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1.
A three-dimensional reconstruction of burial and palaeogeothermal conditions is presented for Miocene sediments of the Carpathian Foredeep beneath the Outer Western Carpathians fold and trust belt in the eastern part of the Czech Republic. The sedimentary units involved include autochthonous Paleozoic sequences, Miocene deposits of the Carpathian Foredeep and of the Western Carpathian nappe system. Reservoir rocks with economic oil and gas accumulations occur in the fractured crystalline basement and in the Neogene Carpathian Foredeep. The studied Vizovice area, is characterized by rocks representing both Variscan and Carpathian orogenic cycles. The 3D thermal maturity and subsidence model presented allows the significance of both tectonic events to be evaluated. The model, calibrated by vitrinite reflectance from eight boreholes proved that eroded units related to the Variscan orogeny approach, in amount, those eroded during the Carpathian orogeny. The thickness of the eroded rocks does not exceed 300 m in either case. Vitrinite reflectance data from representative core samples of the Miocene organic matter show that Rr values increase with depth from 0.36 to 0.58%. A re-evaluation of archival data on the quantity and quality of organic matter shows that total organic carbon ranges from 0.20 to 2.92 wt%, and residual hydrocarbons (S2) from 0.04 to 8.48 mg HC/g rock. These results lead to the conclusion that Neogene Unit II that was interpreted as coastline-through to shallow-marine deposition environment within the Carpathian Foredeep in the Czech Republic is potential source rock for hydrocarbon accumulations. 相似文献
2.
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
3.
The Niudong Buried Hill Field, which lies in the Baxian Depression of the Bohai Bay Basin, is the deepest oil/gas accumulation in eastern China. Its Precambrian dolomite reservoir occurs at burial depths of 5860 m–6027 m. This paper attempts to document the hydrocarbon charging and accumulation history in this field, which could greatly enhance the understanding of the mechanisms for the formation of deep hydrocarbon accumulations. Our previous study of oil trapped in fluid inclusions has demonstrated that the ratio parameters of the fluorescence spectral intensities at 425 nm and 433 nm (Q425/433 ratio), and at 419 nm and 429 nm (Q419/429 ratio) can be more effective for revealing hydrocarbon charging history than the previously-used fluorescence parameters such as Lambda max and red/green quotient as well as fluorescence colors. The hydrocarbon charging and accumulation history in the Niudong Buried Hill Field was studied with an integrated approach involving the application of these two spectral parameters of petroleum inclusion fluorescence as well as utilization of other data including homogenization temperatures of aqueous inclusions coeval with petroleum inclusions, and cross-cutting relationships of cements and “oil veins” in pores and fractures. The results indicate that the dolomite reservoir in the Niudong Buried Hill Field experienced three episodes of hydrocarbon charging. In the first two episodes (between 38.5Ma and 25Ma), the low mature and mature oils, which were derived from source rocks in the Sha-4 Member of the Eocene Shahejie Formation, migrated into the reservoir, but part of them leaked out due to normal faulting at the updip margin of the buried hill. These early-charged oils were preserved mainly in small pores in micritic dolomites by oil-wettability and capillary pressure. In the Neogene, the basin subsided as a whole and local faults at the updip margin became inactive and played a sealing role. By approximately 13Ma, the source rocks became highly mature and the generated hydrocarbons then migrated into the reservoir and accumulated. Therefore, the last charging is the most important for hydrocarbon accumulation in the Niudong Buried Hill Field. 相似文献
4.
The Paraná Basin, southern Brazil, has an atypical thermal and fluid history due to the occurrence of an episodic continental flood volcanism during the Early Cretaceous. So far, there are few data about the influence of this volcanic event on the paleotemperatures and paleofluids of the Paraná Basin sedimentary rocks. The Teresina Formation in the northern flank of the Ponta Grossa dyke swarm hosts high concentration of subsurface igneous rock bodies (sills and dykes), besides its covering by a hundreds meter thick volcanic rock cap. In this study, we used fluid inclusion analysis performed in horizontal and vertical calcite veins from the Teresina Formation and from a Late Cretaceous basic dyke to estimate paleotemperatures and to characterize the composition of diagenetic paleofluids. Homogenization temperatures of requilibrated fluid inclusions show that the Teresina Formation reached temperatures above 200 °C. Horizontal parallel bedding calcite veins from the Teresina Formation record low to high salinity (2–26 wt.% NaCl eq.) aqueous paleofluids. The prevalence of high salinity fluid inclusions associated with light hydrocarbon fluid inclusions indicates deep buried fluids. Fluid inclusions in vertical calcite vein from basic dyke comprise only low salinity aqueous fluids (0–3 wt.% eq.NaCl) interpreted as dominated by meteoric water. The recorded paleotemperatures are attributed to the heating by the Paraná volcanic event during the Early Cretaceous, with the thermal effect of the volcanic rock cap surpassing the effect of nearby sills and dykes. Estimated paleotemperatures higher than 200 °C would allow the generation of light liquid and gaseous hydrocarbons. Overpressured compartments in the Teresina Formation allowed the expulsion of buried pore fluids (high salinity aqueous fluids and hydrocarbons) to fracture systems, where they mixed with meteoric water. The input of meteoric water through fracture systems connected with the surface favored hydrocarbons degradation in the early stages of source rock maturation during the Early Cretaceous. 相似文献
5.
The Carboniferous and Permian sedimentary rocks (mainly the Shanxi and Taiyuan formations) in the Linxing region, eastern Ordos Basin, China, host a significant volume of unconventional gas resources (coalbed methane, shale gas and tight sandstone gas). Currently, the in-situ stress state is poorly understood but knowledge of this is extremely important for a range of applications, such as gas exploration and production, fracture stimulation and wellbore stability. The maximum horizontal stress (SHmax), minimum horizontal stress (Shmin) and vertical stress (Sv) magnitudes, and the SHmax orientation in the Linxing region were systematically analyzed for the first time in the present study, which can provide a reference for subsequent numerical simulation and hydraulic fracturing design. Based on borehole breakouts and drilling-induced tensile fractures interpreted from borehole imaging logs, the SHmax orientation rotates from ∼NEE-SWW-trending in the southern part to ∼ NWW-SEE-trending in the northern part of the Linxing region. Both conventional logs and extended leak-off tests were used for stress magnitude determination. The results revealed three types of in-situ stress fields (Sv > SHmax > Shmin, SHmax > Sv > Shmin and SHmax > Sv ≈ Shmin), and a dominant strike-slip stress regime (SHmax > Sv ≥ Shmin) was found for the entire well section in the target Shanxi Formation and Taiyuan Formation in the Linxing region. In addition, differential stress increased with depth in the Linxing region, which indicates that wellbore instability might be a potentially significant problem when drilling wells that are vertical or ∼ N-S-trending. 相似文献
6.
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
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.
The hydrocarbon migration in tight reservoirs is a complex process, the fluid flow patterns of which are notably different from those of conventional reservoirs. Therefore, specific mathematical models are needed to simulate the secondary hydrocarbon migrations. This study presents a numerical simulation method based on Artificial Immune Ant Colony Algorithm (AIACA) to simulate the secondary hydrocarbon migrations in tight reservoirs. It consists of three core parts: (1) the release modes of artificial ants based on the intensity of hydrocarbon generation; (2) the wandering patterns of artificial ants under the control of the dynamic field and the distribution of pheromones; (3) the updating modes of pheromones based on the changes in reservoir wettability. The simulation of secondary migration can be realized by the observing the dynamic movements and accumulations of the artificial ants. The method has been tested in the Chang 81 tight sandstone reservoir, which is part of the Triassic Yanchang Formation in the Huaqing Area, Ordos Basin in China, and proved to be successful in matching the current data in exploration and development. 相似文献
9.
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
10.
鄂尔多斯盆地北部主力气源岩太原组、山西组煤系地层热成熟史的研究对本区天然气充注过程和有利目标区预测具有重要的参考价值。在对研究区烃源岩评价和一维、二维地质建模研究的基础上。利用BasinMod盆地模拟软件对单井以及研究区内二维剖面、平面进行了煤系烃源岩热演化史模拟研究。研究结果表明：（1）该区在中三叠世进入生烃门限，中侏罗世以后，烃源岩持续埋深，早白垩世末期至最大埋深（4000m左右），绝大多数的天然气都在这一阶段生成，早白垩世末构造抬升以后只有少量天然气生成；（2）研究区上古生界太原组和山西组煤系源岩最大累积生烃强度可达到2200×10^8m^3／km^2，对现今天然气的分布具有较强的控制作用。 相似文献
11.
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
12.
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
13.
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
14.
Thermal history, petroleum system, structural, and tectonic constraints are reviewed and integrated in order to derive a new conceptual model for the Norman Wells oil field, and a new play type for tectonically active foreland regions. The thermal history recorded by Devonian rocks suggests that source rocks experienced peak thermal conditions in the Triassic–Jurassic, during which time oil was likely generated. After initial oil generation and expulsion, the Canol Formation oil shale retained a certain fraction of hydrocarbons. The shallow reservoir (650–350 m) is a Devonian carbonate bank overlain by the Canol Formation and resides within a hanging wall block of the Norman Range thrust fault. Both reservoir and source rocks are naturally fractured and have produced high API non-biodegraded oil. Thrust faults in the region formed after the Paleocene, and a structural cross-section of the field shows that the source and reservoir rocks at Norman Wells have been exhumed by over 1 km since then.The key proposition of the exhumation model is that as Canol Formation rocks underwent thrust-driven exhumation, they crossed a ductile–brittle transition zone and dip-oriented fractures formed sympathetic to the thrust fault. The combination of pore overpressure and new dip-directed subvertical fractures liberated oil from the Canol Formation and allowed for up-dip oil migration. Reservoir rocks were similarly fractured and improved permeability enhanced charging and pooling of oil. GPS and seismicity data indicate that strain transfer across the northern Cordillera is a response to accretion of the Yakutat terrane along the northern Pacific margin of North America, which is also the probable driving force for foreland shortening and rock exhumation at Norman Wells. 相似文献
15.
《Marine and Petroleum Geology》2012,33(1):21-35
The petroleum generation and charge history of the northern Dongying Depression, Bohai Bay Basin was investigated using an integrated fluid inclusion analysis workflow and geohistory modelling. One and two-dimensional basin modelling was performed to unravel the oil generation history of the Eocene Shahejie Formation (Es3 and Es4) source rocks based on the reconstruction of the burial, thermal and maturity history. Calibration of the model with thermal maturity and borehole temperature data using a rift basin heat flow model indicates that the upper interval of the Es4 source rocks began to generate oil at around 35 Ma, reached a maturity level of 0.7% Ro at 31–30 Ma and a peak hydrocarbon generation at 24–23 Ma. The lower interval of the Es3 source rocks began to generate oil at around 33–32 Ma and reached a maturity of 0.7% Ro at about 27–26 Ma. Oil generation from the lower Es3 and upper Es4 source rocks occurred in three phases with the first phase from approximately 30–20 Ma; the second phase from approximately 20–5 Ma; and the third phase from 5 Ma to the present day. The first and third phases were the two predominant phases of intense oil generation.Samples from the Es3 and Es4 reservoir intervals in 12 wells at depth intervals between 2677.7 m and 4323.0 m were investigated using an integrated fluid inclusion workflow including petrography, fluorescence spectroscopy and microthermometry to determine the petroleum charge history in the northern Dongying Depression. Abundant oil inclusions with a range of fluorescence colours from near yellow to near blue were observed and were interpreted to represent two episodes of hydrocarbon charge based on the fluid inclusion petrography, fluorescence spectroscopy and microthermometry data. Two episodes of oil charge were determined at 24–20 Ma and 4–3 Ma, respectively with the second episode being the predominant period for the oil accumulation in the northern Dongying Depression. The oil charge occurred during or immediately after the modelled intense oil generation and coincided with a regional uplift and a rapid subsidence, suggesting that the hydrocarbon migration from the already overpressured source rocks may have been triggered by the regional uplift and rapid subsidence. The expelled oil was then charged to the already established traps in the northern Dongying Depression. The proximal locations of the reservoirs to the generative kitchens and the short oil migration distance facilitate the intimate relationship between oil generation, migration and accumulation. 相似文献
16.
Ancient hydrocarbon seepage occurred in the Hrabůvka quarry at the boundary between the basement of the Bohemian Massif (represented by folded Lower Carboniferous siliciclastics of the Culm facies) and Tertiary sedimentary cover of the Carpathian Foredeep (formed by Lower Badenian siliciclastics and calcareous clays). The unconsolidated Lower Badenian sediments contain lithified domains composed of limestone and breccias with limestone cement, whereas the basement rocks are cut by subvertical neptunic dykes filled up by limestone and calcite-marcasite-pyrite veinlets representing sealed fluid conduits. The deeply negative δ13C values of both vein calcite and limestone (down to −38.1‰ V-PDB) indicate that oxidation of hydrocarbons was the major source of carbon for authigenic mineralization. A fluid inclusion study suggests low fluid temperatures (<50 °C) and low and variable salinities of aqueous fluids associated with hydrocarbons (0.7–6.7 wt. % NaCl eq.). The variability of δ18O values of authigenic carbonates (−1.7 to −8.2‰ V-PDB) could reflect either slight changes in temperature of escaping fluids (mostly within 15 °C), and/or some mixing with meteoric waters. The low δ34S values of vein marcasite (∼–20‰ V-CDT) are consistent with bacterial reduction of sulfate in the hydrothermal system. Low C1/(C2+C3) ratios in hydrocarbon gas extracted from authigenic carbonates (9.9 and 5.8) as well as the high δ13C values of methane (−31.8 and −32.4‰ V-PDB) are compatible with a thermogenic source of hydrocarbons. REE data indicate sequestration of REE from finely dispersed detrital material in the apical part of the hydrothermal system. The available data are compatible with two possible scenarios of fluid origin. The hydrocarbons could have been leached from underlying Paleozoic sedimentary sequence by aqueous fluids that infiltrated into the basement after Tertiary tectonic reactivation. Alternatively, an external source of hydrocarbon-bearing fluids can be found in the adjacent Outer Western Carpathians flysch nappes containing petroleum-producing lithologies. Nevertheless, a regional flow of hydrocarbon-bearing fluids is evidenced by the occurrence of very similar hydrocarbon-bearing vein mineralizations in a wider area. 相似文献
17.
The Eocene Niubao Formation of the Lunpola Basin, a large Cenozoic intermontane basin in central Tibet, is an important potential hydrocarbon source and reservoir unit. It represents ∼20 Myr of lacustrine sedimentation in a half-graben with a sharply fault-bounded northern margin and a low-angle flexural southern margin, resulting in a highly asymmetric distribution of depositional facies and sediment thicknesses along the N-S axis of the basin. An integrated investigation of well-logs, seismic data, cores and outcrops revealed three third-order sequences (SQ1 to SQ3), each representing a cycle of rising and falling lake levels yielding lowstand, transgressive, and highstand systems tracts. Lowstand systems tracts (LST) include delta and fan delta facies spread widely along the gentle southern margin and concentrated narrowly along the steep northern margin of the basin, with sublacustrine fan sand bodies extending into the basin center. Highstand systems tracts (HST) include expanded areas of basin-center shale deposition, with sublacustrine fans, deltas and fan deltas locally developed along the basin margins. Sequence development may reflect episodes of tectonic uplift and base-level changes. The southern margin of the basin exhibits two different structural styles that locally influenced sequence development, i.e., a multi-step fault belt in the south-central sector and a flexure belt in the southeastern sector. The sedimentary model and sequence stratigraphic framework developed in this study demonstrate that N2 (the middle member of Niubao Formation) exhibits superior hydrocarbon potential, characterized by thicker source rocks and a wider distribution of sand-body reservoirs, although N3 (the upper member of Niubao Formation) also has good potential. Fault-controlled lithologic traps are plentiful along the basin margins, representing attractive targets for future exploratory drilling for hydrocarbons. 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.
The evaporite-cored Hoodoo Dome on southern Ellef Ringnes Island, Sverdrup Basin, was examined to improve the understanding of its structural geological history in relation to hydrocarbon migration. Data from geological mapping, reflection seismic, thermal maturity and detrital apatite (U–Th)/He cooling ages are presented. Five stages of diapirism are interpreted from Jurassic to Recent times:1. 180 to 163 Ma (pre-Deer Bay Formation; development of a diapir with a circular map pattern).2. 163 to 133 Ma (Deer Bay to lower Isachsen formations; development of salt wings).3. 115 to 94 Ma (Christopher and Hassel formations; ongoing diapirism and development of an oval map pattern)4. 79 Ma (Kanguk Formation; reactivation of the central diapir).5. 42 Ma to 65 Ma (Eurekan Orogeny; tightening of the anticline).During phase1, the Hoodoo diapir was circular. During phase 2, salt wings formed along its margin. During phase 3, the Hoodoo Dome geometry evolved into a much larger, elongate, doubly plunging anticline. Phase 4 is inferred from thermochronology data as indicated by a cluster of cooling ages, but the extent of motion during that time is unknown. During Phase 5 the dome was tightened creating approximately 700 m of structural relief. Denudation since the end of the Eurekan Orogeny is estimated to be about 600 m.A one dimensional burial history model predicts hydrocarbon generation from Middle and Late Triassic source rocks between 140 and 66 Ma, with majority of hydrocarbon expulsion between 117 and 79 Ma. Hydrocarbon generation post-dates salt wing formation, so that this trap could host natural gas expelled from Triassic source rocks. 相似文献
20.
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