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1.
Scanning and transmission electron microscopic analyses of shale samples from offshore Louisiana, USA, Gulf of Mexico, reveal the relationship between mineralogical and microfabric changes during burial diagenesis. The local geopressured zone begins at 2200-m depth. Above that depth the shales are smectite-rich, generally lack particle orientation, and contain appreciable pores. Below the 2200-m depth, the shales become more illite-rich with increasing burial, more crystalline, and less porous. Microfabric changes are mainly caused by compaction during burial diagenesis; mineralogical changes (smectite-to-illite) and crystal growth also play an important role in fabric alteration during deep burial diagenesis. 相似文献
2.
The Mississippian Barnett Shale (Texas, USA), consisting of organic-rich shales and limestones, hosts the largest gas fields of North America. This study examines sealed fractures from core and outcrop samples of the Barnett Shale of the Fort Worth Basin and aims to: 1) characterize the phases occurring in the fractures from samples having experienced different burial histories; 2) establish a paragenetic sequence to relate the timing of fracture origin and sealing with the burial history of the basin; and 3) contribute to the understanding of the mechanisms of fracture formation in shales, including overpressure origin.Four fracture generations were distinguished in the most deeply buried core samples by characterizing the sealing minerals petrographically and geochemically. The generations were inserted into the framework of a reconstructed burial history for the Fort Worth Basin, which allowed a time sequence for fracture development to be established. This in turn allowed inference of conditions of fracture development, and consideration of fracture mechanisms as well as the origin of the parent fluids of sealing minerals.Type 1 fractures formed during early mechanical compaction (at a few 10 s to 100 m of depth) of still not fully cemented sediments. Type 2 fractures formed during moderate burial (∼2 km), from slightly modified seawater. Their timing is consistent with overpressure generated during rapid deposition and differential compaction of Pennsylvanian lithologies during the onset of the Ouachita compressional event. Type 3 fractures formed during deep burial (>3 km) from silica-rich basinal brines possibly derived from clay diagenesis. Type 4 fractures formed at very deep burial (>4 km), from hot and 18O-rich fluids, carrying light oil (20-30 API) and record the opening of the fluid system after hydrocarbon migration.Differences are highlighted between the timing and thermal regimes under which fractures formed in Barnett lithologies from different areas of the basin, this suggesting that extrapolation of outcrop observations to subsurface must be used with due care. 相似文献
3.
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
4.
Precise hydrogeochemical modeling of early diagenesis is a key in the reconstruction of sedimentary basin models. This determines the mineralogical evolution of the sediment and consequently the porosity of the rock. During early diagenesis also part of the initial organic matter is converted into biogenic gas: CH4 CO2, and H2S. These processes are part of complex reaction chains during sedimentation, and biogeochemical reactions leave different signals that can be observed today. In this work, we reproduce the early diagenetic processes as integrated signals over geological times in sediments of the Demerara Rise by applying chemical thermodynamics using the PHREEQC (version 2) computer code. The investigated sediments are characterized by the presence of black shales in 410–490 mbsf and by a diagenetic barite layer above in 300–350 mbsf at depth of sulfate-methane transition (SMT). We determine the parameters that influence the location of diagenetic barite peaks in sediments overlying black shales by means of a novel modeling approach. Crucial parameters are the amount of bacterial organic matter mineralization, sedimentation rates and bottom water sulfate concentrations. All parameters are intertwining and influence the sulfate-methane cycle. They affect the location of the SMT visualized by diagenetic barite peaks. However, our model approach opens a wide field in exploring early diagenetic reactions, processes and products (such as biogenic methane) over geological times mirrored by diagenetic minerals and pore water concentration profiles that can be detected in present-day sediments. 相似文献
5.
Mineral types (detrital and authigenic) and organic-matter components of the Ordovician-Silurian Wufeng and Longmaxi Shale (siliceous, silty, argillaceous, and calcareous/dolomitic shales) in the Sichuan Basin, China are used as a case study to understand the control of grain assemblages and organic matter on pores systems, diagenetic pathway, and reservoir quality in fine-grained sedimentary rocks. This study has been achieved using a combination of petrographic, geochemical, and mercury intrusion methods. The results reveal that siliceous shale comprises an abundant amount of diagenetic quartz (40–60% by volume), and authigenic microcrystalline quartz aggregates inhibit compaction and preserve internal primary pores as rigid framework for oil filling during oil window. Although silty shale contains a large number of detrital silt-size grains (30–50% by volume), which is beneficial to preserve interparticle pores, the volumetric contribution of interparticle pores (mainly macropores) is small. Argillaceous shale with abundant extrabasinal clay minerals (>50% by volume) undergoes mechanical and chemical compactions during burial, leading to a near-absence of primary interparticle pores, while pores preserved between clay platelets are dominant with more than 10 nm in pore size. Pore-filling calcite and dolomite precipitated during early diagenesis inhibit later compaction in calcareous/dolomitic shale, but the cementation significantly reduces the primary interparticle pores. Pore-throat size distributions of dolomitic shale show a similar trend with silty shale. Besides argillaceous shale, all of the other lithofacies are dominated by OM pores, which contribute more micropores and mesopores and is positively related to TOC and quartz contents. The relationship between pore-throat size and pore volume shows that most pore volumes are provided by pore throats with diameters <50 nm, with a proportion in the order of siliceous (80.3%) > calcareous/dolomitic (78.4%) > silty (74.9%) > argillaceous (61.3%) shales. In addition, development degree and pore size of OM pores in different diagenetic pathway with the same OM type and maturity show an obvious difference. Therefore, we suggest that the development of OM pores should take OM occurrence into account, which is related to physical interaction between OM and inorganic minerals during burial diagenesis. Migrated OM in siliceous shale with its large connected networks is beneficial for forming more and larger pores during gas window. The result of the present work implies that the study of mineral types (detrital and authigenic) and organic matter-pores are better understanding the reservoir quality in fine-grained sedimentary rocks. 相似文献
6.
Two sets of Lower Paleozoic organic-rich shales develop well in the Weiyuan area of the Sichuan Basin: the Lower Cambrian Jiulaodong shale and the Lower Silurian Longmaxi shale. The Weiyuan area underwent a strong subsidence during the Triassic to Early Cretaceous and followed by an extensive uplifting and erosion after the Late Cretaceous. This has brought about great changes to the temperature and pressure conditions of the shales, which is vitally important for the accumulation and preservation of shale gas. Based on the burial and thermal history, averaged TOC and porosity data, geological and geochemical models for the two sets of shales were established. Within each of the shale units, gas generation was modeled and the evolution of the free gas content was calculated using the PVTSim software. Results show that the free gas content in the Lower Cambrian and Lower Silurian shales in the studied area reached the maxima of 1.98–2.93 m3/t and 3.29–4.91 m3/t, respectively (under a pressure coefficient of 1.0–2.0) at their maximum burial. Subsequently, the free gas content continuously decreased as the shale was uplifted. At present, the free gas content in the two sets of shales is 1.52–2.43 m3/t and 1.94–3.42 m3/t, respectively (under a current pressure coefficient of 1.0–2.0). The results are roughly coincident with the gas content data obtained from in situ measurements in the Weiyuan area. We proposed that the Lower Cambrian and Lower Silurian shales have a shale gas potential, even though they have experienced a strong uplifting. 相似文献
7.
The Wufeng-Longmaxi organic-rich shales host the largest shale gas fields of China. This study examines sealed fractures within core samples of the Wufeng-Longmaxi shales in the Jiaoshiba shale gas field in order to understand the development of overpressures (in terms of magnitude, timing and burial) in Wufeng-Longmaxi shales and thus the causes of present-day overpressure in these Paleozoic shale formations as well as in all gas shales. Quartz and calcite fracture cements from the Wufeng-Longmaxi shale intervals in four wells at depth intervals between 2253.89 m and 3046.60 m were investigated, and the fluid composition, temperature, and pressure during natural fracture cementation determined using an integrated approach consisting of petrography, Raman spectroscopy and microthermometry. Many crystals in fracture cements were found to contain methane inclusions only, and aqueous two-phase inclusions were consistently observed alongside methane inclusions in all cement samples, indicating that fluid inclusions trapped during fracture cementation are saturated with a methane hydrocarbon fluid. Homogenization temperatures of methane-saturated aqueous inclusions provide trends in trapping temperatures that Th values concentrate in the range of 198.5 °C–229.9 °C, 196.2 °C-221.7 °C for quartz and calcite, respectively. Pore-fluid pressures of 91.8–139.4 MPa for methane inclusions, calculated using the Raman shift of C-H symmetric stretching (v1) band of methane and equations of state for supercritical methane, indicate fluid inclusions trapped at near-lithostatic pressures. High trapping temperature and overpressure conditions in fluid inclusions represent a state of temperature and overpressure of Wufeng-Longmaxi shales at maximum burial and the early stage of the Yanshanian uplift, which can provide a key evidence for understanding the formation and evolution of overpressure. Our results demonstrate that the main cause of present-day overpressure in shale gas deposits is actually the preservation of moderate-high overpressure developed as a result of gas generation at maximum burial depths. 相似文献
8.
Dongxia Chen Xiongqi Pang Zhenxue Jiang Jianhui Zeng Nansheng Qiu Maowen Li 《Marine and Petroleum Geology》2009
A great difference exists between the hydrocarbon charging characteristics of different Tertiary lacustrine turbidites in the Jiyang Super-depression of the Bohai Bay Basin, east China. Based on wireline log data, core observation and thin-section analyses, this study presents detailed reservoir property data and their controlling effects from several case studies and discusses the geological factors that govern the hydrocarbon accumulation in turbidite reservoirs. The lacustrine fluxoturbidite bodies investigated are typically distributed in an area of 0.5–10 km2, with a thickness of 5–20 m. The sandstones of the Tertiary turbidites in the Jiyang Super-depression have been strongly altered diagenetically by mechanical compaction, cementation and mineral dissolution. The effect of compaction caused the porosity to decrease drastically with the burial depths, especially during the early diagenesis when the porosity was reduced by over 15%. The effect of cementation and mineral dissolution during the late-stage diagenesis is dominated by carbonate cementation in sandstones. High carbonate cement content is usually associated with low porosity and permeability. Carbonate dissolution (secondary porosity zone) and primary calcite dissolution is believed to be related to thermal maturation of organic matter and clay mineral reactions in the surrounding shales and mudstone. Two stages of carbonate cementation were identified: the precipitation from pore-water during sedimentation and secondary precipitation in sandstones from the organic acid-dissolved carbonate minerals from source rocks. Petrophysical properties have controlled hydrocarbon accumulation in turbidite sandstones: high porosity and permeability sandstones have high oil saturation and are excellent producing reservoirs. It is also noticed that interstitial matter content affects the oil-bearing property to some degree. There are three essential elements for high oil-bearing turbidite reservoirs: excellent pore types, low carbonate cement (<5%) and good petrophysical properties with average porosity >15% and average permeability >10 mD. 相似文献
9.
Fractured reservoirs are of prime interest as fracture networks control most of the fluid flow and/or accumulation. However, characterizing 3D fracture patterns from subsurface data remains challenging. Studying fractures on outcrops is a good substitution to 1D data from subsurface exploration tools. In addition, outcrops allow deciphering the nature, origin and conditions for fracture formation through the geodynamic history. In this paper, we aim at characterizing the true 3D fracture patterns and determining the genetic role of facies, diagenesis and rock physical properties. We targeted a platform–slope transect within a carbonate reservoir analog, the Maiella Mountain in central Italy, where implications for analog hydrocarbon reservoir can be discussed.Fracture patterns are sorted based on geometric and kinematic criteria from field measurements and petrographic analyzes on thin-sections. Sedimentary facies, pore types and rock physical properties have been characterized in order to establish the impact of early diagenesis on rock evolution. Diagenetic sequences have been unraveled and correlated to the fractures. Fracture sequences have been determined considering the cross-cutting relationships and compared with burial–uplift history. In the two studied formations (platform and slope carbonates), we interpret a stage of fracturing perpendicular to bedding, formed at shallow depth and occurring prior to major regional tectonic events. The studied carbonates have undergone early diagenesis during fast and shallow burial, conferring early brittle behavior. The amount of stylolites is not correlated to burial depth but to fracture density, porosity and free air P–wave velocity. It means that fracture development, mechanical and petrophysical properties are acquired during early diagenesis.Both studied formations have undergone the same geodynamic history and their brittle response is different and not related to folding but to burial and early cementation. Deciphering the close relationship between sedimentary facies, diagenetic and geodynamic history has allowed unraveling the controling factors on rock properties and therefore on fracture pattern. 相似文献
10.
Nine organic-rich shale samples of Lower Cambrian black shales were collected from a recently drilled well in the Qiannan Depression, Guizhou Province where they are widely distributed with shallower burial depth than in Sichuan Basin, and their geochemistry and pore characterization were investigated. The results show that the Lower Cambrian shales in Qiannan Depression are organic rich with TOC content ranging from 2.81% to 12.9%, thermally overmature with equivalent vitrinite reflectance values in the range of 2.92–3.25%, and clay contents are high and range from 32.4% to 53.2%. The samples have a total helium porosity ranging from 2.46% to 4.13% and total surface area in the range of 9.08–37.19 m2/g. The estimated porosity in organic matters (defined as the ratio of organic pores to the volume of total organic matters) based on the plot of TOC vs helium porosity is about 10% for the Lower Cambrian shales in Qiannan Depression and is far lower than that of the Lower Silurian shales (36%) in and around Sichan Basin. This indicates that either the organic pores in the Lower Cambrian shale samples have been more severely compacted than or they did not develop organic pores as abundantly as the Lower Silurian shales. Our studies also reveal that the micropore volumes determined by Dubinin–Radushkevich (DR) equation is usually overestimated and this overestimation is closely related to the non-micropore surface area of shales (i.e. the surface area of meso- and macro-pores). However, the modified BET equation can remove this overestimation and be conveniently used to evaluate the micropore volumes/surface area and the non-micropore surface areas of micropore-rich shales. 相似文献
11.
This paper investigates the reservoir potential of deeply-buried Eocene sublacustrine fan sandstones in the Bohai Bay Basin, China by evaluating the link between depositional lithofacies that controlled primary sediment compositions, and diagenetic processes that involved dissolution, precipitation and transformation of minerals. This petrographic, mineralogical, and geochemical study recognizes a complex diagenetic history which reflects both the depositional and burial history of the sandstones. Eogenetic alterations of the sandstones include: 1) mechanical compaction; and 2) partial to extensive non-ferroan carbonate and gypsum cementation. Typical mesogenetic alterations include: (1) dissolution of feldspar, non-ferroan carbonate cements, gypsum and anhydrite; (2) precipitation of quartz, kaolinite and ferroan carbonate cements; (3) transformation of smectite and kaolinite to illite and conversion of gypsum to anhydrite. This study demonstrates that: 1) depositional lithofacies critically influenced diagenesis, which resulted in good reservoir quality of the better-sorted, middle-fan, but poor reservoir quality in the inner- and outer-fan lithofacies; 2) formation of secondary porosity was spatially associated with other mineral reactions that caused precipitation of cements within sandstone reservoirs and did not greatly enhance reservoir quality; and 3) oil emplacement during early mesodiagenesis (temperatures > 70 °C) protected reservoirs from cementation and compaction. 相似文献
12.
The oxidation and reduction that occur during early diagenesis of sediments has been studied in the interstitial waters of
a rapidly accumulating sedimentary sequence from the Mediterranean margin of Spain. A series of reactions that are mediated
by progressively lower free energy derived from oxidation of organic matter is evident in the sedimentary sequence. Iron and
manganese are rapidly reduced. Phosphate and alkalinity maxima at a subbottom depth of 15 m indicate maximal organic matter
degradation. Methane first appears at ∼20 m subbottom after sulfate is depleted, and its concentrations quickly climb.
Received: 27 October 1997 / Revision received: 4 March 1998 相似文献
13.
Diagenesis in the uppermost Jurassic to Lower Cretaceous deltaic sandstones and shales of the Scotian Basin is an important control on reservoir quality. Ferruginous zone (sub-oxic) marine pore-water diagenesis controls the initial formation of Fe2+-silicates that are the precursors of grain-rimming chlorite that preserves porosity. This study assesses the regional controls on the type of marine pore-water diagenesis by studying the sedimentology, mineralogy, and geochemistry of the retrogradational units and underlying progradational units in parasequences from conventional cores in two wells in different parts of the basin. Coated grains preserve a record of whether marine pore-water diagenesis below the seafloor was dominantly in the ferruginous or sulphidic geochemical zone. Four types of coated grain were distinguished, each with a different mineral paragenesis. Mineralogical and chemical evidence of ferruginous zone diagenesis includes the presence of diagenetic chlorite and siderite, and the correlation of P with Fe or Ti. Pyrite and Fe-calcite are found where the sulphidic zone is more significant than the ferruginous zone. Ferruginous zone diagenesis was common in low-sedimentation rate retrogradational sediments with low organic carbon, and in delta-front turbidites and river-mouth sandstones. Estuarine, tidal flat and prodeltaic facies that are directly supplied by riverine sediments have a lower Fe:Ti ratio than do fully marine shoreface and open shelf facies as a result of input of detrital ilmenite and its alteration products. The relative contribution of colloidal iron (hydr)-oxides appears greater in distal low-sedimentation rate environments. Where large changes in sedimentation rate occurred at ravinement surfaces, the underlying progradational rocks have evidence of ferruginous zone diagenesis, whatever their facies. Rapid upward migration of the pore-water profile resulting from the change in sedimentation rate reduced the time available for mineral products to form in the deeper pore-water zones. This study has shown that the availability of Fe and organic carbon varying in a complex manner in marine deltaic sediments, but that the resulting diagenesis by marine pore-water can be predicted from facies and paleogeographic setting. 相似文献
14.
The late Quaternary shallow-water carbonates have been altered by a variety of diagenetic processes, and further influenced by high-amplitude global and regional sea level changes. This study utilizes a new borehole drilled on the Yongxing Island, Xisha Islands to investigate meteoric diagenetic alteration in the late Quaternary shallowwater carbonates. Petrographic, mineralogical, stable isotopic and elemental data provide new insights into the meteoric diagenetic processes of the reef limestone. The results show the variation in the distribution of aragonite,high-Mg calcite(HMC) and low-Mg calcite(LMC) divides the shallow-water carbonates in Core SSZK1 into three intervals, which are Unit I(31.20–55.92 m, LMC), Unit II(18.39–31.20 m, aragonite and LMC) and Unit III(upper 18.39 m of core, aragonite, LMC and HMC). Various degrees of meteoric diagenesis exist in the identified three units. The lowermost Unit I has suffered almost complete freshwater diagenesis, whereas the overlying Units II and III have undergone incompletely meteoric diagenesis. The amount of time that limestone has been in the freshwater diagenetic environment has the largest impact on the degree of meteoric diagenesis. Approximately four intact facies/water depth cycles are recognized. The cumulative depletion of elements such as strontium(Sr),sodium(Na) and sulphur(S) caused by duplicated meteoric diagenesis in the older reef sequences are distinguished from the younger reef sequences. This study provides a new record of meteoric diagenesis, which is well reflected by whole-rock mineralogy and geochemistry. 相似文献
15.
The literature pertaining to volume change during diagenesis of clastic sediments is reviewed with respect to the problem of calculating pre- and syn-compaction thicknesses of sediments for basin reconstruction and stragraphic correlation studies. Four major mechanisms for volume change are identified: mechanical compaction, mechanical dissolution, chemical dissolution and phase change. The first two of these are found to be strongly dependent on the effective stress whilst the latter two show at least a pressure dependence. Quantification of the relationships between porosity and depth of burial of a sediment seems to be possible only for specific examples of the first of these processes at present. This quantification is dealt with in the accompanying related publication. 相似文献
16.
Palaeopressure reconstruction to explain observed natural hydraulic fractures in the Cleveland Basin
Natural fractures observed within the Lower Jurassic shales of the Cleveland Basin show evidence that pore pressure must have exceeded the lithostatic pressure in order to initiate horizontal fractures observed in cliff sections. Other field localities do not show horizontal fracturing, indicating lower pore pressures there. Deriving the burial history of the basin from outcrop, VR and heat-flow data gives values of sedimentation rates and periods of depositional hiatus which can be used to assess the porosity and pore pressure evolution within the shales. This gives us our estimate of overpressure caused by disequilibrium compaction alone, of 11 MPa, not sufficient to initiate horizontal fractures. However, as the thermal information shows us that temperatures were in excess of 95 °C, secondary overpressure mechanisms such as clay diagenesis and hydrocarbon generation occurred, contributing an extra 11 MPa of overpressure. The remaining 8.5 MPa of overpressure required to initiate horizontal fractures was caused by fluid expansion due to hydrocarbon generation and tectonic compression related to Alpine orogenic and Atlantic opening events. Where horizontal fractures are not present within the Lower Jurassic shales, overpressure was unable to build up as high due to proximity to the lateral draining of pressure within the Dogger Formation. The palaeopressure reconstruction techniques used within this study give a quick assessment of the pressure history of a basin and help to identify shales which may currently have enhanced permeability due to naturally-occurring hydraulic fractures. 相似文献
17.
Guilhem Hoareau Francis Odonne Elie-Jean Debroas Agnès Maillard Christophe Monnin Pierre Callot 《Marine and Petroleum Geology》2009,26(5):724-737
Numerous dolomite concretions have been discovered in marls of the Eocene Sobrarbe deltaic complex as part of the Ainsa Basin (Spain). This paper presents the first analyses of the shapes, the spatial relationships, the mineralogical, chemical and isotopic compositions of these concretions.The concretions are located above a major fossil submarine slide scar. They are mainly perpendicular to the sedimentary layers. Four distinct shapes of concretions have been distinguished: horizontal flat, sub-vertical cylindrical or cylindrical-complex and stocky. Three main mineral phases are associated with most of the concretions: calcite, celestite and barite. Concretion shapes and mineral occurrences are organized vertically in the marls from bottom to top: (i) at the bottom, flat shapes with septarian cracks filled by calcite and celestite, (ii) in the middle and at the top, cylindrical and cylindrical-complex concretions associated with prismatic barite, calcite and celestite filling conduits related to bioturbations, and (iii) at the top, cylindrical and cylindrical-complex concretions associated with calcite and celestite filling conduits related to bioturbations, and stocky shape concretions.We postulate that concretions have formed by dolomite cementation of the surrounding marls during early diagenesis in the zone of methanogenesis. The high sedimentation rate of the infilling seems to be a factor controlling the mineralogical composition of the concretions. Brown calcite precipitated in voids and fractures of the concretions. Celestite precipitated during burial, completing the filling of voids and fractures. Barite precipitated before celestite, but its time of precipitation relative to brown calcite remains unknown. 相似文献
18.
To study the sedimentary environment of the Lower Cambrian organic-rich shales and isotopic geochemical characteristics of the residual shale gas, 20 black shale samples from the Niutitang Formation were collected from the Youyang section, located in southeastern Chongqing, China. A combination of geochemical, mineralogical, and trace element studies has been performed on the shale samples from the Lower Cambrian Niutitang Formation, and the results were used to determine the paleoceanic sedimentary environment of this organic-rich shale. The relationships between total organic carbon (TOC) and total sulfur (TS) content, carbon isotope value (δ13Corg), trace element enrichment, and mineral composition suggest that the high-TOC Niutitang shale was deposited in an anoxic environment and that the organic matter was well preserved after burial. Stable carbon isotopes and biomarkers both indicate that the organic matter in the Niutitang black shales was mainly derived from both lower aquatic organisms and algaes and belong to type I kerogen. The oil-prone Niutitang black shales have limited residual hydrocarbons, with low values of S2, IH, and bitumen A. The carbon isotopic distribution of the residual gas indicate that the shale gas stored in the Niutitang black shale was mostly generated from the cracking of residual bitumen and wet gas during a stage of significantly high maturity. One of the more significant observations in this work involves the carbon isotope compositions of the residual gas (C1, C2, and C3) released by rock crushing. A conventional δ13C1–δ13C2 trend was observed, and most δ13C2 values of the residual gases are heavier than those of the organic matter (OM) in the corresponding samples, indicating the splitting of ethane bonds and the release of smaller molecules, leading to 13C enrichment in the residual ethane. 相似文献
19.
Lacustrine deep-water turbidite plays are a novel area for exploration in the Huimin Depression, Bohai Bay Basin. Turbidites in the Shang 847 block, a typical turbidite play in the Huimin Depression, provide an opportunity to study the factors controlling the reservoir properties and hydrocarbon accumulation in lacustrine turbidite sandstones. The reservoir quality of turbidite sandstones (very fine-grained, moderately to well sorted, mainly lithic arkose) in this study area are mainly controlled by the distribution patterns of carbonate cements and pseudomatrix. Significant inverse relationships exist between the volume of carbonate cement and both porosity and permeability of the turbidite sandstones. Carbonate cement is located preferentially near the margins of the sandstone bodies. Sandstones with distance from the sandstone–mudstone contact surface less than 0.7 m or with thickness less than 1.2 m are commonly tightly cemented (carbonate cement >15%) with low porosity and permeability (lower than 10% and 0.1 mD, respectively). The source of carbonate cement was most likely external, probably derived from the surrounding mudstone. Most pore-filling carbonate cements occurred during late diagenesis at burial depths greater than 2200 m. The petrophysical properties of turbidites have a positive relationship with the content of kaolinite and chlorite, but have a negative relationship with the content of illite. 2-D and 3-D reconstructions of non-oil bearing and oil-bearing layers indicate that dissolution of carbonate cement, feldspars and unstable rock fragments was more developed in oil-bearing layers than in non-oil bearing layers and hance oil-bearing layers have higher porosity and larger pore sizes. Petrophysical property appears to have a significant effect on the hydrocarbon accumulation in the turbidite sandstones. Sandstones with porosities lower than 9% and/or permeabilities lower than 0.78 mD are not prone to contain oil. 相似文献
20.
Composition, porosity, and reservoir potential of the Middle Jurassic Kashafrud Formation, northeast Iran 总被引：1，自引：0，他引：1
In the Kopet-Dagh Basin of Iran, deep-sea sandstones and shales of the Middle Jurassic Kashafrud Formation are disconformably overlain by hydrocarbon-bearing carbonates of Upper Jurassic and Cretaceous age. To explore the reservoir potential of the sandstones, we studied their burial history using more than 500 thin sections, supplemented by heavy mineral analysis, microprobe analysis, porosity and permeability determination, and vitrinite reflectance.The sandstones are arkosic and lithic arenites, rich in sedimentary and volcanic rock fragments. Quartz overgrowths and pore-filling carbonate cements (calcite, dolomite, siderite and ankerite) occluded most of the porosity during early to deep burial, assisted by early compaction that improved packing and fractured quartz grains. Iron oxides are prominent as alteration products of framework grains, probably reflecting source-area weathering prior to deposition, and locally as pore fills. Minor cements include pore-filling clays, pyrite, authigenic albite and K-feldspar, and barite. Existing porosity is secondary, resulting largely from dissolution of feldspars, micas, and rock fragments, with some fracture porosity. Porosity and permeability of six samples averages 3.2% and 0.0023 mD, respectively, and 150 thin-section point counts averaged 2.7% porosity. Reflectance of vitrinite in eight sandstone samples yielded values of 0.64-0.83%, in the early mature to mature stage of hydrocarbon generation, within the oil window.Kashafrud Formation petrographic trends were compared with trends from first-cycle basins elsewhere in the world. Inferred burial conditions accord with the maturation data, suggesting only a moderate thermal regime during burial. Some fractures, iron oxide cements, and dissolution may reflect Cenozoic tectonism and uplift that created the Kopet-Dagh Mountains. The low porosity and permeability levels of Kashafrud Formation sandstones suggest only a modest reservoir potential. For such tight sandstones, fractures may enhance the reservoir potential. 相似文献