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1.
Benzene extractable aliphatic hydrocarbons from the New Albany Shale in the Illinois Basin were characterized by gas chromatography and mass spectrometry, and the total organic matter of the shale was characterized by solid state carbon-13 cross polarization magic angle spinning nuclear magnetic resonance. Core samples from a northwest-trending cross-section of the Illinois Basin were studied. Gas chromatography (GC) and gas chromatography-mass spectrometric analysis (GC/MS) data indicate a regional variation of the aliphatic composition of the shale extracts. A positive, linear relationship between the two ratios, pristane/n-C17 and phytane/n-C18, is indicated. The NMR results indicated that organic matter deposited in northwestern Illinois shale is relatively high in aliphatic hydrocarbon content while, in contrast, organic matter found in southeastern Illinois shale is relatively low in aliphatic hydrocarbon content. Our findings suggest that the organic variation of the shale is mainly due to the differences in thermal maturity of the shale organic matter and the use of pristane/n-C17 ratio as a thermal parameter in the study of oil may be extended to the study of the ancient sediments.  相似文献   

2.
The lower part of Shayi Member (Es1x Sub-Member) composed mainly of dark mudstones and shales is the dominant source rocks for the Lixian Slope. Based on organic petrology, organic and inorganic geochemistry analyses of several mudstone and shale samples selected from Es1x Sub-Member, this research provides an overview on type, origin and thermal maturity of organic matters, as well as depositional environment of Es1x Sub-Member. Kerogen microscopy observation shows that the macerals are dominated by sapropelinite with a significant mixture of vitrinite and inertinite, indicating that aquatic algal-bacterial organic matter inputs are dominate with a significant contribution of terrigenous organic matter inputs. This statement is supported by n-alkane patterns distribution characteristics, high (n-C21 + n-C22)/(n-C28 + n-C29) values (average = 1.77), the plot of high Ph/n-C18 values (average = 4.15) versus low Pr/n-C17 values (average = 1.13), and high proportion of C27 sterane and C29 sterane (average = 37.7 and 42.0%, respectively). In addition, the rather low Pr/Ph values (average = 0.38), high gammacerane index values (average = 0.30), high V/Ni and V/(V + Ni) values (average = 11.84 and 0.89, respectively), high Sr/Ba and Sr/Cu values (average = 8.54 and 108, respectively), indicative of a saline water condition and a anoxic depositional environment. The low C29 sterane ααα 20S/(20S + 20R), C29 sterane αββ/(αββ + ααα), C31 homohopane 22S/(22S + 22R), C32 homohopane 22S/(22S + 22R), Ts/(Ts + Tm) values and relatively high moretane/hopane values show that the level of thermal maturity of organic matters in Es1x Sub-Member are low.  相似文献   

3.
Experimental studies of the effects of thermochemical sulfate reduction (TSR) on light hydrocarbons were conducted in sealed gold tubes for 72 h at 400 °C and 50 MPa. A variety of pyrolysis experiments were carried out, including anhydrous, hydrous without MgSO4 (hydrous experiments) and hydrous with MgSO4 (TSR experiments). Common reservoir minerals including montmorillonite, illite, calcite and quartz were added to various experiments. Measurements of the quantities of n-C9+ normal alkanes (high molecular weight, HMW), n-C6-8 normal alkanes (low molecular weight, LMW), C7-8 isoalkanes, C6-7 cycloalkanes and C6-9 monoaromatics and compound specific carbon isotope analyses were made. The results indicate that TSR decreases hydrocarbon thermal stability significantly as indicated by chemically lower concentrations and isotopically heavier LMW saturated hydrocarbons in the TSR experiments compared to the hydrous and anhydrous experiments. In the LMW saturated hydrocarbon fraction, cycloalkanes tend to be more resistant to TSR than n-alkanes and isoalkanes. TSR promotes aromatization reactions and favors the generation of monoaromatics, resulting in higher chemical concentrations and isotopically equivalent compositions of monoaromatics in the anhydrous, hydrous and TSR experiments. This indicates that LMW monoaromatics are thermally stable during the pyrolysis experiments. Acid rather than basic catalyzed ionic reactions probably play a major role in TSR. This is suggested by the promotion effects of acid-clay minerals including illite and particularly montmorillonite. The basic mineral calcite retards the destruction of n-C9+ normal alkanes within the TSR experiments. Furthermore, clay minerals have a minor influence on the generation of LMW monoaromatics and play a negative role in regulating the concentrations of LMW saturated hydrocarbons; calcite does not favor the generation of LMW monoaromatics and plays a positive role in controlling the concentrations of LMW saturates relative to clay minerals. Quartz has a negligible role in the TSR experiments.Due to their differential responses to TSR, LMW hydrocarbon parameters, such as Schaefer [Schaefer, R.G., Littke, R., 1988. Maturity-related compositional changes in the low-molecular-weight hydrocarbon fraction of Toarcian Shale. Organic Geochemistry 13, 887-892], Thompson [Thompson, K.F.M., 1988. Gas-condensate migration and oil fractionation in deltaic systems. Marine and Petroleum Geology 5, 237-246], Halpern [Halpern, H., 1995. Development and application of light-hydrocarbon-based star diagrams. American Association of Petroleum Geologists Bulletin 79, 801-815] and Mango [Mango, F.D., 1997. The light hydrocarbons in petroleum: a critical review. Organic Geochemistry 26, 417-440] parameters and stable carbon isotopic compositions of individual LMW saturated hydrocarbons in TSR affected oils should be used with caution. In addition, water promotes thermal cracking of n-C9+ normal alkanes and favors the generation of LMW cycloalkanes and monoaromatics. The result is lower concentrations of n-C9+ HMW normal alkanes and higher concentrations of LMW cycloalkanes and monoaromatics in hydrous experiments relative to anhydrous experiments with or without minerals.This investigation provides a better understanding of the effects of TSR on LMW hydrocarbons and the influence of reservoir minerals on TSR in natural systems. The paper shows how LMW hydrocarbon indicators in TSR altered oils improve understanding of the processes of hydrocarbon generation, migration and secondary alteration in subsurface petroleum reservoirs.  相似文献   

4.
Organic geochemical characterization of cutting samples from the Abu Hammad-1 and Matariya-1 wells elucidates the depositional environment and source rock potential of the Jurassic and Lower Cretaceous successions and the Middle Miocene to Pleistocene section in the southern and eastern Nile Delta Basin. The burial and thermal histories of the Mesozoic and Miocene sections were modeled using 1D basin modeling based on input data from the two wells. This study reveals fair to good gas-prone source rocks within the Upper Jurassic and Lower Cretaceous sections with total organic carbon (TOC) averaging 2.7% and hydrogen index (HI) up to 130 mg HC/g TOC. The pristane/n-C17 versus phytane/n-C18 correlation suggests mixed marine and terrestrial organic matter with predominant marine input. Burial and thermal history modeling reveals low thermal maturity due to low heat flow and thin overburden. These source rocks can generate gas in the western and northern parts of the basin where they are situated at deeper settings. In contrast, the thick Middle Miocene shows fair source rock quality (TOC averaging at 1.4%; HI maximizing at 183 mg HC/g TOC). The quality decreases towards the younger section where terrestrial organic matter is abundant. This section is similar to previously studied intervals in the eastern Nile Delta Basin but differs from equivalents in the central parts where the quality is better. Based on 1D modeling, the thick Middle Miocene source rocks just reached the oil generation stage, but microbial gas, however, is possible.  相似文献   

5.
24-n-Propylcholestane (24-npc), a C30 sterane compound derived from sterol precursors which are the major sterol constituents of modern pelagophyte microalgae, occurs in certain Neoproterozoic rocks and oils and throughout the Phanerozoic rock record. This broad distribution leads 24-npc to be widely considered a reliable indicator of open to partially restricted marine depositional conditions for source rocks and oils. Here we report two significant hiatuses in the occurrences of 24-npc in the Lower Paleozoic marine rock record: the first in the Middle–Late Cambrian and the second in the Late Ordovician–early Silurian transition for a range of lithofacies (carbonates and siliciclastic rocks), organic carbon contents (both organic-lean and organic-rich), and paleoceanographic environments (shelf and deeper water marine settings) and observed offshore of two paleocontinents, Laurentia and Baltica. The Ordovician–Silurian gap is at least 9 million years, and possibly up to 20 million years, in duration. Robust older occurrences of 24-npc steranes in some Neoproterozoic rocks and oils suggest that oceanographic conditions in our intervals of Lower Paleozoic time were unfavorable for the proliferation of pelagophyte algae as phytoplankton. Caution should therefore be applied when interpreting a lacustrine versus marine depositional environmental setting for source rocks and oils in these intervals of Early Paleozoic time using lipid biomarker assemblages.  相似文献   

6.
The free, adsorbed and inclusion oils were recovered by sequential extraction from eleven oil and tar containing reservoir rocks in the Tazhong Uplift of Tarim Basin. The results of gas chromatography (GC) and GC–mass spectrometry analyses of these oil components and seven crude oils collected from this region reveal multiple oil charges derived from different source rocks for these oil reservoirs. The initially charged oils show strong predominance of even over odd n-alkanes in the range n-C12 to n-C20 and have ordinary maturities, while the later charged oils do not exhibit any predominance of n-alkanes and have high maturities. The adsorbed and inclusion oils of the reservoir rocks generally have high relative concentrations of gammacerane and C28 steranes, similar to the Cambrian-Lower Ordovician source rocks. In contrast, the free oils of these reservoir rocks generally have low relative concentrations of gammacerane and C28 steranes, similar to the Middle-Upper Ordovician source rocks. There are two interpretations of this result: (1) the initially charged oils are derived from the Cambrian-Lower Ordovician source rocks while the later charged oils are derived from the Middle-Upper Ordovician source rocks; and (2) both the initially and later charged oils are mainly derived from the Cambrian-Lower Ordovician source rocks but the later charged oils are contaminated by the oil components from the Silurian tar sandstones and the Middle-Upper Ordovician source rocks.  相似文献   

7.
Frontier exploration in the Kuqa Depression, western China, has identified the continuous tight-sand gas accumulation in the Lower Cretaceous and Lower Jurassic as a major unconventional gas pool. However, assessment of the shale gas resource in the Kuqa Depression is new. The shale succession in the Middle–Upper Triassic comprises the Taliqike Formation (T3t), the Huangshanjie Formation (T3h) and the middle–upper Karamay Formation (T2–3k), with an average accumulated thickness of 260 m. The high-quality shale is dominated by type III kerogen with high maturity and an average original total organic carbon (TOC) of about 2.68 wt%. An improved hydrocarbon generation and expulsion model was applied to this self-contained source–reservoir system to reveal the gas generation and expulsion (intensity, efficiency and volume) characteristics of Middle–Upper Triassic source rocks. The maximum volume of shale gas in the source rocks was obtained by determining the difference between generation and expulsion volumes. The results indicate that source rocks reached the hydrocarbon expulsion threshold of 1.1% VR and the hydrocarbon generation and expulsion reached their peak at 1.0% VR and 1.28% VR, with the maximum rate of 56 mg HC/0.1% TOC and 62.8 mg HC/0.1% TOC, respectively. The volumes of gas generation and expulsion from Middle–Upper Triassic source rocks were 12.02 × 1012 m3 and 5.98 × 1012 m3, respectively, with the residual volume of 6.04 × 1012 m3, giving an average gas expulsion efficiency of 44.38% and retention efficiency of 55.62%. Based on the gas generation and expulsion characteristics, the predicted shale gas potential volume is 6.04 × 1012 m3, indicating a significant shale gas resource in the Middle–Upper Triassic in the eastern Kuqa Depression.  相似文献   

8.
Yuhong Liao  Ansong Geng   《Applied Geochemistry》2009,24(11):2123-2132
The effect of isotopic fractionation during primary migration of hydrocarbons from coals is rarely noticed because it overlaps with the isotopic effects of maturation. In this research, geological chromatography-like effects and possible physical isotopic fractionation effects on n-alkanes during primary migration from four coals and one mudstone were studied through two types of generation–expulsion simulations (generation–expulsion simulations I and II). In order to monitor the kinetic isotopic fractionation effect during primary migration and to differentiate the isotopic effects of primary migration from the isotopic effects of maturation, generation–expulsion simulation was upgraded in two aspects, source rock was separated into at least five layers, and deuterated n-C15D32 was added to the initial layer of the source rock (simulation II). The experimental results suggested that all terrestrial source rocks exhibit significant geological chromatography-like effects in generation–expulsion simulation. Expulsion efficiencies shown by vitrinite-rich coals are much lower than algal cannel, fusinite-rich coal and mudstone. There also exist significant physical isotopic fractionation effects in hydrocarbon primary migration processes from vitrinite-rich coals, but there is no significant isotopic fractionation effect from fusinite-rich brown coal and mudstone. Pore structure and specific surface area of source rock samples were measured by gas adsorption of both N2 and CO2. This indicated that vitrinite-rich coals have a higher proportion of microporosity. The differences in pore structure and adsorptive capacity of source rocks may be responsible for differences in expulsion efficiencies and isotopic fractionation effects in generation–expulsion simulations. The isotopic fractionation effect due to primary migration should be considered in making oil-source correlation when vitrinite-rich coals are concerned.  相似文献   

9.
Biodegradation, one of the most important weathering processes, alters the composition of spilled oil, making it difficult to identify the source of the release and to monitor its fate in the environment. A laboratory experiment was conducted to simulate oil spill weathering process of microbial degradation to investigate compositional changes in a range of source- and weathering-dependent molecular parameters in oil residues, and the conventional diagnostic ratios for oil spill identification were also evaluated. The conventional diagnostic ratios of n-alkane displayed obvious changes after biodegradation, especially for Pr/n-C17 and Ph/n-C18 with relative standard deviation more than 118.84 %, which suggests they are invalid for oil source identification of the middle-serious spill. Many polycyclic aromatic hydrocarbons (PAHs) are more resistant to biodegradation process than their saturated hydrocarbon counterparts, thus making PAHs to be one of the most valuable fingerprinting classes of hydrocarbons for oil identification. Biomarker ratios of hopanes and steranes were also useful for source identification even after moderate biodegradation, and the diagnostic ratios from them could be used in tracking origin and sources of hydrocarbon pollution. Finally, the carbon isotopic type curve may provide another diagnostic means for correlation and differentiation of spilled oils, and be particularly valuable for lighter refined products or severely biodegraded oils, the source of which may be difficult to identify by routine biomarker techniques.  相似文献   

10.
<正>The oil source of the Tarim Basin has been controversial over a long time.This study characterizes the crude oil and investigates the oil sources in the Lunnan region,Tarim Basin by adopting compound specific isotopes of n-alkanes and biomarkers approaches.Although the crude oil has a good correlation with the Middle-Upper Ordovician(O_(2+3)) source rocks and a poor correlation with the Cambrian-Lower Ordovician((?)-O_1) based on biomarkers,theδ~(13)C data of n-alkanes of the Lunnan oils show an intermediate value between(?)-O_1 and O_(2+3) genetic affinity oils,which suggests that the Lunnan oils are actually of an extensively mixed source.A quantification of oil mixing was performed and the results show that the contribution of the Cambrian-Lower Ordovician source rocks ranges from 11%to 70%(averaging 36%),slightly less than that of the Tazhong uplift.It is suggested that the inconsistency between the biomarkers andδ~(13)C in determining the oil sources in the Lunnan Region results from multiple petroleum charge episodes with different chemical components in one or more episode(s) and different sources.The widespread marine mixed-source oil in the basin indicates that significant petroleum potential in deep horizons is possible.To unravel hydrocarbons accumulation mechanisms for the Lunnan oils is crucial to further petroleum exploration and exploitation in the region.  相似文献   

11.
The presence of shale oil in the Cretaceous Hengtongshan Formation in the Tonghua Basin, drilled by the well TD-01, has been discussed in this geological investigation for the first time. To evaluate the high-quality source rocks of Cretaceous continental shale oil, the distribution characteristics and the evolution of the ancient environment, samples of shale were systematically analyzed in terms of sedimentary facies, organic geochemistry, and organic carbon isotopic composition. The results demonstrate that a TOC value of 1.5% represents the lower-limit TOC value of the high-quality source rocks. Source rocks have an aggregate thickness of 211 m and contain abundant organic matter, with TOC values of 2.69% on average and a maximum value over 5.44%. The original hydrocarbon-generative potential value(S_1+S_2) is between 0.18 mg/g and 6.13 mg/g, and the Ro is between 0.97% and 1.40%. The thermal maturation of the source rocks is relatively mature to highly mature. The δ13C value range is between -34.75‰ and -26.53‰. The ratio of saturated hydrocarbons to aromatic hydrocarbons is 1.55 to 5.24, with an average of 2.85, which is greater than 1.6. The organic types are mainly type Ⅱ_1, followed by type Ⅰ. The organic carbon source was C_3 plants and hydrophytes. The paleoclimate of the Hengtongshan Formation can be characterized as hot and dry to humid, and these conditions were conducive to the development of high-quality source rocks. A favorable paleoenvironment and abundant organic carbon sources provide a solid hydrocarbon generation base for the formation and accumulation of oil and gas in the shale of the Tonghua Basin.  相似文献   

12.
Previous studies have postulated the contribution of present-day low-total organic carbon(TOC) marine carbonate source rocks to oil accumulations in the Tabei Uplift, Tarim Basin, China. However, not all present-day low-TOC carbonates have generated and expelled hydrocarbons; therefore, to distinguish the source rocks that have already expelled sufficient hydrocarbons from those not expelled hydrocarbons, is crucial in source rock evaluation and resource assessment in the Tabei Uplift. Mass balance can be used to identify modern low-TOC carbonates resulting from hydrocarbon expulsion. However, the process is quite complicated, requiring many parameters and coefficients and thus also a massive data source. In this paper, we provide a quick and cost effective method for identifying carbonate source rock with present-day low TOC, using widely available Rock-Eval data. First, we identify present-day low-TOC carbonate source rocks in typical wells according to the mass balance approach. Second, we build an optimal model to evaluate source rocks from the analysis of the rocks' characteristics and their influencing factors, reported as positive or negative values of a dimensionless index of Rock-Eval data(IR). Positive IR corresponds to those samples which have expelled hydrocarbons. The optimal model optimizes complicated calculations and simulation processes; thus it could be widely applicable and competitive in the evaluation of present-day low TOC carbonates. By applying the model to the Rock-Eval dataset of the Tabei Uplift, we identify present-day low-TOC carbonate source rocks and primarily evaluate the contribution equivalent of 11.87×10~9 t oil.  相似文献   

13.
It is concluded that there are three hydrocarbon generation and accumulation processes in northeastern Sichuan on the basis of the characteristics of solid bitumen, gas-light oils-heavy oils, homogenization temperature of fluid inclusions and diagenesis for beach- and reef-facies dolomite gas- bearing reservoirs in the Puguang Gas Field, northeastern Sichuan Basin, southern China. The first hydrocarbon generation and accumulation episode occurred in the Indosinian movement （late Middle Triassic）. The sapropelic source rocks of the O3w （Upper Ordovician Wufeng Formation）-S1l （Lower Silurian Longmaxi Formation） were buried at depths of 2500 m to 3000 m with the paleogeothermal temperature ranging from 70℃ to 95℃, which yielded heavy oil with lower maturity. At the same time, intercrystalline pores, framework pores and corrosion caused by organic acid were formed within the organic reef facies of P2ch （Upper Permian Changxing Formation）. And the first stage of hydrocarbon reservoir occurred, the level of surface porosity of residual solid bitumen {solid bitumen/ （solid bitumen ＋ residual porosity）} was higher than 60%. The second episode occurred during the Middle Yanshanian movement （late Middle Jurassic）. During that period, the mixed organic source rocks were deposited in an intra-platform sag during the Permian and sapropelic source rocks of O3w-S1l experienced a peak stage of crude oil or light oil and gas generation because they were buried at depths of 3500 m to 6800 m with paleogeothermal temperatures of 96-168℃. At that time, the level of surface porosity of residual solid bitumen of the T1f shoal facies reservoirs was between 25% and 35%, and the homogenization temperatures of the first and second stages of fluid inclusions varied from 100℃ to 150℃. The third episode occurred during the Late Yanshanian （Late Cretaceous） to the Himalayan movement. The hydrocarbon reservoirs formed during the T1f and P2ch had the deepest burial of 7700 m to 8700 m and paleogeotemperatu  相似文献   

14.
The carbon geochemistry of serpentinized peridotites and gabbroic rocks recovered at the Lost City Hydrothermal Field (LCHF) and drilled at IODP Hole 1309D at the central dome of the Atlantis Massif (Mid-Atlantic Ridge, 30°N) was examined to characterize carbon sources and speciation in oceanic basement rocks affected by long-lived hydrothermal alteration. Our study presents new data on the geochemistry of organic carbon in the oceanic lithosphere and provides constraints on the fate of dissolved organic carbon in seawater during serpentinization. The basement rocks of the Atlantis Massif are characterized by total carbon (TC) contents of 59 ppm to 1.6 wt% and δ13CTC values ranging from −28.7‰ to +2.3‰. In contrast, total organic carbon (TOC) concentrations and isotopic compositions are relatively constant (δ13CTOC: −28.9‰ to −21.5‰) and variations in δ13CTC reflect mixing of organic carbon with carbonates of marine origin. Saturated hydrocarbons extracted from serpentinites beneath the LCHF consist of n-alkanes ranging from C15 to C30. Longer-chain hydrocarbons (up to C40) are observed in olivine-rich samples from the central dome (IODP Hole 1309D). Occurrences of isoprenoids (pristane, phytane and squalane), polycyclic compounds (hopanes and steranes) and higher relative abundances of n-C16 to n-C20 alkanes in the serpentinites of the southern wall suggest a marine organic input. The vent fluids are characterized by high concentrations of methane and hydrogen, with a putative abiotic origin of hydrocarbons; however, evidence for an inorganic source of n-alkanes in the basement rocks remains equivocal. We propose that high seawater fluxes in the southern part of the Atlantis Massif likely favor the transport and incorporation of marine dissolved organic carbon and overprints possible abiotic geochemical signatures. The presence of pristane, phytane and squalane biomarkers in olivine-rich samples associated with local faults at the central dome implies fracture-controlled seawater circulation deep into the gabbroic core of the massif. Thus, our study indicates that hydrocarbons account for an important proportion of the total carbon stored in the Atlantis Massif basement and suggests that serpentinites may represent an important—as yet unidentified—reservoir for dissolved organic carbon (DOC) from seawater.  相似文献   

15.
Combined with the actual geological settings, tight oil is the oil that occurs in shale or tight reservoirs, which has permeability less than 1 mD and is interbedded with or close to shale, including tight dolomitic oil and shale oil. The Fengcheng area (FA), at the northwest margin of the Junggar Basin, northwest China, has made significant progress in the tight oil exploration of the Fengcheng (P1f) Formation recently, which indicates that the tight oil resources have good exploration prospects. Whereas the lack of recognition of hydrocarbon generation and expulsion characteristics of Permian P1f source rocks results in the misunderstanding of tight oil resource potential. Based on the comprehensive analysis of geological and geochemical characteristics of wells, seismic inversion, sedimentary facies, tectonic burial depth, etc., the characteristics of P1f source rocks were investigated, and the horizontal distributions of the following aspects were predicted: the thickness of source rocks, abundance and type of organic matter. And on this basis, an improved hydrocarbon generation potential methodology together with basin simulation techniques was applied to unravel the petroleum generation and expulsion characteristics of P1f source rocks in FA. Results show that the P1f source rocks distribute widely (up to 2039 km2), are thick (up to 260 m), have high total organic content (TOC, ranging from 0.15 to 4 wt%), are dominated by type II kerogen and have entered into low mature–mature stage. The modeling results indicate that the source rocks reached hydrocarbon generation threshold and hydrocarbon expulsion threshold at 0.5% Ro and 0.85% Ro and the comprehensive hydrocarbon expulsion efficiency was about 46%. The amount of generation and expulsion from the P1f source rocks was 31.85 × 108 and 15.31 × 108 t, respectively, with a residual amount of 16.54 × 108 t within the source rocks. Volumetrically, the geological resource of shale oil is up to 15.65 × 108 t. Small differences between the amounts calculated by the volumetric method compared with that by hydrocarbon generation potential methodology may be due to other oil accumulations present within interbedded sands associated with the oil shales. Copyright © 2015 John Wiley & Sons, Ltd.  相似文献   

16.
Multidisciplinary analysis of the carbonaceous sediments of Warkalli Formation (Mio-Pliocene) from the Warkalli cliff section has been done to assess the source of organic matter, palaeodepositional settings and the hydrocarbon potential. The n-alkane distribution from n-C12 to n-C33 along with bimodal distribution indicates significant organic matter contribution from microbial activity and higher plants. The contribution from angiosperm source vegetation is indicated by the oleanane type of triterpenoids. The hopanes distribution indicates the immature stage of the organic matter, which is in agreement with the Tmax (av. 401 °C) and huminite reflectance (av. 0.28% Rr) values. The total organic carbon (TOC) contents vary between 0.8 and 6.72 wt. % in the studied sediments. Hydrogen index and oxygen index values range from 16 to106 mg HC/g TOC, and 113 to 344 mg CO2/g TOC, respectively. The maceral content is low, being dominated by the detrohuminite submaceral and the mineral matter accounts for 68 to 77% of the total composition. The phytoclast group (63–87%) is dominant with subordinate amorphous organic matter (4–35%). The study shows that the sediments were deposited in a marginal suboxic basin with intermittent variations. All the parameters unequivocally suggest that the studied sequence holds the potential to generate gaseous hydrocarbons.  相似文献   

17.
Hydrous pyrolysis (HP) experiments were used to investigate the petroleum composition and quality of petroleum generated from a Brazilian lacustrine source rock containing Type I kerogen with increasing thermal maturity. The tested sample was of Aptian age from the Araripe Basin (NE-Brazil). The temperatures (280–360 °C) and times (12–132 h) employed in the experiments simulated petroleum generation and expulsion (i.e., oil window) prior to secondary gas generation from the cracking of oil. Results show that similar to other oil prone source rocks, kerogen initially decomposes in part to a polar rich bitumen, which decomposes in part to hydrocarbon rich oil. These two overall reactions overlap with one another and have been recognized in oil shale retorting and natural petroleum generation. During bitumen decomposition to oil, some of the bitumen is converted to pyrobitumen, which results in an increase in the apparent kerogen (i.e., insoluble carbon) content with increasing maturation.The petroleum composition and its quality (i.e., API gravity, gas/oil ratio, C15+ fractions, alkane distribution, and sulfur content) are affected by thermal maturation within the oil window. API gravity, C15+ fractions and gas/oil ratios generated by HP are similar to those of natural petroleum considered to be sourced from similar Brazilian lacustrine source rocks with Type I kerogen of Lower Cretaceous age. API gravity of the HP expelled oils shows a complex relationship with increasing thermal maturation that is most influenced by the expulsion of asphaltenes. C15+ fractions (i.e., saturates, aromatics, resins and asphaltenes) show that expelled oils and bitumen are compositionally separate organic phases with no overlap in composition. Gas/oil ratios (GOR) initially decrease from 508–131 m3/m3 during bitumen generation and remain essentially constant (81–84 m3/m3) to the end of oil generation. This constancy in GOR is different from the continuous increase through the oil window observed in anhydrous pyrolysis experiments. Alkane distributions of the HP expelled oils are similar to those of natural crude oils considered to be sourced from similar Brazilian lacustrine source rocks with Type I kerogen of Lower Cretaceous age. Isoprenoid and n-alkane ratios (i.e., pristane/n-C17 and phytane/n-C18) decrease with increasing thermal maturity as observed in natural crude oils. Pristane/phytane ratios remain constant with increasing thermal maturity through the oil window, with ratios being slightly higher in the expelled oils relative to those in the bitumen. Generated hydrocarbon gases are similar to natural gases associated with crude oils considered to be sourced from similar Brazilian lacustrine source rocks with Type I kerogen of Lower Cretaceous, with the exception of elevated ethane contents. The general overall agreement in composition of natural and hydrous pyrolysis petroleum of lacustrine source rocks observed in this study supports the utility of HP to better characterize petroleum systems and the effects of maturation and expulsion on petroleum composition and quality.  相似文献   

18.
Shales of very low metamorphic grade from the 2.78 to 2.45 billion-year-old (Ga) Mount Bruce Supergroup, Pilbara Craton, Western Australia, were analyzed for solvent extractable hydrocarbons. Samples were collected from ten drill cores and two mines in a sampling area centered in the Hamersley Basin near Wittenoom and ranging 200 km to the southeast, 100 km to the southwest and 70 km to the northwest. Almost all analyzed kerogenous sedimentary rocks yielded solvent extractable organic matter. Concentrations of total saturated hydrocarbons were commonly in the range of 1 to 20 ppm (μg/g rock) but reached maximum values of 1000 ppm. The abundance of aromatic hydrocarbons was ∼1 to 30 ppm. Analysis of the extracts by gas chromatography-mass spectrometry (GC-MS) and GC-MS metastable reaction monitoring (MRM) revealed the presence of n-alkanes, mid- and end-branched monomethylalkanes, ω-cyclohexylalkanes, acyclic isoprenoids, diamondoids, tri- to pentacyclic terpanes, steranes, aromatic steroids and polyaromatic hydrocarbons. Neither plant biomarkers nor hydrocarbon distributions indicative of Phanerozoic contamination were detected. The host kerogens of the hydrocarbons were depleted in 13C by 2 to 21‰ relative to n-alkanes, a pattern typical of, although more extreme than, other Precambrian samples. Acyclic isoprenoids showed carbon isotopic depletion relative to n-alkanes and concentrations of 2α-methylhopanes were relatively high, features rarely observed in the Phanerozoic but characteristic of many other Precambrian bitumens. Molecular parameters, including sterane and hopane ratios at their apparent thermal maxima, condensate-like alkane profiles, high mono- and triaromatic steroid maturity parameters, high methyladamantane and methyldiamantane indices and high methylphenanthrene maturity ratios, indicate thermal maturities in the wet-gas generation zone. Additionally, extracts from shales associated with iron ore deposits at Tom Price and Newman have unusual polyaromatic hydrocarbon patterns indicative of pyrolytic dealkylation.The saturated hydrocarbons and biomarkers in bitumens from the Fortescue and Hamersley Groups are characterized as ‘probably syngenetic with their Archean host rock’ based on their typical Precambrian molecular and isotopic composition, extreme maturities that appear consistent with the thermal history of the host sediments, the absence of biomarkers diagnostic of Phanerozoic age, the absence of younger petroleum source rocks in the basin and the wide geographic distribution of the samples. Aromatic hydrocarbons detected in shales associated with iron ore deposits at Mt Tom Price and Mt Whaleback are characterized as ‘clearly Archean’ based on their hypermature composition and covalent bonding to kerogen.  相似文献   

19.
Based on thermal simulation experiment, interactions between volcanic fluids and source rocks were studied. Gas generations in the dry system and fluid system under different temperatures were analyzed. The results showed that the various types of source rocks are similar in composition, containing gaseous C1-C5 hydrocarbons, H2 and CO2 whose gas yields increase with increasing temperature. The gas yield of source rocks of type I is the high- est, followed by type II, and that of source rocks of type III is the lowest, indicating that the yield of hydrocarbon gases is related to their hydrocarbon generating potential. Although the generating potential of type III is the lowest, it can still be regarded as a useful gas source when it is buried deeply enough. The basic volcanic fluid restrains the generation of gaseous hydrocarbons in different types of source rocks, but promotes the generation of inorganic gases.  相似文献   

20.
The exploration conducted in the Bohai Bay basin, eastern China has demonstrated that the abundant petroleum resources have close affinities to the hydrocarbon kitchen with rich organic matter. A number of oil-generating associations with various characteristics of organic geochemistry and assemblages of multiple reservoir facies are developed due to the multi-center sedimentation, multi-source supply and multi-cycle evolution of filling, which have resulted in the formation of multiple oil and gas accumulation zones of various layers and trap styles. Among them the Paleogene Shahejie Formation is the most important hydrocarbon accumulation combination in the Dongying sag. Heretofore, its proved reserve has reached nearly 1.8×109t, which accounts for more than 90% of the total proved reserves of the Dongying sag. Based on previous studies, more than 600 source rock samples and 186 crude oil samples of the Shahejie Formation, collected from 30 oilfields, have been treated with organic geochemical testing  相似文献   

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