342 results about "Formation water" patented technology

A porous media grouting test system and method taking temperature effects into consideration. The system comprises a porous media formation simulation model (1), a grouting system (2), a water level adjustment system, a formation temperature control system and a data analysis system, wherein the porous media formation simulation model (1) is used for simulating a porous media formation; the water level adjustment system and the formation temperature control system are used for simulating the conditions of different water saturation levels and different water temperatures and ground temperatures; and the data analysis system is used for comparing different time-series data collected by sensors such as a temperature sensor and a pressure sensor with data such as temperature data and pressure data that is obtained by means of coupled solving of a heat transfer equation and a momentum equation, so as to verify and analyze a grouting diffusion path. Free simulation of different water saturation levels is realized by means of a water level adjustment system, and simulation of different ground temperatures is realized by means of a formation temperature control system, thereby realizing the research on grouting diffusion under different water levels and different water temperatures and ground temperatures.

The invention belongs to the technical field of gas storages, and particularly relates to an experimental method and device for evaluating fault stability under injection-production alternating stress of a gas storage. The method comprises the following steps: acquiring reservoir information of a to-be-detected gas storage; making a three-dimensional model according to the reservoir information, and configuring model parameters according to formation water and natural gas initially injected into the three-dimensional model; an injection-production pipe is inserted into the three-dimensional model, the multi-cycle gas injection-production process is simulated, and fault changes in the three-dimensional model are monitored; and optimizing model parameters of the three-dimensional model according to the fault change condition, and determining optimal model parameters. A fault with any dip angle can be simulated, the experimental model comprises a whole geologic body simulating a gas storage, surrounding rocks including a cover layer and a bottom supporting layer and wrapping the periphery of a reservoir body, the reservoir is disconnected by the fault, the contact relation of the two reservoirs can be designed according to the actual condition of the stratum, and an injection-production well is designed in the model. The injection-production well simulates high-speed injection-production of the gas storage.

The invention relates to a non-linear seepage experiment method for gas breaking through a cover layer based on dark field imaging. The method comprises the following steps: placing a microfluidic rock chip on an objective table of a dark field scattering microscope; the injection end of the microfluidic rock chip is connected with a fluid injection module, and the outlet end of the microfluidic rock chip is connected with a downstream outflow pipeline; injecting the formation water solution into the micro-fluidic rock chip until the micro-fluidic rock chip is filled with the formation water solution; opening a gas injection system, and adjusting the dark field scattering microscope until a clear image of a micro-fluidic rock chip pore structure and carbon dioxide displacement formation water is obtained; injecting carbon dioxide with different pressures into the micro-fluidic rock chip, and observing nonlinear seepage migration images of carbon dioxide and formation water in the micro-fluidic rock chip; when it is observed that carbon dioxide migrates to the outlet end of the rock chip, the breakthrough moment is obtained, and the upstream and downstream pressure difference value of the microfluidic rock chip is the breakthrough pressure. According to the method, the nonlinear seepage of the carbon dioxide displacement formation water in the nanopores can be accurately observed, and the breakthrough pressure can be determined.

The invention discloses a low-permeability gas reservoir productivity prediction method, a storage medium and a low-permeability gas reservoir productivity prediction device, and belongs to the technical field of low-permeability gas reservoir development. Based on the gas-water two-phase motion equation, establishing a gas phase productivity equation considering the high-speed non-darcy effect, the starting pressure gradient and the stress sensitive effect; establishing a water yield calculation formula considering the starting pressure gradient and the stress sensitive effect; the water-phase relative permeability is expressed on the basis of the relation between the gas-water relative permeability ratio and the water saturation; using a gas-water relative permeability model to express the gas-phase relative permeability considering the active degree of the water body; and substituting the gas phase relative permeability into the gas phase productivity equation. According to the method, the influence of the water body active degree, the starting pressure gradient and the stress sensitive effect on the productivity of the gas reservoir is considered, the multi-factor coupled productivity prediction model including formation water invasion is established, the technical problem that the productivity of the low-permeability gas reservoir is difficult to accurately predict through a traditional method is solved, and the development efficiency and economic benefits of the low-permeability gas reservoir are effectively improved.

The invention provides a dynamic visual simulation system and method for carbon dioxide formation water reaction precipitation, and belongs to the technical field of geological sequestration. The dynamic visual simulation system and method for the carbon dioxide formation water reaction precipitation comprise a microcosmic etching chip model; a piston container; the pressure-making injection system is connected with the piston container; a carbon dioxide liquefaction module; the carbon dioxide quantitative injection system is connected with the carbon dioxide liquefaction module; the supercritical generator is connected to the downstream of the carbon dioxide quantitative injection system; a microscopic etching chip model is arranged in the visual reaction kettle, and the visual reaction kettle is connected with the supercritical generator; the back pressure loading system is connected to the outlet end of the visual reaction kettle; the microscopic image visual acquisition module is arranged above the visual reaction kettle; an annular pressure tracking pump; the control terminal computer is connected with all the modules, and the problems that the influence rule of sediment on reservoir seepage in carbon dioxide geological sequestration is unclear, and sequestration risks are difficult to predict are solved.

The invention relates to a carbon dioxide-water-rock dynamic coupling simulation device and method in a geological storage process. The device disclosed by the invention has high-precision temperature and pressure control capability, can accurately simulate various complex geological and engineering environmental conditions, provides a high-precision data basis for research on dynamic migration and transformation of carbon dioxide, and is beneficial to deeply revealing internal laws and mechanisms of the carbon dioxide. According to the device, a mixed solution of liquid carbon dioxide and formation water is adopted and injected from the cross section of the rock core, differential reaction generated in the rock under the condition of continuous carbon dioxide filling can be revealed, and powerful data support is provided for deeply knowing the dynamic behavior of carbon dioxide and interaction between the carbon dioxide and surrounding media.

The invention relates to a surfactant oil displacement composition suitable for a high-temperature and high-salt oil reservoir and application of the surfactant oil displacement composition. The surfactant oil displacement composition comprises the following components in percentage by mass: 0.10-0.50 wt% of a nitrogen-containing surfactant, less than 0.12 wt% of a sulfur-containing surfactant or hydrophobic salt and the balance of water. The surfactant oil displacement composition stably exists under the conditions that the temperature is 70-130 DEG C, the total mineralization degree of formation water is (10-25) * 10 < 4 > mg / L, and the concentration of calcium and magnesium ions is (1-2.5) * 10 < 4 > mg / L, and is kept clear without forming precipitates. The interfacial tension of the surfactant oil displacement composition can reach 10 <-2 > mN / m order of magnitude under high-temperature and high-salt conditions, the oil washing efficiency can reach 80% or above, and the surfactant oil displacement composition is suitable for improving the recovery efficiency of a high-temperature and high-salt oil reservoir in tertiary oil recovery.

Systems and methods of separating multiphase flows in a flowline of a downhole fluid sampling and analysis tool, measuring target ions in the water phase, and separating between formation water and injection water are described. The system to separate the multiphase flows includes a three-dimensional barrier permeable to water and repelling oil and / or drilling mud filtrate into at least one bypass channel within the flowline of the downhole fluid sampling and analysis tool. For instance, the system to measure the targeted ions includes the system to separate the multiphase flows and an optical sensor, wherein the three-dimensional barrier has an aperture inside the three-dimensional barrier to let a light from an optical sensor go through perpendicular to the flowline.

The invention relates to the technical field of water flooding gas reservoirs, in particular to a rock core displacement fluid saturation testing method and a testing device thereof.The method comprises the steps that S1, the original formation pressure and temperature of a gas reservoir are obtained; s2, obtaining a rock core, and testing physical property data of the rock core; then carrying out nuclear magnetic testing on the rock core; s3, saturating the rock core with formation water, and then carrying out nuclear magnetic testing; s4, carrying out gas drive water seepage test on the rock core according to the data in the S1, and obtaining the drive water quantity; s5, performing nuclear magnetic test on the depleted rock core; s6, obtaining the irreducible water saturation of the depleted rock core according to the nuclear magnetic test results of the steps S2, S3 and S5; s7, the total irreducible water saturation of the rock core is obtained according to the rock core physical property data, the displacement water amount and the irreducible water saturation of the rock core after exhaustion; the device comprises a drying oven, a first container, a second container, a core holder, a confining pressure pump, a displacement pump, a back pressure assembly, a receiving container and an electronic balance. The accuracy of fluid saturation determination can be improved.

The invention discloses a method for simulating and calculating the CO2 burying rate of an exhausted gas reservoir, which comprises the following steps: S1, acquiring rock core, formation water, methane and CO2 samples, and measuring the basic physical properties of each sample; s2, under the formation condition, the rock core is saturated with formation water and subjected to methane displacement till no water is discharged; s3, CO2 displacement is conducted on the rock core, and CO2 injection and extraction data in the process are recorded till the depletion state is achieved; s4, under the constant pressure condition, the rock core is subjected to standing treatment, and the basic physical property of the rock core subjected to standing treatment is measured; and S5, establishing a CO2 burying rate calculation model, and calculating the CO2 burying rate in combination with the parameters obtained in the steps. According to the method, the CO2 burying rate can be accurately calculated, and evaluation indexes and references are provided for the safety of CO2 geological storage.

The invention provides a tight sandstone gas reservoir formation water division method based on mercury intrusion and online nuclear magnetic resonance, and relates to the field of gas reservoir formation water production, and the method specifically comprises the following steps: obtaining a tight sandstone core standard rock sample; cutting the rock core into two sections, and performing a high-pressure mercury injection experiment on the first section of the rock core; and scanning the nuclear magnetic resonance signal T2 spectrum curve of the rock core in the completely saturated water state and the area of the nuclear magnetic resonance T2 spectrum curve. And carrying out gas drive and nuclear magnetic scanning experiments. And sequentially increasing the displacement pressure differences to obtain a nuclear magnetic resonance correction curve under different displacement pressure differences. And drawing a water saturation and displacement pressure difference relation curve, and defining the critical pressure difference of different types of formation water production according to the curve form and the slope change rule. And processing the data to obtain the formation water production rule of the tight sandstone gas reservoir in different states. According to the technical scheme, the problem that in the prior art, the critical output pressure difference and the dynamic output rule of various types of formation water in different pore diameter ranges cannot be quantitatively represented is solved.

The invention discloses a huff-puff mining experimental device and method based on the pressure flooding crack propagation effect, and relates to the technical field of oil and gas exploiting.The huff-puff mining experimental device comprises an experimental rock plate and a temperature control box, an injection port of the experimental rock plate is connected with an intermediate container, a liquid outlet is provided with a liquid drainage valve, and the intermediate container is connected with a displacement pump; monitoring the fluid pressure in the experimental rock plate through a pressure detection device; the crack pressure in the experimental rock plate is controlled through a pressure control device; observing the fluid percolation condition in the internal crack of the reservoir rock sample by using an observation device; sequentially injecting saturated formation water and formation crude oil into the experimental rock plate through a displacement pump, then injecting displacement fluid, and monitoring the pressure and flow of the injected fluid and the response condition of the crack; soaking the well and continuously monitoring the pressure change; and after the soaking is finished, opening the drain valve, recording the oil gas quantity produced in the flowback process, and calculating the recovery ratio. According to the invention, fluid seepage and soaking diffusion flowback laws under dynamic expansion of the pressure-driven fracture can be studied.

Method and systems are provided that characterize a geological formation, which involve collecting or obtaining electrical signal data that results from interaction of electrical signals with the formation. The electrical signal data is processed to determine data characterizing relative permittivity and conductivity of the formation. The data characterizing relative permittivity and conductivity of the formation are used as inputs to models to determine data characterizing water saturation of the formation, particularly useful in formation evaluation and reservoir saturation dynamic monitoring in fresh water and mixed salinity environments.

The invention discloses a method for analyzing diagenesis of clay minerals by combining physical simulation and numerical simulation, which comprises the following steps: selecting clay single minerals, and preparing a formation water solution; respectively filling the clay single mineral and the stratum water solution into a plurality of reaction kettles, and carrying out diagenesis physical simulation; establishing a numerical simulation model with the same physical simulation experiment condition, and outputting mineral and ion data; according to mineral and ion data, fitting a physical simulation experiment result and a numerical simulation result, and determining a mineral corrosion rate; and establishing a geologic model by taking the mineral dissolution rate as a reference, and performing clay single mineral diagenesis simulation within a geological time scale. According to the method, numerical simulation parameters are constrained by physical simulation experiment results, and comparison and verification of numerical simulation and physical simulation results are realized by adjusting mineral corrosion kinetic parameters in real time, so that the numerical simulation experiment results are close to actual conditions.

The invention discloses a grouting splitting pressure simulation device under high-ground and high-water-pressure conditions, and relates to the technical field of tunnel and underground engineering model tests. A first water permeable unit controlled by the water injection unit and a second water permeable unit controlled by the confining pressure unit are respectively arranged at two ends in the length direction, so that water pressure and stratum confining pressure are independently applied. The integrated grouting unit of the device is used for grouting soil in the box and is provided with a comprehensive detection unit, the comprehensive detection unit monitors various parameters such as grouting pressure, water pressure, confining pressure, flow, soil resistance and wave velocity in real time, and independent loading and accurate dynamic control of the grouting pressure, formation water pressure and formation stress can be achieved; therefore, the grouting process of the deep-buried tunnel under the conditions of different burial depths, high water head differences and complex grout characteristics can be simulated in a laboratory with high precision, and the technical bottleneck that the complex environment of high ground stress and high water pressure coupling is difficult to reproduce in a traditional test method is effectively solved.

A system may include a lower completion disposed in a main bore of a multilateral well in a position downhole from a junction of the multilateral well. The system may also include a fluid separator configured to receive formation fluid, which includes oil and water, flowing from the lower completion. The fluid separator may be configured to at least partially separate the formation fluid into formation oil and formation water. The fluid separator may also be configured to output the formation oil, via a separator oil outlet, to flow uphole, and output the formation water, via a separator water outlet, to flow toward a lateral bore of the multilateral well. Further, the system may include a water cut sensor disposed uphole from the fluid separator. The water cut sensor may be configured to measure the percentage of water in the formation oil.

The invention belongs to the technical field of oil and gas development, and discloses a formation water comprehensive compression coefficient measuring method and system.The method comprises the steps that a fracture network distribution rule and pore structure parameters are extracted; preparing a micro-fluidic chip; preparing formation water fluid containing dissolved gas, and injecting the formation water fluid into the micro-fluidic chip; carrying out a formation water failure development experiment under a reservoir in-situ condition, and recording gas-water saturation and pressure change in the micro-fluidic chip; quantifying the variation of the volume of the precipitated bubbles along with the pressure drop, and calculating a first compression coefficient contributed by the dissolved gas part and a second compression coefficient contributed by the formation water body part; and superposing the two coefficients to obtain the formation water comprehensive isothermal compression coefficient. According to the method, the formation water gassing expansion process can be monitored in real time, the formation water comprehensive isothermal compressibility coefficient can be more accurately calculated in combination with gas-water saturation and pressure change, and the problem that fluid seepage and fluid characteristics of the fractured low-porosity sandstone gas reservoir cannot be fully reflected is solved. The system has the same advantages as the method.

The invention discloses a fractured formation horizontal well wall stability quantitative control method under transient temperature and pressure coupling, and relates to the technical field of deep oil and gas drilling. The method comprises the following steps: analyzing the internal temperature of a drill column, the annulus temperature and the well wall temperature reflecting the transient temperature difference disturbance boundary effect by utilizing a drilling process API RP 13D rheological drilling fluid circulating temperature field control equation; establishing a dynamic ECD prediction model coupled with the annulus temperature and the pressure disturbance effect, and taking the transient temperature difference between the dynamic temperature of the well wall and the original temperature of the stratum, the transient pressure difference between the transient pressure of the well wall and the original pore pressure of the stratum and the transient stress difference between the transient pressure of the well wall and the original radial stress as dynamic disturbance boundary conditions; a pore pressure field and a stress field of rock around a well of the fractured formation under the heat-fluid-solid coupling effect under the non-uniform ground stress condition are analyzed in combination with a dual-pore thermoelasticity theory, a safe density window of the horizontal well of the fractured formation is determined, and well wall instability can be effectively prevented.

The invention discloses a method for characterizing changes of carbon dioxide salt water layer sealing pore permeability along with time based on a carbon dioxide-water-rock reaction. The method for characterizing the change of the carbon dioxide salt water layer sealing pore permeability along with the time based on the carbon dioxide-water-rock reaction comprises the following steps: carrying out a static CO2-water-rock reaction simulation experiment on a saturated core by adopting experimental formation water to obtain the particle sizes of suspended matters under different pressures; performing dynamic CO2-water-rock reaction experiments in the injection process under different pressures by adopting different research area stratum cores, and performing mercury injection test, porosity test and permeability test on the research area stratum cores before and after the experiments to obtain porosity and permeability change rate charts after CO2-water-rock reaction under different pressures; the long-term CO2-water-rock reaction pore permeability change is simulated through multi-field coupling of the model, and the quantification of the change of the pore permeability along with the time in the whole sealing process of injecting the carbon dioxide into the salt water layer is obtained.

The invention relates to the technical field of oil-gas exploration and development and oil-gas resource evaluation, in particular to a method for testing the influence of soluble salt on coal rock gas production. According to the method, the semi-open system high-temperature and high-pressure hydrocarbon generation and expulsion simulation experiment equipment is utilized, simulation formation water with different salts and different mineralization degrees is prepared, and under parameter control close to geological conditions, the influence of the mineralization degrees on coal rock gas generation is quantitatively evaluated. After all tests are completed according to the method disclosed by the invention, the relationship between formation water with different salts and different mineralization degrees and coal rock gas production is systematically established. The system has the advantages of being simple in structure, reasonable in design, comprehensive, high in operability and the like. Reasonable experimental methods and experimental schemes improve the reliability and accuracy of results, and the practicability is higher.

The invention discloses an experimental device and an experimental method for monitoring oil-gas-water components in a shaft, and particularly relates to the technical field of monitoring equipment.The experimental device comprises the shaft, a single-mode laser, a polarization maintaining optical fiber, a Brillouin optical time domain reflectometer, a condensate gas tank, a pressurization driving device, a stratum water tank, a condensate oil tank, a natural gas tank, a conveying device, an oil-gas-water separator and a waste oil tank; the polarization-maintaining optical fiber is spirally wound outside the shaft, and two ends of the polarization-maintaining optical fiber are respectively connected with the single-mode laser and the Brillouin optical time domain reflectometer; the pressurization driving device is used for pressurizing the condensate gas to the dew point pressure higher than that of the condensate gas and driving the condensate gas to leave the condensate gas tank; the conveying device is used for conveying formation water of the formation water tank, condensate oil of the condensate oil tank and natural gas of the natural gas tank to the shaft, and an outlet of the shaft is connected with the waste oil tank through the oil-gas-water separator. The oil-gas-water three-phase fluid in the shaft can be captured and dynamically tracked in real time, the measurement precision is high, and the experimental device is simple in structure and convenient to install.

The invention discloses a method, a device and equipment for identifying the flooding level of a to-be-developed drilling well and a medium. The method comprises the following steps: determining typical water flooded layers, and determining resistivity thresholds between the water flooded layers; rock-electricity parameters and formation water resistivity corresponding to the to-be-developed drilling well are determined; determining a porosity parameter corresponding to the to-be-developed drilling well, and determining a critical change curve between the critical water saturation of the to-be-developed drilling well under different water flooded layers and the porosity parameter based on a resistivity threshold value, a rock electricity parameter, the formation water resistivity and the porosity parameter; and on the basis of the porosity parameter, the rock electricity parameter, the formation water resistivity, the conventional logging curve and the critical change curve corresponding to the to-be-developed drilling well, determining a flooding level identification result corresponding to the to-be-developed drilling well. According to the invention, accurate identification of the to-be-developed well flooding level can be realized, the flexibility and accuracy of well flooding level identification are greatly improved, and the identification efficiency is improved.

Provided is a method for verifying fault-sand body matching by selective crude oil charging based on parallel displacement simulation. The method includes: selecting a plurality of groups of natural oil-bearing core samples having different porosities and making core columns; testing a charging power and a throat radius corresponding to a first core column, and calculating a vertical oil column height produced by simulated lateral abutting with a fault; mounting the second core column in a clamping simulation system; conducting a crude oil charging saturated formation water core simulation experiment, and simulating a variety of superimposition relationships of sand bodies spatially laterally abutting against the fault; regulating different charging pressures, simulating a vertical oil column height produced by lateral abutting with the fault, and analyzing a fault-sand body power configuration relationship under the action of a buoyancy based on a difference between crude oil charging behaviors in different simulated situations.

The invention relates to the technical field of shale exploitation, and discloses a shale reservoir wettability dynamic determination method, which comprises: S1, selecting a shale plunger core, carrying out supercritical CO2 cleaning and vacuum drying, and carrying out high pressure saturation by using simulated crude oil to obtain an initial oil saturation; and S2, the saturated rock core is loaded into a high-temperature and high-pressure rock core holder, and under the simulated formation temperature and pressure condition, simulated formation water containing the paramagnetic contrast agent is injected at the constant flow speed for displacement till the water content of the outlet end reaches 98%. According to the invention, dynamic and three-dimensional space representation of wettability is realized: three modal data of nuclear magnetic resonance, resistivity and sound wave are synchronously acquired in the displacement process, so that the limitation of a traditional static method is overcome, and the dynamic process of the wettability changing along with the fluid saturation state can be captured in real time; and finally, a high-resolution three-dimensional wettability distribution map is generated, and non-uniform distribution of wettability in the core is visually revealed.

The invention provides a shale primary formation water ion composition evaluation method and device. The method comprises the following steps: acquiring ion composition and tritium content of flow-back fluid in at least one time after hydraulic fracturing of a target well section of a target shale gas well; the ion composition and the tritium content of fracturing fluid used for hydraulic fracturing of the target well section of the target shale gas well are obtained; on the basis of the obtained tritium content of the flow-back fluid at each time and the tritium content of fracturing fluid used for hydraulic fracturing of the target well section of the target shale gas well, the mixing proportion of formation water in the flow-back fluid at each time is determined; and determining the ion composition of the formation water of the target well section of the target shale gas well by combining the determined mixing proportion of the formation water in the flow-back fluid at each time based on the obtained ion composition of the flow-back fluid at each time and the obtained ion composition of the fracturing fluid at each time. According to the method, the water ion composition of the primary formation of the shale reservoir can be accurately determined by utilizing the fracturing flow-back fluid ion content and tritium nuclide characteristics.

A method for passively producing hydrogen from a geological formation includes drilling a plurality of lateral wellbores into an iron-rich geological formation from a mother wellbore extending from a surface location. Each of the plurality of lateral wellbores has an inclination along its length of less than 90 degrees. A biocide configured to inactivate hydrogen-consuming microbes is placed into the plurality of lateral wellbores and thereby into formation water that is flowed from the geological formation into the plurality of wellbores. Hydrogen gas effervesced from the formation water in the plurality of lateral wellbores is collected via the mother wellbore. The hydrogen gas is generated at least in part from a water reduction reaction of minerals of the geological formation with the formation water and risen through the plurality of lateral wellbores passively by buoyancy effects without pumping.

The invention relates to the technical field of equipment detection, and discloses an equipment measurement and detection method, system and equipment, and the method comprises the steps: utilizing logging equipment to synchronously measure a first resistivity measurement value, a second resistivity measurement value and a third resistivity measurement value of different depths of an underground stratum; calculating a well fluid invasion depth value according to the first resistivity measurement value, the second resistivity measurement value and the third resistivity measurement value; solving a real formation resistivity value based on the well fluid invasion depth value; and performing gradient distortion correction on the real formation resistivity value according to the well fluid conductivity and the formation water conductivity to obtain a formation resistivity detection result. According to the method, the accuracy, adaptability and reliability of well fluid invasion correction of the resistivity logging equipment are improved.

The invention discloses a method, a system, equipment and a medium for detecting an oil-water two-phase relative permeability curve, and belongs to the technical field of oil-gas field development technologies. The detection method of the oil-water two-phase relative permeability curve comprises the following steps: washing oil and drying a rock core sample, vacuumizing the rock core sample, and injecting formation water into the rock core sample, so that the rock core sample reaches a saturated water state; injecting crude oil into the core sample at a preset oil reservoir temperature to enable the core sample to reach a saturated oil state; performing water-displacing oil operation on the rock core sample at a preset flow rate, and scanning the rock core sample at a plurality of scanning nodes by using a CT (Computed Tomography) scanning device; oil saturation and water saturation are calculated according to an actually measured rock core CT value, and parameter fitting is performed on the Corey model according to the oil saturation and the water saturation to obtain an oil-water two-phase relative permeability curve. The method can accurately detect the oil-water two-phase relative permeability curve of the rock core.

The invention discloses a fractured horizontal well crack water exploration numerical simulation method. The method comprises the steps that a crack and a water injection well corresponding to a target fractured horizontal well are determined; establishing an oil reservoir geologic model corresponding to the target fractured horizontal well on-site scale, and distinguishing formation water components and injection water components of the water injection well in the oil reservoir geologic model by giving different definitions; based on the different definitions, a historical fitting result is simulated through numerical values, and a source water injection well and a source crack of production water of the target fractured horizontal well are determined; the problem that effective water plugging measures cannot be specifically formulated due to the fact that the existing horizontal well numerical simulation water exploration technology cannot comprehensively and accurately recognize the water outlet crack condition is effectively solved.

The application discloses a method and system for predicting water inrush of sandified dolomite stratum under water-rich conditions, comprising: obtaining first detection data and second detection data; extracting first cross-section data and second cross-section data; the cross-section data is position data of a cross-section with discontinuity; comparing the first cross-section data and the second cross-section data, and taking a region with a difference greater than a preset value between the first cross-section data and the second cross-section data as a target drilling region; obtaining third cross-section data; forming cross-section fitting data of the target cross-section; and predicting construction water inrush risk. The method and system for predicting water inrush of sandified dolomite stratum under water-rich conditions effectively improve the advanced detection capability of sandified dolomite tunnel construction, improve construction safety and reduce construction risk by data fusion on the detection data in front of a tunnel face and accurate data acquisition and completion in combination with the advanced drilling technology.