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1.
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   

2.
The Pearl River Mouth Basin in the South China Sea has accumulated >2 km of Eocene sediments in its deep basin, and has become the exploration focus due to the recent discoveries of the HZ25-7 oil field in the Eocene Wenchang (E2w) Formation. In this study, the geochemical characteristics of potential source rocks and petroleum in the HZ25-7 oil field are investigated and the possible origins and accumulation models developed. The analytical results reveal two sets of potential source rocks, E2w and Enping (E2e) formations developed in the study area. The semi-deep-to-deep lacustrine E2w source rocks are characterized by relatively low C29 steranes, low C19/C23 tricyclic terpane (<0.6), low C24 tetracyclic terpane/C30 hopane (<0.1), low trans-trans-trans-bicadinane (T)/C30 hopane (most <2.0), and high C30 4-methyl sterane/ΣC29 sterane (>0.2) ratios. In contrast, the shallow lacustrine and deltaic swamp-plain E2e source rocks are characterized by relatively high C29 steranes, high C19/C23 tricyclic terpane (>0.6), high C24 tetracyclic terpane/C30 hopane (>0.1), variable yet overall high T/C30 hopane, and low C30 4-methyl sterane/ΣC29 sterane (<0.2) ratios. The relatively low C19/C23 tricyclic terpane ratios (mean value: 0.39), low C24 tetracyclic terpane/C30 hopane ratios (mean value: 0.07), high C30 4-methyl sterane/ΣC29 sterane ratios (mean value: 1.14), and relatively high C27 regular sterane content of petroleum in the HZ25-7 oil field indicate that the petroleum most likely originated from the E2w Formation mudstone in the Huizhou Depression. One stage of continuous charging is identified in the HZ25-7 oil field; oil injection is from 16 Ma to present and peak filling occurs after 12 Ma. Thin sandstone beds with relatively good connectivity and physical properties (porosity and permeability) in the E2w Formation are favorable conduits for the lateral migration of petroleum. This petroleum accumulation pattern implies that the E2w Formation on the western and southern margins of the Huizhou Depression are favorable for petroleum accumulation because they are located in a migration pathway. Thus exploration should focus in these areas in the future.  相似文献   

3.
Oil samples from Lower Cretaceous to Eocene reservoirs in southwest Iran were analyzed using gas chromatography–mass spectrometry and gas chromatography–isotope ratio mass spectrometry for genetic classification of oil families and determining their maturity. The Studied oil samples are non-biodegraded and their gravity range from 18.3 to 37° API. The slight even/odd n-alkane predominance, coupled with low Pr/Ph values, suggests their likely source rocks with a predominance of algal organic matter, type IIS kerogen deposited under strongly reducing marine environments. The biomarker distribution of investigated oils is characterized by high concentration of both C29 and C30 hopanes and ratios of C29/C30H are generally greater than unity. There is a marked predominance of C29 regular sterane over C27 and C28 homologs in our studied oils. High sterane/hopane values and cross plot of the δ13C sat versus δ13C aro show contribution of marine organic matter. Medium value of gammacerane index and other salinity indices show water density stratification and high salinity conditions of the environment of deposition. It can be concluded that the studied reservoirs, due to their variable maturity have different API gravity and contain two oil families (types A and B) with latter being deeper and comprising more mature oils.  相似文献   

4.
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   

5.
The Akyaka section in the central Taurus region in the southern part of Turkey includes the organic matter and graptolite-rich black shales which were deposited under dysoxic to anoxic marine conditions in the Early Silurian. A biostratigraphical analysis, based on graptolite assemblages, indicates that the sediments studied may well be referable to the querichi Biozone and early Telychian, Llandovery. A total of 15 samples have been subjected to Leco and Rock-Eval pyrolysis and graptolite reflectance measurements for determination of their source rock characteristics and thermal maturity. The total organic carbon content of the graptolite-bearing shales varies from 1.75 to 3.52 wt% with an average value of 2.86 wt%. The present Rock-Eval pyrolytic yields and calculated values of hydrogen and oxygen indexes imply that the recent organic matter type is inert kerogen. The measured maximum graptolite reflectance (GRmax %) values are between 5.04% and 6.75% corresponding to thermally over maturity. This high maturity suggests a deep burial of the Lower Silurian sediments resulting from overburden rocks of Upper Paleozoic to Mesozoic Upper Cretaceous and Middle-Upper Eocene thrusts occurred in the region.  相似文献   

6.
This work presents new insights of the generation, quality and migration pathways of the hydrocarbons in the East Baghdad Oil Field.The Khasib and Tannuma formations in East Baghdad are considered as oil reservoirs according to their high porosity (15-23%) and permeability (20-45 mD) in carbonate rocks. The hydrocarbons are trapped by structural anticline closure trending NW-SE. Gas chromatography analysis on these oil reservoirshave shown biomarkers of abundant ranges of n-alkanes of less than C22 (C17-C21) with C19 and C18 peaks. This suggests mainly liquid oil constituents of paraffinic hydrocarbons from marine algal source of restricted palaeoenvironments in the reservoir. The low non aromatic C15 + peaks are indicative for slight degradation and water washing. Oil biomarkers of Pr./Ph. = 0.85, C31/C30 < 1.0, location in triangle of C27-C29 sterane, C28/C29 of 0.6 sterane, Oleanane of 0.01 and CPI = 1.0, indicate an anoxic marine environment with carbonate deposits of Upper Jurassic to Early Cretaceous age. Four Miospores, seven Dinoflagellates and one Tasmanite species confirm affinity to the upper most Jurassic to Lower Cretaceous Chia Gara and Ratawi Formations.The recorded palynomorphs from the Khasib and Tannuma Formations are of light brown color of TAI = 2.8-3.0 and comparable to the mature palynomorphs that belong to the Chia Gara and the Lower part of Ratawi Formations.The Chia Gara Formation generated oil during Upper Cretaceous to Early Palaeogene and accumulated in structural traps of Cretaceous age, such as the Khasib and Tannuma reservoirs. The Chia Gara Formation generated and expelled high quantities of oil hydrocarbons according to their TOC wt% of 0.5-8.5 with S2 = 2.5-18.5 mg Hc/g Rock, high hydrogen index of the range 150-450 mg Hc/g Rock, good petroleum potential of 4.5-23.5 mg Hc/g Rock, mature (TAI = 2.8-3.0 and Tmax = 428-443C), kerogen type II and palynofacies parameters of up to 100% AOM (Amorphous Organic Matters). This includes algae deposits in a dysoxic-anoxic to suboxic-anoxic environment.Alternative plays are discussed according to the migration pathways.  相似文献   

7.
Structured organic matters of the Palynomorphs of mainly dinoflagellate cysts are used in this study for dating the limestone, black shale, and marl of the Middle Jurassic (Bajocian–Bathonian) Sargelu Formation, Upper Jurassic (Upper Callovian – Lower Oxfordian) Naokelekan Formation, Upper Jurassic (Kimeridgian and Oxfordian) Gotnia and Barsarine Formations, and Upper Jurassic – Lower Cretaceous (Tithonian-Beriassian) Chia Gara source rock Formations while spore species of Cyathidites australis and Glechenidites senonicus are used for maturation assessments of this succession. Materials' used for this palynological study are 320 core and cutting samples of twelve oil wells and three outcrops in North Iraq.Terpane and sterane biomarker distributions, as well as stable isotope values, were determined for oils potential source rock extracts of Jurassic-Lower Cretaceous strata to determine valid oil-to-source rock correlations in North Iraq. Two subfamily carbonate oil types-one of Middle Jurassic age (Sargelu) carbonate rock and the other of mixed Upper Jurassic/Cretaceous age (Chia Gara) with Sargelu sources as well as a different oil family related to Triassic marls, were identified based on multivariate statistical analysis (HCA & PCA). Middle Jurassic subfamily A oils from Demir Dagh oil field correlate well with rich, marginally mature, Sargelu source rocks in well Mk-2 near the city of Baiji. In contrast, subfamily B oils have a greater proportion of C28/C29 steranes, indicating they were generated from Upper Jurassic/Lower Cretaceous carbonates such as those at Gillabat oil field north of Mansuriyah Lake. Oils from Gillabat field thus indicate a lower degree of correlation with the Sargelu source rocks than do oils from Demir Dagh field.Palynofacies assessments are performed for this studied succession by ternary kerogen plots of the phytoclast, amorphous organic matters, and palynomorphs. From the diagram of these plots and maturation analysis, it could be assessed that the formations of Chia Gara and Sargelu are both deposited in distal suboxic to anoxic basin and can be correlated with kerogens classified microscopically as Type A and Type B and chemically as Type II. The organic matter, comprised principally of brazinophyte algae, dinoflagellate cysts, spores, pollen, foraminifera test linings, and phytoclasts in all these formations and hence affected with upwelling current. These deposit contain up to 18 wt% total organic matters that are capable to generate hydrocarbons within mature stage of thermal alteration index (TAI) range in Stalplin's scale (Staplin, 1969) of 2.7–3.0 for the Chia Gara Formation and 2.9–3.1 for the Sargelu Formation. Case study examples of these oil prone strata are; one 7-m (23-ft) thick section of the Sargelu Formation averages 44.2 mg HC/g S2 and 439 °C Tmax (Rock-Eval pyrolysis analyses) and 16 wt% TOC especially in well Mk-2 whereas, one 8-m (26-ft) thick section of the Chia Gara and 1-m (3-ft) section of Naokelekan Formations average 44.5 mg HC/g S2 and 440 °C Tmax and 14 wt% TOC especially in well Aj-8. One-dimension, petroleum system models of key wells using IES PetroMod Software can confirm their oil generation capability.These hydrocarbon type accumulation sites are illustrated in structural cross sections and maps in North Iraq.  相似文献   

8.
This study aims at investigating hydrocarbon generation potential and biological organic source for the Tertiary coal-bearing source rocks of Pinghu Formation (middle-upper Eocene) in Xihu depression, East China Sea shelf basin. Another goal is to differentiate coal and mudstone with respect to their geochemical properties. The coal-bearing sequence has a variable organofacies and is mainly gas-prone. The coals and carbonaceous mudstones, in comparison with mudstones, have a higher liquid hydrocarbon generation potential, as reflected by evidently higher HI values (averaging 286 mg HC/g C) and H/C atomic ratios (round 0.9). The molecular composition in the coal-bearing sequence is commonly characterized by unusually abundant diterpenoid alkanes, dominant C29 sterane over C27 and C28 homologues and high amount of terrigenous-related aromatic biomarkers such as retene, cadalene and 1, 7-dimethylphenanthrene, indicating a predominantly terrigenous organic source. The source rocks show high Pr/Ph ratios ranging mostly from 3.5 to 8.5 and low MDBTs/MDBFs ratios (<1.0), indicating deposition in an oxic swamp-lacustrine environment. The coals and carbonaceous mudstones could be differentiated from the grey mudstones by facies-dependent biomarker parameters such as relative sterane concentration and gammacerane index and carbon isotope composition. Isotope and biomarker analysis indicate the genetic correlation between the Pinghu source rocks and the oils found in Xihu depression. Moreover, most oils seem to be derived from the coal as well as carbonaceous mudstone.  相似文献   

9.
The molecular composition, stable carbon and hydrogen isotopes and light hydrocarbons of the Upper Paleozoic tight gas in the Daniudi gas field in the Ordos Basin were investigated to study the geochemical characteristics. Tight gas in the Daniudi gas field displays a dryness coefficient (C1/C1–5) of 0.845–0.977 with generally positive carbon and hydrogen isotopic series, and the C7 and C5–7 light hydrocarbons of tight gas are dominated by methylcyclohexane and iso-alkanes, respectively. The identification of gas origin and gas-source correlation indicate that tight gas is coal-type gas, and the gases reservoired in the Lower Permian Shanxi Fm. (P1s) and Lower Shihezi Fm. (P1x) had a good affinity and were derived from the P1s coal-measure source rocks, whereas the gas reservoired in the Upper Carboniferous Taiyuan Fm. (C3t) was derived from the C3t coal-measure source rocks. The molecular and methane carbon isotopic fractionations of natural gas support that the P1x gas was derived from the P1s source rocks. The differences of geochemical characteristics of the C3t gas from different areas in the field suggest the effect of maturity difference of the source rocks rather than the diffusive migration, and the large-scale lateral migration of the C3t gas seems unlikely. Comparative study indicates that the differences of the geochemical characteristics of the P1s gases from the Yulin and Daniudi gas fields originated likely from the maturity difference of the in-situ source rocks, rather than the effect of large-scale lateral migration of the P1s gases.  相似文献   

10.
Thirty-six Silurian core and cuttings samples and 10 crude oil samples from Ordovician reservoirs in the NC115 Concession, Murzuq Basin, southwest Libya were studied by organic geochemical methods to determine source rock organic facies, conditions of deposition, thermal maturity and genetic relationships. The Lower Silurian Hot Shale at the base of the Tanezzuft Formation is a high-quality oil/gas-prone source rock that is currently within the early oil maturity window. The overall average TOC content of the Hot Shale is 7.2 wt% with a maximum recorded value of 20.9 wt%. By contrast, the overlying deposits of the Tanezzuft Formation have an average TOC of 0.6 wt% and a maximum value of 1.1 wt%. The organic matter in the Hot Shale consists predominantly of mixed algal and terrigenous Type-II/III kerogen, whereas the rest of the formation is dominated by terrigenous Type-III organic matter with some Type II/III kerogen. Oils from the A-, B- and H-oil fields in the NC115 Concession were almost certainly derived from marine shale source rocks that contained mixed algal and terrigenous organic input reflecting deposition under suboxic to anoxic conditions. The oils are light and sweet, and despite being similar, were almost certainly derived from different facies and maturation levels within mature source rocks. The B-oils were generated from slightly less mature source rocks than the others. Based on hierarchical cluster analysis (HCA), principal component analysis (PCA), selected source-related biomarkers and stable carbon isotope ratios, the NC115 oils can be divided into two genetic families: Family-I oils from Ordovician Mamuniyat reservoirs were probably derived from older Palaeozoic source rocks, whereas Family-II oils from Ordovician Mamuniyat–Hawaz reservoirs were probably charged from a younger Palaeozoic source of relatively high maturity. A third family appears to be a mixture of the two, but is most similar to Family-II oils. These oil families were derived from one proven mature source rock, the Early Silurian, Rhuddanian Hot Shale. There is a good correlation between the Family-II and -III oils and the Hot Shale based on carbon isotope compositions. Saturated and aromatic maturity parameters indicate that these oils were generated from a source rock of considerably higher maturity than the examined rock samples. The results imply that the oils originated from more mature source rocks outside the NC115 Concession and migrated to their current positions after generation.  相似文献   

11.
Natural gas samples from two gas fields located in Eastern Kopeh-Dagh area were analyzed for molecular and stable isotope compositions. The gaseous hydrocarbons in both Lower Cretaceous clastic reservoir and Upper Jurassic carbonate reservoir are coal-type gases mainly derived from type III kerogen, however enriched δD values of methane implies presence of type II kerogen related material in the source rock. In comparison Upper Jurassic carbonate reservoir gases show higher dryness coefficient resulted through TSR, while presence of C1C5 gases in Lower Cretaceous clastic reservoir exhibit no TSR phenomenon. Carbon isotopic values indicate gas to gas cracking and TSR occurrence in the Upper Jurassic carbonate reservoir, as the result of elevated temperature experienced, prior to the following uplifts in last 33–37 million years. The δ13C of carbon dioxide and δ34S of hydrogen sulfide in Upper Jurassic carbonate reservoir do not primarily reflect TSR, as uplift related carbonate rock dissolution by acidic gases and reaction/precipitation of light H2S have changed these values severely. Gaseous hydrocarbons in both reservoirs exhibit enrichment in C2 gas member, with the carbonate reservoir having higher values resulted through mixing with highly-mature-completely-reversed shale gases. It is likely that the uplifts have lifted off the pressure on shale gases, therefore facilitated the migration of the gases into overlying horizons. However it appears that the released gases during the first major uplift (33–37 million years ago) have migrated to both reservoirs, while the second migrated gases have only mixed with Upper Jurassic carbonate reservoir gases. The studied data suggesting that economic accumulations of natural gas/shale gases deeper than Upper Jurassic carbonate reservoir would be unlikely.  相似文献   

12.
The objectives of our study were to assess the thickness, lateral extent, organic richness and maturity of the potential source rocks in Hungary and to estimate the volumes of hydrocarbons generated, in order that potential shale gas and shale oil plays could be identified and characterised.The Upper Triassic Kössen Marl in south-west Hungary could represent the best potential shale gas/shale oil play, due to its high organic richness, high maturity and the presence of fracture barriers. The area of gas- and oil-generative maturity is around 720 km2 with the unexpelled petroleum estimated to be up to 9 billion barrel oil-equivalent.The Lower Jurassic sediments of the Mecsek Mountains and under the Great Plain contain fair quality gas-prone source rocks, with low shale gas potential, except for a thin Toarcian shale unit which is richer in organic matter. The latter could form a potential shale gas play under the Great Hungarian Plain, if it is thicker locally.The Lower Oligocene Tard Clay in north-east Hungary could represent the second best potential shale oil play, due to its organic richness, favourable maturity and large areal extent (4500 km2) with around 7 billion barrel oil-equivalent estimated in-place volume of petroleum.Middle Miocene marine formations could represent locally-developed shale gas plays; they have fair amounts of organic matter and a mixture of type II/III kerogen, but their vertical and lateral variability is high.The Upper Miocene lacustrine Endrőd Marl contains less organic matter and the kerogen is mainly type III, which is not favourable for shale gas generation. The high carbonate and clay content, plus the lack of upper and lower fracture barriers would represent additional production challenges.  相似文献   

13.
This study investigates the source rock characteristics of Permian shales from the Jharia sub-basin of Damodar Valley in Eastern India. Borehole shales from the Raniganj, Barren Measure and Barakar Formations were subjected to bulk and quantitative pyrolysis, carbon isotope measurements, mineral identification and organic petrography. The results obtained were used to predict the abundance, source and maturity of kerogen, along with kinetic parameters for its thermal breakdown into simpler hydrocarbons.The shales are characterized by a high TOC (>3.4%), mature to post-mature, heterogeneous Type II–III kerogen. Raniganj and Barren Measure shales are in mature, late oil generation stage (Rr%Raniganj = 0.99–1.22; Rr%Barren Measure = 1.1–1.41). Vitrinite is the dominant maceral in these shales. Barakar shows a post-mature kerogen in gas generation stage (Rr%Barakar = 1.11–2.0) and consist mainly of inertinite and vitrinite. The δ13Corg value of kerogen concentrate from Barren Measure shale indicates a lacustrine/marine origin (−24.6–−30.84‰ vs. VPDB) and that of Raniganj and Barakar (−22.72–−25.03‰ vs. VPDB) show the organic provenance to be continental. The δ13C ratio of thermo-labile hydrocarbons (C1–C3) in Barren Measure suggests a thermogenic source.Discrete bulk kinetic parameters indicate that Raniganj has lower activation energies (ΔE = 42–62 kcal/mol) compared to Barren Measure and Barakar (ΔE = 44–68 kcal/mol). Temperature for onset (10%), middle (50%) and end (90%) of kerogen transformation is least for Raniganj, followed by Barren Measure and Barakar. Mineral content is dominated by quartz (42–63%), siderite (9–15%) and clay (14–29%). Permian shales, in particular the Barren Measure, as inferred from the results of our study, demonstrate excellent properties of a potential shale gas system.  相似文献   

14.
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.
Crude oil samples from Cretaceous and Tertiary reservoir sections in the Zagros Fold Belt oil fields, southern Iraq were investigated using non-biomarker and biomarker parameters. The results of this study have been used to assess source of organic matter, and the genetic link between oils and their potential source rocks in the basin. The oils are characterized by high sulphur and trace metal (Ni, V) contents and relatively low API gravity values (17.4–22.7° API). This indicates that these oils are heavy and generated from a marine source rock containing Type II-S kerogen. This is supported by their biomarker distributions of normal alkanes, regular isoprenoids, terpanes and steranes and the bulk carbon isotope compositions of their saturated and aromatic hydrocarbons. The oils are characterized by low Pr/Ph ratios (<1), high values of the C35 homohopane index and C31-22R/C30 hopane ratios, relatively high C27 sterane concentrations, and the predominance of C29-norhopane. These biomarkers suggest that the oils were generated predominantly from a marine carbonate source rock, deposited under reducing conditions and containing plankton/algal and microorganisms source input. The presence of gammacerane also suggests water column stratification during source rock deposition.The biomarker characteristics of the oils are consistent with those of the Middle Jurassic Sargelu carbonate as the effective source rock in the basin. Biomarker maturity data indicate that the oils were generated from early maturity source rocks.  相似文献   

16.
Identification of the main hydrocarbon source rocks of the large Puguang gas field (northeastern Sichuan Basin, southwest China) has been the subject of much discussion in recent years. A key aspect has been the lack of a comprehensive understanding of the development of hydrocarbon source rocks of the Upper Permian Longtan Formation, which had been thought to contain mainly coal seams and thick carbonate layers. In this paper, based on geological data from more than ten wells and outcrops and their related mineralogy and geochemistry, we investigated the depositional environment and main factors controlling organic matter enrichment in the Longtan Formation. We propose a model which combines information on the geological environment and biological changes over time. In the model, organic matter from prolific phytoplankton blooms was deposited in quiescent platform interior sags with rising sea-levels. During the Longtan period, the area from Bazhong to Dazhou was a platform interior sag with relatively deep water and a closed environment, which was controlled by multiple factors including syngenetic fault settling, isolation of submarine uplifts and rising sea-levels leading to water column stratification. Although the bottom water was anoxic, the phytoplankton were able to bloom in the well-lit upper euphotic zone thus giving rise to a set of sapropelic black shales and marlstones containing mostly algal organic matter with minor terrestrial contributions. As a consequence, these rocks have a high hydrocarbon generation potentials and can be classified as high-quality source rocks. The area from Bazhong to Dazhou is a center of hydrocarbon generation, being the main source of reservoired paleo-oils and presently discovered as pyrobitumen in the Puguang gas field. The identification of these source rocks is very important to guide future petroleum exploration in the northeastern Sichuan Basin.  相似文献   

17.
The origin of the fourteen major oil fields in the Bozhong sub-basin, Bohai Bay basin was studied based on the results of Rock-Eval pyrolysis on more than 700 samples and biomarker analysis on 61 source rock samples and 87 oil samples. The three possible source rock intervals have different biomarker assemblages and were deposited in different environments. The third member of the Oligocene Dongying Formation (E3d3, 32.8–30.3 Ma in age) is characterized mainly by high C19/C23 tricyclic terpane (>0.75), high C24 tetracyclic terpane/C26 tricyclic terpane (>2.5), low gammacerane/αβ C30 hopane (<0.15) and low 4-methyl steranes/ΣC29 steranes (<0.15) ratios, and was deposited in sub-oxic to anoxic environments with significant terrigenous organic matter input. The first (E2s1, 35.8–32.8 Ma) and third (E2s3, 43.0–38.0 Ma) members of the Eocene Shahejie Formation have low C19/C23 tricyclic terpane and low C24 tetracyclic terpane/C26 tricyclic terpane ratios and were deposited in anoxic environments with minor terrestrial organic matter input, but have different abundances of 4-methyl steranes and gammacerane. The hydrocarbon-generating potential and biomarker associations of these three source rock intervals were controlled by tectonic evolution of the sub-basin and climate changes. Three oil families derived from E2s3, E2s1 and E3d, respectively, and three types of mixed oils have been identified. All large oil fields in the Bozhong sub-basin display considerable heterogeneities in biomarker compositions and originated from more than one source rock interval, which suggests that mixing of oils derived from multiple source rock intervals or multiple generative kitchens, and/or focusing of oils originated from a large area of a generative kitchen, is essential for the formation of large oil fields in the Bozhong sub-basin. E2s3- and E2s1-derived oils experienced relatively long-distance lateral migration and accumulated in traps away from the generative kitchen. E3d3-derived oils had migrated short distances and accumulated in traps closer to the generative kitchen. Such a petroleum distribution pattern has important implications for future exploration. There is considerable exploration potential for Dongying-derived oils in the Bozhong sub-basin, and traps close to or within the generative kitchens have better chance to contain oils generated from the Dongying Formation.  相似文献   

18.
Sixty crude oils from the Termit Basin (Eastern Niger) were analysed using biomarker distributions and bulk stable carbon isotopic compositions. Comprehensive oil-to-oil correlation indicates that there are two distinct families in the Termit Basin. The majority of the oils are geochemically similar and characterized by low Pr/Ph (pristane to phytane ratios) and high gammacerane/C30 hopane ratios, small amounts of C24 tetracyclic terpanes but abundant C23 tricyclic terpane, and lower δ13C values for saturated and aromatic hydrocarbon fractions. All of these geochemical characteristics indicate possible marine sources with saline and reducing depositional environments. In contrast, oils from well DD-1 have different geochemical features. They are characterized by relatively higher Pr/Ph and lower gammacerane/C30 hopane ratios, higher amounts of C24 tetracyclic terpane but a low content of C23 tricyclic terpane, and relatively higher δ13C values for saturated and aromatic hydrocarbon fractions. These geochemical signatures indicate possible lacustrine sources deposited under freshwater, suboxic-oxic conditions. This oil family also has a unique biomarker signature in that there are large amounts of C30 4α-methylsteranes indicating a freshwater lacustrine depositional environment.The maturity of the Termit oils is assessed using a number of maturity indicators based on biomarkers, alkyl naphthalenes, alkyl phenanthrenes and alkyl dibenzothiophenes. All parameters indicate that all of the oils are generated by source rocks within the main phase of the oil generation stage with equivalent vitrinite reflectance of 0.58%–0.87%.  相似文献   

19.
Intense thermochemical sulfate reduction (TSR) and up to 18% H2S are found in the Upper Permian Changxing Formation (P3ch) in the northeast (NE) Sichuan Basin, China, despite that rare gypsum or anhydrite was found in this formation. Here, we present new concentration data of carbonate-associated sulfate (CAS) from carbonate host rocks, C, O, and Sr isotope data for TSR-related calcites, and S isotope data for sulfur compounds obtained during this study. These data along with spatial-temporal changes in palaeogeopressure conditions, hydraulic conductivity and the physical capacity indicate that the H2S was generated locally from TSR within the P3ch reservoirs. We propose that the reactive sulfates were derived from CAS released during dolomitization and recrystallization of earlier dolomite within the P3ch Fm. and from the cross-formational migration of evaporative brines from the Lower Triassic Feixianguan Formation (T1f) to P3ch Fm. Our calculation shows that the two sources could provide enough SO42− for the generation of H2S within the P3ch reservoirs. Early downward migration of sulfate-rich evaporative brines from the T1f formation occurred in near-surface and shallow burial diagenetic settings (mainly <1000 m). The evaporative brines seeped into porous grainstones and displaced preexisting seawater, causing pervasive dolomitization within the P3ch Fm. Subsequently, TSR calcites precipitated from the pore water have high Sr concentrations (up to 7767 ppm), close to the T1f TSR calcites, and 87Sr/86Sr ratios mainly from 0.7074 to 0.7078, which are significantly higher than those of Late Permian seawater but within the range of early Triassic seawater.  相似文献   

20.
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   

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