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Diagenesis plays a crucial role in shale oil reservoir formation. However, complex organic-inorganic interactions result in pore system formation and heterogeneity changes at the centimeter, or even micrometer scale, which controls the evolution of shale oil reservoirs. In this paper, an integrated approach including core observation, thin section observation, cathodoluminescence thin section observation, scanning electron microscope, μ-XRF analysis, electron microprobe analysis, AMICS analysis, LA-ICP-MS analysis, and isotope analysis was used to clarify the laminae combination carbonate-rich shale, diagenetic alterations in different types of shale laminae and the controls on shale oil reservoir formation. According to the lamina combination, the carbonate-rich shale in the Permian Lucaogou Formation can be divided into three types. They are shale consists of dolomitic lamina and terrigenous felsic lamina (Type A shale), shale consists of calcite-rich tufaceous lamina and terrigenous felsic lamina (Type B shale) and shale consists of calcareous lamina and tufaceous lamina (Type C shale). Dolomite cementation is the major diagenesis in terrigenous felsic lamina of Type A shale. The dolomite can be identified as the early stage forming from recrystallization of micrite dolomite, and the late stage precipitate from adjacent dolomitic lamina. In the terrigenous felsic lamina of Type B shale, however, the calcite cementation is the dominated diagenesis, which was sourced from adjacent calcite-rich tufaceous lamina. Also, some feldspar dissolutions occurred in terrigenous felsic lamina during organic matter evolution. For the Type C shale, the main diagenetic alteration is micrite calcite recrystallization in calcareous lamina. The dissolution and precipitation of carbonate minerals between different laminae of carbonate-rich shale reveal that the organic matter evolution significantly influence the diagenetic alterations of inorganic minerals. Particularly, the diagenetic mass transfer and redistribution at the micro-scale in a relatively diagenetic system were confirmed by organic-inorganic interactions in laminated shale. In this process, dissolution pores and recrystallization pores have provided considerable reservoir pores for shale oil. • The laminae combination and diagenetic alterations of carbonate-rich shale were identified. • The diagenetic mass transfer at the micro-scale during organic-inorganic interactions in laminated shale were clarified. • The pores induced by diagenetic mass transfer within a closed system is crucial for shale reservoir formation. [ABSTRACT FROM AUTHOR]

Sandy-conglomerate reservoir has gradually become a major target of oil and gas exploration. Complex diagenetic process and diagenetic fluid play a significant role in affecting reservoir heterogeneity. Carbonate cements form at various stages of the diagenesis process and record various geological fluid information. Recently, one-billion-ton sandy conglomerate oil field was exposed in Triassic Baikouquan Formation, Mahu sag, Junggar Basin. Therefore, an integrated study applying casting thin sections, cathodeluminescence, fluorescence, carbon and oxygen stable isotopes, electronic probe microanalysis and aqueous fluid inclusions measurements was performed in order to identify the types of carbonate mineral and its representative diagenetic environment and discuss the influences of different CO2 injections on reservoir quality. The main findings are as follows: The reservoir is mainly composed of 70.33% conglomerate and 16.06% coarse-grained sandstone. They are characterized by low compositional maturity and abundant lithic debris. Four types carbonate cements are identified according to the petrological and geochemical characteristics, including two types of Mn-rich calcite, ferroan calcite, siderite and dawsonite. They display an unusual broad spectrum of δ13C values (−54.99‰ to +8.8‰), suggesting both organic and inorganic CO2 injections. The δ13C values of siderite are close to 0, and its formation is related to meteoric water. The δ13C values of ferroan calcite and the occurrence of dawsonite indicate the trace of inorganic mantle-derived magmatic fluids. The δ13C values and trace elements of Mn-rich calcite record the information of hydrocarbon-bearing fluids. The fluid inclusions measurement data and reservoir properties and oil-test data show that the oil content of reservoir is not only affected by the formation time of different cements, but also by the relative content of dissolution and cementation. For these reservoirs altered by carbonate cements, it does not cause poor oil-bearing due to blockage of secondary minerals. [ABSTRACT FROM AUTHOR]

• Carbonate cements and chlorite can alter some pore spaces from water-wet to oil-wet. • High oil saturation occurred in tight reservoirs with moderate carbonates or chlorite. • The high quality reservoirs mainly located in between with sandstone-mudstone interfaces and central parts of the sand bodies. Oil accumulation, being difficult and complicated, is an important issue in petroleum exploration researches. Authigenic minerals, such as carbonate cements and chlorite, can in certain reservoirs alter the wettability of some pore spaces from water-wet to oil-wet. Generally, these oil-wet pore spaces are favorable for oil accumulation. The alteration of reservoir wettability induced by authigenic minerals and the impacts on oil accumulation in tight sandstone reservoirs were investigated using a suite of mineralogical and geochemical characterization techniques, including thin section observation, SEM-EDS, XRD, QEMSEM, CL, quantitative grain fluorescence (QGF), fluorescence spectral analysis, contact angle measurement and sealed coring oil saturation testing on the fourth member of the Lower Cretaceous Quantou Formation (K 1 q 4) in the southern Songliao Basin, China. The study shows that the tight sandstone reservoirs are compositionally immature with detrital grains distributed homogeneously. Quartz, carbonates and clay minerals that show heterogeneous distribution characteristics are the major authigenic minerals in some parts of the intergranular pores. The detrital mineral assemblage suggests that the reservoir rocks at deposition and before diagenesis had characterized by strong water-wet properties. With the development of authigenic minerals, carbonate cements and authigenic chlorite tend to alter the wettability of some parts of the existing pore spaces from water-wet to oil-wet. In the K 1 q 4 sandstone reservoirs, oil prefers to accumulate in the cemented residual pore spaces around carbonate cements and chlorite. Reservoirs containing about 4–5% carbonate cements are suggested to be more preferable to oil accumulation. These reservoirs are mainly located between sandstone-mudstone interfaces and central parts of the sand bodies. Chlorites have mainly two effects: on one hand, chlorite alters the wettability of existing pore spaces and provides preferential accumulation sites for oil in the tight sandstone reservoirs, on the other hand it can reduce the adhesion of oil through forming "clay-oil flocs" and promote further migration. Consequently, the reservoirs with moderate amount of carbonate cements or chlorite always show relative high oil saturation in the K 1 q 4 tight sandstones. [ABSTRACT FROM AUTHOR]

Reservoir quality is the key parameter controlling shale oil enrichment. However, the complicated lithofacies, which control diagenesis, result in reservoir heterogeneity in the shale strata, creating challenges for reservoir prediction. Combining with the detail analysis of inorganic and organic geochemistry, characteristics of the main lithofacies and diagenetic alteration were investigated in Permian Lucaogou Formation, Jimusar sag, Junggar Basin. Laminated rocks with laminae combinations containing pyroclastic and terrigenous clastic laminae, terrigenous clastic and dolomite laminae, and pyroclastic and carbonate laminae were identified. Massive rocks mainly includes dolomicrite, dolomitic tuff, silt dolostone, dolomitic siltstone, and tuffaceous siltstone. Feldspar dissolution and carbonate cementation were the two dominant diagenetic types, further causing heterogeneity of the shale oil reservoirs. Feldspar dissolution generally occurred in laminated rocks containing pyroclastic laminae with low content of carbonate minerals (PL1), as well as in their adjacent interbedded siltstones. Carbonate cementation generally occurred in laminated rocks containing carbonate laminae, as well as in their adjacent interbedded siltstones. Whether in laminated and massive rocks, sparry carbonate crystals were also precipitated adjacent to organic matter and in microfractures. In the burial processes, enriched transition metal elements of V and Ti in pyroclastic laminae promote catalytic pyrolysis of organic matter. Abundant CO 2 produced during the catalytic pyrolysis promoted feldspar dissolution. Dissolution of sedimentary carbonate minerals by organic acids and CO 2 provided the material sources for secondary carbonate cements. It promoted the recrystallization and re-precipitation of sparry carbonate crystals adjacent to organic matter and in the terrigenous clastic laminae or interbedded siltstones. Ca2+, Mg2+ Sr2+, Fe2+, and Mn2+ produced by the transformation of smectite to illite in the pyroclastic laminae also provided Ca source for secondary carbonate cements. External diagenetic fluids providing materials along microfractures is another genesis of carbonate cements in the Permian Lucaogou Formation. • Petrographic features in the shale strata in Permian Lucaogou Formation were identified based on in situ analytical method. • Differential feldspar dissolution and carbonate precipitation generally occurred in different lithofacies. • Catalytic pyrolysis of organic matter in presence of transition metal elements in pyroclastic laminae promoted dissolution. • Development of carbonate cements in the shale strata were mainly provided by three material sources. [ABSTRACT FROM AUTHOR]

Understanding reservoir heterogeneity and associated diagenesis, have a paramount importance for efficient petroleum exploration and development strategies. Diagenetic variations and factors that control these processes have, therefore, been investigated in this study using petrographic and geochemical methods, including cathodoluminescence, scanning electron microscopy, x-ray fluorescence, electron probe microanalyses and stable isotope analysis. Mechanical compaction and chemical diagenesis trends have obviously varied as a function of rock types and geological locations. The conglomerate reservoirs with high content of tuffaceous matrix and characterized by poor sorting showed stronger compaction. The tuffaceous matrix displays a large degree of dissolution during the progressive burial diagenesis due to its thermodynamic instability. The tuffaceous matrix in Na-rich conglomerate reservoir rocks mainly transformed into analcite, while it transformed into illite in K-rich conglomerate reservoir rocks. In most conglomerate reservoirs far away from deep-rooted faults, calcite cements are indicated to have been sourced from the decarboxylation of organic matter in the interbedded mudstones. Carbonate cements in conglomerate reservoirs near the deep-rooted faults possibly formed from hydrothermal fluids or thermochemical oxidation of pre-existing methane accumulations. This study can serve us an excellent example for the control of sediment composition and paleo-fluid evolution on diagenetic variations in fan-delta conglomerate reservoirs. • Compaction and dissolution in conglomerate reservoirs were controlled by sediment composition and texture. • Authigenic silicoaluminate minerals formation in conglomerate reservoirs were controlled by sediment composition. • Carbonate cements formation in conglomerate reservoirs were controlled by paleo-fluids evolution. [ABSTRACT FROM AUTHOR]

The influence of oil-wet calcite cements on oil migration in clastic reservoirs is of significant interest in the field of petroleum exploration. However, the microscopic migration of oil in microscopic pore spaces with oil-wet calcite cements has not been directly observed. Microscopic observations of oil migration were conducted in a glass micromodel at normal temperature and pressure to investigate the influence mechanism of oil-wet calcite cements on oil migration in pore spaces. The calcites were precipitated as cements prior to the oil migration. A two-dimensional glass micromodel with two interconnected spaces with the same pore throat structures was used in the experimental study. A new method to create firmly adhering calcites was used to precipitate equal amounts of calcites in the two interconnected spaces. The oil migration was recorded in real-time under a microscope throughout the experiment. The experimental results show that oil migration occurs faster in spaces with than without oil-wet calcites. During the oil migration in the pore-throat spaces, the oil migrates towards the surfaces of the oil-wet calcites when the oil is in contact with the calcites. The presence of oil-wet calcites significantly reduces the oil breakthrough pressure. The electrostatic attraction between the carboxylic groups and calcites and the intermolecular forces between the carboxylic groups and organic molecules in the oil cause the oil migration towards the surfaces of the oil-wet calcites. The experimental results indicate that oil preferentially migrates into clastic reservoirs that possess appropriate amounts of oil-wet calcite cements precipitated prior to oil emplacement. • Experimental method that allows calcite to precipitate and adhere tightly in glass micromodel was developed. • Microscopic processes of the influence of oil-wet calcites on oil migration in pore spaces were observed in micromodel. • Mechanism of oil-wet carbonate minerals affecting oil migration and accumulation in pore spaces was discussed. [ABSTRACT FROM AUTHOR]

Carbonate concretion is an authigenic aggregation of minerals commonly found in sandstone and shale, especially in organic-rich shale. In the outcrop, large number of carbonate concretions developed in Chang 7 member in Tongchuan. Those concretions were studied in terms of stable isotope, clumped isotope to delineate its origin and sedimentary environment. Two types of concretions are identified. Type A concretionsmainly distribute in organic-rich shale. This concretion was divided into the inner circular layer and the outer circular layer. In the inner circular layer, the value of δ13C‰(VPDB) is 9.98‰~14.19‰, and the value of δ18O‰(VPDB) is −13.32‰~-10.07‰. On the contrary, the δ13C and δ18O value of outer circular layer are4.74‰~-0.59‰,-17.86‰~-15.59‰ respectively. The formation palaeotemperature of different parts of concretion ranged from 28.6 to 76.5 °C. This may be due to methanogenesis arising from bacterial activities in the fermentation zone, and the fractional distillation of carbon isotope of organic matter was caused by the methane bacterial activities. The calcite and dolomite spherulites in carbonate concretions may be due to the calcilization and dolomitization of cyanobacteria in the early diagenesis. The type B concretions were distributed in the fine sandstone, silty sandstone, and silty mudstone. The internal structure of concretions is uniform. The carbon isotopic values were negative, and δ13C was −5.019~-12.013‰, and the δ18O values was −17.6~-19.281‰. The value of 87Sr/86Sr was in the range of 0.710072–0.710392. The temperature was established at 60.4 °C through clumped isotopes analysis. Based on isotopic analysis, the formation palaeotemperature at different parts of concretion was 55.4–65.6 °C. The origin of the concretion may be related to dehydroxylation in diagenesis, formed in the early-middle stage of diagenesis. • Carbon, Oxygen and Strontium isotope are used in the article. • The origin of two kinds of concretions is discussed. • The formation temperature of concretions is determined by clumped isotope. [ABSTRACT FROM AUTHOR]