276 results about "Formation water" patented technology

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 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 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.

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 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 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.

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 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.

The invention relates to a water-rock reaction mechanism in-situ measurement device and method, and belongs to the field of carbon dioxide geological sequestration experiment determination. The device comprises a formation water tank, a Raman probe, a reaction kettle, a vacuum pump, a gas tank, a formation water pipeline, a liquid circulating pump, a vacuum pipeline, a gas pipeline, a gas circulating pump, a connecting piece, a gas-liquid circulating pipeline and a sampling pipeline, wherein a sampler is arranged on the sampling pipeline. According to the invention, through combined arrangement of the formation water pipeline, the gas pipeline, the Raman probe and the pipeline where the connecting piece is located, real-time measurement of Raman spectrum data in the whole water-rock reaction process is realized; liquid and gas are mixed and circulated in the device in the water-rock reaction process by utilizing the combined arrangement of a gas-liquid circulating pipeline, a gas circulating pump and a liquid circulating pump, so that the accuracy of detection data is improved.

The application discloses a watered-out layer secondary interpretation method under the condition of small layer level oil-water interface understanding, and steps are as follows: step 1, small layer geological modeling and oil-water interface fine calibration; step 2, well logging data standardization and quality control; step 3, continuous calculation of small layer mixed formation water resistivity; step 4, completion of reservoir parameter quantitative calculation; step 5, obtaining of primary interpretation based on small layer oil-water interface; step 6, implementation of secondary iteration correction under the constraint of production dynamics; and step 7, output of interpretation results and application suggestions. The application belongs to the technical field of oilfield development well logging interpretation, and solves the problems that the prior art is not accurate in key parameter calculation, the interpretation process is single, and the precision and actual development demand are not matched.

The invention belongs to the technical field of oil-gas field development, and discloses a low-salinity formation water identification method, which comprises the following steps of: obtaining data corresponding to a test oil well through drilling data, and comparing step by step according to the obtained data to judge whether water is discharged from a formation; the invention further discloses a low-salinity formation water recognition device and equipment and a storage medium. The method is suitable for identifying the low-salinity formation water, whether water flows out of the formation or not is judged in real time by draining the test oil well, an important basis is provided for identifying the low-salinity formation water, and the defects of a formation water judgment method are overcome.

The invention discloses a water-producing gas well formation water distinguishing method, device and equipment and a medium, and relates to the technical field of formation water distinguishing. The method comprises the following steps: acquiring a chromatogram of output filtrate, determining an ion determination result according to the chromatogram, and generating a relation curve graph of a sampling date and the ion content in the ion determination result according to an anion determination result and a cation determination result; determining the gas well producing area layer water according to the relation curve graph of the sampling date and the ion content in the ion measurement result; and judging the water type of the formation water according to the affinity between anions and cations in the ion measurement result. And meanwhile, the formation water production reservoir is judged, so that the accuracy of distinguishing the formation water of the water production gas well and the applicability of distinguishing the formation water can be improved.

The invention discloses a method for establishing initial conditions of a gas reservoir through uniform initialization of a heterogeneous large rock plate model, and belongs to the technical field of gas reservoir development. On the basis that a conventional rock plate is provided with injection and production well inlets and outlets, the two sieve pipe injection channels are additionally arranged, the two ends of the sieve pipe are connected through the pipeline, and fluid can be injected into the sieve pipe; plugging or heating plugging removal operation is achieved by injecting a plugging agent into the four pipelines in good time, namely, an injection well and a production well are plugged firstly, formation water is injected through a screen pipe to make a rock plate saturated, and then formation water in the rock plate is displaced through gas injection of the screen pipe; the screen pipe is plugged, and a plugging removal injection and production well preparation experiment is carried out; the rock plate reaches an initial state of a gas drive / depletion experiment; the problem that the screen pipe becomes a high-permeability channel to affect a gas drive experiment and cause distortion of gas drive experiment data is avoided, the accuracy of a large flat plate model longitudinal heterogeneous gas reservoir water invasion failure or constant volume failure evaluation experiment can be improved, and the method has important significance on compact reservoir transformation and effective development.

The application discloses a reservoir gas-water relative permeability determination method, and relates to the field of reservoir permeability determination. The method comprises the following steps: obtaining a core sample of a target reservoir and determining the geometric size of the core sample; injecting simulated formation water into the core sample until the core sample is saturated, and performing nuclear magnetic scanning to obtain a reference nuclear magnetic signal and an initial porosity distribution; performing a multistage gas injection pressure experiment in an intermittent displacement mode to obtain quasi-steady-state displacement data; constructing a two-phase percolation numerical model with phase permeability curve parameters and capillary pressure curve parameters as to-be-inverted parameters; constructing a target function based on the quasi-steady-state data and performing inversion solving to obtain optimal parameters; and determining the phase permeability curve and the capillary pressure curve based on the optimal parameters. The application obtains the fluid distribution inside the core through nuclear magnetic resonance, obtains quasi-steady-state data in combination with intermittent displacement, and inversely solves the phase permeability and the capillary pressure, so that the problem that the fluid distribution inside the core cannot be accurately reflected and the multi-solution problem cannot be solved is solved, and the influence of the capillary end effect is eliminated.

A resettable, segmented pressure-driven water injection process string and method, belonging to the field of oilfield engineering technology, comprises, from bottom to top, a seated sliding sleeve connected sequentially to a lower reset sliding sleeve, packer I, a middle reset sliding sleeve, packer II, an upper reset sliding sleeve, packer III, a high-pressure well-washing valve, and tubing threads. The water injection string is lowered into the casing. The upper end of the tubing is suspended above the lower four-way valve at the water injection wellhead via a self-sealing core. A ball-dropped blowout preventer is located above the test gate at the water injection wellhead. An annular pressure self-balancing device is connected to the left-side production valve. The lower balancing hole, drain hole I, and inlet hole I of the annular pressure self-balancing device are connected to the left-side casing gate valve at the water injection wellhead via a connecting pipe. This invention is applicable to segmented pressure-driven water injection in oilfield water injection wells, meeting the needs of segmented formation water injection. The injection string can be reused, improving the qualification rate of the injection segments and saving operating costs.

The invention relates to the technical field of rock core experiments of oil and gas field development, in particular to a method and device for analyzing edge-bottom water gas reservoir chemical water shutoff recovery efficiency, and the device comprises a second full-diameter rock core holder for clamping a full-diameter rock core and simulating edge-bottom water; the high-pressure gas source is connected with the first full-diameter rock core holder and is used for providing saturated natural gas for the full-diameter rock core in the first full-diameter rock core holder; the high-pressure water source is connected with the second full-diameter core holder and is used for providing saturated formation water for the full-diameter core in the second full-diameter core holder; the standard container is used for collecting and metering gas flowing out of the first full-diameter core holder in real time; the I SCO pump is used for applying confining pressure to the first full-diameter core holder and / or the second full-diameter core holder. According to the method, indoor evaluation of the effect of improving the recovery efficiency by chemical water plugging can be carried out before chemical water plugging tests of gas reservoirs at the edge and the bottom of a mine field, and a direct basis is provided for formulating a recovery efficiency improving scheme.

The invention relates to the technical field of water-preserved coal mining, and discloses a water-preserved coal mining method for reinforcing a water-resisting layer by grouting and filling a separation layer area, which comprises the following steps of: determining a water-resisting layer to be reinforced by grouting according to stratum hydrogeological conditions disclosed by geological data in a coal mine exploration stage; before coal seam mining, drill sites are arranged in a mining area and the periphery of the mining area, vertical drill holes are constructed, and the vertical drill holes penetrate into a water-resisting layer to be subjected to grouting reinforcement; after vertical drilling construction is completed, hole washing is conducted, the final hole static water level is observed, the unit water absorption rate of an injected layer section is measured through a drilling water pressing test, and after the grouting technical standard is met, a horizontal jet hole is constructed through the radial jet hole forming technology; the static water level of the vertical drill hole is observed after grouting is completed, and coal seam mining is conducted according to a mining scheme determined by a coal mine after the static water level is stable; after a coal seam is mined and a rock stratum separation layer is formed, grouting drill holes are formed in the ground to fill a rock stratum separation layer area. According to the invention, the coal mining mode that the water-bearing layer above the water-resisting layer does not leak and the surface water source supply is not reduced can be realized.

A quantitative evaluation method for determining the influence of formation water salinity on shale gas reservoir reserves relates to the field of shale gas resource quantity and reserve evaluation, and solves the problem that the existing method is difficult to accurately describe the influence of formation water distribution and salinity on formation water, thereby making the result of calculating the formation gas reservoir reserves inaccurate. The method comprises the following steps: S1: collecting basic data of target shale layer in a target area, and constructing a shale reservoir model consistent with the real underground situation; S2: inserting shale gas into the shale reservoir model; determining the size of the methane gas reservoir in the model; S3: inserting methane gas molecules under different temperatures and pressures into the three numerical models of the reservoir, and recording the calculated methane gas reservoir quantity simulation value; S4: establishing a three-dimensional data coordinate system; S5: establishing a quantitative fitting relationship between the methane gas reservoir quantity simulation value and the underground pressure and salinity conditions. The quantitative evaluation method can accurately calculate the result of the formation gas reservoir reserves.

The utility model relates to the field of oil field production, in particular to a device for simulating the air injection oxidation effect of a water-containing oil reservoir, which comprises a containing bin, a first bottle body, a second bottle body and a third bottle body. The first end of the containing bin communicates with the first outlet valve and the second outlet valve. The first bottle body is communicated with the containing bin through a first pipeline and a first valve. The second bottle body is communicated with the containing bin through a second pipeline and a second valve. The third bottle body is communicated with the containing bin through a third pipeline and a third valve. And the first bottle body, the second bottle body and the third bottle body are respectively used for filling formation water, crude oil and air. The formation water, the crude oil and the air filled in the corresponding bottle bodies are fed into the accommodating bins through the corresponding pipelines, so that the air injection oxidation process of the water-containing oil reservoir can be simulated, and the problem that the oxidation effect of the formation water-containing oil reservoir is difficult to simulate due to the fact that injection of the formation water into the oil reservoir oxidation simulation system is not considered in the prior art is solved.

The invention discloses a quantitative evaluation method for resistivity heterogeneity of logging fusion formation water, and relates to the technical field of oil exploration and development. The method comprises the following steps of: obtaining formation signal data acquired by various logging and calculating reference formation water resistivity; a machine learning model is constructed based on feature data extracted from conventional logging, the formation water resistivity is a target variable of the machine learning model, and the machine learning model is trained to obtain a formation water resistivity prediction model; collecting conventional logging data, extracting feature data in the conventional logging data, inputting the feature data into the formation water resistivity prediction model, and outputting a formation resistivity prediction value; the formation resistivity prediction values of multiple depths form a continuous prediction curve to serve as a quantitative evaluation result of formation water resistivity heterogeneity, and the problem of accurate evaluation in the absence of nuclear magnetic resonance logging data is solved.