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Pure shales in the first member of Qingshankou Formation (simplified as Qing 1 Member) in the southern Songliao Basin, i.e., the semi-deep and deep lacustrine shales, are characterized by a high content of clay minerals and poor hydrocarbon mobility, making the development of shale oil difficult. According to the drilling and testing results, the shale of Qing 1 Member can be classified into 3 lithofacies, i.e., bedded argillaceous shale, laminated diamictite shale, and interbedded felsic shale. The TOC and brittle minerals control the enrichment of shale oil, of them, TOC controls the total oil content, in other words, the total oil content increases with the increase of TOC; while the laminae made up of brittle minerals contain a large number of bigger intergranular pores which are favorable enrichment space for movable shale oil. In consideration of the origins of the 3 lithofacies, two shale oil enrichment models are classified, i.e., the deep lacustrine high-TOC bedded argillaceous shale (Model-I) and the semi-deep lacustrine moderate-high-TOC laminated diamictite shale (Model-II). In the Model-I, the shale is characterized by high hydrocarbon generation ability, high total oil content, abundant horizontal bedding fractures, and vertical and high angle fractures locally; the complex fracture network formed by horizontal bedding fractures and vertical fractures improve the storage capacity and permeability of the shale reservoir, increase the enrichment space for movable oil. In the Model-II, the shale is characterized by good hydrocarbon generation ability and fairly high total oil content, and as the brittle laminae contain large intergranular pores, the shale has a higher movable oil content. Based on the two models, shale oil sweet-spot areas of 2880 km 2 in the southern Songliao Basin are favorable for further exploration. Aimed at the difficulties in reservoir fracturing of the lacustrine shale with a high content of clay minerals, the composite fracturing technology with supercritical carbon dioxide was used in the shale oil reservoir for the first time, realizing large-scale volume fracturing in shale with a high content of clay minerals and strong heterogeneity, marking a breakthrough of oil exploration in continental shale with a high content of clay minerals in China.
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Based on the latest geological, seismic, drilling and outcrop data, we studied the geological structure, tectonic evolution history and deformation process of the southwestern Sichuan fold-thrust belt to find out the potential hydrocarbon exploration areas in deep layers. During key tectonic periods, the southwestern Sichuan fold-thrust belt developed some characteristic strata and structural deformation features, including the Pre-Sinian multi-row N-S strike rifts, step-shaped platform-margin structures of Sinian Dengying Formation, the western paleo-uplift in the early stage of Late Paleozoic, the Late Paleozoic-Middle Triassic carbonate platform, foreland slope and forebulge during Late Triassic to Cretaceous, and Cenozoic multi-strike rejuvenated fold-thrusting structures. The fold-thrust belt vertically shows a double-layer structural deformation controlled by the salt layer in the Middle Triassic Leikoupo Formation and the base detachment layer at present. The upper deformation layer develops the NE-SW strike thrusts propagating toward basin in long distance, while the deeper deformation layer had near north-south strike basement-involved folds, which deformed the detachment and thrusting structures formed earlier in the upper layer, with the deformation strength high in south part and weak in north part. The southern part of the fold-thrust belt is characterized by basement-involved fold-thrusts formed late, while the central-northern part is dominated by thin-skin thrusts in the shallow layer. The Wuzhongshan anticlinal belt near piedmont is characterized by over-thrust structure above the salt detachment, where the upper over-thrusting nappe consists of a complicated fold core and front limb of a fault-bend fold, while the deep layer has stable subtle in-situ structures. Favorable exploration strata and areas have been identified both in the upper and deeper deformation layers separated by regional salt detachment, wherein multiple anticlinal structures are targets for exploration. Other potential exploration strata and areas in southwestern Sichuan fold-thrust belt include the deep Sinian and Permian in the Wuzhongshan structure, pre-Sinian rifting sequences and related structures, platform-margin belt of Sinian Dengying Formation, and Indosinian paleo-uplift in the east of the Longquanshan structure.
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Large-scale gas accumulation areas in large oil-gas basins in central and Western China have multiple special accumulation mechanisms and different accumulation effects. Based on the geological theory and method of natural gas reservoir formation, this study examined the regional geological and structural background, formation burial evolution, basic characteristics of gas reservoirs, and fluid geology and geochemistry of typical petroliferous basins. The results show that the geological processes such as structural pumping, mudstone water absorption, water-soluble gas degasification and fluid sequestration caused by uplift and denudation since Himalayan stage all can form large-scale gas accumulation and different geological effects of gas accumulation. For example, the large-scale structural pumping effect and fluid sequestration effect are conducive to the occurrence of regional ultra-high pressure fluid and the formation of large-scale ultra-high pressure gas field; mudstone water absorption effect in the formation with low thickness ratio of sandstone to formation is conducive to the development of regional low-pressure and water free gas reservoir; the water-soluble gas degasification effect in large- scale thick sandstone can not only form large-scale natural gas accumulation; moreover, the degasification of water-soluble gas produced by the lateral migration of formation water will produce regional and regular isotopic fractionation effect of natural gas, that is, the farther the migration distance of water-soluble gas is, the heavier the carbon isotopic composition of methane formed by the accumulation.
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The origin of overpressure and its effect on petroleum accumulation in the large Permian/Triassic conglomerate oil province in the Mahu Sag, Junggar Basin have been investigated based on comprehensive analysis of log curve combinations, loading-unloading curves, sonic velocity-density cross-plot, and porosity comparison data. The study results show that there are two kinds of normal compaction models in the study area, namely, two-stage linear model and exponent model; overpressure in the large conglomerate reservoirs including Lower Triassic Baikouquan Formation and Permian Upper and Lower Wu’erhe Formations is the result of pressure transfer, and the source of overpressure is the overpressure caused by hydrocarbon generation of Permian Fengcheng Formation major source rock. The petroleum migrated through faults under the driving of hydrocarbon generation overpressure into the reservoirs to accumulate, forming the Permian and Triassic overpressure oil and gas reservoirs. The occurrence and distribution of overpressure are controlled by the source rock maturity and strike-slip faults connecting the source rock and conglomerate reservoirs formed from Indosinian Movement to Himalayan Movement. As overpressure is the driving force for petroleum migration in the large Mahu oil province, the formation and distribution of petroleum reservoirs above the source rock in this area may have a close relationship with the occurrence of overpressure.
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Based on analysis of NMR T2 spectral characteristics, a new method for identifying fluid properties by decomposing T2 spectrum through signal analysis has been proposed. Because T2 spectrum satisfies lognormal distribution on transverse relaxation time axis, the T2 spectrum can be decomposed into 2 to 5 independent component spectra by fitting the T2 spectrum with Gauss functions. By analyzing the free relaxation response characteristics of crude oil and formation water, the dynamic response characteristics of the core mutual drive between oil and water, the petrophysical significance of each component spectrum is clarified. T2 spectrum can be decomposed into clay bound water component spectrum, capillary bound fluid component spectrum, micropores fluid component spectrum and macropores fluid component spectrum. According to the nature of crude oil in the target area, the distribution range of T2 component spectral peaks of oil-bearing reservoir is 165-500 ms on T2 time axis. This range can be used to accurately identify fluid properties. This method has high adaptability in identifying complex oil and water layers in low porosity and permeability reservoirs.
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Through field geologic survey, fine interpretation of seismic reflection data and analysis of well drilling data, the differential deformation, tectonic transfer and controlling factors of the differential deformation of the Gumubiezi Fault (GF) from east to west have been studied systematically. The study shows that GF started to move southward as a compressive decollement along the Miocene gypsum-bearing mudstone layer in the Jidike Formation at the Early Quaternary and thrust out of the ground surface at the northern margin of the Wensu Uplift, and the Gumubiezi anticline formed on the hanging wall of the GF. The displacement of the GF decreases gradually from 1.21 km in the east AA′ transect to 0.39 km in the west CC′ transect, and completely disappears in the west of the Gumubiezi anticline. One part of the displacement of the GF is converted into the forward thrust, and another part is absorbed by Gumubiezi anticline. The formation of the GF is related to the gypsum-bearing mudstone layer in the Jidike Formation and barrier of the Wensu Uplift. The differential deformation of the GF from east to west is controlled by the development difference of gypsum-bearing mudstone layer in the Jidike Formation. In the east part, gypsum-bearing mudstone layer in the Jidike Formation is thicker, the deformation of the duplex structure in the north of the profile transferred to the basin along gypsum-bearing mudstone layer; to the west of the Gumubiezi structural belt (GSB), the gypsum-bearing mudstone layer in Jidike Formation decreases in thickness, and the transfer quantity of deformation of the duplex structure along the gypsum-bearing mudstone layer to the basin gradually reduces. In contrast, on the west DD′ profile, the gypsum-bearing mudstone is not developed, the deformation of the deep duplex structure cannot be transferred along the Jidike Formation into the basin, the deep thrust fault broke to the surface and the GF disappeared completely. The displacement of the GF to the west eventually disappeared, because the lateral ramp acts as the transitional fault between east and west part of GSB.
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Based on comprehensive analysis of core, cast thin section, logging and seismic data, the sedimentary and reservoir architectures of the MB1-2 sub-member of Mishrif Formation in Halfaya Oilfield, Iraq, are studied. The MB1-2 sub-member of Mishrif Formation has three types of microfacies, lagoon, bioclastic shoal, and tidal channel, and facies architecture controlled by sequence stratigraphy. In the 4 th-order sequence, the lagoon facies aggradated vertically, and the bioclastic shoals in lenticular shape embed in the background of lagoon, the end of the sequence is incised by the "meandering river" shape tide channel, which represents the depositional discontinuity. Three types of reservoirs including tidal channel grainstone to packstone reservoirs, bioclastic shoal grainstone to packstone reservoirs and dissolved lagoon wackestone reservoirs are developed. The reservoir architectures within tidal channel and bioclastic shoal are strickly controlled by grainy facies, whereas the dissolved lagoon reservoirs controlled by both facies and dissolution are related to the sequence boundary. The reservoir sections occur mainly in the 4th sequence highstand systems tract (HST) and are separated by barriers formed in the transgressive systems tract (TST). Complicated facies architecture and dissolution modification resulted in strong heterogeneity within the reservoir, which showed the characteristics of "attic type" architecture. The results of this study can guide the development of similar reservoirs in the Middle East.
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The influence of water on gas generation from humic type organic matter at highly to over mature stage was investigated with thermal simulation experiments at high temperature and pressure. The result of the experiments indicates that the effect of water on gas generation was controlled by the thermal maturity of organic matter. Water could enhance gas generation and increase hydrocarbon gas yields significantly at over mature stage of humic type organic matter. Hydrogen isotopic compositions of coal-derived gases generated at highly to over mature stage were mainly controlled by thermal maturity of source rocks, but also affected by formation water. Highly and over mature coal measure source rocks are widely distributed in China. The hydrocarbon gas generation capacity of coal measure source rocks and resource potential of coal-derived gases in deep formations would be significantly enhanced assuming that formation water could be involved in the thermal cracking of highly to over mature organic matter in real geological settings.
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Layering detection is an important step in petroleum engineering. Time series of post-stack seismic data and wire-line log data belong to subsurface layering. They exhibit multifractal properties with complex patterns because of the heterogeneity and different genetic properties in the earth layers. In a multifractal configuration, any piece of a series has a distinct Hurst exponent that reflects its nature and can be used for zone detection. Time series are post-stack seismic traces and wire-line log data near the well-bores. Self-similar Autoregressive Exogenous (SAE) model is a modified method which can place self-similar post-stack seismic and wire-line log segments across layers with the same lithology. The results satisfy the capability of layering identification from seismic data by SAE model.
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The Duvernay project in Canada was taken as an example to summarize the advanced technology and engineering management model of shale oil and gas development in North America. Preliminary suggestions were put forward to accelerate the commercial development of domestic continental shale oil and gas. The advanced technologies, valuable knowledge and rich experience were introduced, including the evaluation of geological target area of the project, rapid long horizontal drilling and completion, high-intensity fracturing, and well spacing optimization. In particular, the concept and connotation of the full-life cycle management of North American unconventional resource projects were analyzed. Its emphasis on early evaluation and risk management, and a highly competitive market environment have played an important role in promoting technological innovation and management innovation. In addition, the low-cost sharing system of industry-wide knowledge and experience and the management mode were applied. These management approaches are of great significance for reference in accelerating the exploration and development of unconventional resources in China. China possesses abundant shale oil and gas resources, which are an important replacement to guarantee the national oil and gas energy supply. However, due to the late start and special geological characteristics and engineering difficulties in China, there is a large gap in technology level and management mode compared with North America. According to the advanced experience and enlightenment of the shale oil and gas development in North America, a preliminary proposal to accelerate the development of shale oil and gas in China was made.
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By using salt dissolution experiment, imbibition experiment and high temperature and high pressure nuclear magnetic resonance (NMR) on-line test, the evaluation methods for salt dissolution of inter salt shale oil-bearing cores were established, and the effects of salt dissolution on spontaneous imbibition and permeability were analyzed. The intensity of salt dissolution is quantitatively evaluated by comparing the signal quantity and distribution characteristics of T2 spectrum (transverse relaxation time) measured at different times. In salt dissolution experiment, salt in the core is gradually dissolved as the injected water is continuously immersed in the core. The spontaneous imbibition experiment of inter-salt shale oil-bearing core can be divided into three stages: strong imbibition and weak salt dissolution, strong salt dissolution promoting imbibition, and weak salt dissolution and weak imbibition. The salt dissolution in spontaneous imbibition is very obvious, and the salt dissolution contributes more than 60% of recovery. The micro-pore structure in different cross sections or different parts of inter-salt shale oil-bearing core isn’t uniform, and the pore volume, porosity and permeability increase after salt dissolution.
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Tight oil reservoir development is faced with the key technical problem that "water cannot be injected and oil cannot be produced" yet. With the diphenyl ethers water-soluble (gemini) surfactants as water phase shell and C10-C14 straight-chain hydrocarbon compounds as oil phase kernel, a nanofluids permeation flooding system was prepared by microemulsion technology, and its characteristics and EOR mechanisms were evaluated through experiments. The system has the following five characteristics: (1) "Small-size liquid": the average particle size of the system is less than 30 nm, which can greatly reduce the starting pressure gradient of water injection, and effectively enter and expand the sweep volume of micro-nano matrix; (2) "Small-size oil" : the system can break the crude oil into "small-size oil" under the flow condition, which can greatly improve the percolation ability and displacement efficiency of the crude oil in the micro-nano matrix; (3) Dual-phase wetting: the system has contact angles with the water-wet and oil-wet interfaces of (46±1)° and (68±1)° respectively, and makes it possible for capillarity to work fully under complex wetting conditions of the reservoir; (4) High surface activity: the interfacial tension between the system and crude oil from a tight oil reservoir in Xinjiang is 10 -3-10 -2 mN/m, indicating the system can effectively improve the displacement efficiency of oil in fine pore throats; (5) Demulsification and viscosity reduction: the system has a demulsification and viscosity reduction rate of more than 80% to inversely emulsified crude oil from a tight oil reservoir in Xinjiang, so it can improve the mobility of crude oil in the reservoir and wellbore. The system can be used to increase oil production by fracturing in tight reservoirs, replenish formation energy by reducing injection pressure and increasing injection rate, and enhance oil recovery by displacement and cyclic injection, providing key technical support for effective production and efficient development and recovery enhancement of tight reservoirs.
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In view of high oil viscosity at high temperatures, slow steam chamber expansion rate, low oil rate, and low oil/steam ratio of domestic super heavy oil blocks developed with dual-horizontal well steam assisted gravity drainage (SAGD), the solvent-aided oil viscosity reduction tests were carried out, based on which the analytical equations and similarity laws of solvent-expanded SAGD (ES-SAGD) were deduced. The large 2-D ES-SAGD scaled physical simulation experiments were conducted to compare the SAGD performances of the conventional steam and two formulas of solvent-steam system. The experimental results show that the light hydrocarbon solvents have good viscosity reduction effects to oil, and the oil reduction ratio can reach 96.5% by adding 5% N-hexane at 50 ℃. Moreover, adding light hydrocarbon solvent (10% in the experiments) into the steam can bring the oil viscosity reduction effect of solvent and high temperature steam into play, speed up the lateral steam chamber expansion rate, increase the oil drainage rate and enhance the oil recovery degree. Adding 1% of xylene into the steam-solvent system can dissolve the asphalt to reduce asphalt precipitation, reduce the porous flow resistance and further enhance the oil recovery factor. The ES-SAGD recovery by reusing the solvents can realize replacement of the steam with small amount of solvents. Although currently higher in cost, the technology has the advantages of higher oil drainage rate, reduced production period, and enhanced oil recovery. The ES-SAGD theoretical model by modifying the SAGD model based on the oil viscosity reduction characteristics of solvents has been validated by the experiments and can be applied in ES-SAGD production predictions.
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It is difficult to build an effective water flooding displacement pressure system in the middle section of a horizontal well in an ultra-low permeability sandstone reservoir. To solve this problem, this study proposes to use packers, sealing cannula and other tools in the same horizontal well to inject water in some fractures and produce oil from other fractures. This new energy supplement method forms a segmental synchronous injection-production system in a horizontal well. The method can reduce the distance between the injection end and the production end, and quickly establish an effective displacement system. Changing the displacement between wells to displacement between horizontal well sections, and point water flooding to linear uniform water flooding, the method can enhance water sweeping volume and shorten waterflooding response period. The research shows that: (1) In the synchronous injection and production of horizontal well in an ultra-low-permeability sandstone reservoir, the water injection section should select the section where the natural fractures and artificial fractures are in the same direction or the section with no natural fractures, and the space between two sections should be 60-80 m. (2) In addition to controlling injection pressure, periodic water injection can be taken to reduce the risk of re-opening and growth of natural fractures or formation fracture caused by the gradual increase of water injection pressure with water injection going on. (3) Field tests have verified that this method can effectively improve the output of single well and achieve good economic benefits, so it can be widely used in the development of ultra-low permeability sandstone reservoirs.
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The effects of gravity, capillary force, and viscous force on the migration characteristics of oil and gas interface in oxygen-reduced air-assisted gravity drainage (OAGD) were studied through a two-dimensional visualization model. The effects of bond number, capillary number and low-temperature oxidation on OAGD recovery were studied by long core displacement experiments. On this basis, the low-temperature oxidation number was introduced and its relationship with the OAGD recovery was established. The results show that the shape and changing law of oil and gas front are mainly influenced by gravity, capillary force and viscous force. When the bond number is constant (4.52×10 -4), the shape of oil-gas front is controlled by capillary number. When the capillary number is less than 1.68×10 -3, the oil and gas interface is stable. When the capillary number is greater than 2.69×10 -2, the oil and gas interface shows viscous fingering. When the capillary number is between 1.68×10 -3 and 2.69×10 -2, the oil and gas interface becomes capillary fingering. The core flooding experiments results show that for OAGD stable flooding, before the gas breakthrough, higher recovery is obtained in higher gravity number and lower capillary number. In this stage, gravity is predominant in controlling OAGD recovery and the oil recovery could be improved by reducing injection velocity. After gas breakthrough, higher recovery was obtained in lower gravity and higher capillary numbers, which means that the viscous force had a significant influence on the recovery. Increasing gas injection velocity in this stage is an effective measure to improve oil recovery. The low-temperature oxidation number has a good correlation with the recovery and can be used to predict the OAGD recovery.
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The feasibility of gas kick early detection outside the riser was analyzed based on gas-liquid multiphase flow theory. Then an experimental platform for gas kick early detection based on Doppler ultrasonic wave was established and the propagation experiments in two-phase flow of gas-water (sucrose solutions) were conducted. The time and frequency domains of the Doppler ultrasonic wave signals during the experiments were analyzed. The results show that: (1) No matter the pump was on or off, the detected average Doppler ultrasonic signal voltage increased first and then decreased with the increase of the gas void fraction, and had a quadratic function relation with gas void fraction, so the average voltage change of the monitored signals can be used to deduce the approximate gas void fraction. The Doppler ultrasonic wave signal voltage was significantly reduced in magnitude and variation in the solution with higher viscosity, and the viscosity has stronger impact on the magnitude of signal than density. (2) When the pump was stopped, the Doppler shift increased with the increase of gas void fraction, and the two showed a nearly linear relation, so the detected amount of Doppler shift can reflect the variation of gas void fraction quantitatively. When the pump was on, the sound energy produced by frequency converter had a more significant impact on amplitude spectrum than gas void fraction, so it is impossible to determine whether gas kick occurs by frequency domain signal analysis. (3) This method is a non-contact measurement, with no contact with the drilling fluid and no disruption to the drilling operation. It can quantitatively characterize the gas void fraction according to the change of Doppler ultrasonic signal, enabling earlier detection of gas kick.
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Most multiphase flow separation detection methods used commonly in oilfields are low in efficiency and accuracy, and have data delay. An online multiphase flow detection method is proposed based on magnetic resonance technology, and its supporting device has been made and tested in lab and field. The detection technology works in two parts: measure phase holdup in static state and measure flow rate in flowing state. Oil-water ratio is first measured and then gas holdup. The device is composed of a segmented magnet structure and a dual antenna structure for measuring flowing fluid. A highly compact magnetic resonance spectrometer system and intelligent software are developed. Lab experiments and field application show that the online detection system has the following merits: it can measure flow rate and phase holdup only based on magnetic resonance technology; it can detect in-place transient fluid production at high frequency and thus monitor transient fluid production in real time; it can detect oil, gas and water in a full range at high precision, the detection isn’t affected by salinity and emulsification. It is a green, safe and energy-saving system.
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Considering the complicated interactions between temperature, pressure and hydration reaction of cement, a coupled model of temperature and pressure based on hydration kinetics during deep-water well cementing was established. The differential method was used to do the coupled numerical calculation, and the calculation results were compared with experimental and field data to verify the accuracy of the model. When the interactions between temperature, pressure and hydration reaction are considered, the calculation accuracy of the model proposed is within 5.6%, which can meet the engineering requirements. A series of numerical simulation was conducted to find out the variation pattern of temperature, pressure and hydration degree during the cement curing. The research results show that cement temperature increases dramatically as a result of the heat of cement hydration. With the development of cement gel strength, the pore pressure of cement slurry decreases gradually to even lower than the formation pressure, causing gas channeling; the transient temperature and pressure have an impact on the rate of cement hydration reaction, so cement slurry in the deeper part of wellbore has a higher rate of hydration rate as a result of the high temperature and pressure. For well cementing in deep water regions, the low temperature around seabed would slow the rate of cement hydration and thus prolong the cementing cycle.
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Continental shale oil is a general term for liquid hydrocarbons and many kinds of organic matter in continental organic-rich shale series with vitrinite reflectance of more than 0.5% at buried depth of more than 300 m, and is an important type of source-rock oil and gas. Based on the evolution model of oil generation and expulsion in organic-rich shale series controlled by maturity, continental shale oil is divided into two types: medium-high maturity and medium-low maturity. (1) The continental shale series in China develop high-quality source rocks of freshwater and saltwater lacustrine facies, as well as multiple types of reservoirs, including clastic rocks, carbonate rocks, diamictite, tuff and shale, forming a number of "sweet sections" and "sweet areas" of continuous distribution inside or near source rocks, which have large scale resources. (2) Experimental analysis of organic rich shale samples shows that the shale samples with wavy and horizontal beddings have good storage conditions, and the horizontal permeability of shale is tens to hundreds of times of its vertical permeability, which is conducive to the lateral migration and accumulation of shale oil in the source rocks. (3) After evaluation, the geological resources of medium-high maturity shale oil are about 10 billion tons, which can be effectively developed by horizontal drilling and volumetric fracturing, and will be a practical field of oil exploration in recent years. Shale oil with medium and low maturity has huge resource potential, and technological recoverable resources of (70-90) billion tons, making it a strategic alternative resource of oil industry. However, economic development of this type of shale oil needs in-situ conversion technology breakthroughs. Continental shale oil is an inevitable choice in the process of Chinese continental petroleum exploration from "outside source" to "inside source". Making breakthroughs in the core technologies such as "sweet area" evaluation and optimization, horizontal well volume fracturing and in-situ conversion technology and equipment is the key to realizing scale development of continental shale oil economically.
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Based on thin-section, argon-ion polished large-area imaging and nano-CT scanning data, the reservoir characteristics and genetic mechanisms of the Lower Silurian Longmaxi shale layers with different laminae and laminae combinations in the Sichuan Basin were examined. It is found that the shale has two kinds of laminae, clayey lamina and silty lamina, which are different in single lamina thickness, composition, pore type and structure, plane porosity and pore size distribution. The clayey laminae are about 100 μm thick each, over 15% in organic matter content, over 70% in quartz content, and higher in organic pore ratio and plane porosity. They have abundant bedding fractures and organic matter and organic pores connecting with each other to form a network. In contrast, the silty laminae are about 50 μm thick each, 5% to 15% in organic matter content, over 50% in carbonate content, higher in inorganic pore ratio, undeveloped in bedding fracture, and have organic matter and organic pores disconnected from each other. The formation of mud lamina and silt lamina may be related to the flourish of silicon-rich organisms. The mud lamina is formed during the intermittent period, and silt lamina is formed during the bloom period of silicon-rich organisms. The mud laminae and silt laminae can combine into three types of assemblages: strip-shaped silt, gradating sand-mud and sand-mud thin interlayers. The strip-shaped silt assemblage has the highest porosity and horizontal/vertical permeability ratio, followed by the gradating sand-mud assemblage and sand-mud thin interlayer assemblage. The difference in the content ratio of the mud laminae to silt laminae results in the difference in the horizontal/vertical permeability ratio.
