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We investigated diagenesis of the sandstones from the DN2 Gas Field of the Kuqa Foreland Basin (KFB), in order to infer the timing of fluid migration and discuss the linkage between fluids and tectonics. The textures and chemical composition of authigenic minerals, fluid evidence from fluid inclusions and formation water measurements were all used to fulfill this aim. Eodiagenesis occurred with the participation of meteoric water and connate water. Mesodiagenesis is related to high salinity fluids, which were attributed as originating from the overlying Neogene Jidike Formation evaporite (principal minerals including halite, anhydrite, glauberite, carnallite and thenardite). The onset of high salinity fluid migration is inferred to occur during the late Miocene (12.4–9.2 Ma) through the use of homogenization temperatures measured in the present study and K‐Ar dating of authigenetic illites from previous work. This period is consistent with the crucial phase (13–10 Ma) that witnessed the rapid uplift of the southern Tianshan Mts and the stage when calcite and anhydrite veins formed in the studied strata. We thus argue that diagenesis related to high salinity fluids occurred as a response to the Tianshan Mts' rapid uplift and related tectonic processes. The flow of high salinity fluids was probably driven by a density gradient and channeled and focused by fractures formed contemporaneously. [ABSTRACT FROM AUTHOR]

The Cretaceous sandstone reservoir in the Kuche Depression, Tarim Basin, western China, was investigated with reference to its reservoir property evolution during diagenesis. Six general diagenetic stages were recognized through petrographic, mineralogical and geochemical analyses. Fluid-rock interaction experiments were conducted under these six continuous diagenetic conditions, that is with a simulation sequence of compaction → early diagenesis → organic acid incursion I → elevated temperature/pressure → organic acid incursion II → late diagenesis. Corresponding to these six experimental stages, a total of six models were constructed. Finally, an extended model of fluid-rock interaction during diagenesis at a geological timescale (from 30 Ma to present) was constructed after various parameters had been validated. Results demonstrate that the diagenetic stages from both the experimental and numerical simulations generally matched findings obtained from the petrographic and geochemical analyses: (i) With compaction becoming weakened, cementation by various minerals was gradually increased. (ii) Quartz overgrowth occurred because the contemporaneous sedimentary water was alkaline. (iii) Most minerals (for example, calcite and feldspar minerals) displayed dissolution owing to the first organic acid incursion, resulting in the visual porosity increasing to 29·26%. (iv) Increases in temperature and pressure caused a minor fluctuation of the porosity change. (v) The cement that formed during earlier stages largely dissolved with the second organic acid incursion. (vi) During the last stage, the reservoir fluid was diluted by sedimentary alkaline water and most minerals precipitated under an alkalic environment. The present porosity simulated is about 11·4%, comparable with the actually measured data. This study demonstrates that the combination of petrographic observations, laboratory experiments and numerical simulations can not only reconstruct the diagenetic process, but also provide a quantitative evaluation and prediction of reservoir petrophysical properties. [ABSTRACT FROM AUTHOR]

The reservoir diagenetic process and the petroleum charge histories of the Cretaceous Bashijiqike Formation (K 1 bs) in the Kuqa Depression, Tarim Basin were studied using an integrated petrographic, fluid inclusion, reservoir diagenesis and basin modeling approach. A suite of techniques were used in the investigation including optical microscopy, scanning electron microscope (SEM), X-ray diffraction (XRD), fluorescence spectroscopy, microthermometry, and Laser Raman microspectroscopy. The workflow comprises petrographic characterization of the reservoir sandstone, identification of fluid inclusion assemblages, and construction of the diagenetic history of the reservoir sandstone with reference to the hydrocarbon charge and emplacement. Key diagenetic events identified include quartz overgrowths, early calcite cementation, dolomite cementation, alteration of kaolinite, bitumen emplacement, micro-quartz and ankerite cementation. The first diagenetic event was characterized by quartz overgrowths and followed by calcite and dolomite cementation. Kaolinite and ankerite cementation were the last diagenetic events, coincided with hydrocarbon charge and emplacement. Three episodes of hydrocarbon charge and emplacement have been recorded by the diagenetic products and fluid inclusions in the K1bs Formations: (1) the first episode of oil charge was recorded in the early calcite cement, and were trapped around at 18 Ma; (2) the second and third episodes of hydrocarbon charge were recorded in the telo-diagenetic ankerite, and were trapped around at 4–6 Ma. The timing of oil emplacement determined from fluid inclusion homogenization temperature and basin modeling is consistent with the formation order of the diagenetic minerals. This study has thus demonstrated that integrated analysis of fluid inclusion and reservoir diagenesis can be an effective tool for determining hydrocarbon charge and emplacement history. [ABSTRACT FROM AUTHOR]

Carbonate reservoirs, especially dolomite reservoirs, contain large reserves of oil and gas. The complex diagenesis is quite challenging to document the dolomite reservoirs formation and evolution mechanism. Porosity development and evolution in dolomite reservoirs primarily reflect the comprehensive effect of mineral dissolution/precipitation during dolomitization. In this study, multicomponent multiphase flow and solute transport simulation was employed to investigate dolomitization in the deep carbonate strata of the Tarim Basin, Northwest China, where active exploration is currently under way. One- and two-dimensional numerical models with various temperatures, fluid compositions and hydrodynamic characteristics were established to quantificationally study dolomitization and its effect on porosity. After determining the main control factors, detailed petrologic characteristics in the studied area were also analyzed to establish four corresponding diagenetic numerical models under different sedimentary environments. These models enabled a systematic analysis of mineral dissolution/precipitation and a quantitative recovery of porosity evolution during various sedimentation-diagenesis processes. The results allowed for a quantitative evaluation and prediction of reservoir porosity, which would provide a basis for further oil and gas exploration in deep carbonate reservoirs. [ABSTRACT FROM AUTHOR]

The diagenetic evolution of the lower Eocene red-bed high-quality reservoirs in the Dongying Depression was systematically investigated through an integrated petrographic, petrophysical, fluid evolution and thermal history analysis. The reservoirs experienced several phases of diagenesis, including compaction, carbonate cementation, gypsum and ankerite cementation, feldspar and carbonate dissolution, quartz overgrowth cementation, and clay-mineral cementation and transformation. An early alkaline diagenetic environment caused significant cementation of calcite and gypsum in the reservoir sandstone units near the sandstone-mudstone contacts. Acidic formation fluids caused widespread dissolution of the feldspar and carbonate cements, leading to synchronous occurrences of primary intergranular pores and acidic dissolution pores. From the middle parts of the reservoir sandstone units to the sandstone-mudstone contacts, dissolution wanes gradually with ferro-carbonate progressively diminishing. Migration of exogenetic thermal fluid along faults may have contributed to the gradual decrease in dissolution and the gradual increase in cementation from the lower part to the upper part of fault blocks. The alternating alkaline and acidic diagenetic environments and the distribution of diagenetic products caused the development of the high-quality red-bed reservoirs in the middle part of the thick-layered sandstone units in the lower part of fault blocks. Because of the spatial and temporal relationships between the diagenetic stages and their products, lithological traps of a diagenetic origin were developed in the red-bed reservoirs. [ABSTRACT FROM AUTHOR]

Lacustrine carbonate-rich shales are well developed within the Mesozoic-Cenozoic strata of the Bohai Bay Basin (BBB) of eastern China and across southeast Asia. Developing an understanding of the diagenesis of these shales is essential to research on mass balance, diagenetic fluid transport and exchange, and organic-inorganic interactions in black shales. This study investigates the origin and distribution of authigenic minerals and their diagenetic characteristics, processes, and pathways at the scale of lacustrine laminae within the Es4s-Es3x shale sequence of the BBB. The research presented in this study is based on thin sections, field emission scanning electron microscope (FESEM) and SEM-catholuminescence (CL) observations of well core samples combined with the use of X-ray diffraction (XRD), energy dispersive spectroscopy, electron microprobe analysis, and carbon and oxygen isotope analyses performed using a laser microprobe mass spectrometer. The dominant lithofacies within the Es4s-Es3x sequence are a laminated calcareous shale (LCS-1) and a laminated clay shale (LCS-2). The results of this study show that calcite recrystallization 1 is the overarching diagenetic process affecting the LCS-1, related to acid generation from organic matter (OM) thermal evolution. This evolutionary transition is the key factor driving the diagenesis of this lithofacies, while the transformation of clay minerals is the main diagenetic attribute of the LCS-2. Diagenetic differences occur within different laminae and at variable locations within the same lamina level, controlled by variations in mineral composition and the properties of laminae interfaces. The diagenetic fluid migration scale is vertical and responses (dissolution and replacement) are limited to individual laminae, between zero and 100 μm in width. In contrast, the dominant migration pathway for diagenetic fluid is lateral, along the abrupt interfaces between laminae boundaries, which leads to the vertical transmission of diagenetic responses. The recrystallization boundaries between calcite laminae act as the main migration pathways for the expulsion of hydrocarbons from these carbonate-rich lacustrine shales. However, because the interaction between diagenetic fluids and the shales themselves is limited to the scale of individual lamina, this system is normally closed. The occurrence of abnormal pressure fractures can open the diagenetic system, however, and cause interactions to occur throughout laminae; in particular, the closed-open (C–O) diagenetic process at this scale is critical to this shale interval. Multi-scale C–O systems are ubiquitous and episodic ranging from the scale of laminae to the whole basin. Observations show that such small-scale systems are often superimposed onto larger ones to constitute the complex diagenetic system seen within the BBB combining fluid transport, material and energy exchange, and solid-liquid and organic-inorganic interactions. [ABSTRACT FROM AUTHOR]

Accurate prediction of reservoir porosity and permeability is essential for prospecting hydrocarbon reserves and petroleum production capacity. We propose an innovative reservoir porosity and permeability prediction method through identifying sedimentary-diagenetic facies, determining the porosity-permeability trends using core measurement data, extrapolating the spatial distribution of the sedimentary-diagenetic facies using log data through the Bayes discriminant analysis and predicting the reservoir porosity and permeability. The essence of the method was illustrated and its effectiveness was demonstrated using the Eocene beach-bar sandstones in the Dongying Depression, Bohai Bay Basin, eastern China. The Eocene beach bar sandstones are classified into fine sandstone, siltstone, and argillaceous siltstone based on grain sizes, sorting, and matrix contents. The major diagenetic processes that influence the porosity and permeability of the beach-bar sandstones are compaction, carbonate cementation and feldspar dissolution. Seven sedimentary-diagenetic facies were identified in the beach-bar sandstones based on the lithological types, and their corresponding diagenesis and influence extent on reservoir properties. The variation ranges of porosity and permeability (log K) of these sedimentary-diagenetic facies are typically less than 6% and 1.2, respectively. Both the porosity and permeability have well defined functional relationships with depth. The sedimentary-diagenetic facies can be identified effectively from logging data through the use of the Bayes discriminant analysis and corresponding cross-plots. The porosity and permeability (log K) of the well evaluated in the study were predicted with errors in the range of ±3% and ±0.6, respectively, based on the distribution and the fitting equation of the trend lines for the seven sedimentary-diagenetic facies. The predicted porosities and permeability of sedimentary-diagenetic facies match the measured porosities and permeability well. [ABSTRACT FROM AUTHOR]

The Kebai Fault zone of the West Junggar Basin in northwestern China is a unique region to gain insights on the formation of large-scale petroleum reservoirs in volcanic rocks of the western Central Asian Orogenic Belt. Carboniferous volcanic rocks are widespread in the Kebai Fault zone and consist of basalt, basaltic andesite, andesite, tuff, volcanic breccia, sandy conglomerate and metamorphic rocks. The volcanic oil reservoirs are characterized by multiple sources and multi-stage charge and filling history, characteristic of a complex petroleum system. Geochemical analysis of the reservoir oil, hydrocarbon inclusions and source rocks associated with these volcanic rocks was conducted to better constrain the oil source, the petroleum filling history, and the dominant mechanisms controlling the petroleum accumulation. Reservoir oil geochemistry indicates that the oil contained in the Carboniferous volcanic rocks of the Kebai Fault zone is a mixture. The oil is primarily derived from the source rock of the Permian Fengcheng Formation (P 1 f ), and secondarily from the Permian Lower Wuerhe Formation (P 2 w ). Compared with the P 2 w source rock, P 1 f exhibits lower values of C 19 TT/C 23 TT, C 19+20 TT/ΣTT, Ts/(Ts + Tm) and ααα-20R sterane C 27 /C 28 ratios but higher values of TT C 23 /C 21 , HHI, gammacerane/αβ C 30 hopane, hopane (20S) C 34 /C 33 , C 29 ββ/(ββ + αα), and C 29 20S/(20S + 20R) ratios. Three major stages of oil charge occurred in the Carboniferous, in the Middle Triassic, Late Triassic to Early Jurassic, and in the Middle Jurassic to Late Jurassic periods, respectively. Most of the oil charged during the first stage was lost, while moderately and highly mature oils were generated and accumulated during the second and third stages. Oil migration and accumulation in the large-scale stratigraphic reservoir was primarily controlled by the top Carboniferous unconformity with better porosity and high oil enrichment developed near the unconformity. Secondary dissolution pores and fractures are the two major reservoir storage-space types in the reservoirs. Structural highs and reservoirs near the unconformity are two favorable oil accumulation places. The recognition of the large-scale Carboniferous volcanic reservoirs in the Kebai Fault zone and understanding of the associated petroleum accumulation mechanisms provide new insights for exploring various types of volcanic reservoir plays in old volcanic provinces, and will undoubtedly encourage future oil and gas exploration of deeper strata in the region and basins elsewhere with similar settings. [ABSTRACT FROM AUTHOR]

Abstract: Tight gas sandstone (tight gas) reservoirs have been widely discovered in a number of basins in China including the Sichuan, Ordos, Turpan-Hami (Tuha), Songliao, Junggar, Tarim, Chuxiong and East China Sea basins. Genetically they are of either primary or secondary accumulations. The tight gas accumulations are mostly associated with coal strata. The reservoir rocks are mainly lithic arkosic sandstones and feldspathic lithic arenite. They are characterized by low compositional maturities, low cement contents and moderate petrological textural maturities. The diagenetic evolution of the reservoirs is generally at a high level, reaching the mid-late diagenesis stages. Reservoir porosities are dominated by secondary intragranular dissolution porosity and intergranular dissolution porosity with subordinate primary residual intergranular porosity. The pore throats are sheet like or bending-flake like in geometry and generally have poor connectivity. The tight gas reservoirs have poor petrophysical properties and show strong heterogeneities. Locally, some moderately porous and low permeable or low porous and moderately permeable sandstone reservoirs are present. Compaction and cementation appear to be key factors contributing to the formation of the tight gas sandstone reservoirs. Based on the synthesis of a vast data set obtained from some known tight sandstone gas accumulations from (1) the upper Palaeozoic sandstones in the Ordos Basin, (2) the Triassic Xujiahe Formation in the Sichuan Basin, (3) the Jurassic sandstones from the foothill belt in the Tuha Basin and (4) the Cretaceous deep reservoirs in the Songliao Basin, the criteria for recognizing tight gas sandstone reservoirs in China can be established as an in situ permeability of less than or equal to 0.1mD and with no natural commercial production. [Copyright &y& Elsevier]

The second member of the Upper Triassic Xujiahe Formation is an important target for tight gas exploration in the western Sichuan Basin. The diagenetic history and reservoir evolution were investigated using integrated analyses of petrography, X-ray diffraction (XRD), scanning electron microscopy (SEM), cathodoluminescence (CL), fluid inclusion microthermometry and stable carbon and oxygen isotopes. The sandstones consist mainly of litharenites, sublitharenites and feldsparthic litharenites with fine-to medium-sand grain sizes, moderate to good sorting and subangular to subrounded roundness. The reservoir properties of the sandstones are generally poor with low porosity and matrix permeability, small pore-throat radii, and high displacement pressure. Eodiagenesis is composed mainly of mechanical compaction, precipitation of siderite, stage-I quartz overgrowths, chlorite, calcite and ferroan calcite. Mesodiagenesis consists mainly of mechanical and chemical compaction, calcite and ferroan calcite precipitation, stage-II and stage-III quartz cementation, feldspar dissolution and precipitation of illite, dolomite and ankerite. Three types of sandstone lithofacies are defined according to sandstone textures and composition, diagenetic minerals, grain sizes, sorting and pore types: lithofacies I, II and III. Compaction appears to reduce the reservoir quality more significantly compared to cementation. Authigenic chlorite coats were constructive in preserving primary porosity, while carbonate cementation decreased reservoir quality. Diagenetic evolution pathways and reservoir quality prediction models for the Upper Triassic Xujiahe Formation sandstones have been proposed to shed light on the different reservoir quality evolution patterns of various sandstone lithofacies. Lithofacies I ─ medium and coarse-grained sandstones characterized by extensive chlorite coating, feldspar dissolution and a low content of clay matrix and cement, appears to have the best reservoir properties and may serve as a high-quality reservoir facies in these tight sandstone reservoirs. • The sandstones have undergone compaction, feldspar dissolution, quartz, carbonate and clay mineral cementations. • Compaction and cementation are prominently destructive diagenetic processes, while dissolution is effectively constructive. • The reservoir quality prediction models are proposed to elucidate the different evolution patterns of various lithofacies. [ABSTRACT FROM AUTHOR]

The tight reservoir property and oil accumulation are greatly affected by the complexity and heterogeneity of pore structure. Fine-grained, mixed sedimentary formation samples from the Permian Lucaogou Formation in the Jimsar Sag were systematically studied focusing on their fractal characteristics and effects on the storage space, minerals and diagenesis, and its implication for tight oil accumulation. Fractal dimensions were calculated by the MICP model equation. The lacustrine fine-grained, mixed sedimentary samples are characterized by single and multi-fractal structures. Compared with the multi-fractal reservoir, the pore-throat structure of single fractal reservoir is more uniform and the pore throat size is relatively smaller. Minerals and diagenesis have apparent influences on fractal characteristics of the lacustrine MSR tight oil reservoir. The enrichment of terrestrial minerals can increase the heterogeneity of storage space and might be the reason for the multi-fractal pore structures. The enrichment of tuff in mixed sedimentary rock (MSR) can greatly improve the property and reduce the fractal dimension of tight reservoirs through dissolution. Large-pore filling calcite has dual effects on destroying reservoir space and reducing heterogeneity, which makes the weak correlation between calcite and fractal dimension. Fractal characteristics implicate that pore structures play a very significant role in controlling the accumulation of tight oil. MSRs with D or D e more than 2.586 and porosity (average pore-throat radius) less than 6.3% (0.05 μm) are mostly incapable of effectively accumulating oil. • Pore structures of lacustrine fine-grained MSRs are characterized by single and multi-fractal structures. • Terrestrial minerals might be the reason for the multi-fractal pore structures. • Tuff reduce the fractal dimension of tight reservoirs through dissolution. • Fractal characteristics of pore structures play a very significant role in controlling the accumulation of tight oil. [ABSTRACT FROM AUTHOR]

Abstract In order to better predict the petrophysical properties of the tight sandstone reservoirs in the Upper Triassic Yanchang Formation, Ordos Basin, China, the nature of the diagenetic system involved was investigated using a suite of petrographic and geochemical techniques including thin section and X-Ray Diffraction analysis, scanning electron microscopy, MAPS mineralogy, Cathodeluminescence, electron probe microanalysis and fluid inclusion analysis on a set of selected tight sandstone samples. The sandstones investigated are texturally mature but compositionally immature with an average framework grain composition of Q 32 F 41 L 27. Authigenic quartz, calcite, and chlorite coatings are the major cements, while feldspars are partially dissolved. Two groups of quartz cement are present in the tight sandstone reservoirs. Smectite to illite conversion provided silica source for the first group of quartz overgrowth (Qo-I), while the silica source for the second quartz overgrowth (Qo-II) was mainly originated from feldspar dissolution. Calcite cements consist of two types, namely Ca-I and Ca-II. The Ca-I calcite cement contains no chlorite coatings and have higher concentrations of Fe2+ and Mg2+, whereas the Ca-II calcite cement developed over the chlorite coatings. Plagioclase dissolution appears to be always accompanied by calcite cementation, while K-feldspar albitization forms euhedral albite locally. The burial diagenesis processes were, in most cases, not episodic but occurred as slow adjustments in response to increased burial depths and temperatures. In all the studied diagenetic minerals, elemental distributions appear to be strictly constrained by the interaction of authigenic minerals involved, indicating that the chemical reactions during the diagenesis comply well with the general principle of mass balance. The diagenesis in the Upper Triassic Yanchang Formation tight sandstones was thus mainly developed in a closed geochemical system, where mineral dissolution and precipitation are approximately balanced, and diagenetic fluids were not affected by external sources significantly. Mechanical compaction has played a more important role in destroying the primary porosities of the Upper Triassic Yanchang Formation than the cementation. Highlights • There are two groups of quartz cement in the tight sandstone reservoirs. • Two types of calcite cement are present in the tight sandstone reservoirs. • Diagenesis of the tight sandstone reservoirs occurred in a closed geochemical system. [ABSTRACT FROM AUTHOR]

Abstract Lacustrine beach-bar sandstone reservoirs are economical important exploration targets in the Dongying Depression, Bohai Bay Basin. The factors that controls reservoir quality and hydrocarbon accumulation in lacustrine beach-bar sandstones were systematically investigated through an integrated petrographic, petrophysical, and diagenesis analysis. The reservoir properties of the beach-bar sandstones are mainly affected by compaction, carbonate cementation and dissolution. Significant negative relationships exist between both the porosity and permeability and the volume of carbonate cement. Carbonate cement is mainly distributed along the sandstone-mudstone contacts. Sandstones with thicknesses less than 1 m are generally tightly cemented to form zones with low petrophysical properties. The material source of the carbonate cement in the tightly cemented zone was highly likely from the interbedded mudstone. Content of carbonate cements in the center of the thick sandstones is low, whereas compaction is the dominant diagenetic process, with some dissolution. There is a positive correlation between the petrophysical properties of the beach-bar sandstones and the content of kaolinite. The petrophysical properties have an inverse correlation with the contents of illite and illite-smectite mixed-layer clays. Reservoir petrophysical property largely controls hydrocarbon accumulation in the beach-bar sandstones. Compared with non-oil bearing sandstones, oil-bearing sandstones have higher porosity and a larger pore-throat size. Sandstones with a porosity of less than 8.5% and/or low permeability of less than 1.02 × 10−3 μm2 are mostly incapable of accumulating oil. Highlights • The reservoir quality is controlled by compaction, carbonate cementation and dissolution. • Carbonate cementation mainly affects the reservoirs along the sandstone-mudstone contacts. • Compaction and dissolution mainly affect the reservoirs in the center of sandstones. • Reservoir petrophysical properties largely control hydrocarbon accumulation. • Lower limits of the porosity and permeability are required for hydrocarbon accumulation. [ABSTRACT FROM AUTHOR]

Generally, researchers believe that authigenic quartz precipitates in acidic medium and authigenic albite precipitates in alkaline medium. However, the lacustrine carbonate-rich fine-grained sedimentary rocks in the upper fourth sub-member and the lower third sub-member (Es 4 s–Es 3 x) of the Shahejie Formation in the Jiyang Depression were observed and it was found that authigenic microcrystalline quartz and albite generally develop together. Moreover, authigenic quartz and albite also develop with microcrystalline Fe-rich dolomite and calcite in clay laminae, while in carbonate laminae, they primarily develop with recrystallized calcite. In this study, thin-section, cathodoluminescence, field-emission scanning electron microscopy (FESEM), laser ablation inductively coupled plasma mass spectrometry (LA-ICP-MS) and inclusion analyses were conducted to study authigenic minerals. The results show that authigenic quartz and albite are characterized by rich Ge in mudstone, and the material components mainly originate from the transformation of clay minerals and the dissolution of terrigenous feldspar debris. In limestone, they are characterized by poor Ge, and the material components primarily originate from the transformation of clay minerals. The paragrowth and intergrowth of authigenic quartz and albite primarily depend on the degree of supersaturation of the corresponding ion concentration under high temperature, high or ultrahigh pressure. During the early diagenetic stage, authigenic quartz and albite initially formed in a weakly alkaline environment; however, on entering the middle diagenetic period, authigenic quartz, albite, and sparry calcite formed in a weakly acidic environment, and the formation rate reached its peak. Our results elucidate the migration direction and enrichment law of shale oil in calcareous fine-grained sedimentary rocks through the genetic mechanism of authigenic quartzs and albites. Shale oil is generated from organic matter in the clay lamina, following which it migrates, accumulates, and preserves to the adjacent sparry calcite lamina under the joint driving effect of organic matter hydrocarbon generation overpressure and clay mineral dehydration overpressure. • The paragrowth and intergrowth of authigenic quartz and albite mainly depend on the degree of ionic supersaturation. • Authigenic quartz and albite in mudstone primarily originate from clay minerals transformation and feldspar clasts dissolution. • Authigenic quartz and albite in limestone primarily originate from the transformation of clay minerals. • The origin mechanism of authigenic quartz and albite indicates the migration direction and enrichment mechanism of shale oil. [ABSTRACT FROM AUTHOR]

Lamina, a common lithologic unit in shale, is the smallest unit for organic–inorganic fluid–rock interactions. The effects of lamina-scale diagenetic processes are superimposed to exert on lithofacies-scale diagenetic sequences, which further impose on the entire diagenetic system of a shale reservoir. Organic acids from kerogen maturation are indispensable components in diagenetic reaction. However, previous studies mainly focused on low molecular weight (LMW) water soluble acids, few studies have paid attention to the role of high molecular weight (HMW) carboxylic acids dissolved in fluid–rock reactions. Herein, by taking the shale of the seventh member of the Upper Triassic Yanchang Formation in the Ordos Basin, China, as a case study, we investigate the mutual impacts between mineral alteration and HMW organic acid degradation. The characterization is carried out at two scales: lamina-scale (organic-rich clay-rich lamina and organic-lean silty lamina) and lithofacies-scale (shale and sandstone). Integrated analytical techniques (microdrill technique, thin section observation, X-ray diffraction, advanced mineral identification and characterization system, Rock-Eval pyrolysis, Fourier transform ion cyclotron resonance mass spectrometry) are performed. Results show that, in reservoirs of both silty lamina and sandstone, consumption of LMW aqueous acids through mineral transformation reactions promotes the forward evolution of HMW carboxylic acids in the bitumen phase toward decarboxylation or dehydration. During diagenesis, short chain fatty acids (SCFAs) are more easily broken down into small acids and, thus, more susceptible to be consumed. The lamina-scale reservoirs (silty lamina) have the privilege to receive abundant aqueous organic acids to maintain the micro-geochemical environment and progressively boost organic–inorganic fluid–rock interactions. The resultant dissolution pores not only accumulate plenty of bitumen but also an appreciable amount of bitumen dissolved acids. Because of the strong storage capacity of silty lamina within lithofacies-scale source rock (shale), fluids are less readily to expel out to lithofacies-scale reservoir (sandstone). As a result, the sandstone may not receive enough fluids from shale to maintain a consistent diagenetic environment, resulting in the observed discontinuous diagenesis of quartz precipitation transition to quartz dissolution. [ABSTRACT FROM AUTHOR]

The diagenetic characteristics and differences between the Eocene red-bed sandstone deposited in an arid environment and gray-bed sandstone deposited in a relatively humid environment were investigated systematically by an integrated analysis of petrography, X-ray diffraction, carbon and oxygen stable isotopes and fluid inclusion microthermometry. Strong eodiagenetic calcite and gypsum/anhydrite cementation occurred at the boundary of the Eocene red-bed sandstone, while the centre of the red-bed sandstone was characterized by relatively strong quartz dissolution and weak mesodiagenetic feldspar dissolution and ferro-carbonate cementation. Eodiagenetic calcite cementation at the boundary of the gray-bed sandstone and quartz dissolution were relatively weak, while the carbonate cemented zone at the boundary of the gray-bed sandstone was strengthened by mesodiagenetic ferro-carbonate cement. Relatively strong feldspar dissolution and ferro-carbonate cementation occurred in the centre of gray-bed sandstone beds. By comparing the diagenetic differences between the red-bed sandstones and gray-bed sandstones, it is shown that sedimentary environment had an obvious influence on reservoir diagenetic evolution and reservoir properties through influencing the chemical properties of connate water, the transformation rate and degree of clay minerals in interbedded mudstone, and the properties of diagenetic fluids during burial process. • Eodiagenetic calcite cementation and quartz dissolution in the red-bed were stronger than that in the gray-bed sandstone. • Mesodiagenetic feldspar dissolution and carbonate cementation in the red-bed were weaker than that in the gray-bed sandstone. • Reservoir space in the red-bed is mainly primary pores, while that in the gray-bed is mainly secondary pores. • Sedimentary environment had obvious influence on the reservoir diagenetic evolution. [ABSTRACT FROM AUTHOR]