expulsion from the Qishn source rock began during the Miocene (>21 Ma) and persisted to present-day. Therefore, the Qishn Formation can act as an effective oil-source but only limited quantities of oil can be expected to have been generated and expelled in the Jiza sub-basin. 相似文献
15.
Studies of the Mesozoic and Cenozoic sequence crossed by the Barreiro-4 borehole provide an improved understanding of the organic matter deposited in the Lower Tagus sub-basin (Lusitanian Basin, Portugal) and the implications for the potential source rock and depositional environment. This study focused on 43 samples (Middle Jurassic to Neogene) that were subjected to palynofacies and organic geochemistry analyses (Total Organic Carbon, Rock-Eval pyrolysis and molecular biomarker analysis). The palynofacies data indicate that the sequence contains mainly phytoclasts (non-opaque phytoclasts). However, the Middle Jurassic samples are dominated by Amorphous Organic Matter (AOM). Continental and/or marine palynomorphs are present in all the samples. The Cretaceous samples are characterized by small amounts of kerogen that have high contents of solid bitumen. The Total Organic Carbon (TOC) content is generally less than 1 wt.%. The Rock-Eval S1 and S2 parameters vary from 0.01 to 3.50 mgHC/g rock and 0.15 to 34.03 mgHC/g rock, respectively, with the highest values corresponding to the Cretaceous samples. The hydrogen index (HI) and oxygen index (OI) values range from 35 to 552 mgHC/g TOC and 4 to 180 mgHC/g TOC, respectively. The Tmax values range from 416 to 437 °C. The biomarker analysis showed that n-alkanes with 15–30 carbon atoms are present and usually have a unimodal distribution with a predominance of low to medium molecular weight compounds. The CPI values range between 0.63 and 3.65, and the pristane/phytane ratios vary between 0.48 and 1.64, indicating alternation of oxic–anoxic conditions along the sequence. The distribution of terpanes shows small amounts of tricyclic and tetracyclic terpanes in most of the samples (except for some Cretaceous samples) and a predominance of pentacyclic terpanes. The amount of 17α (H),22,29,30-trisnorhopane (Tm) usually exceeds the amount of 18α (H),22,29,30-trinorneohopane (Ts). The 20S/(20S + 20R) and αββ/(ααα + αββ) ratios of the C29 steranes generally have values below the range of equilibrium, indicating an immature stage of the OM. 相似文献
16.
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
17.
The Qiongdongnan Basin and Zhujiang River(Pearl River) Mouth Basin, important petroliferous basins in the northern South China Sea, contain abundant oil and gas resource. In this study, on basis of discussing impact of oil-base mud on TOC content and Rock-Eval parameters of cutting shale samples, the authors did comprehensive analysis of source rock quality, thermal evolution and control effect of source rock in gas accumulation of the Qiongdongnan and the Zhujiang River Mouth Basins. The contrast analysis of TOC contents and Rock-Eval parameters before and after extraction for cutting shale samples indicates that except for a weaker impact on Rock-Eval parameter S_2, oil-base mud has certain impact on Rock-Eval S_1, Tmax and TOC contents. When concerning oil-base mud influence on source rock geochemistry parameters, the shales in the Yacheng/Enping,Lingshui/Zhuhai and Sanya/Zhuhai Formations have mainly Type Ⅱ and Ⅲ organic matter with better gas potential and oil potential. The thermal evolution analysis suggests that the depth interval of the oil window is between 3 000 m and 5 000 m. Source rocks in the deepwater area have generated abundant gas mainly due to the late stage of the oil window and the high-supper mature stage. Gas reservoir formation condition analysis made clear that the source rock is the primary factor and fault is a necessary condition for gas accumulation. Spatial coupling of source, fault and reservoir is essential for gas accumulation and the inside of hydrocarbon-generating sag is future potential gas exploration area. 相似文献
18.
Currently, global shale gas exploration and exploitation are focused on marine shale. Recently, major shale gas-oil breakthroughs have been made within continental and marine–continental transitional shale in China. This study will show how transitional shale is of great importance. Based on geological field surveys, core observations, thin section analysis, organic geochemistry and X-ray diffraction, we systematically studied the basic geological characteristics (including lithology, mineral composition, and organic geochemistry) of this transitional shale. By comparative analysis of well logging data from 260 wells in the Taiyuan–Shanxi shale, we will show that these methods are effective for identifying organic-rich shale from conventional well logs and determining its thickness distribution in the Carboniferous–Permian strata of the Taiyuan–Shanxi transitional coal-bearing formation.The results indicate that the Taiyuan–Shanxi shale has a high TOC (most 2%–4%) and that the lithology is primarily carbonaceous shale with type Ⅱ2-Ⅲ kerogens. The high thermal maturation (Ro ≥ 1.1%) favors the generation of gas. The mineral components primarily include clay minerals, quartz, and plagioclase with a moderate brittle mineral content (47 wt.%) and high clay mineral content (51 wt.%) dominated by kaolinite (43%) and mixed-layer illite-smectite (31%). The transitional organic-rich shale on conventional log curves is generally characterized by higher gamma ray (GR), neutron porosity (CNL), acoustic travel time (AC), resistivity (Rt), potassium (K), and uranium (U) readings and a lower density (DEN), photoelectric absorption index (PE) and thorium-uranium ratio (TH/U). After analyzing the log response characteristics of the organic-rich shale, the most sensitive logging curves (such as CNL, AC, DEN, PE and U) were optimized to conduct logging overlays and to construct cross-plots to qualitatively identify organic-rich shale. The identified organic-rich shale amalgamates in the middle-upper member of the Taiyuan Formation and the lower member of the Shanxi Formation consistent with the results of the TOC analysis and practical gas logging. Based on the qualitative evaluation methods of the modified △LogR and a multivariate linear regression model, we calculated the TOC of shale wells in the Taiyuan–Shanxi formation. From this we calculated the characteristic values of organic-rich shale thickness. The results indicate that organic-rich shale in the Taiyuan formation is thicker than that in the Shanxi formation. Additionally, the thickness of organic-rich shale within lagoons and deep reed swamp facies are much thicker (25–35 m and 40–80 m) than other structural profile types, whereas their lateral distribution is less than that of marine shale. The relatively small continuous thickness of the single shale layer and high clay content may have negative effects for developing the shale gas potential. 相似文献
19.
This study presents approaches for evaluating hybrid source rock/reservoirs within tight-rock petroleum systems. The emerging hybrid source rock/reservoir shale play in the Upper Cretaceous Second White Specks and Belle Fourche formations in central Alberta, Canada is used as an example to evaluate organic and inorganic compositions and their relationships to pore characteristics. Nineteen samples from a 77.5 m-long core were analyzed using organic petrography, organic geochemistry, several methods of pore characterization, and X-ray powder diffraction (XRD). The lower part of the studied section includes quartz- and clay-rich mudrocks of the Belle Fourche Formation with low carbonate content, whereas the upper portion contains calcareous mudrocks of the Second White Specks Formation. Strata are mineralogically composed of quartz plus albite (18–56 wt. %), carbonates (calcite, dolomite, ankerite; 1–65 wt. %), clays (illite, kaolinite, chlorite; 15–46 wt. %), and pyrite (2–12 wt. %). Petrographic examinations document that organic matter represents marine Type II kerogen partly biodegraded with limited terrestrial input. Vitrinite reflectance Ro (0.74–0.87%), Tmax values (438–446 °C) and biomarkers indicate mid-maturity within the oil window. The relatively poor remaining hydrocarbon potential, expressed as an S2 value between 2.1 and 6.5 mg HC/g rock, may result from an estimated 60–83% of the original kerogen having been converted to hydrocarbons, with the bulk having migrated to adjacent sandstone reservoirs. However, the present-day remaining total organic carbon TOCpd content remains relatively high (1.7–3.6 wt. %), compared with the estimated original TOCo of 2.4–5.0 wt. %. The calculated transformation ratio of 60–83% suggests that the remaining 17–40 wt. % of kerogen is able to generate more hydrocarbons. The studied section is a tight reservoir with an average Swanson permeability of 3.37·10−5 mD (measured on two samples) and total porosity between 1.7 and 5.0 vol. % (3 vol. % on average). The upper part of the sandy Belle Fourche Formation, with slightly elevated porosity values (3.5–5 vol. %), likely represents the interval with the best reservoir properties in the studied core interval. Total pore volume ranges between 0.0065 and 0.0200 cm3/g (measured by a combination of helium pycnometry and mercury immersion). Mesopores (2–50 nm ∅) are the most abundant pores and occupy 34–67% of total porosity or a volume of 0.0030–0.0081 cm3/g. In comparison, micropores (<2 nm ∅) cover a wide range from 6 to 60% (volume 0.0007–0.0053 cm3/g), and macropores (>50 nm ∅) reach up to 57% with the exception of some samples failing to indicate the presence of this pore fraction (volume 0.0000–0.0107 cm3/g). Macroporosity is mostly responsible for variations in total porosity, as suggested by macroporosity's strongest correlation with total porosity within the section. The relatively narrow ranges of TOC and minerals contents among measured samples limit our ability to further deconvolute factors that influence changes in total porosity and pore size distribution. 相似文献
20.
The non-marine Fushun Basin in NE China is a fault-controlled basin filled with Eocene sediments. It hosts the largest opencast coal and oil shale mine in Asia. A single thick oil shale layer overlying sub-bituminous coal occurs within the Middle Eocene Jijuntun Formation. Based on mineralogy, inorganic and organic geochemistry, organic petrography, stable isotope geochemistry, and vitrinite reflectance measurements, the depositional environment and the oil shale potential of the oil shale-bearing succession were investigated. The Jijuntun Formation is subdivided into a lower and an upper unit characterized by a low and high quality oil shale, respectively. The thick oil shale layer of the Jijuntun Formation developed under long-lasting stable conditions in a deep freshwater lake, after drowning of a swamp. The organic matter in the lower unit is characterized by landplant-derived macerals. The sediments containing a type II kerogen (HI: ∼400 mgHC/gTOC) were deposited during warm and humid conditions. Lacustrine organisms predominant in the upper unit are forming kerogen type I (HI: ∼700 mgHC/gTOC). High bioproductivity and excellent preservation conditions resulted in high TOC contents up to 23.6 wt.% in the upper unit. The organic matter preservation was controlled by photic zone anoxia originating in a temperature stratified water column in the deep lake, without significant changes in bottom water salinity. Mid-Eocene cooling during deposition of the upper unit of the Jijuntun Formation is reflected by clay mineral composition. A hot and arid climate favoring brackish conditions in a shallow lake prevailed during accumulation of the overlying carbonate-rich Xilutian Formation. Individual geochemical parameters in the Fushun Basin have to be used with caution, e.g. the maturity proxy Tmax is affected by kerogen type, the redox proxy Pr/Ph ratio is probably biased by different sources of isoprenoids. This demonstrates the importance of multi-proxy studies. 相似文献