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1.
解龙 《地质与勘探》2016,52(4):774-782
本文在南羌塘盆地土门地区获得一套上三叠统土门格拉组泥质烃源岩。通过有机质丰度、有机质类型和有机质热演化程度的分析,结果表明,土门格拉组泥质烃源岩有机碳含量在0.54%~1.36%之间,达到了中等-好烃源岩标准,局部达到很好烃源岩标准;干酪根镜检结果显示,有机质类型主要为II1型。镜质体反射率Ro为1.61%~2.76%,岩石热解峰温Tmax介于340~544℃之间,干酪根腐泥组颜色为棕色-棕褐色,表明有机质演化达到过成熟阶段。土门地区土门格拉组泥质烃源岩的发现进一步表明羌塘盆地上三叠统烃源岩具备良好的生烃(气)潜力。  相似文献   

2.
1D petroleum system modeling was performed on wells in each of four oil fields in South Iraq, Zubair (well Zb-47), Nahr Umr (well NR-9), West Qurna (well WQ-15 and 23), and Majnoon (well Mj-8). In each of these fields, deposition of the Zubair Formation was followed by continuous burial, reaching maximum temperatures of 100°C (equivalent to 0.70%Ro) at depths of 3,344–3,750 m of well Zb-47 and 3,081.5–3,420 m of well WQ-15, 120°C (equivalent to 0.78%Ro) at depths of 3,353–3,645 m of well NR-9, and 3,391–3,691.5 m of well Mj-8. Generation of petroleum in the Zubair Formation began in the late Tertiary, 10 million years ago. At present day, modeled transformation ratios (TR) indicate that 65% TR of its generation potential has been reached in well Zb-47, 75% TR in well NR-9 and 55-85% TR in West Qurna oil field (wells WQ-15 and WQ-23) and up to 95% TR in well Mj-8, In contrast, younger source rocks are immature to early mature (<20% TR), whereas older source rocks are mature to overmature (100% TR). Comparison of these basin modeling results, in Basrah region, are performed with Kifle oil field in Hilla region of western Euphrates River whereas the Zubair Formation is immature within temperature range of 65–70°C (0.50%Ro equivalent) with up to 12% (TR?=?12%) hydrocarbon generation efficiency and hence poor generation could be assessed in this last location. The Zubair Formation was deposited in a deltaic environment and consists of interbedded shales and porous and permeable sandstones. In Basrah region, the shales have total organic carbon of 0.5–7.0 wt%, Tmax 430–470°C and hydrogen indices of up to 466 with S2?=?0.4–9.4 of kerogen type II & III and petroleum potential of 0.4–9.98 of good hydrocarbon generation, which is consistent with 55–95% hydrocarbon efficiency. These generated hydrocarbons had charged (in part) the Cretaceous and Tertiary reservoirs, especially the Zubair Formation itself, in the traps formed by Alpine collision that closed the Tethys Ocean between Arabian and Euracian Plates and developed folds in Mesopotamian Basin 15–10 million years ago. These traps are mainly stratigraphic facies of sandstones with the shale that formed during the deposition of the Zubair Formation in transgression and regression phases within the main structural folds of the Zubair, Nahr Umr, West Qurna and Majnoon Oil fields. Oil biomarkers of the Zubair Formation Reservoirs are showing source affinity with mixed oil from the Upper Jurassic and Lower Cretaceous strata, including Zubair Formation organic matters, based on presentation of GC and GC-MS results on diagrams of global petroleum systems.  相似文献   

3.
This paper presents geochemical analysis of drilled cutting samples from the OMZ‐2 oil well located in southern Tunisia. A total of 35 drill‐cutting samples were analyzed for Rock‐Eval pyrolysis, total organic carbon (TOC), bitumens extraction and liquid chromatography. Most of the Ordovician, Silurian and Triassic samples contained high TOC contents, ranging from 1.00 to 4.75% with an average value of 2.07%. The amount of hydrocarbon yield (pyrolysable hydrocarbon: S2b) expelled during pyrolysis indicates a good generative potential of the source rocks. The plot of TOC versus S2b, indicates a good to very good generative potential for organic matter in the Ordovician, Silurian and Lower Triassic. However, the Upper Triassic and the Lower Jurassic samples indicate fair to good generative potential. From the Vankrevelen diagram, the organic matter in the Ordovician, Silurian and Lower Triassic samples is mainly of type II kerogen and the organic matter from the Upper Triassic and the Lower Jurassic is dominantly type III kerogen with minor contributions from Type I. The thermal maturity of the organic matter in the analyzed samples is also evaluated based on the Tmax of the S2b peak. The Ordovician and Lower Silurian formations are thermally matured. The Upper Silurian and Triassic deposits are early matured to matured. However, Jurassic formations are low in thermal maturity. The total bitumen extracts increase with depth from the interval 1800–3000 m. This enrichment indicates that the trapping in situ in the source rocks and relatively short distance vertical migration can be envisaged in the overlying reservoirs. During the vertical migration from source rocks to the reservoirs, these hydrocarbons are probably affected by natural choromatography and in lower proportion by biodegradation.  相似文献   

4.
The relationship between sporo-pollen color and the degree of maturation of organic matter is discussed with regard to oil generation and evolution, as typified by the Cretaceous system in the Daqing Oil Field, central Songliao Basin, Northeast China. Color variation of spores and pollen is considered as a function of sedimentary environment and thermal alteration. Sporo-pollen color is classified into seven grades, and the degree of thermal alteration is studied in terms of color index. Results show that the sporo-pollen color index for the strata at the depth of 1,000–3,000 m (stratigraphically from the first member of the Liangjiang Formation to the upper Quantou Formation) ranges from 2.5–5.0, corresponding to a palaeotemperature range of 60°–140°C. These are the optimum oil-generating strata. The strata underlying the lower Quantou Formation below 3,000 m with the color index in excess of 5 and the palaeotemperature over 140°C may be favorable for gas accumulation. As for the strata at the depth of less than 1,000 m, i.e., stratigraphically overlying the second member of the Liangjiang Formation, which are characterized by a color index of 1.0–1.5 and a palaeotemperature of less than 60°C, the degree of maturation of organic matter is lower than that in the oil-generating strata.  相似文献   

5.
Organic geochemical and petrological assessment of coals/coaly shales and fine grained sediments, coupled with organic geochemical analyses of oil samples, all from Permo–Triassic sections of the Southern Sydney Basin (Australia), have enabled identification of the source for the widely distributed oil shows and oil seeps in this region. The Permian coals have higher hydrogen indices, higher liptinite contents, and much higher total organic matter extract yields than the fine grained sediments. A variety of source specific parameters obtained from n-alkanes, regular isoprenoids, terpanes, steranes and diasteranes indicate that the oil shows and seeps were generated and expelled predominantly from higher plant derived organic matter deposited in oxic environments. The source and maturity related biomarkers and aromatic hydrocarbon distributions of the oils are similar to those of the coals. The oil-coal relationship also is demonstrated by similarities in the carbon isotopic composition of the total oils, coal extracts, and their individual n-alkanes. Extracts from the Permo–Triassic fine grained sediments, on the other hand, have organic geochemical signatures indicative of mixed terrestrial and prokaryotic organic matter deposited in suboxic environments, which are significantly different from both the oils and coal extracts. The molecular signatures indicating the presence of prokaryotic organic matter in some of the coal extracts and oils may be due to thin sections of possibly calcareous lithologies interbedded within the coal measures. The genetic relationship between the oils and coals provides new evidence for the generation and expulsion of oils from the Permian coals and raises the possibility for commercial oil accumulations in the Permian and Early Triassic sandstones, potentially in the deeper offshore part of the Sydney Basin.  相似文献   

6.
The paper presents data on the composition of biomarkers from bitumen extracts and the chemical structure of kerogen from Corg-rich sedimentary rocks before and after hydrothermal treatment in an autoclave at 300°C. Samples selected for this study are kukersite and Ordovician Dictyonema shale from the Baltics, Domanik oil shale from the Ukhta region, Upper Permian brown coal from the Pre-Ural foredeep, carbonaceous shale from the Oxfordian horizon of the Russian plate, and Upper Jurassic oil shales from the Sysola oil shale bearing region. The rocks contain type I, II, III, and II-S kerogens. The highest yield of extractable bitumen is achieved for Type II-S kerogen, whereas Type III kerogen produces the lowest amount of bitumen. The stages of organic matter thermal maturation achieved during the experiments correspond to a transition from PC2–3 to MC1–2. The 13C NMR data on kerogen indicate that the aromatic structures of geopolymers underwent significant changes.  相似文献   

7.
PETROLEUM GEOLOGICAL CONDITIONS IN QIANGTANG BASIN  相似文献   

8.
With oil-generating formations in the Dongying basin as the objective of study, this paper deals with the relations among petroporphyrins, lithology, oxidation-reduction conditions, maturation and conversion of organic matter, and burial depth. It is considered that the content of petroporphyrins in the oil-generating formations depends on the quantity and nature of organic matter, sediment ary environment and burial depth. There is a porphyrin-rich interval at 2,200–2,700 m with the corresponding geothermal temperature ranging from 93° to 119°C. It is also an oil-accumulating zone. Nickel in the crude or in the nucleus of petroporphyrin is accumulated during the process of oil generation. Nickel-porphyrin abundance in the oil-generating formations has a negative correlation with the content of nickel. Evaluation of the oil-generating formations has been made on the bosis of petroporphyrin data.  相似文献   

9.
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   

10.
The Upper Triassic oil accumulations in the Ordos Basin is the most successful tight oil play in China,with average porosity values of less than 10% and permeability values below 1.0 mD.This study investigated the geological characteristics and origin of the tight oil accumulations in the Chang 6 member of the Upper Triassic Yanchang Formation in the Shanbei area based on over 50,000 petrological,source-rock analysis,well logging and production data.The tight oil accumulation of the Chang 6 member is distributed continuously in the basin slope and the centre of the basin.The oilwater relationships are complex.Laumontite dissolution pores are the most important storage spaces,constituting 30%-60% of total porosity and showing a strong positive relationship with oil production.The pore-throat diameter is less than 1 μm,and the calculated critical height of the oil column is much larger than the tight sand thickness,suggesting that the buoyancy was probably of limited importance for oil migration.The pressure difference between the source rocks and sandstone reservoirs is inferred to have provided driving force for hydrocarbon migration.Two factors of source-reservoir configuration and laumontite dissolution contributed to the formation of the Chang 6 tight oil accumulations.Intense hydrocarbon generation and continuous sand bodies close to the hydrocarbon kitchen are the foundation for the large-scale oil distribution.Dissolution of feldspar-laumontite during the process of organic matter evolution generated abundant secondary pores and improved the reservoir quality.  相似文献   

11.
Paleogeotemperatures of the Tarim Basin have been determined on the basis of the degree of thermal alteration of organic matter and its thermal history. Evidence shows that the paleogeothermal gradient for this area is generally low: 3°C/100 m for the Paleozoic group and 2.5°C/100 m for the Mesozoic group. The establishment of a geological paleogeothermal model makes it possible to gain a deeper understanding of oil-generating processes. The peak of oil-generation is generally set at a depth of 5000–6000 m. Higher pressure within the strata is favourable for the preservation of oil at great depths. Organic matter enclosed in carbonate minerals is believed to be another important source of oil. It is suggested that there may be large reserves of natural gases in the area studied with a rough estimation of about 0.6 × 104 billion m3.  相似文献   

12.
Hydrocarbon potential of the Sargelu Formation,North Iraq   总被引：1，自引：1，他引：0  
Microscopic and chemical analysis of 85 rock samples from exploratory wells and outcrops in northern Iraq indicate that limestone, black shale and marl within the Middle Jurassic Sargelu Formation contain abundant oil-prone organic matter. For example, one 7-m (23-ft.)-thick section averages 442 mg?HC/g S2 and 439 °C Tmax (Rock-Eval pyrolysis analyses) and 16 wt.% TOC. The organic matter, comprised principally of brazinophyte algae, dinoflagellate cysts, spores, pollen, foraminiferal test linings and phytoclasts, was deposited in a distal, suboxic to anoxic basin and can be correlated with kerogens classified as type A and type B or, alternatively, as type II. The level of thermal maturity is within the oil window with TAI?=?3? to 3+, based on microspore colour of light yellowish brown to brown. Accordingly, good hydrocarbon generation potential is predicted for this formation. Terpane and sterane biomarker distributions, as well as stable isotope values, were determined for oils and potential source rock extracts to determine valid oil-to-source rock correlations. Two subfamily carbonate oil types—one of Middle Jurassic age (Sargelu) carbonate rock and the other of Upper Jurassic/Cretaceous age—as well as a different oil family related to Triassic marls, were identified based on multivariate statistical analysis (HCA and 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 R28 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. One-dimension petroleum system models of key wells were developed using IES PetroMod Software to evaluate burial-thermal history, source-rock maturity and the timing and extent of petroleum generation; interpreted well logs served as input to the models. The oil-generation potential of sulphur-rich Sargelu source rocks was simulated using closed system type II-S kerogen kinetics. Model results indicate that throughout northern Iraq, generation and expulsion of oil from the Sargelu began and ended in the late Miocene. At present, Jurassic source rocks might have generated and expelled between 70 % and 100 % of their total oil.  相似文献   

13.
The influence of syndepositional fault patterns on palaeocurrents is demonstrated in fluvial to shallow-marine sandstones of Upper Triassic basins in the High Atlas. The synsedimentary nature of faults is deduced from hydroplastic slickensides, thickness variations due to block tilting and dislocation of layers next to the fault scarp. On a regional scale, it is shown that the major normal fault trend of N050–070° controlled the overall palaeocurrent pattern which was directed towards the west-southwest, i.e. in the direction of the future Atlantic ocean. Some anomalies in the palaeocurrent pattern could be related to an increase in subsidence which induced a general coarsening of sediment towards the top of the Triassic.  相似文献   

14.
According to the materials of geochemical study in the core of the ultradeep hole SV-27 of aromatic fractions of bitumoids of the Vilyui syneclise (East Siberia) by the method of chromatography–mass spectrometry, starting from the depth of >5000 m, four diastereomers of previously unknown hydrocarbons, which become predominant in the fraction at a depth of ～6500 m, were distinguished. Similar hydrocarbons were found in organic matter of Upper Paleozoic rocks of the Kharaulakh anticlinorium in the Verkhoyansk folded area. According to the intense molecular ion m/z 366 and the character of the basic fragmental ions (m/z 238, 309, and 323), the major structure of the compounds studied was determined as 17-desmethyl-23-methylmonoaromatic steroid C27. The absence of such steroids in oil of the Vilyui syneclise shows that deep micro-oils did not participate in the formation of oil fringes of gas condensate deposits of the region.  相似文献   

15.
Palynological and organic geochemical analysis are performed in this study for 220 samples of cores and cuttings collected from the Ordovician Khabour, Silurian Akkas, and Upper Devonian Kaista Formations in wells Akkas/1-6, Khleisya/1, KH5/6, and KH5/1 of West Iraq. Their diagnostic organic matters are abundant acritarchs (134 species belonging to 54 genera, including marine algae of Tasmanites, Deflandstrum, and brazinophytes) and a few spores (21 species belonging to 16 genera) and Chitinozoa (43 species belonging to 12 genera) as well as scolecodonts, graptolite siculae, cuticles, and amorphous organic matters. On the basis of acritarchs with tentative selections of Chitinozoa and spores, this succession is subdivided into ten palynozones (PZ1–PZ10) within a stratigraphic framework and correlated with equivalent strata in Saudi Arabia and Libya. Beds of the Khabour and lower part of Akkas Formations were deposited in anoxic–dysoxic marine shelf environments northern Gondwana Continent with provincial acritarchs. These deposits were extending from outer to inner neritic with affects of local upwelling currents and lagoons, especially in boreholes Akkas/1, KH5/1, and KH5/6. Hydrocarbon generations potential are assessed by plotting organic matter types in palynofacies context of Bujaks (1970) graphical model with depths along with log of thermal maturation indices on the basis of the color changes of the acritarchs Diexallophasis denticulata–Orthosphaeridium ternatus and Baltisphaeridium constrictum as well as kerogen types and total organic carbon (TOC). These organic matters are up to 16% TOC, especially for the hot shale of the Lower Silurian Akkaz Formation, very low asphalting and sulfur, saturated and aromatic hydrocarbons of more than 96%, and high peaks of C2–C20 gas chromatography that could indicate predominant gas generation with some light oils. The associated gases are mainly methane and ethane of CH4, C2H6, and C3H8. Accordingly, source potential for wet gas and condensates could be assessed for depth of 2,750–3,000 m and dry gas for depth of 3,570–3,650 m in well Akkas-1 only from the Ordovician Kabour Formation. Little oil might be generated from the lower Silurian Akkas formation in borehole Akkas-1 and KH5/6. These potential source rocks are extended toward Jordon, southwest Iraqi Desert and Syria. Accumulation sites of these generated gas and little oil could be within the sandstone porosities of 10–17% and permeability of 500 mD sealed by the non permeable shale's along closures of the structured anticline fold and fault of this field as well as along the unconformity boundary of the Upper Silurian Akkas Formation with the Upper Devonian Kaista Formation. Accordingly, Lower Paleozoic total petroleum system of generation, migration, and accumulations could be assessed for a basin includes West Iraq and their extensions in Jordon and Syria.  相似文献   

16.
Three exploration wells were selected near Mosul city (Az-29, Bm-15, and Kd-1) to study the palynozones and hydrocarbon generation potential of the Upper Triassic Baluti and Kurrachine Formations. This study was completed in two phases: The first was a study of palynofacies and their paleoenvironmental indications, degree of preservation, diversity of palynomorphs, and organic maturity of the rocks according to palynomorphs’ color using a refracted light microscope. More than 80 slides of organic matter were used for this study. Four palynofacies were tentatively recognized. (1) The first palynofacies is diagnostic of the Baluti Formation in the Az-29 and Kd-1 wells; (2) The second palynofacies appeared at different depths in the Kurrachine Formation in three wells. (3) The third was only found between the depths of 4,534 to 4,685 m in the well Az-29. (4) The fourth was only found between 3,500- and 3590-m depth in the well Bm-15. A distal coastal marine environment is suggested for the Baluti Formation and restricted lagoonal environment for the Kurrachine Formation. The second phase used organic geochemical analyses to confirm the suggested paleoenvironmental and hydrocarbon generation material. Three techniques were used, namely total organic carbon, pyrolysis, and pyrolysis gas chromatography, on more than 35 samples from different depths in three wells. The analyses proved that a sufficient quantity of organic matter occurs that and has suitable maturity for hydrocarbon generation potential of oil and gas.  相似文献   

17.
Paleotemperature indicators and apatite fission track analysis of Australian continental margin cover sequences accreted to the active Banda arc–continent collision indicate little to no heating during rapid late Neogene uplift and exhumation. Thermal maturation patterns of vitrinite reflectance, conodont alteration and illite crystallinity show that peak paleotemperatures (PPT) increase with stratigraphic and structural burial. The highest PPT is found in the northern hinterland of the accretionary wedge, which was beneath progressively thicker parts of the upper plate towards the north. Major discontinuities in the pattern of PPT are associated with the position of major thrust ramps such as those forming the Ramelau/Kekneno Arch (RKA). PPT for Upper Triassic to Neogene strata south of the RKA are 60–80°C, which are similar to, and in many cases lower than, correlative and age equivalent units drilled on the NW Australian Shelf. Permian to Lower Triassic sedimentary strata thrust over younger units within and north of the RKA have PPT of 100–220°C. Thrust sheets accreted beneath the upper plate have PPT approximately 90°C higher than those frontally accreted. Metamorphism of the northernmost units of these sequences yield PPT of >300°C. Thrust stacking yields an inverted thermal profile of PPT decreasing discontinuously downward and to the south (towards the foreland). The timing of PPT is constrained by apatite fission track ages from mostly Triassic continental margin cover sequences. Ages of Upper Triassic units are primarily coeval with deposition and show little evidence of thermal annealing, whereas those of Lower Triassic units are almost completely annealed and range from 1.8±0.5–19.2±9.7 Ma. The clustering of apatite fission track ages into two distinct groups indicates that the upper boundary of the partial annealing zone has remained for some time at a Triassic stratigraphic interval in the slope and rise of the NW Australian continental margin. The position of this zone on the present shelf is higher in the stratigraphic column due to the greater thickness of post-breakup shelf facies units. Thrust stacking of rise, slope and shelf units produces an inverted vertical profile of increasing apatite fission track age with depth. Lack of any long confined track lengths in apatite from all of the units requires rapid and recent exhumation of the thrust stack, which is coincident with rapid phases of Pliocene–Pleistocene exhumation documented throughout Timor. These data preclude pre-Late Miocene tectonic burial or pre-Pliocene exhumation of the NW Australian continental margin.  相似文献   

18.
Organic geochemical analysis and palynological studies of the organic matters of subsurface Jurassic and Lower Cretaceous Formations for two wells in Ajeel oil field, north Iraq showed evidences for hydrocarbon generation potential especially for the most prolific source rocks Chia Gara and Sargelu Formations. These analyses include age assessment of Upper Jurassic (Tithonian) to Lower Cretaceous (Berriasian) age and Middle Jurassic (Bathonian–Tithonian) age for Chia Gara and Sargelu Formations, respectively, based on assemblages of mainly dinoflagellate cyst constituents. Rock-Eval pyrolysis have indicated high total organic carbon (TOC) content of up to 18.5 wt%, kerogen type II with hydrogen index of up to 415 mg HC/g TOC, petroleum potential of 0.70–55.56 kg hydrocarbon from each ton of rocks and mature organic matter of maximum temperature reached (Tmax) range between 430 and 440 °C for Chia Gara Formation, while Sargelu Formation are of TOC up to 16 wt% TOC, Kerogen type II with hydrogen index of 386 mg HC/g TOC, petroleum potential of 1.0–50.90 kg hydrocarbon from each ton of rocks, and mature organic matter of Tmax range between 430 and 450 °C. Qualitative studies are done in this study by textural microscopy used in assessing amorphous organic matter for palynofacies type belonging to kerogen type A which contain brazinophyte algae, Tasmanites, and foraminifera test linings, as well as the dinoflagellate cysts and spores, deposited in dysoxic–anoxic environment for Chia Gara Formation and similar organic constituents deposited in distal suboxic–anoxic environment for Sargelu Formation. The palynomorphs are of dark orange and light brown, on the spore species Cyathidites australis, that indicate mature organic matters with thermal alteration index of 2.7–3.0 for the Chia Gara Formation and 2.9–3.1 for the Sargelu Formation by Staplin's scale. These characters have rated the succession as a source rock for very high efficiency for generation and expulsion of oil with ordinate gas that charged mainly oil fields of Baghdad, Dyala (B?aquba), and Salahuddin (Tikrit) Governorates. Oil charge the Cretaceous-Tertiary total petroleum system (TPS) are mainly from Chia Gara Formation, because most oil from Sargelu Formation was prevented passing to this TPS by the regional seal Gotnia Formation. This case study of mainly Chia Gara oil source is confirmed by gas chromatography–mass spectrometry analysis for oil from reservoirs lying stratigraphically above the Chia Gara Formation in Ajeel and Hamrine oil fields, while oil toward the north with no Gotnia seal could be of mainly Sargelu Formation source.  相似文献   

19.
This study uses clay mineral assemblages, illite ??crystallinity?? (IC), chlorite ??crystallinity?? (CC), illite polytypes, the b cell-dimension of K-white mica, mineral geothermo-geobarometers and homogenization temperatures of fluid inclusions to investigate the transition from diagenesis to metamorphism in a 7?km thick Triassic flysch sequence in the well Hongcan 1, eastern Tibetan plateau. The 7,012.8?m deep borehole penetrated flysch of Upper to the Middle Triassic age and represents a unique chance to characterize low temperature metamorphic processes in an unusually thick sedimentary sequence developed on thickened continental crust. Mineral assemblage analysis reveals a burial metamorphic pattern with kaolinite and chlorite/smectite mix-layer phases present in the upper 1,500?m, and illite/smectite mixed-layer phases extending to a depth of 3,000?m. The metamorphic index mineral, graphite, was detected in sedimentary rock below 5,000?m using Raman spectroscopy. There exists a good correlation between IC and CC within the prograde burial sequence; with CC anchizonal boundaries of 0.242 and 0.314°2?? (upper and lower boundaries, respectively) corresponding to Kübler??s IC limits at 0.25 and 0.42°2??. Illite polytypism also shows an increase in the 2M 1 polytype with increasing depth, with ca. 60?% 2M 1 abundance compared to the 1M type at the surface, to 100?% 2M 1 at the bottom of the borehole. Fluid inclusion analysis show HHC-rich bearing fluids correspond to the diagenetic zone, CH4-rich bearing fluids appear at transitional zone from diagenetic to low anchizone and H2O-rich bearing fluids mark the high anchizone to epizone. Based on chlorite chemical geothermometer, calcite?Cdolomite geothermo-barometers as well as homogenization temperature of fluid inclusions, a paleotemperature range of 118?C348?°C is estimated for the well with a pressure facies of low to intermediate type.  相似文献   

20.
The fluvial Triassic reservoir subarkoses and arkoses (2409·5–2519·45 m) of the El Borma oilfield, southern Tunisia, were subjected to cementation by haematite, anatase, infiltrated clays, kaolinite and K-feldspar at shallow burial depths from meteoric waters. Subsequently, basinal brines controlled the diagenetic evolution of the sandstones and resulted initially in the precipitation of quartz overgrowths, magnesian siderite, minor ferroan magnesite and anhydrite. The enrichment of siderite in 12C isotope (δ13CPDB= - 14·5 to - 9‰) results from derivation of carbon from the thermal decarboxylation of organic matter. During further burial, the precipitation of dickite and pervasive transformation of kaolinite into dickite occurred, followed by the formation of microcrystalline K-feldspar and quartz, chlorite and illite, prior to the emplacement of oil. Present day formation waters are Na-Ca-Cl brines evolved by the evaporation of seawater and water/mineral interaction and are in equilibrium with the deep burial (≤ 3·1 km) minerals. These waters are suggested to be derived from the underlying Silurian and Devonian dolomitic mudstones.  相似文献   

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