527 results about "Arenite" patented technology

The invention belongs to the petroleum exploration field, and concretely relates to a compact sandstone reservoir complex netted fracture prediction method. The method comprises the steps of: building a geological structure model and a fracture growth model; testing magnitudes and directions of ancient and modern crustal stresses; completing a rock mechanic parameter experiment; testing rock mechanic parameters and fracture stress sensitivities; developing a fracture rock multistage composite rupture criterion; performing a rock deformation physical test to obtain a peak value intensity; building a relation model between single axle state stress-strain and fracture bulk density; building a relation model between triaxial state stress-strain and fracture bulk density and occurrence; building a relation model between single axle state stress-strain and fracture bulk density; calculating and stimulating fracture parameters under modern conditions; and verifying the reliability of a fracture quantitative prediction result. The method can accurately obtain compact sandstone reservoir complex netted fracture parameters, and perform quantitative characterization, is suitable for quantitative prediction of any fracture mainly with a brittle reservoir, and reduces exploitation risks and costs.

An aqueous oilfield treatment fluid containing a chelating agent and an HF source is described. This fluid is effective at dissolving siliceous materials such as clays and keeping the dissolved materials in solution. In particular it is effective at preventing re-precipitation of initially-dissolved silicon as silica and therefore reduces damage to sandstones with which it is contacted. Methods are given for using this fluid for sandstone matrix stimulation, removal of clay-containing drilling fluid components and filter cakes from wellbores, sandstone acid fracturing, and gravel pack and proppant pack cleaning.

The invention is a method for simulating sandstone deposition. The sandstone is simulated by estimating the grain size distribution and mineral composition of grains in the sandstone, simulating sedimentation of grains from the grain size distribution and mineral composition of the grains, simulating compaction of the grains, and simulating cementation of the grains. Properties of the sandstone such as porosity and permeability may be estimated from the simulated sandstone. The method permits multiple mineralogies to be simulated during the burial history of sedimentation, compaction and cementation.

A method of fracturing using deformable proppants minimizes proppant pack damage, without compromising the fracturing fluid's proppant transport properties during pumping, by use of deformable proppants. Selection of proppant is dependent upon the mechanical properties of the formation rock. The strength of the deformable proppant is dependent upon the modulus of the formation rock being treated such that the proppant is capable of providing, at the very least, a minimum level of conductivity in in-situ stress environments. The maximum elastic modulus of the deformable proppant is less than the minimum modulus of the formation rock which is being treated. The method is particularly applicable in fracturing operations of subterranean reservoirs such as those comprised primarily of coal, chalk, limestone, dolomite, shale, siltstone, diatomite, etc.

The invention relates to a calibration method for representing dense sandstone pore size distribution by adopting nuclear magnetic resonance; the method comprises the steps of measuring the rock porosity and the skeleton density; carrying out a low-temperature broken sample N2 absorption and desorption experiment, and carrying out a nuclear magnetic resonance test and a high pressure Hg injection test on a regular column sample in a saturated formation water state; converting pore volume obtained through N2 absorption into porosity components under different pore throat radiuses by using a capillary accumulated Hg inlet curve, and establishing a pore proportion summation curve by synthesizing low temperature N2-high pressure Hg injection; determining a best calibration coefficient by comparing the nuclear magnetic resonance pore proportion summation curves under the different C values to realize the conversion between nuclear magnetic resonance T2 spectrum and the pore throat radius; establishing a relation between parameters of the calibration coefficient C and a reflection pore-throat structure according to lithological characters; carrying out nuclear magnetic resonance conversion on dense sandstone reservoirs which are positioned in the same region and have the same lithological character. According to the method, the nuclear magnetic resonance T2 spectrum is calibrated by combining low temperature N2 absorption and a high pressure Hg injection experiment, and large pores, micropores and mesopores are calibrated, so that the distribution of different grades of pore sizes in dense sandstone can be effectively represented.

The invention belongs to the field of oil exploration and particularly relates to an effectiveness evaluation method for a compact sandstone reservoir map cracking system. The effectiveness evaluation method for the compact sandstone reservoir map cracking system includes the following steps that a crack discrete network geologic model is established, crack formation periods are statistically analyzed, crack filling sources are statistically analyzed, crack superior filling directions and systems are statistically analyzed, crack filling master control geologic factors are analyzed, the relation between the crack permeability and current primary stress is established, and the space effectiveness of the map cracking system is evaluated. The purposes of accurately acquiring effective evaluation of compact sandstone reservoir well point crack filling periods, filling superior directions, filling degrees and the space effectiveness of the map cracking system are achieved, the filling degrees and the filling superior directions of compact sandstone reservoir cracks under the multi-period formation fluid precipitation and crystallization effect are effectively predicted, guarantees are provided for fracturing modification design and development scheme optimization of a fractured reservoir, and the risk and cost of exploration and development are reduced.

The invention discloses a multiple-stratum-series tight sandstone gas reservoir well spacing method. The method includes the following steps that first, based on high-resolution sequence stratigraphy, distribution of sand bodies is depicted, an effective reservoir stratum is predicted through the earthquake and well logging technology, and an enrichment region is preferentially selected; second, based on a favorable region, a longitudinal structure of the sand bodies is fine dissected through the geology and well logging technology, and therefore the horizontal distribution law of the sand bodies can be researched; third, in the preferential favorable region, well spacing is performed according to conditions. The well spacing method is reasonable and takes the complex geology that multiple gas-bearing series longitudinally develop in an upper palaeozoic tight sandstone gas reservoir, the single layer yield is low and the lateral variety of the reservoir stratum is fast into consideration, the drilling success of a development well can be guaranteed, the development effect can be improved to the maximum extent, and the economical and effective development of the tight sandstone gas reservoir is achieved.

The invention relates to a geologic history period sandstone reservoir porosity evolution recovery method which comprises the following steps: (1) establishing a sandstone reservoir diagenesis evolution sequence and a corresponding paleoburial depth of the reservoir during diagenesis; (2) establishing a normal compaction layout; (3) establishing a functional relationship between porosity and surface porosity; (4) carrying out sandstone reservoir porosity backstripping inversion under the restriction of the diagenesis sequence; (5) correcting by mechanical compaction and hot compaction; and (6) on the basis of the steps above, determining the true porosities of the main diagenetic stages, and establishing the geologic history period sandstone reservoir porosity evolution curve. The invention intensively solves the key problems of the determination of diagenesis occurrence time and paleoburial depth, the relationship between porosity and surface porosity, compaction correction and the like in the existing geologic history period sandstone reservoir porosity evolution recovery method, can effectively predict the porosity of the sandstone reservoir in the oil gas forming period, and provides instructions for effective evaluation on the reservoir.

The invention belongs to the field of oil-gas field development and relates to an experimental evaluation method for fracturing fluid damage in an unconventional tight sandstone oil-gas exploration and development process. The method includes: subjecting fracturing fluid to high-pressure instant reverse injection into a rock core, and simulating flow invasion damages of fracturing fluid in cracks in a continuous extension process after a stratum is fractured by the fracturing fluid; adopting a high-speed centrifuge to set up original water saturation of a reservoir; under the condition of the original water saturation of the reservoir, adopting nitrogen for testing permeability before and after injection of the fracturing fluid into the rock core, and judging fracturing fluid damage degrees according to gas log permeability change rate. By complete simulation of a fracturing fluid injection mode in a fracturing process, adoption of nitrogen for testing permeability accords with seepage characteristics of the tight sandstone gas reservoir, and defects of high experimental displacement pressure, long displacement time, large experimental data errors and the like are avoided.

The present invention relates to a tight sandstone effective reservoir identifying method. The method comprises: first describing tight sandstone reservoir basic geological features one by one according to geological factors that affect tight sandstone reservoir forming; then determining a main controlling factor of petroleum accumulation according to static and dynamic data of a producing well, determining a reservoir-forming pattern of the tight sandstone according to the obtained main controlling factor, and delineating a favorable distribution range of an effective reservoir under constraint of the reservoir-forming pattern; determining lower limiting values of oiliness, physical property and electrical property of a reservoir stratum in the delineated favorable distribution range of the effective reservoir by using a statistical method; and finally superimposing, on a plane, a plane distribution image of the foregoing determined parameters, and delineating an effective reservoir range, to identify a tight sandstone effective reservoir. According to the present invention, a tight sandstone oil-gas layer is identified and is finely depicted under constraint of the reservoir-forming pattern, so that a conventional deficiency that a central oil layer is not continuous because of single-well logging interpretation is overcome, thereby implementing continuous prediction of a tight sandstone oil sand body.

The invention relates to a rich argillaceous sand stone three-dimension equivalent speed prediction model which is deduced by improving a method of calculating elastic modulus of dry rocks in a Xu-White speed prediction model. The model calculates the elastic modulus of dry rocks by replacing the aspect ratio of a fixed pore in the Xu-White model by four three-dimension shape (spherical shape, needle shape, tray shape and crack shape) pores which are raised by Berryman (1955) according to a statistic pore distribution spectrum, the improved model can simulate the geometric size which is more close to argillaceous micro cracks in rich argillaceous sand stone by freely adjusting the pore aspect ratio, thereby directly and truly reflecting the shape of underground reservoir space and ensuring the coincidence of a predicted result and the actual measuring result.

The invention relates to the field of precise prediction and evaluation of tight and heterogeneous sandstone reservoir and discloses a multi-parameter permeability prediction method for tight sandstone reservoir. The method comprises steps as follows: (1), determining geological main controlling factors of permeability of the tight sandstone reservoir, wherein the geological main controlling factors comprise porosity, granularity and degree of fracture development; (2), establishing a logging prediction model of porosity and granularity and an earthquake prediction model; (3), determining geological main controlling factors of the degree of fracture development; (4), establishing a fracture development index model according to the geological main controlling factors obtained in the step (3); (5), establishing a comprehensive prediction model of multi-parameter permeability under earthquake-geological constraints. According to the method, accurate prediction of single well and plane ofpermeability of the tight sandstone reservoir is realized.

Method for constructing an integrated rock physics model that simulates both shale anisotropy and stress-induced anisotropy of clastic rocks. In the model, the total pore volume is divided into three parts according to the estimated shale volume and effective stress: (1) clay-related pores, (2) sand-related pores, and (3) microcracks (mainly in the sand component). The pore space is then partitioned into the clay-related and sand-related pores using a scheme first disclosed by Xu and White in 1995. The model simulates shale anisotropy via the preferred orientation of clay-related pores and stress-induced anisotropy via the preferred orientation of microcracks, which is controlled by the differential stresses. Laboratory measurements or well logs are needed to establish a relationship between crack density and the effective stress.

The invention discloses a representation method for diagenetic seismic facies of a sandstone reservoir. According to the representation method for the diagenetic seismic facies of the sandstone reservoir, quantitative indexes of typical rock electric parameters for reflecting the diagenetic characteristic of the sandstone reservoir and the environment are utilized to accurately evaluate the diagenetic facies longitudinal phase sequence of the sandstone reservoir of a non-core hole and the plane distribution and the rule of the diagenetic facies of the target stratum reservoir, more effective technical information is provided for sandstone oil and gas exploration and development, favorable blocks of the sandstone oil and gas exploration and development are optimized, the forecasting accuracy of the favorable blocks is improved, the success rate of exploration and development is improved, and the cost of exploration and development is lowered.

The invention discloses a sweet spot identification and comprehensive evaluation method for a tight sand reservoir. According to the method, eight conventional logging curve data are taken as a basis. By utilizing the SPSS data analysis software, common factors capable of comprehensively reflecting the characteristics of a reservoir in a target area are extracted based on the PCA (principal component analysis) method. According to the physical significance of each common factor, the sweet spots of the tight sand reservoir are recognized, and a sweet spot qualitative recognition model for the tight sand reservoir is established. On the above basis, a common factor calculation model for porosity and permeability is established in conjunction with physical property test data, so that the types of the reservoir are divided. According to the physical property parameters of various reservoir types and the parameter characteristics of common factors, a quantitative evaluation standard for the tight sand reservoir is determined. Therefore, the qualitative recognition and the quantitative evaluation for the sweet spots of the tight sand reservoir are realized. Based on the method, a novel idea and a novel method are provided for the interpretation and evaluation of the tight sand reservoir. Therefore, the interpretation and evaluation reliability of the tight sand reservoir is improved. The exploration and development cost is reduced.

The invention relates to the field of research on the physical properties of sandstone of low-permeability dense sandstone reservoir, and discloses a construction method of a dense sandstone multi-scale pore model and an application. The invention provides the construction method of a dense sandstone multi-scale pore model, which comprises the following steps: (1) developing a mercury injection experiment and establishing a rock sample capillary pressure curve; (2) establishing a three-dimensional digital core by using Micro-CT scanning; (3) determining the spatial position coordinates and geometric construction characteristic parameters of the pore and simplifying the pore into pore nodes; (4) determining the communication relation among the pore nodes according to the spatial position ofthe pore nodes; (5) distributing pore throat radius, establishing an initial pore model, and then fitting the initial pore model into a capillary pressure curve; and (6) adjusting pore throat parameters and pore parameters in the initial pore model according to the actually measured capillary pressure curve. The pore model disclosed by the invention is accurate and reliable.

The invention provides a method for determining a diagenetic process and a porosity evolution process of a foreland basin sandstone reservoir. The method comprises steps as follows: determining reservoir genesis and petrologic features; determining a burial process and tectonic uplift and subsidence periods; determining a diagenesis type, features and strength of the reservoir by a cathodoluminescence microscope and / or through QEMScan (Quantitative Evaluation of Minerals by SCANning electron microscopy), and recovering the diagenetic process; determining reservoir space features and the porosity evolution process by a fluorescence microscope and / or a confocal laser scanning microscope. With the adoption of the method, the diagenetic process and the porosity evolution process of the ultra-deep compact foreland basin sandstone reservoir with complicated burial process, extremely great depth, extremely small pores and extremely low porosity and permeability can be effectively analyzed; the method can be used for predicating the quality of the sandstone reservoirs in different areas in the plane and the vertical profile, so that more and larger oil and gas fields can be discovered.

The present invention refers to a biotechnological process that enhances oil recovery of a 14 to 25 API Gravity oil contained in carbonate-containing and / or clayey sandstone porous rock systems with low permeability (7 to 100 mD), thus focused to petroleum wells associated to zones with low recovery factor. The process utilizes the indigenous extremophile microorganisms activity from the oil reservoir and an IMP culture, as well as its metabolites (gases, acids, solvents and surfactants), which improve oil mobility and are able to develop at 60 to 95° C. temperatures, 7 to 154.6 Kg / cm2 (100 to 2,200 psi) pressures and NaCl content from 5,000 to 45,000 ppm, in anaerobic conditions. The biotechnological process of the present invention includes: indigenous microorganisms sampling, collecting and characterization from the reservoir; formulation of culture media; selection, enrichment, activation and preservation of such microorganisms, as well as biostimulation (indigenous microorganisms) and bioaugmentation (IMP culture) to increase the metabolite production, useful for oil recovery in a porous media impregnated with oil in carbonate-containing and / or clayey sandstone porous systems, with one or several cycles and confinement periods from 5 to 10 days, to increase oil recovery. Experimental tests show that the biotechnological process of the present invention supplies an oil recovery increase up to 30%, additional to that obtained in secondary recovery processes.

The invention discloses a method for determining a hydrocarbon accumulation threshold of hydrocarbon containing basin fragmentary rock. The method comprises the following steps: (1), establishing a change model about how sandstone and mudstone change with embedded depth in a research zone; (2), establishing a relation model of sandstone and mudstone permeability and porosity; (3), establishing a relation model of sandstone and mudstone hole radii, the porosity and the permeability, and calculating the hole radius values of sandstone and mudstone in different depth; (4), calculating a ratio of mudstone interface potential energy to sandstone interface potential energy, establishing a change model about how the ratio changes with the embedded depth, and determining a maximum boundary and a minimum boundary when the ratio of the mudstone interface potential energy to the sandstone interface potential energy is distributed along with the embedded depth; (5), calculating ratios of the mudstone interface potential energy to the sandstone interface potential energy about a hydrocarbon layer and a dry layer in the research zone, and subjecting the ratios of the mudstone interface potential energy to the sandstone interface potential energy about the hydrocarbon layer and the dry layer in the research zone to the change model established in step (4); (6), dividing a borderline about how the potential energy of the opposite interfaces of the hydrocarbon layer and the dry layer is distributed along with the embedded depth; and (7), sandstone porosity corresponding to an intersection point between the borderline and the maximum boundary of the ratio of the mudstone interface potential energy to the sandstone interface potential energy being reservoir layer critical porosity corresponding to the hydrocarbon accumulation threshold of the research zone.

The invention provides a similar limit water cut period take-turn water drive method for a multi-layer sandstone reservoir. The method includes the steps that a geological model based on single-cause sand bodies is established; on the basis that the geological model based on the single-cause sand bodies is established, a remaining oil distribution model based on the single-cause sand bodies is established; the single-cause sand bodies similar in property are combined into cause sand body sets; according to the reservoir characteristics of different single-cause sand body sets in a layer system and the remaining oil distribution conditions, the corresponding vectorization water drive adjustment scheme is determined; take-turn water drive based on the single-cause sand body sets is performed. With the similar limit water cut period take-turn water drive method for the multi-layer sandstone reservoir, influences of the heterogeneity of reservoir stratums of the multi-layer sandstone reservoir on water drive development can be reduced to the maximum, comprehensive displacement and balance displacement in a plane in the longitudinal direction of the single-cause sand bodies are achieved, and therefore a high-strength and high-efficiency water driving flow field can be established, and water drive sweep efficiency and water drive recovery efficiency can be improved substantially.

The invention belongs to the technical field of uranium mineralization prediction, and particularly discloses a paleochannel type sandstone-type uranium ore deposit positioning method. The method includes the following steps of firstly, recognizing whether a uranium ore geological region to be positioned belongs to a uranium production paleochannel or not; secondly, if yes, delineating a uranium production paleochannel section in the region; thirdly, delineating a soil radon gas abnormal area of the uranium production paleochannel section delineated in the second step; fourthly, overlapping the uranium production paleochannel section delineated in the second step with the soil radon gas abnormal area delineated in the third step, thereby positioning a paleochannel type sandstone-type uranium mineralization favorable area, namely, the overlapping area of the uranium production paleochannel section and the soil radon gas abnormal area. The method has the advantages of being high in positioning accuracy, high in ore finding efficiency, rapid and low in cost.

The invention provides a manufacturing method of a low-cost sandstone artificial rock core for experimental teaching and relates to the technical field of petroleum engineering.The manufacturing method of the low-cost sandstone artificial rock core comprises the following steps that rock core framework particles different in particle diameter are selected; the framework particles are mixed with a cementing agent, and distilled water is added for even stirring; the mixture is charged into a mold, the mold is arranged in an artificial rock core manufacturing device for pressure exerting, the mixture is taken out and put in a high-temperature drying oven for drying and shape fixing after cementing of the artificial rock core is completed, and cutting is performed after natural cooling is performed to reach normal temperature to obtain a standard test sample, namely the low-cost sandstone artificial rock core.The rock cores different in porosity, permeability and cementation degree are manufactured under the condition that the usage amount of the cementing agent and the diameters of sand grains are changed.The rock cores manufactured by adopting the manufacturing method are similar to natural rock cores in appearance, shape, pore structure, cementation degree and other aspects and can be used for rock core flow experiments.The manufacturing method of the low-cost sandstone artificial rock core for experimental teaching is simple, safe, easy to operate and wide in material source and can be widely applied to general teaching experiments.

The invention discloses an experimental method of organic acid generation and an erosion effect of the organic acid on a tight oil reservoir. The experimental contents include (1) a hot simulation experiment for proportioning kerogen and a clay mineral to form a sample and generating an organic acid; (2) a hot simulation experiment for generating the organic acid by virtue of thermal evolution of shale; (3) a hot simulation experiment for the erosion effect of the organic acid on tight sandstone and monomineral; and (4) a hot simulation experiment for artificially proportioning the sample. The mechanism and influence factors of the development of the tight reservoir, especially erosion pores of the shale reservoir can be clarified by analyzing the experimental data, and a dynamics model of the organic acid generation and a thermodynamic model of the decarboxylation and erosion reaction of the organic acid can be established; the geological application can be realized by combining the models with the sedimentary and burial history, thermal history and mineral association characteristics of the reservoir in a research area, the development situation of a secondary erosion pore in different geologic periods can be quantitatively evaluated, and a foundation can be set for predicting a tight oil exploration sweet spot area.

The invention relates to the technical field of geological prospection and provides a method for determining an ancient porosity of compact sandstone in a pool-forming period. The method includes following steps: (A) obtaining reservoir lithology, sorting coefficient and diagenesis characteristics; (B) according to composition of different diagenesis characteristics in a diagenesis sequence, establishing a reservoir porosity comprehensive evolution model according to initial porosity, a porosity loss model, a porosity increase model and a crack porosity model; (C) establishing a reservoir porosity evolution history model according to a reservoir diagenesis step with combination of the reservoir initial porosity and the reservoir porosity comprehensive evolution model; (D) matching a to-be-test pool-forming period of compact sandstone gas reservoir with the reservoir porosity comprehensive evolution model to further determine the ancient porosity of the compact sandstone in the pool-forming period. By means of the method, the determined ancient porosity of the compact sandstone in the pool-forming period is obtained by means of match with the pool-forming period of the compact sandstone gas reservoir in the historical period of geology, so that a difficult problem that the ancient porosity of the compact sandstone in the pool-forming period cannot be accurately obtained in the prior art.

The invention belongs to the technical field of oil and gas field reservoir geological analysis, in particular to a braided river sedimentary heterogeneous tight sandstone gas reservoir geological modeling method comprising the following steps: establishing a braided river reservoir internal structure model; establishing a braided river reservoir geological knowledge base; and taking the braided river reservoir internal structure model as a framework, applying the stochastic modeling method based on the target, inputting the parameters of the braided river reservoir geological knowledge base,establishing multiple implementation models and selecting the implementation model with the highest coincidence rate as the training image of multi-point geostatistical modeling, and selecting seismicattributes as the soft constraint conditions of the training image to establish multiple implementation models again and selecting the implementation model with the highest coincidence rate as the braided river sedimentary facies model. The problem of low average coincidence rate of establishing the geological model in the prior art can be solved, and the existing mine field data are fully integrated and the coincidence rate of the established geological model can be enhanced.

The invention discloses a method for quantitatively expressing diagenetic logging facies of a sandstone reservoir. The method for quantitatively expressing the diagenetic logging facies of the sandstone reservoir can used for accurately evaluating a longitudinal phase sequence of diagenetic facies of a non-coring well sandstone reservoir, and plane distribution and principle of diagenetic facies of a target stratum reservoir by utilizing quantitative indexes of typical stone electrical parameters for reflecting diagenetic characteristics and environment of the sandstone reservoir, so as to provide effective technical information for the exploration and development of oil and gas of sandstones; a favorable block for the exploration and development of the oil and gas of the sandstones is preferably selected, so that the predication accuracy of the favorable block is improved, the success rate of the exploration and development is improved and the cost of the exploration and development is reduced.

The invention provides an artificial sandstone physical model and a manufacturing method and application thereof. The manufacturing method for the artificial sandstone physical model includes the following steps that ball-milling mixing is carried out on quartz sand, feldspar, kaolin and talc to obtain mixed powder; agglomerant is added to the mixed powder, blending and mixing are carried out, and mixed materials are obtained; the mixed materials are laid in a die, and the die with the fully-mixed materials is obtained; after the die with the fully-mixed materials is compacted, a blank is dried and sintered in sequence, and the artificial sandstone physical model is obtained. The artificial sandstone physical model is obtained through the manufacturing method. The invention further provides the application of the artificial sandstone physical model in seismic wave response simulation study of sandstone reservoirs. According to the model, the manufacturing method and the application, various rock physical parameters and mechanical characteristics are closer to those of the artificial sandstone physical model for natural rocks, and the artificial sandstone physical model can be applied to the seismic wave response simulation study of the sandstone reservoirs.

An ultra-lightweight, high strength ceramic proppant made from mixture of naturally occurring clays, preferably porcelain clay, kaolin and / or flint-clay, earthenware clay or other naturally occurring clays having an alumina content between about 5.5% and about 35%. The proppant has an apparent specific gravity from about 2.10 to about 2.55 g / cc, and a bulk density of from about 1.30 to about 1.50 g / cc. This ultra-lightweight proppant is useful in hydraulic fracturing of oil and gas wells, and has greater conductivity than sand at pressures up to 8,000 psi as measured by Stim-Lab after 50 hours and 275° F. on Ohio Sandstone, in the presence of deoxygenated aqueous 2% solution of KCI.

The invention provides a redbed sand-shale interbedded slope raw surface artificial soil preparation method, which prepares the artificial soil with raw material components including redbed sandstone rock, redbed shale rock, compound containing silkworm excrement and / or wormcast and / or algae residue, peat, straw, livestock and poultry manure, high water-absorbent resin, attapulgite powder, polyvinyl acetate and fertilizer which are effectively mixed under certain conditions. The preparation method has significant effects in speeding up the formation of redbed sand-shale interbedded slope raw surface artificial soil aggregate structure, increasing the water and fertilizer-keeping performances of the soil, improving the physical and chemical properties of the soil and promoting the plant growth and development.

The invention discloses a microscopic rock network model manufacturing method. The microscopic rock network model manufacturing method comprises the steps that a pore-throat passage is extracted, pores and throat ways in the pore throat passage are separated, pore patterns and throat way patterns are obtained, and pore masks and throat way masks are manufactured correspondingly; through the pore masks and the throat way masks, base pieces are etched to form etched base pieces; and the etched base pieces are in key fit with cover pieces to form a microscopic rock network model. According to themicroscopic rock network model manufacturing method, through pore-throat separating, image aligning and repeated photoetching, a micro-nano oil gas flowing passage which is closer to the reality of an oil reservoir is achieved in the microscopic glass model, control over the reaction time in the etching technique is accurate, the depth-width ratio, smoothness and flatness of the passage are good,pressure does not need to be provided in the key fit process, the nano passage can be better protected, key fit of the real sand rock microscopic models of the micron pores and the nano throat ways is achieved, and microscopic dynamic change, such as Haines phase step and non-wetting phase coalescence, which cannot occur on a two-dimensional planar model is taken on.