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Clastic rock reservoirs in petroliferous basins are generally rich in feldspars. Feldspar dissolution has developed widely in clastic reservoirs, and the resulting secondary pores are crucial in deeply buried reservoirs. Based on a study of the diagenesis of clastic reservoirs in the Bohai Bay Basin, Tarim Basin, and Pearl River Mouth Basin and physical and numerical simulation experiments of fluid-rock interactions, this paper proposed a successive formation model of secondary pores via feldspar dissolution in deeply buried clastic reservoirs, considering the global research progresses in feldspar dissolution in clastic rocks. Feldspar dissolution can occur from shallow open systems to deep-ultra deep closed systems in petroliferous basins, resulting in the successive formation of secondary pores at different diagenetic stages. The successive mechanism includes three aspects. The first aspect is the succession of corrosive fluids that dissolve minerals. Meteoric freshwater dominates at the Earth's surface and the early diagenetic A stage. Subsequently, organic acids and CO2 formed via kerogen maturation dominate at the early diagenetic B stage to the middle diagenetic stage. CO2 and organic acids formed via hydrocarbon oxidation in hydrocarbon reservoirs dominate at the middle diagenetic B stage to the late diagenetic stage. The second aspect is the successive formation processes of secondary pores via feldspar dissolution. Large-scale feldspar secondary pores identified in deep reservoirs include secondary pores formed at shallow-medium depths that are subsequently preserved into deep layers, as well as secondary pores formed at deep depths. Existing secondary pores in deeply buried reservoirs are the superposition of successively feldspar dissolution caused by different acids at different stages. The third aspect is a successive change in the feldspar alteration pathways and porosity enhancement/preservation effect. Open to semi-open diagenetic systems are developed from the Earth's surface to the early diagenetic stage, and feldspar dissolution forms enhanced secondary pores. Nearly closed to closed diagenetic systems develop in the middle to late diagenetic stages, and feldspar dissolution forms redistributional secondary pores. The associated cementation causes compression resistance of the rock, which is favorable for the preservation of secondary pores in deep layers. These new insights extend the formation window of secondary pores in petroliferous basins from the traditional acid-oil generation window to a high-temperature gas generation window after hydrocarbon charging. The proposed model explains the genesis of deep-ultra deep high-quality reservoirs with low-permeability, medium-porosity and dominating feldspar secondary pores, which is significant for hydrocarbon exploration in deep to ultra-deep layers. [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]

The Es1 sandstone is a fruitful hydrocarbon zone of Eocene Shahejie Formation. Therefore, the present study comprises the subsurface facies analysis established on the description of seven wells. Methods include core observation, thin section petrography, scanning electron microscope (SEM), cathodoluminescence (CL), and X-ray diffraction to evaluate the microfacies, lithofacies, and rock characteristics. Two microfacies of lithofacies have been established as sandstone microfacies and mudstone microfacies on the basis of grain size. Among them, sandstone is further divided into four sub-microfacies on the basis of microscopic studies, rock fragments and mineral composition, which are arkose sandstone, lithic arkose, feldspathic litharenite, and litharenite. These microfacies consisting quartz, feldspar as abundant detrital grains followed by rock fragments and micas, whereas calcite, ferro-calcite, quartz overgrowth, and clay are the main cement. The Es1 sandstone consists of good primary porosity and permeability as well as good secondary porosity caused by fracturing and dissolution of unstable minerals that enhance the reservoir quality. Whereas cementation and compaction reduce the reservoir characteristics. Studied formation divided into five lithofacies including conglomerate sandstone lithofacies, medium to coarse-grain sandstone lithofacies, fine sandstone lithofacies, siltstone lithofacies, and mudstone lithofacies. Core observation, sedimentary structures, facies sequences of the well log, and sedimentary composition reveal that Es1 deposited into the lacustrine delta fan depositional environment. Rock grain size indicates that Es1 contains mixtures of grains including pebbles, sand-size as well as minor silt and clay size. Grain size varies from conglomerate to clay size. The Es1 sandstone was deposited in braided river (conglomerates sandstone), channel bar, lacustrine, fluvial channel (massive bedding, cross-bedding, and graded bedding sandstone), deltaic, and flood-plain (siltstone and mudstone) sedimentary environment. It is concluded that higher transport energies in channels deposited coarse-grain sediments in shallowest part of the lake setting. However, the energy decreases towards greater depth which deposited mudstone in central part of the lake. [ABSTRACT FROM AUTHOR]

The Permian Fengcheng Formation is a set of complex sedimentary strata in the Mahu Sag, northwestern Junggar Basin, where various types of carbonate minerals occur. Coarse crystalline calcite assemblages and other carbonate minerals, such as dolomite, shortite and sodium carbonates, are also common in the Fengcheng Formation. Their dissolution by meteoric freshwater leaching at tectonic high positions, which was controlled by an unconformity, developed uncommonly high-quality secondary porosity and contributed to unconventional oil and gas exploration. Based on core analyses, thin section studies under optical and cathodoluminescence (CL) microscopes, geological interpretations of seismic profiles, and carbon and oxygen isotope composition analyses from coarse crystalline calcite assemblages and comparisons to other carbonate minerals, this study focuses on the origin of coarse crystalline calcite assemblages and the mechanism of unconformity-related dissolution to form hydrocarbon reservoir spaces. Coarse crystalline calcite assemblages are the products of multiple stages of recrystallization of other carbonate minerals in nearby host rocks. Hydrolysis of feldspar and volcanic sediments provided additional Ca2+ for calcite precipitation. The dissolution and reprecipitation of carbonate minerals were associated with organic maturation and hydrocarbon expulsion and migration. The crystallization process was slow, which allowed the crystal assemblages to grow to large sizes. Organic carbon was involved in the formation of the coarse crystalline calcite assemblages, which resulted in much more negative carbon isotope compositions than those of other carbonate minerals via diluting the carbon isotope compositions of preexisting carbonate minerals. Later tectonic uplift caused a regional unconformity and formed dissolution reservoirs in tectonically high positions. Furthermore, faults and fractures provided paths for the solutes to transfer to lower positions and reprecipitate when they became saturated. [ABSTRACT FROM AUTHOR]

The study of pore characteristics is of great importance in reservoir evaluation, especially in deeply buried sandstone. It controls the storage mechanism and reservoir fluid properties of the permeable horizons. The first member of Eocene Shahejie Formation (Es1) sandstone is classified as feldspathic litharenite and lithic arkose. The present research investigates the pore characteristics and reservoir features of the deeply buried sandstone reservoir of Es1 member of Shahejie Formation. The techniques including thin-section petrography, mercury injection capillary pressure (MICP), scanning electron microscopy and laser scanning confocal microscope images were used to demarcate the pores including primary intergranular pores and secondary intergranular, intragranular, dissolution and fracture pores. Mercury injection test and routine core analysis were led to demarcate the pore network characteristics of the studied reservoir. Pore size and pore throat size distribution are acquired from mercury injection test. Porosity values range from 0.5% to 30%, and permeability ranges 0.006–7000 mD. Pore radii of coarse-grained sandstone and fine-grained sandstone range from 0.2 to > 4 µm and 1 nm to 1.60 µm, respectively, by MICP analysis. The mineral composition also plays an important role in protecting the pores with pressure from failure. Fractured sandstone and coarse-grained sandstone consist of large and interconnected pores that enhance the reservoir porosity and permeability, whereas fine-grained sandstone and siltstone consist of numerous pores but not well interconnected, and so they consist of high porosity with low permeability. [ABSTRACT FROM AUTHOR]

As important metal sulfides in the geochemical cycle of sulfur, the characteristics and formation processes of pyrites can provide useful clues regarding their environment. Based on previous findings, shale pyrites were divided into three major classes (euhedral pyrites, framboidal pyrites (framboids) and metasomatic pyrites) and six sub-classes in this study. At the microscopic scale, each type of pyrite is associated with a different formation process. Framboids are formed by burst nucleation in environments with a homogeneous distribution of nutrients while euhedral pyrites are usually formed on pre-existing sites (such as =FeS on the minerals surface) in the heterogeneous system. Metasomatic pyrites formed by the replacement of other ions in accountable material by iron ions and hydrogen sulfide ions in hydrothermal events. The morphology and isotope value of pyrite provide information to track the origins of their nutrient and characteristics of sulfur and iron pools. In addition, the trace element content of pyrite can serve as a proxy for paleo-ocean trace element abundance, indicating changes in atmospheric oxygen content. Additionally, pyrite can also serves as an indicator of shale gas reservoirs. [ABSTRACT FROM AUTHOR]

Facies identification is a fundamental issue on evaluation and prediction for siliciclastic sediments. The purpose of this paper is to identify sedimentary-diagenetic facies and investigate the influence of sedimentary-diagenetic facies on reservoir quality in coarse-grained deposits from the Eocene Es4 interval, Dongying Depression, Bohai Bay Basin. Based on detailed core observation, thin section petrography combined with conventional wireline logs and core measurement analysis, 12 types of sedimentary- diagenetic facies were divided according to their lithofacies, diagenetic products and related contributions to reservoir quality. The identification and spatial distribution of these sedimentary-diagenetic facies can be determined based on the Bayes discriminant analysis and related cross-plot analysis. The variations of porosity and permeability with burial depth were precisely determined with ±2% for porosity and ±1 × 10–3 μm2 for permeability. The spatial distribution of reservoir porosity and permeability can be predicted quantitatively: high zones of porosity and permeability mainly distributed in the central sections of thick-bedded sandbody, ranging from 6% to greater than 12% for reservoir porosity and from 1 × 10–3 μm2 to greater than 6 × 10–3 μm2; relatively low zones of porosity (less than 6%) and permeability (less than 1 × 10–3 μm2) mainly occur in the bottom and the margin of the thick-bedded sandbody. [ABSTRACT FROM AUTHOR]

Petrographic analysis combined with thin section observation, fluid inclusions, burial history analysis, and core porosity and permeability, were used to determine diagenetic evolution and its effect on reservoir-quality of beach-bar sandstone reservoirs of Eocene Es4s interval in the Boxing sag, Bohai Bay Basin. Diagenesis is mainly characterized by strong compaction, undercompaction, cementation of carbonate, quartz, pyrite and clay minerals, dissolution of detrital grains and carbonate cements, lime-mud matrix recrystallization and hydrocarbon filling. Paragenetic sequence is determined as 'early compaction / precipitation of calcite, dolomite and framboidal pyrite → dissolution of feldspar grains and early-formed carbonate cements/precipitation of quartz → hydrocarbon filling → precipitation of ferroan calcite and ankerite/lime-mud matrix recrystallization → dissolution of ferroan carbonate cements'. In the same diagenetic environment, diagenetic processes for different lithofacies significantly varied and subsequently resulted in great heterogeneity for reservoir quality during progressive burial. Lithofacies for both bar body and beach edge subfacies which are far from sandstone-mudstone contacts, are well sorted and have a strong ability to resist compaction. Abundant primary and secondary porosities are well developed because of modifications by acidic dissolution and hydrocarbon filling. The present physical properties are relatively well and numerous oil beds are developed through shallow to deep burial depth. Lithofacies for both bar body and beach edge subfacies which are adjacent to sandstone-mudstone contacts, are typically characterized by extensive cementation of calcite and dolomite. The present physical properties are bad and dry beds are extensively developed for sandstone reservoirs in both bar body and beach edge subfacies which are adjacent to sandstone-mudstone contacts. Lithofacies for both bar edge and beach mat subfacies were deposited in weak hydrodynamic conditions with high contents of limemud matrix. The reservoir porosity decreases continually due to strong compaction and weak dissolution. The present physical properties are extremely poor and dry beds are commonly developed through shallow to deep burial except for minor oil beds developed in the shallow burial. [ABSTRACT FROM AUTHOR]

Various types of geofluids exist in deep and ultra-deep layers in petroliferous basins. The geofluids are much more active under high-temperature and high-pressure (HTHP) conditions, but their properties are unclear. We simulated the mixing of different fluids in CH4/C3H8/C6H14/C8H18-water systems and C6H14/C8H18-CO2-H2O systems at temperatures of 25°C to 425°C and pressures of 5 MPa to 105 MPa, using an in-situ micron quartz capillary tube thermal simulation system and molecular dynamics numerical simulation software. The mixing processes, patterns, and mechanisms of various fluids were analyzed at microscale under increasing temperature and pressure conditions. The results show that the miscibility of fluids in the different alkane-H2O and alkane-CO2-H2O systems is not instantaneous, but the miscibility degree between different fluid phases increases as the temperature and pressure rise during the experiments. The physical thermal experiments (PTEs) show that the mixing process can be divided into three stages: initial miscibility, segmented dynamic miscibility, and complete miscibility. The molecular dynamics numerical simulations (MDNSs) indicate that the mixing process of fluids in the alkane-H2O and alkane-CO2-H2O systems can be divided into seven and eight stages, respectively. The carbon number affects the miscibility of alkanes and water, and the temperature and pressure required to reach the same miscibility stage with water increase with the carbon number (C3H8, C6H14, CH4, C8H18). CO2 has a critical bridge role in the miscibility of alkanes and water, and its presence significantly reduces the temperatures required to reach the initial, dynamic, and complete miscibility of alkanes and water. The results are of great significance for analyzing and understanding the miscibility of geofluids in deep and ultra-deep HTHP systems. [ABSTRACT FROM AUTHOR]

During the burial processes of deep/ultra-deep hydrocarbon reservoirs, the interactions between hydrocarbon-bearing fluids and reservoirs significantly affect the quality evolution of hydrocarbons and reservoirs; thus, this topic requires further investigation. In this study, the continuous evolution and the coupling mechanisms in various anhydrous and hydrous nC16H34-(water)-(calcite) systems in fused silica capillary capsules (FSCCs) were investigated using laser Raman spectroscopy, fluorescence color analysis, and fluorescence spectroscopy, and the mineral alterations were analyzed using scanning electron microscopy (SEM). The experimental results show that extensive organic-inorganic interactions occur in the systems if water is present, and different inorganic components have different effects on hydrocarbon degradation. Distilled water promotes free-radical thermal cracking and steps oxidation, forming more low-molecular-weight hydrocarbons, CO2, and organic acids (e.g., acetic acids) but suppresses the free-radical cross-linking, generating less high-molecular-weight hydrocarbons. However, in the presence of CaCl2 water, the yields of hydrocarbon gases are lower than in the distilled water system because high concentrations of Ca ions inhibit the generation of free radicals. Calcites, which exhibit different surface reactivities in different fluid conditions, affect hydrocarbon degradation in different ways. In the anhydrous nC16H34-calcite system, calcites promote the generation of both hydrocarbon gases and high-molecular-weight hydrocarbons. In contrast, in the hydrous nC16H34-distilled (CaCl2) water-calcite system, calcites promote the generation of hydrocarbon gases and suppress the generation of high-molecular-weight hydrocarbons. Calcite also reacts with organic acids via surface reactions to form secondary pores. Therefore, except for the formation temperature and pressure, organic-inorganic interactions are controlled by multiple factors, such as the water saturation, water type, water salinity, and the mineral content, resulting in different evolutions of the hydrocarbon degradation and reservoir properties. [ABSTRACT FROM AUTHOR]

The Paleozoic Wufeng-Longmaxi shale is one of the main horizons for shale gas exploration in Sichuan Basin. Outcrop, core and thin section observations, X-ray diffraction analysis, trace element geochemistry and other methods have been used to understand the sedimentary characteristics and identify hydrocarbon source rocks in suitable sedimentary paleoenvironments in the Wufeng-Longmaxi shale in northern Guizhou Province. The thickness of the Wufeng-Longmaxi Formation ranges from 20 to 200 m and it was mainly deposited on a deep-water shelf. The TOC content is high, up to 5.75%. The main non-organic minerals are detrital quartz and clay minerals, with a little plagioclase feldspar, potassium feldspar, calcite, dolomite and pyrite. There is also biogenic microcrystalline quartz. Six lithofacies have been identified: siliceous shale, clay shale, calcareous shale, silty shale, carbonaceous shale, and muddy siltstone. Using biological Ba, V/(V+Ni), TOC, V/Cr, B, Sr/Ba and other indicators, we estimate primary productivity, redox conditions and paleosalinity and show that the early stage of Wufeng-Longmaxi deposition occurred under strong anoxic conditions, high paleosalinity and yielded a high TOC content and an excellent potential shale gas source. The anoxic environment was destroyed at the late stages of Wufeng-Longmaxi deposition, the TOC content decreased, so that it is likely to be a high quality source rock. Organic pores acted as the key reservoir space in the shales, and the pores are mainly mesopose, with most pore diameters less than 20 nm. The siliceous shale has high TOC content and brittle mineral (quartz) content making it an important exploration target for shale oil and gas exploration. [ABSTRACT FROM AUTHOR]

The Lower Permian Lucaogou Formation in the Jimsar sag, Junggar Basin is a typical tight-oil reservoir in China. For effective exploration and production, the formation of a high-quality reservoir must be thoroughly studied. In this work, the tight-oil reservoir was examined using a variety of methods, including core and thin-section observations, XRD, SEM, CL and fluid inclusion and isotope testing. The tight-oil reservoirs were primarily deposited in saline lake environments, which are dominated by variable admixture of dolomite, quartz, feldspar, tuff, calcite and pyrite. Nine main lithofacies were identified: (1) siliceous mudstone, (2) dolomitic siliceous mudstone, (3) dolomitic mudstone, (4) intraclast packstone/grainstone, (5) ooid grainstone, (6) bioclast grainstone, (7) dolomitic siltstone, (8) mixed siliclastic and intraclast grainstone and (9) brecciated dolomitic mudstone. The pore types are classified into four categories: primary intergranular, moldic, intercrystalline and fracture pores. The properties of tight-oil reservoirs are quite poor, with low porosity (ave. 7.85%) and permeability (ave. 0.110 mD) and a small pore-throat radius (ave. 0.086 μm). The tight-oil reservoirs are dominated by the aggradation of a repetitive meter-scale sedimentary facies succession that records distinct lacustrine expansions and contractions. These tight carbonates have also undergone significant diagenetic alterations, such as dolomitization, dissolution, neomorphism and fracture created intercrystalline and moldic pores, vug and fractures; chemical and mechanical compaction and carbonate cementation have decreased the reservoir quality. Variations in reservoir quality in the Jimusar sag are due to a combination of lithofacies type, high-frequency cyclic depositional architecture, dissolution intensity, dolomitization and tectonic related deformation. This integrated study has helped in understanding the reservoir heterogeneity and hydrocarbon potential of the Jimusar fine-grained rocks. [ABSTRACT FROM AUTHOR]

The sedimentary environment, formation conditions, sedimentary characteristics and the basin evolution model of high-frequency oscillatory lake in arid climatic background of the Lower Eocene in the Dongying depression were studied through the analysis of drilling cores, sporepollen, geochemistry and geophysics data. During the sedimentary period of the Eocene E k -E s formations, because of the frequent alternation between dry and wet climates in the arid climatic background and the gentle paleogeomorphology, the lake level and salinity of the Early Eocene Dongying depression frequently and rapidly increased and decreased, which is referred to as a high-frequency oscillatory lake. The sedimentation and distribution of sediments in this high-frequency oscillatory lake basin were controlled by the frequently alternating dry-wet climates. During periods with relatively wet climate, the seasonal floods and unstable rivers led to the formation of over-flooding lake deltas in the gentle slope belt, and fine-grained clastic sediments, with minor thin layers of gypsum-salt rocks in the sag belt. During the relatively arid climatic periods, sedimentation occurred mainly in the limited area of the sag belt with thick gypsum-salt rocks. Because of the impact of the salinity stratification of the lake water, these gypsum-salt rocks exhibit annular structural features. A sedimentary cycle of the oscillatory lake began with isochronous flood channels and ended with relatively thick gypsum rocks and salt rocks. The thickness of one oscillatory cycle is generally 4-20 m. The superposition of multiple sedimentary cycles of the oscillatory lake constitutes the overall vertical filling sequence of the high-frequency oscillatory lake basin. [ABSTRACT FROM AUTHOR]

In order to clarify the dynamic process of feldspar dissolution–precipitation and explore the formation mechanism of secondary porosity, six batch reactor experiments were conducted at 200 °C and pH = 7 measured at room temperature. Temporal evolution of fluid chemistry was analyzed with an inductively coupled plasma optical emission spectrometer (ICP-OES). Solid reaction products were retrieved from six batch experiments terminated after 36, 180, 276, 415, 766 and 1008 h. Scanning electron microscopy (SEM) revealed dissolution features and significant secondary mineral adhered on the feldspar surface. The process of feldspar dissolution–precipitation proceeded slowly and full equilibrium was not achieved after 1008 h. Saturation indices suggested that the albite and K-feldspar dissolution occurred throughout the experiments. The average dissolution rates for albite and K-feldspar were 2.28 × 10−10 and 8.51 × 10−11 mol m−2 s−1, respectively. Based on the experimental data, the reaction process of alkaline feldspar was simulated and the secondary porosity had increased 0.3% after the experiment. [ABSTRACT FROM AUTHOR]