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1.
The quality of source rocks plays an important role in the distribution of tight and conventional oil and gas resources. Despite voluminous studies on source rock hydrocarbon generation, expulsion and overpressure, a quality grading system based on hydrocarbon expulsion capacity is yet to be explored. Such a grading system is expected to be instrumental for tight oil and gas exploration and sweet spot prediction. This study tackles the problem by examining Late Cretaceous, lacustrine source rocks of the Qingshankou 1 Member in the southern Songliao Basin, China. By evaluating generated and residual hydrocarbon amounts of the source rock, the extent of hydrocarbon expulsion is modelled through a mass balance method. The overpressure is estimated using Petromod software. Through correlation between the hydrocarbon expulsion and source rock evaluation parameters [total organic carbon (TOC), kerogen type, vitrinite reflectance (Ro) and overpressure], three classes of high-quality, effective and ineffective source rocks are established. High-quality class contains TOC >2%, type-I kerogen, Ro >1.0%, overpressure >7Mpa, sharp increase of hydrocarbon expulsion along with increasing TOC and overpressure, and high expulsion value at Ro >1%. Source rocks with TOC and Ro <0.8%, type-II2 & III kerogen, overpressure <3Mpa, and low hydrocarbon expulsion volume are considered ineffective. Rocks with parameters between the two are considered effective. The high-quality class shows a strong empirical control on the distribution of tight oil in the Songliao Basin. This is followed by the effective source rock class. The ineffective class has no measurable contribution to the tight oil reserves. Because the hydrocarbon expulsion efficiency of source rocks is controlled by many factors, the lower limits of the evaluation parameters in different basins may vary. However, the classification method of tight source rocks proposed in this paper should be widely applicable. 相似文献
2.
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
3.
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
4.
《Marine and Petroleum Geology》2012,32(1):110-124
The transport properties of Permian to Miocene oil shales (Torbanite, Posidonia, Messel, Himmetoglu, and Condor) were studied using petrophysical and geochemical techniques. The aims of this study were to assess permeability of oil shales, evaluate the evolution of porosity, specific surface area and intergranular permeability during high temperature compaction tests and to verify the suitability of intergranular permeability for petroleum expulsion. Measured permeability coefficients for two samples were 0.72 × 10−21 m² for the Eocene Messel shale and 2.63 × 10−21 m² for the Lower Jurassic Posidonia shale from S. Germany, respectively. BET specific surface areas of the original samples ranged from 0.7 to 10.6 m²/g and decreased after compaction to values from 0.3 to 3.7 m²/g. Initial porosity values ranged from 7.6 to 20.1 % for pre-deformation and from 9.99 to 20.7 % for post-deformation samples. Porosity increased during the high-temperature compaction experiments due to petroleum generation and expulsion. Permeability coefficients estimated using the Kozeny–Carman equation varied from 6.97 × 10−24 m² to 5.22 × 10−21 m² for pre-deformation and from 0.2 × 10−21 m² to 4.8 × 10−21 m² for post-deformation samples reflecting the evolution of their porosity and BET specific surface areas. Measured and calculated permeability were similar for the Messel shale whereas calculated permeability was two orders of magnitude lower for the Posidonia shale from S. Germany. Petroleum expulsion efficiencies under the experimental conditions ranged from 38.6% for the Torbanite to 96.2% for the Posidonia shale from S. Germany. They showed strong positive correlation with the petroleum generation index (R² = 0.91) and poor correlations with porosity (R² = 0.46), average pore throat diameters (R² = 0.22), and compaction (R² = 0.02). Estimated minimum pore-system saturations for petroleum expulsion during the experiments were 12% for the Torbanite and 30% for the Posidonia shale from N. Germany. Pore-system saturation determines whether expulsion occurs mainly through matrix or fracture permeability. For samples with saturation levels above 20%, fracture permeability dominated during the experiments. Evidence based on the measured permeability coefficients, expulsion flow rates, consideration of capillary displacement during generation-related pore invasion and the existence of transport porosity suggests that fracture permeability is the principal avenue of petroleum expulsion from source rocks. This conclusion is supported by microscopic observations. 相似文献
5.
Mixed layer clay minerals, vitrinite reflectance and geochemical data from Rock-Eval pyrolysis were used to constrain the burial evolution of the Mesozoic–Cenozoic successions exposed at the Kuh-e-Asmari (Dezful Embayment) and Sim anticlines (Fars province) in the Zagros fold-and-thrust belt. In both areas, Late Cretaceous to Pliocene rocks, show low levels of thermal maturity in the immature stages of hydrocarbon generation and early diagenetic conditions (R0 I–S and Ro% values < 0.5). At depths of 2–4 km, Tmax values (435–450 °C) from organic-rich layers of the Sargelu, Garau and Kazhdumi source rocks in the Kuh-e-Asmari anticline indicate mid to late mature stages of hydrocarbon generation. One dimensional thermal models allowed us to define the onset of oil generation for the Middle Jurassic to Eocene source rocks and pointed out that sedimentary burial is the main factor responsible for measured levels of thermal maturity. Specifically, the Sargelu and Garau Formations entered the oil window prior to Zagros folding in Late Cretaceous times, the Kazhdumi Formation during middle Miocene (syn-folding stage), and the Pabdeh Formation in the Late Miocene–Pliocene after the Zagros folding. In the end, the present-day distribution of oil fields in the Dezful Embayment and gas fields in the Fars region is primarily controlled by lithofacies changes and organic matter preservation at the time of source rock sedimentation. Burial conditions during Zagros folding had minor to negligible influence. 相似文献
6.
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
7.
In order to investigate the hydrocarbon generation process and gas potentials of source rocks in deepwater area of the Qiongdongnan Basin, kinetic parameters of gas generation(activation energy distribution and frequency factor) of the Yacheng Formation source rocks(coal and neritic mudstones) was determined by thermal simulation experiments in the closed system and the specific KINETICS Software. The results show that the activation energy(Ea) distribution of C1–C5 generation ranges from 50 to 74 kcal/mol with a frequency factor of 2.4×1015 s–1 for the neritic mudstone and the Ea distribution of C1–C5 generation ranges from 49 to 73 kcal/mol with a frequency factor of 8.92×1013 s–1 for the coal. On the basis of these kinetic parameters and combined with the data of sedimentary burial and paleothermal histories, the gas generation model of the Yacheng Formation source rocks closer to geological condition was worked out, indicating its main gas generation stage at Ro(vitrinite reflectance) of 1.25%–2.8%. Meanwhile, the gas generation process of the source rocks of different structural locations(central part, southern slope and south low uplift) in the Lingshui Sag was simulated. Among them, the gas generation of the Yacheng Formation source rocks in the central part and the southern slope of the sag entered the main gas window at 10 and 5 Ma respectively and the peak gas generation in the southern slope occurred at 3 Ma. The very late peak gas generation and the relatively large gas potential indices(GPI:20×108–60×108 m3/km2) would provide favorable conditions for the accumulation of large natural gas reserves in the deepwater area. 相似文献
8.
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
9.
The Penglai 9-1 (PL9-1) oil field, which contains China's third largest offshore oil accumulation (in-place reserves greater than 2.28 × 108 ton or 1.49 × 109 bbl), was found in shallow reservoirs (700–1700 m, 2297–5577 ft) within the most active fault zone in east China. The PL9-1 field contains two oil-bearing series, the granite intrusions in Mesozoic (Mz) and both the sandstone reservoirs in Neogene Guantao (Ng) and Neogene Minghuazhen (Nm) Formation. The origins of the PL9-1 field, both in terms of source rock intervals and generative kitchens, were determined by analyzing biomarker distributions for 61 source rock samples and 33 oil samples. The Mesozoic granite intrusions, which hold more than 80% of the oil reserves in the field, were charged in the west by oil generated from the third member (Es3) of the Shahejie Formation in the Bodong depression. The Neogene reservoirs of the PL9-1 field were charged in the west by oil generated from the third member (Es3) of the Shahejie Formation in the Bodong depression and in the south by oil generated from the first member (Es1) of the Shahejie Formation in the Miaoxibei depression. Interactive contact between the large fan delta and the mature source rocks residing in the Es3 Formation of the Bodong depression resulted in a high expulsion efficiency from the source rocks and rapid oil accumulation in the PL9-1 field, which probably explains how can this large oil field accumulate and preserve within the largest and most active fault zone in east China. 相似文献
10.
Two petroleum source rock intervals of the Lower Cretaceous Abu Gabra Formation at six locations within the Fula Sub-basin, Muglad Basin, Sudan, were selected for comprehensive modelling of burial history, petroleum maturation and expulsion of the generated hydrocarbons throughout the Fula Sub-basin. Locations (of wells) selected include three in the deepest parts of the area (Keyi oilfield); and three at relatively shallow locations (Moga oilfield). The chosen wells were drilled to depths that penetrated a significant part of the geological section of interest, where samples were available for geochemical and source rock analysis. Vitrinite reflectances (Ro %) were measured to aid in calibrating the developed maturation models.The Abu Gabra Formation of the Muglad Basin is stratigraphically subdivided into three units (Abu Gabra-lower, Abu Gabra-middle and Abu Gabra-upper, from the oldest to youngest). The lower and upper Abu Gabra are believed to be the major source rocks in the province and generally contain more than 2.0 wt% TOC; thus indicating a very good to excellent hydrocarbon generative potential. They mainly contain Type I kerogen. Vitrinite reflectance values range from 0.59 to 0.76% Ro, indicating the oil window has just been reached. In general, the thermal maturity of the Abu Gabra source rocks is highest in the Abu Gabra-lower (deep western part) of the Keyi area and decreases to the east toward the Moga oilfied at the Fula Sub-basin.Maturity and hydrocarbon generation modelling indicates that, in the Abu Gabra-Lower, early oil generation began from the Middle- Late Cretaceous to late Paleocene time (82.0–58Ma). Main oil generation started about 58 Ma ago and continues until the present day. In the Abu Gabra-upper, oil generation began from the end of the Cretaceous to early Eocene time (66.0–52Ma). Only in one location (Keyi-N1 well) did the Abu Gabra-upper reach the main oil stage. Oil expulsion has occurred only from the Abu Gabra-lower unit at Keyi-N1 during the early Miocene (>50% transformation ratio TR) continuing to present-day (20.0–0.0 Ma). Neither unit has generated gas. Oil generation and expulsion from the Abu Gabra source rocks occurred after the deposition of seal rocks of the Aradeiba Formation. 相似文献
11.
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
12.
There are two sets of carbonate source rocks in the Lower Carboniferous layers in Marsel: the Visean (C1v) and Serpukhovian (C1sr). However, their geochemical and geological characteristics have not been studied systematically. To assess the source rocks and reveal the hydrocarbon generation potential, the depositional paleoenvironment and distribution of C1v and C1sr source rocks were studied using total organic carbon (TOC) content, Rock-Eval pyrolysis and vitrinite reflectance (Ro) data, stable carbon isotope data, gas chromatography (GC) and gas chromatography-mass spectrometry (GC-MS) analysis data. The data were then compared with well logging data to understand the distribution of high-quality source rocks. The data were also incorporated into basin models to reveal the burial and thermal histories and timing of hydrocarbon generation. The results illustrated that the average residual TOC contents of C1v and C1sr were 0.79% and 0.5%, respectively, which were higher than the threshold of effective carbonate source rocks. Dominated by type-III kerogen, the C1v and C1sr source rocks tended to be gas-bearing. The two source rocks were generally mature to highly mature; the average Ro was 1.51% and 1.23% in C1v and C1sr, respectively. The source rocks were deposited in strongly reducing to weakly oxidizing marine–terrigenous environments, with most organic material originating from higher terrigenous plants and a few aquatic organisms. During the Permian, the deep burial depth and high heat flow caused a quick and high maturation of the source rocks, which were subsequently uplifted and eroded, stopping the generation and expulsion of hydrocarbons in the C1v and C1sr source rocks. The initial TOC fitted by the △logR method was recovered, and it suggests that high-quality source rocks (TOC ≥ 1%) are mainly distributed in the northern and central local structural belt. 相似文献
13.
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
14.
Reinhard Gratzer Achim BechtelReinhard F. Sachsenhofer Hans-Gert LinzerDoris Reischenbacher Hans-Martin Schulz 《Marine and Petroleum Geology》2011,28(6):1171-1186
The Alpine Foreland Basin is a minor oil and moderate gas province in central Europe. In the Austrian part of the Alpine Foreland Basin, oil and minor thermal gas are thought to be predominantly sourced from Lower Oligocene horizons (Schöneck and Eggerding formations). The source rocks are immature where the oil fields are located and enter the oil window at ca. 4 km depth beneath the Alpine nappes indicating long-distance lateral migration. Most important reservoirs are Upper Cretaceous and Eocene basal sandstones.Stable carbon isotope and biomarker ratios of oils from different reservoirs indicate compositional trends in W-E direction which reflect differences in source, depositional environment (facies), and maturity of potential source rocks. Thermal maturity parameters from oils of different fields are only in the western part consistent with northward displacement of immature oils by subsequently generated oils. In the eastern part of the basin different migration pathways must be assumed. The trend in S/(S + R) isomerisation of ααα-C29 steranes versus the αββ (20R)/ααα (20R) C29 steranes ratio from oil samples can be explained by differences in thermal maturation without involving long-distance migration. The results argue for hydrocarbon migration through highly permeable carrier beds or open faults rather than relatively short migration distances from the source. The lateral distance of oil fields to the position of mature source rocks beneath the Alpine nappes in the south suggests minimum migration distances between less than 20 km and more than 50 km.Biomarker compositions of the oils suggest Oligocene shaly to marly successions (i.e. Schoeneck, Dynow, and Eggerding formations) as potential source rocks, taking into account their immature character. Best matches are obtained between the oils and units a/b (marly shale) and c (black shale) of the “normal” Schöneck Formation, as well as with the so-called “Oberhofen Facies”. Results from open system pyrolysis-gas chromatography of potential source rocks indicate slightly higher sulphur content of the resulting pyrolysate from unit b. The enhanced dibenzothiophene/phenanthrene ratios of oils from the western part of the basin would be consistent with a higher contribution of unit b to hydrocarbon expulsion in this area. Differences in the relative contribution of sedimentary units to oil generation are inherited from thickness variations of respective units in the overthrusted sediments. The observed trend towards lighter δ13C values of hydrocarbon fractions from oil fields in a W-E direction are consistent with lower δ13C values of organic matter in unit c. 相似文献
15.
With the rapid economic development, the water quality is worsening and red tide takes place frequently in the Changjiang Estuary and adjacent seawaters. To improve the marine water quality, the total inland pollutant load should be controlled effectively. With efficiency and fairness in consideration, the total maximum allowable loads of CODMn, NH3–N, inorganic nitrogen and active phosphate to the seawaters were calculated and allocated by the linear programming method based on the water quality response fields of the pollution sources. The maximum allowable loads are 2008 × 103 tons, 169 × 103 tons, 226 × 103 tons and 18 × 103 tons for CODMn, NH3–N, inorganic nitrogen and active phosphate when the water quality targets are requested to be achieved in the whole studied region, and 346 × 103 tons and 32 × 103 tons for inorganic nitrogen and active phosphate when the water quality targets to be achieved only in the red tide sensitive area. The cut task of CODMn and NH3–N is relatively easy and can be finished by the watershed environmental plan; while the cut task of inorganic nitrogen and active phosphate is tremendous. The coastal provinces should install more denitrification and dephosphorization facilities in the existing waste water treatment plants or build new ones to control the red tides in the concerned seawaters. 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.
The Yuqi block is an important area for oil and gas exploration in the northern Akekule uplift, Tarim Basin, northwestern China. The Upper Triassic Halahatang Formation (T3h) within the Yuqi block can be subdivided into a lowstand system tract (LST), a transgressive system tract (TST), and a highstand system tract (HST), based on a study of initial and maximum flood surfaces. Oil in the lowstand system tract of the Halahatang Formation is characterized by medium to lightweight (0.8075 g/cm3–0.9258 g/cm3), low sulfur content (0.41%–1.4%), and high paraffin content (9.65%–10.25%). The distribution of oil and gas is principally controlled by low-amplitude anticlines and faults. Based on studies of fluorescence thin sections and homogenization temperatures of fluid inclusions, reservoirs in the T3h were formed in at least two stages of hydrocarbon charge and accumulation. During the first stage (Jurassic–Cretaceous) both the structural traps and hydrocarbon reservoirs were initiated; during the second stage (Cenozoic) the structural traps were finally formed and the reservoirs were structurally modified. The reservoir-forming mechanism involved external hydrocarbon sources (i.e. younger reservoirs with oil and gas sourced from old rocks), two directions (vertical and lateral) of expulsion, and multi-stage accumulation. This model provides a theoretical fundament for future oil and gas exploration in the Tarim Basin and other similar basins in northwestern China. 相似文献
18.
Chengdao is an offshore area in the Bohai Bay Basin that contains approximately 25.7 × 108 bbl of oil and gas reserves within the sandstone reservoirs in Neogene strata. However, previous predictions of hydrocarbon accumulation in Neogene traps are inaccurate, resulting in a current failure rate of 50% when drilling for hydrocarbons in this area. To build an improved exploration model for Neogene traps, we select 92 traps from Neogene strata in the Chengdao area to quantify the filling degree, which is an indicator of hydrocarbon accumulation efficiency. The quantified filling degree is based on actual geological and exploration data and differs significantly among various trap types. The filling degree of traps also varies significantly with their structural locations and decreases generally from the northwest to the southeast along the Chengbei Fault zone. Vertically, the filling degree is highly heterogeneous, initially increasing from the bottom to the middle of Neogene strata and then decreasing towards the top of the strata. These Neogene hydrocarbon reservoirs are sourced from the Paleogene, and as they lay vertically away from the source rocks, their hydrocarbon enrichment is constrained largely by hydrocarbon migration distance and vertical migration pathways. The sealing capacity of faults and cap rocks, sandbody orientation and reservoir sedimentary facies determine the maximum column height, which in turn affects the amount of hydrocarbon accumulation within these traps. A scatter plot analysis of individual controls and volumetric filling for each trap type is compiled using multivariate linear regression analysis to quantify controls and the dominant control of hydrocarbon accumulation is determined. 相似文献
19.
Understanding the hydrocarbon accumulation pattern in unconventional tight reservoirs is crucial for hydrocarbon evaluation and oil/gas extraction from such reservoirs. Previous studies on tight oil accumulation are mostly concerned with self-generation or from source to reservoir rock over short distances. However, the Lucaogou tight oil in Jimusar Sag of Junggar Basin shows transitional feature in between. The Lucaogou Formation comprises fine-grain sedimentary rocks characterized by thin laminations and frequently alternating beds. The Lucaogou tight silt/fine sandstones are poorly sorted. Dissolved pores are the primary pore spaces, with average porosity of 9.20%. Although the TOC of most silt/fine sandstones after Soxhlet extraction is lower than that before extraction, they show that the Lucaogou siltstones in the area of study have fair to good hydrocarbon generation potential (average TOC of 1.19%, average S2 of 4.33 mg/g), while fine sandstones are relatively weak in terms of hydrocarbon generation (average TOC of 0.4%, average S2 of 0.78 mg/g). The hydrocarbon generation amount of siltstones, which was calculated according to basin modeling transformation ratio combined with original TOC based on source rock parameters, occupies 16%–72% of oil retention amount. Although siltstones cannot produce the entire oil reserve, they certainly provide part of them. Grain size is negatively correlated with organic matter content in the Lucaogou silt/fine sandstones. Fine grain sediments are characterized by lower deposition rate, stronger adsorption capacity and oxidation resistance, which are favorable for formation of high quality source rocks. Low energy depositional environment is the primary reason for the formation of siltstones containing organic matter. Positive correlation between organic matter content and clay content in Lucaogou siltstones supports this view point. Lucaogou siltstones appear to be effective reservoir rocks due to there relatively high porosity, and also act as source rocks due to the fair to good hydrocarbon generation capability. 相似文献
20.
Shixi Bulge of the central Junggar Basin in western China is a unique region that provides insight into the geological and geochemical characteristics of large-scale petroleum reservoirs in volcanic rocks of the western Central Asian Orogenic Belt. Carboniferous volcanic rocks in the Shixi Bulge mainly consist of striped lava and agglomerate, as well as breccia lava and tight tuff. Volcanic rocks differ in porosity and permeability. Striped lava exhibits the highest porosity (average: 14.2%) but the lowest permeability (average: 0.67 × 10−15 m) among the rock types. Primary gas pores are widely developed and mostly filled. Secondary dissolution pores and fractures are two major reservoir storage spaces. Capillary pressure curves suggest the existence of four pore structure types of reservoir rocks. Several factors, namely, lithology, pore structure, and various diagenesis, govern the physical properties of volcanic rocks. The oil is characterized by a high concentration of tricyclic terpane, a terpane distribution of C23 < C21 > C20, and sterane distributions of C27 < C28 < C29 and C27 > C28 < C29. Oil and gas geochemistry revealed that the oil is a mixture derived primarily from P2w source rock and secondarily from P1j source rock in the sag west of Pen-1 Well. The gases are likely gas mixtures of humic and sapropelic organic origins, with the sapropelic gas type dominant in the mixture. The gas mixture is most likely cracked from kerogen rather than oils. The Carboniferous volcanic reservoirs in Shixi Bulge share some unique characteristics that may provide useful insights into the various roles of different volcanic reservoir types in old volcanic provinces. The presence of these reservoirs will undoubtedly encourage future petroleum exploration in volcanic rocks up to the deep parts of sedimentary basins. 相似文献